<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, 1999
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
----------------- ----------------
Commission Registrant, State of Incorporation I.R.S. Employer
File Number Address and Telephone Number Identification No.
- ------------- -------------------------------------- ------------------
0-30338 RGS Energy Group, Inc. 16-1558410
(Incorporated in New York)
89 East Avenue
Rochester, NY 14649
Telephone (716)771-4444
1-672 Rochester Gas and Electric Corporation 16-0612110
(Incorporated in New York)
89 East Avenue
Rochester, NY 14649
Telephone (716)546-2700
Securities Registered Pursuant to section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
RGS Energy Group, Inc.
Common stock, $.01 par value New York Stock Exchange
Securities Registered Pursuant to section 12(g) of the Act:
Title of each class
- -------------------
Rochester Gas and electric Corporation
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 whether each registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
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Indicate 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, 2000 the aggregate market value of the voting stock of RGS
Energy Group, Inc. ("RGS") held by nonaffiliates was approximately:
$733,460,000.
On January 1, 2000 the aggregate market value of the voting stock of Rochester
Gas and Electric Corporation ("RG&E") held by nonaffiliates was:
None.
As of the close of business on January 1, 2000, (i) RGS had outstanding
35,943,213 shares of Common Stock ($.01 par value) and, (ii) all of the
outstanding shares of Common Stock ($5 par value) of RG&E were held by RGS.
RG&E meets the conditions set forth in General Instructions (J)(1)(a) and (b)
of Form 10-K and is therefore, filing this form with the reduced disclosure
format pursuant to General Instructions (J)(2).
Documents Incorporated By Reference
Portions of RGS's definitive proxy statement in connection with the 2000
Annual Meeting of Shareholders, to be filed with the Commission pursuant to
Regulation 14A not later than 120 days after December 31, 1999, are incorporated
in Part III of this report. Information required by Part III with respect to
RG&E has been omitted pursuant to General Instruction (J)(2)(c).
<PAGE>
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed August 2,
1999, which is the parent company of Rochester Gas and
Electric Corporation, RGS Development Corporation and
Energetix, Inc.
CWIP Construction work-in progress
RGS Development RGS Development Corporation, a wholly-owned subsidiary of
the Company
EITF Emerging Issues Task Force
Energetix Energetix, Inc., a wholly-owned subsidiary of the Company
Energy Choice A competitive electric retail access program of RG&E being
phased-in over a period ending July, 2001.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by RG&E
Griffith Griffith Oil Company, Inc ., an oil, gasoline and propane
distribution company acquired by Energetix in 1998
ISO Independent System Operator
LDC Local Distribution Company
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which RG&E owns
a 14% share
NOI Notice of Inquiry
NOPR Notice of Proposed Rulemaking
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYNOC New York Nuclear Operating Company
NYPA New York Power Authority
O&M Operation and Maintenance
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned
subsidiary of RGS
SEC Securities and Exchange Commission
Settlement Competitive Opportunities Case Settlement among RG&E, PSC
and other parties which provides the framework for the
development of competition in the electric energy
marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
<PAGE>
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
Information Required on Form 10-K
<TABLE>
<CAPTION>
Page
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FILING FORMAT 1
FORWARD-LOOKING STATEMENTS 1
<CAPTION>
Item
Number Description
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<S> <C> <C>
Part I
- ------
Item 1 Business 1
Item 2 Properties 14
Item 3 Legal Proceedings 16
Item 4 Submission of Matters to a Vote of Security Holders 19
Item 4A Executive Officers of the Registrant 19
Part II
- -------
Item 5 Market for the Registrant's Common Equity and
Related Stockholder Matters 22
Item 6 Selected Financial Data 24
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 27
Item 7A Quantitative and Qualitative Disclosures about
Market Risk 50
Item 8 Financial Statements and Supplementary Data 51
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 88
Part III
- --------
Item 10 Directors and Executive Officers of the Registrant 89
Item 11 Executive Compensation 89
Item 12 Security Ownership of Certain Beneficial Owners and
Management 89
Item 13 Certain Relationships and Related Transactions 89
Part IV
- -------
Item 14 Exhibits, Financial Statement Schedules and Reports
on Form 8-K 90
Signatures 95
</TABLE>
<PAGE>
1
FILING FORMAT
This Annual report on Form 10-K is a combined report being filed by two
different registrants: RGS Energy Group, Inc. ("RGS") and Rochester Gas and
Electric Corporation ("RG&E"). See "Corporate Structure" in Item 1. Except
where the content clearly indicates otherwise, any references in the report to
"RGS" or the "Company" include all subsidiaries of RGS including RG&E. RG&E
makes no representation as to the information contained in this report in
relation to RGS and its subsidiaries other than RG&E.
FORWARD-LOOKING STATEMENTS
This report contains statements which are not historic fact and which can
be classified as forward looking. These statements can be identified by the use
of certain words which suggest forward looking information, such as "believes,"
"will," "expects," "projects," "estimates" and "anticipates". They can also be
identified by the use of words which relate to future goals or strategies.
Actual results or developments might differ materially from those included in
the forward-looking statements because of factors such as those discussed in
Item 7.
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.
<TABLE>
<CAPTION>
CAPTION PAGE
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<S> <C>
Corporate Structure 1
Electric Operations 3
Gas Operations 5
Unregulated Operations 6
Regulatory Matters 6
Fuel Supply 7
Financing and Capital Requirements Program 8
Environmental Quality Control 10
Research and Development 11
Operating Statistics 12
</TABLE>
CORPORATE STRUCTURE
RGS Energy Group Inc. Incorporated in 1998 in the State of New York, RGS
became the holding company for RG&E on August 2, 1999. RGS has no employees and
no significant business operations other than through RG&E and RGS's other
subsidiaries as described below.
Rochester Gas and Electric Corporation. Incorporated in 1904 in the State
of New York, RG&E is engaged principally in the business of generating,
purchasing, transmitting and distributing electricity, and purchasing,
transporting and distributing natural gas. The business produces and distributes
electricity and distributes gas in parts of nine counties centering about the
City of Rochester. At December 31, 1999 the RG&E had 1,975 employees.
RG&E's service area for its regulated business 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
<PAGE>
2
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 RG&E's service area
manufacture consumer goods. Many of RG&E's industrial customers are nationally
known, such as Xerox Corporation, Eastman Kodak Company, Bausch & Lomb
Incorporated and Delphi Automotive Systems, Inc.
Energetix, Inc. It is part of the Company's financial strategy to seek
growth by entering into unregulated businesses. The Competitive Opportunities
Settlement (discussed under Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations) allows the Company to invest up
to $100 million in unregulated businesses. The first step in this direction was
the formation and operation of Energetix. Energetix is an unregulated
subsidiary that brings energy products and services to the marketplace including
the marketing of electricity, natural gas, gasoline, oil and propane fuel energy
services in an area extending approximately in a 150-mile radius around
Rochester. Energetix has over 15,000 customers for natural gas and electricity
service.
Acquisitions under Energetix' control include Griffith Oil Co., Inc., the
second largest oil and propane distribution company in New York State, and
Stanbury Propane, Bobbett Gas Service and Clark Oil. The acquisitions give
Energetix access to 70,000 customers, 65,000 of which are residing outside of
the RG&E's regulated franchise territory. Including the acquisitions, Energetix
has 379 employees and operates 18 customer service centers.
RGS Development Corporation. In 1998, the Company formed RGS Development
to pursue unregulated business opportunities in the energy marketplace. RGS
Development operations have not been material to RGS's results of operations or
its financial condition.
Seasonal Nature of Business. The business of RGS and RG&E 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 natural
gas, kerosene, propane and heating oil, the greatest sales occur in the winter
months due to spaceheating usage. In addition, gasoline sales reflect seasonal
fluctuations due to increased consumer driving during the warmer months. In
each of the communities in which it renders regulated utility service, RG&E,
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.
Segment Information. 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 regulated 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 Operations. Percentages of the Company's
operating revenues derived from electric and gas service and unregulated
businesses for each of the last three years are as follows:
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3
<TABLE>
<CAPTION>
RGS RG&E
---------------------
1999 1999 1998 1997
------ ------ ------ -----
<S> <C> <C> <C> <C>
Electric 57.9% 64.1% 66.4% 67.6%
Gas 23.1% 25.5% 26.6% 32.4%
Unregulated 19.0% 10.4% 7.0% - %
----- ----- ----- ----
100.0% 100.0% 100.0% 100.0%
</TABLE>
RGS 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.
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, Energy Choice Program,
FERC Open Access, PSC Proceeding on Nuclear Generation, Proposed Purchase of
Nuclear Plants, PSC Gas Restructuring and the competitive challenges the Company
faces in its electric and gas business and how it is responding to those
challenges.
ELECTRIC OPERATIONS
Overview. In November 1997 the PSC approved a Settlement Agreement among
RG&E, 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 through July 1, 2002. Regarding RG&E's electric business, starting
in 1996 the FERC issued new rules to facilitate the development of competitive
wholesale markets. In 1998, FERC issued an order that conditionally authorizes
the establishment of an independent system operator (NYISO) to administer a
state-wide open access tariff. In 1999 the FERC issued an Order approving the
NYISO Open Access tariff, the NYISO Services tariff and the related ISO
Agreements of each of the Member Systems of the New York Power Pool. In
November 1999 the NYISO implemented a competitive wholesale market for the sale,
purchase and transmission of electricity in New York State. In December 1999
FERC issued Rule No. 2000 which calls for transmission owners to join regional
transmission organizations to boost competition (see following discussion under
"Regulatory Matters"). At the State level, the PSC endorsed a fundamental
restructuring of the electric utility industry in the State in its "Competitive
Opportunities Proceeding". RG&E's Competitive Opportunities Settlement in 1997,
including its 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. Through
December 31, 1999, eight energy service companies have been qualified by the
Company to serve retail customers under the Energy Choice Program.
In December 1999, RG&E exercised its right-of-first-refusal to acquire the
interests of Niagara Mohawk Power Corporation (Niagara Mohawk) and New York
State Electric and Gas Corporation (NYSEG)in the Nine Mile Two Plant and to buy
Nine Mile One (see Item 7 under the heading "Proposed Purchase of Nuclear
Plants" for further information). In a number of proceedings involving nuclear
generation in New York State, including the proceedings related to the proposed
sale of interests in Nine Mile, the PSC is expected to address issues related to
the future of nuclear generation in the State. A final determination of these
issues is not expected until later in 2000.
Electric System. The total net generating capacity of RG&E's electric
system is 1,033,000 kilowatts (Kw). In addition RG&E purchases 120,000 Kw of
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4
firm power under contract and 35,000 Kw of non-contractual peaking power from
the New York Power Authority (NYPA), 150,000 Kw of a 1,000,000 Kw pumped storage
plant owned by NYPA in Schoharie County, New York and 44,000 Kw of firm power
from NYPA's 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York.
RG&E's net peak load of 1,433,000 Kw occurred on July 6, 1999.
The percentages of electricity actually generated and purchased for the
years 1995-1999 are as follows:
<TABLE>
<CAPTION>
RGS RG&E
--------------------------------------
1999 1999 1998 1997 1996 1995
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Sources of Generated Energy:
Nuclear 52.2% 54.9% 59.5% 61.6% 49.4% 52.8%
Fossil 18.7 19.6 22.0 20.0 18.2 18.6
Hydro and Other 1.5 1.6 2.1 2.7 3.0 2.0
----- ----- ----- ----- ----- -----
Total Generated Net 72.4 76.1 83.6 84.3 70.6 73.4
Purchased 27.6 23.9 16.4 15.7 29.4 26.6
----- ----- ----- ----- ----- -----
Total Electric Energy 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== ===== =====
</TABLE>
Generating Facilities. The RG&E's four 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 two fossil fuel
generating stations, the Russell and Allegany Stations. In terms of capacity
these comprise 46%, 15%, 25% and 6%, respectively, of the Company's current
electric generating system. For information relating to the retirement of Beebee
Station and the sale of Oswego Unit Six in 1999 see Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Fossil Unit Status".
Nine Mile Two, a nuclear generating unit in Oswego County, New York with a
designed capability of 1,143 Mw as estimated by Niagara Mohawk, was completed
and entered commercial service in Spring 1988. Niagara Mohawk 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 Mohawk (41%) Long Island Power
Authority (formerly Long Island Lighting Company) (18%), NYSEG (18%) and Central
Hudson Gas & Electric Corporation (9%). Under the operating Agreement, Niagara
Mohawk serves as operator of Nine Mile Two, but all five cotenant owners share
certain policy, budget and managerial oversight functions. Niagara Mohawk and
NYSEG have proposed to sell their interests in Nine Mile Two and Nine Mile One
to AmerGen and to turn over operational control of the plants to AmerGen as
well. RG&E has exercised its right to match the AmerGen offer and proposes to
purchase the interests and enter into an operating agreement with Entergy Nine
Mile, LLC (see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Proposed Purchase of Nuclear Plants").
The gross and net book cost of the RG&E's share of the Nine Mile Two facility
including $374 million of disallowed costs previously written off, as of
December 31, 1999 are $880 million and $376 million, respectively.
RG&E's Ginna Plant, which has been in commercial operation since July 1,
1970, provides 480 Mw of the RG&E's electric generating capacity. In August
1991 the NRC approved the RG&E's application for amendment to extend the Ginna
Plant operating license expiration date from April 25, 2006 to September 18,
2009.
<PAGE>
5
The gross and net book cost of the Ginna Plant facility as of December 31,
1999 are $579 million and $267 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. RG&E 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 $5.2 million, $7.5 million and $8.0
million for the years 2000, 2001 and 2002, 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.
RG&E has three licensed hydroelectric generating stations (Stations 2,5 and
26) with an aggregate capability of 47 megawatts.
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 $88.1 million per licensed facility for each
nuclear incident, payable at a rate not to exceed $10 million per incident per
year. Those assessments are subject to periodic inflation indexing and a
surcharge for New York State premium taxes. RG&E's interests in two nuclear
units could expose it to a potential liability for each accident of $100.4
million through retrospective assessments of $11.4 million per incident 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,
RG&E is required to have and maintain financial protection to cover radiation
injury claims of certain nuclear workers. RG&E 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 RG&E, 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, RG&E could be assessed under these former policies along
with the other policyholders. RG&E's share could be up to $3.1 million in any
one year.
RG&E 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 damage
at nuclear generating units. If an insuring program's losses exceeded its other
resources available to pay claims, RG&E could be subject to maximum assessments
in any one policy year of approximately $1.8 million and $8.0 million in the
event of losses under the replacement power and property damage coverages,
respectively.
GAS OPERATIONS
With the unbundling of interstate gas pipeline 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 had a choice of suppliers since November 1996,
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6
subject to certain phase-in limitations through 1998 for loss of gas commodity
sales. Some of these customers are large, nationally known, publicly held
companies. In 1998 the PSC issued a gas restructuring policy statement which
concluded, among other things, that the most effective way to establish a
competitive gas supply market is for gas distribution companies to cease selling
gas. For further information concerning issues relating to RG&E under the PSC's
Gas Policy Statement see Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations under the heading "Rates and
Regulatory Matters".
As of December 31, 1999 RG&E's daily city gate resource capability is
3,700,000 therms and its daily contracted transportation capacity is 4,493,000
therms (where one Therm is equivalent to 100,000 British Thermal Units). RG&E
optimizes its assets by contracting for gas resources that align with its system
requirements. RG&E 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).
RG&E sells, distributes and transports natural gas to a geographic
territory in a nine-county area centered around the City of Rochester, NY. RG&E
purchases all of its required gas supply from numerous marketers and producers
under contracts containing various terms and conditions. RG&E's natural gas
supply mix includes long-term, short-term and spot natural gas purchases
transported on both firm and interruptible transportation contracts.
Approximately 30% of the gas delivered to customers by RG&E during 1999 was
purchased directly by commercial, industrial and municipal customers from energy
marketers. RG&E provided the transportation of gas on its system to these
customers' premises. As RG&E customers continue to migrate to gas marketers,
including Energetix, RG&E is terminating gas supply and transportation contracts
upon expiration.
During 1999, approximately 80% of RG&E's natural gas supply was purchased
from various suppliers under long-term and short-term contracts which includes
baseload monthly purchases and 20% was purchased on the daily spot natural gas
market to maximize natural gas cost savings. The company hedges its exposure to
fluctuations in natural gas commodity prices through the use of futures
contracts and storage assets.
UNREGULATED OPERATIONS
Energetix serves over 15,000 electric and gas customers and appliance service
warranty customers and, through its acquisitions of Griffith Oil Company, Inc.,
Stanbury Propane, Clark Oil and Bobbett Gas Service approximately 70,000
customers for its other products including oil, diesel, kerosene, propane and
gasoline. See Note 4 of the Notes to Financial Statements for additional
operating information and Management's Discussion and Analysis of Financial
Condition and Results of Operations under Unregulated Operating Revenues and
Sales for information on products, revenues and sales.
REGULATORY MATTERS
RG&E is subject to PSC regulation of rates, service, and sale of
securities, among other matters. RG&E 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, RG&E is also subject to regulation by the
Nuclear
<PAGE>
7
Regulatory Commission (NRC). The impact of regulation is discussed throughout
this report.
FERC ORDER NO. 2000. On December 15, 1999, FERC adopted Order No. 2000
(the Rule), a significant action regarding electric industry restructuring which
calls for transmission owners to join regional transmission organizations (RTOs)
on a voluntary basis. The RTOs will serve as umbrella organizations, which will
put all public utility transmission facilities in a region under common control.
RTOs are expected to benefit consumers through lower electricity rates resulting
from a wider choice of services and service providers. FERC is scheduling
regional workshops in the first half of 2000 as part of a collaborative process
to accommodate regional needs. The Rule requires all public utilities that own,
operate or control interstate transmission facilities to file by October 15,
2000(or for public utilities like RG&E already participating in an ISO by
January 15, 2001), a proposal for an RTO, or, alternatively, a description of
any efforts made by the utility to participate in an RTO.
On November 18, 1999 the NYISO implemented a competitive wholesale market
for the sale, purchase and transmission of electricity and ancillary services in
New York State. Previously, FERC authorized the NYISO, approved tariffs and
approved ISO agreements of the Member Systems. Whether the NYISO is considered
an RTO under the Rule is expected to be determined as part of the collaborative
process described above. For further information regarding "FERC Open Access
Transmission Orders and Company Filings" see Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations. Additional
information regarding the Rule and the characteristics and functions of an RTO
can be found at http://www.ferc.fed.us/news1/policy/pages/orders.htm.
FERC GAS MARKET PROPOSALS. On July 29, 1998, the FERC issued a Notice of
Proposed Rulemaking (NOPR) (RM98-10) on short-term natural gas transportation
services, which proposed an integrated package of revisions to its regulations
governing interstate natural gas pipelines. Under the proposed approach
regulatory policies are intended to maximize competition in the short-term
transportation market, mitigate the ability of companies to exercise residual
pipeline market power, and provide opportunities for greater flexibility
providing pipeline services without disadvantaging customers that have limited
access to gas supplies. The proposed changes include, among other things,
initiatives to revise pipeline scheduling procedures and the policies that
govern the flow of gas through the pipelines; require pipelines to auction
short-term capacity; and permit pipelines to negotiate rates and terms of
services.
In conjunction with the NOPR, the FERC also issued a Notice of Inquiry
(NOI) (RM98-12) on its pricing policies in the existing long-term market and
pricing policies for new capacity. No final orders have been issued in these
proceedings. Thus, the Company is presently unable to estimate the effects of
these matters on future operations.
See Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Rates and Regulatory Matters" for
information regarding a gas restructuring policy statement, a gas interim
settlement and approved proposal, and a flexible pricing tariff for major
industrial and commercial electric customers.
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
<PAGE>
8
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 2001(3) 2002(2)
Conversion 2000(4) 2002(2)
Enrichment 2009(5) 2003(6)
Fabrication 2009 2004
</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) RG&E has two contracts in place which will supply 100 percent of the annual
Ginna Plant uranium requirements in 2000. A third contract is in place,
which is supplying 500,000 pounds of uranium between 1999 and 2004 as
scheduled by RG&E. This material may be scheduled for delivery against
requirements in 2001, or may be scheduled for later delivery depending on
the market price of uranium at the time. The remaining requirements are
uncommitted.
(4) A contract is in place covering 100% of requirements in 2000. Remaining
requirements will be filled from market purchases or a new long term
contract.
(5) RG&E has a contract for nuclear fuel enrichment services which, assures
provision of 100% of the Ginna Plant's requirements through the end of the
current operating license.
(6) Nine Mile Two is covered for 75% of requirements through 2003 (with an
option to increase to 100%).
With appropriate lead times, RG&E will pursue arrangements for the supply
of uranium requirements and related services beyond those years for which
arrangements have been made as shown above.
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. RG&E's 2000 coal requirements are expected to be approximately
500,000 tons. In 1999 92% of its requirements were purchased under contract and
8% were purchased on the spot market. RG&E maintains a reserve supply of coal
ranging from 30-60 days supply at maximum burn rates.
The sulfur content of the coal utilized in RG&E's coal-fired facility
ranges from 1.0 to 2.0 pounds per million BTU. Under existing New York State
regulations, RG&E's coal-fired facility may not burn coal which exceeds a sulfur
content of 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. In 2000, Phase II Acid Rain Requirements will apply,
requiring the surrender of SO2 allowances to match SO2 emissions.
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of RGS's capital requirements, financial objectives and the
resources available to meet such requirements may be found in Item 7 -
<PAGE>
9
Management's Discussion and Analysis of Financial Condition and Results of
Operations. RG&E expects to issue up to $200 million of long-term debt in
connection with its proposed acquisition of the Nine Mile One facility and the
Niagara Mohawk and NYSEG interests in Nine Mile Two. Through December 31, 1999
RGS has repurchased 2.9 million shares of Common Stock under a program which
began in May 1998. Common Stock is the only security issued by RGS. Preferred
Stock and Mortgage Bonds have been issued by RG&E. The sale of additional
issues of these securities by RG&E depends on regulatory approval and RG&E's
ability to meet certain requirements contained in its mortgage and Restated
Certificate of Incorporation.
Under the New York State Public Service Law, RG&E is required to secure
authorization from the PSC prior to issuance of any stock or any debt having a
maturity of more than one year.
RG&E'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 forty supplemental indentures.
Before additional First Mortgage Bonds are issued, the following financial
requirements must be satisfied:
(a) The First Mortgage prohibits the issuance of additional First Mortgage
Bonds unless earnings (as defined) for a period of twelve months ending not
earlier than sixty days prior to the issue date of the additional bonds are
at least 2.00 times the annual interest charges on First Mortgage Bonds,
both those outstanding and those proposed to be outstanding. The ratio
under this test for the twelve months ended December 31, 1999 was 5.83.
(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, 1999 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately $423,190,000.
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, 1999, RG&E could
issue $227,169,000 of Bonds against Bonds that have matured or been
redeemed.
RG&E's Restated Certificate of Incorporation (Charter) provides that,
without consent by two-thirds of the votes entitled to be cast by the preferred
stockholders, RG&E 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, 1999, the coverage ratio under
(b) above (the more restrictive provision) was 2.10.
For other information with respect to long-term and short-term borrowing
arrangements and limitations see Item 8, Note 6 - Long-Term Debt and Note 9 -
Short-Term Debt.
The Charter of RGS does not contain any financial tests for the issuance of
common or preferred stock. The Charter of RG&E does not contain any financial
tests for the issuance of common or preference stock.
<PAGE>
10
RGS has not issued any mortgage bonds or preferred stock. RG&E's
securities ratings at December 31, 1999 were:
<TABLE>
<CAPTION>
First
Mortgage Preferred
Bonds Stock
-------- ---------
<S> <C> <C>
Standard & Poor's Corporation A- BBB
Moody's Investors Service A3 baa1
Duff & Phelps A- 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 RGS's facilities are subject to various federal, state and
local environmental standards. To assure compliance with these requirements,
RGS expended approximately $2.5 million on a variety of projects and facility
additions during 1999.
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. RG&E has storage capacity at the Ginna Plant through
the end of its license in 2009. 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.
RG&E has wastewater discharge permits from NYSDEC for each of its steam
electric generating stations. The Ginna Station permit is dated February 1998;
the Beebee station permit is dated February 1999; and the Russell Station permit
is dated June 1999. These permits are each valid for a period of five years
from their effective dates. Consistent with the Ginna permit, no significant
changes to the wastewater discharge treatment systems are currently required,
nor anticipated. At Beebee station, the plant went off line in June, 1999. Two
of three discharge points have either been re-routed or have ceased operation.
The wastewater treatment plant continues to operate in a batch mode at a
significantly reduced frequency. At Russell Station an oil/water separator has
been installed as a preventive measure against oil contamination within the
station wastewaters. The cost of this separator is approximately $.6 million.
RG&E is developing strategies responsive to the Federal Clean Air Act
amendments of 1990 (CAA) which will primarily affect air emissions from RG&E'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 only an
O&M impact. The most recent strategic developments still envision this
combination of efforts as the most cost effective means of proceeding although
there is some New York State legislative activity that could impact RG&E's
ability to rely upon the emission allowance market to meet some of its
environmental commitments. RG&E cannot predict the outcome of these matters in
the Legislature and, as a result, RG&E's projections are based solely on the
combination strategy. Capital expenditures due to CAA requirements are expected
to be limited to $0.3 million in 2000. In 2000, it is estimated that additional
<PAGE>
11
O&M costs for emissions control will range between $2.7 million and $3.4
million. O&M costs could increase further after this point depending on new
Federal and state regulations. Any further capital expenditures for additional
NOx control have been deferred until after 2000. These additional capital costs
and any increases in annual operating costs that would be incurred as a result
of these capital additions beyond the year 2000 cannot be predicted accurately
until a final strategy is chosen which will await pending Federal and State
regulatory decisions. (See Item 8, Note 10 under the heading "Environmental
Matters" regarding initiatives of the New York Governor concerning the state's
oxides of nitrogen (NOx) and sulfur dioxide (SO2) control programs and the New
York Attorney General requesting historic information regarding certain
upgrades, modifications and maintenance activities at coal fired power plants.)
RG&E believes that additional expenditures and costs made necessary by
mandated environmental protection programs will be allowable for ratemaking
purposes under cost of service rate regulation; but under the terms of RG&E's
Competitive Opportunities Settlement Agreement, which sets a threshold of $2.5
million for recoverability of expenditures and costs resulting from mandates,
the full amount of these items may not be recoverable. Capital expenditures for
meeting various federal, State and local environmental standards are estimated
to be $0.3 million for the year 2000, $1.5 million for the year 2001 and $.5
million for the year 2002. These estimates, which could change based on the
impact of the initiatives described above, 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 3 - Legal Proceedings and Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations, with respect to other
environmental matters.
RESEARCH AND DEVELOPMENT
RG&E'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 1999, 1998 and 1997 were $2.9 million,
$3.4 million, and $4.5 million, respectively. These expenditures represent
RG&E's contribution to research administered by Electric Power Research
Institute, New York Gas Group, 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>
12
Electric Department Statistics
<TABLE>
<CAPTION>
RGS RG&E
Year Ended December 31 1999 1999 1998 * 1997 1996 1995
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Electric Revenue (000's)
Residential $ 282,391 $ 282,391 $ 250,073 $ 252,464 $ 254,885 $ 256,294
Commercial 166,410 166,410 203,316 210,643 215,763 215,696
Industrial 112,390 112,390 130,778 144,305 153,337 157,464
Municipal and Other 47,098 47,098 58,889 72,061 66,898 67,128
---------- ---------- ---------- ---------- ---------- ----------
Electric revenue -- retail customers 608,289 608,289 643,056 679,473 690,883 696,582
Energy Marketers 65,204 65,204 15,049 --- --- ---
Other Electric Utilities 25,251 25,251 28,995 20,856 16,885 25,883
Other unregulated electric revenues 4,007 1,450 522 --- --- ---
---------- ---------- ---------- ---------- ---------- ----------
Total electric revenues 702,751 700,194 687,622 700,329 707,768 722,465
Electric Expense (000's)
Fuel for electric generation 49,297 49,297 53,954 47,665 40,938 44,190
Purchased electricity 53,013 53,013 27,024 28,347 46,484 54,167
Other unregulated fuel expense 1,324 33 --- --- --- ---
Operation and maintenance 233,845 233,845 233,422 246,275 246,175 243,556
Unregulated operation and maintenance 2,233 1,046 1,997 --- --- ---
Depreciation and amortization 103,000 102,970 102,133 103,395 92,615 78,812
Taxes - local, state and other 84,492 83,922 89,600 91,111 95,010 102,380
---------- ---------- ---------- ---------- ---------- ----------
Total electric expense 527,204 524,126 508,130 516,793 521,222 523,105
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 175,547 176,068 179,492 183,536 186,546 199,360
Federal income tax 55,203 55,527 61,477 61,837 61,901 59,500
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Electric Operations (000's) $ 120,344 $ 120,541 $ 118,015 $ 121,699 $ 124,645 $ 139,860
---------- ---------- ---------- ---------- ---------- ----------
Electric Sales - KWH (000's)
Residential 2,269,005 2,269,005 2,119,846 2,139,064 2,132,902 2,144,718
Commercial 1,783,128 1,783,128 2,036,144 2,118,991 2,061,625 2,064,813
Industrial 1,762,369 1,762,369 1,913,611 2,010,613 2,010,963 1,964,975
Municipal and Other 481,610 481,610 516,585 537,051 520,885 531,311
---------- ---------- ---------- ---------- ---------- ----------
Total retail sales 6,296,112 6,296,112 6,586,186 6,805,719 6,726,375 6,705,817
Energy Marketers(including Energetix) 762,999 762,999 174,676 --- --- ---
Other electric utilities 1,111,928 1,111,928 1,498,669 1,218,794 994,842 1,484,196
Other unregulated sales 23,147 2,372 --- --- --- ---
---------- ---------- ---------- ---------- ---------- ----------
Total electric sales 8,194,186 8,173,411 8,259,531 8,024,513 7,721,217 8,190,013
Electric Customers at December 31
Residential 310,861 310,861 310,045 308,909 307,181 306,601
Commercial 30,178 30,178 30,483 30,940 30,620 30,426
Industrial 1,026 1,026 1,128 1,300 1,325 1,347
Municipal and Other 2,324 2,324 2,689 2,824 2,688 2,711
Unregulated electric customers 6,937 --- 830 --- --- ---
---------- ---------- ---------- ---------- ---------- ----------
Total electric customers 351,326 344,389 345,175 343,973 341,814 341,085
---------- ---------- ---------- ---------- ---------- ----------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,692,605 1,692,605 1,962,889 1,664,914 1,512,513 1,631,933
Nuclear 4,734,703 4,734,703 5,323,639 5,119,544 4,094,272 4,645,646
Hydro 133,317 133,317 189,512 227,867 248,990 171,886
Pumped storage 233,279 233,279 232,927 238,900 246,726 237,904
Less energy for pumping (349,836) (349,836) (348,438) (358,350) (370,097) (361,144)
Other 1,334 1,334 195 890 936 1,565
---------- ---------- ---------- ---------- ---------- ----------
Total generated - net 6,445,402 6,445,402 7,360,724 6,893,765 5,733,340 6,327,790
Purchased 2,088,761 2,067,986 1,465,797 1,301,636 2,437,433 2,343,484
---------- ---------- ---------- ---------- ---------- ----------
Total electric energy 8,534,163 8,513,388 8,826,521 8,195,401 8,170,773 8,671,274
RG&E System Net Capability -
KW at December 31
Total system net capability 1,382,000 1,382,000 1,588,000 1,614,000 1,617,000 1,619,000
RG&E Net Peak Load - KW 1,433,000 1,433,000 1,388,000 1,421,000 1,305,000 1,425,000
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
13
<TABLE>
<CAPTION>
Gas Department Statistics
RGS RG&E
Year Ended December 31 1999 1999 1998 * 1997 1996 1995
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Gas Revenue (000's)
Residential $ 5,658 $ 5,658 $ 2,944 $ 5,852 $ 6,010 $ 4,081
Residential spaceheating 212,786 212,786 201,686 249,101 246,945 230,934
Commercial 31,134 31,134 40,196 51,893 52,073 51,117
Industrial 3,016 3,004 4,222 5,800 6,175 6,686
Municipal and other 26,077 26,077 25,492 23,663 35,076 1,045
Other unregulated gas revenues 5,805 2,896 117 ---- ---- ----
---------- ---------- ---------- ---------- ---------- ----------
Total gas revenue 284,476 281,555 274,657 336,309 346,279 293,863
---------- ---------- ---------- ---------- ---------- ----------
Gas Expense (000's)
Gas purchased for resale 146,985 146,985 155,497 196,579 202,297 167,762
Other unregulated fuel expense 4,473 1,998 --- --- --- ---
Operation and maintenance 64,045 64,045 68,202 68,834 66,982 64,878
Unregulated operation and maintenance 2,842 1,331 2,541 --- --- ---
Depreciation 12,601 12,571 12,876 13,127 12,999 12,781
Taxes - local, state and other 28,358 27,788 28,108 30,685 31,858 31,514
---------- ---------- ---------- ---------- ---------- ----------
Total gas expense 259,304 254,718 267,224 309,225 314,136 276,935
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax Benefit 25,172 26,837 7,433 27,084 32,143 16,928
Federal Income Tax Benefit 8,032 8,356 (92) 3,442 7,600 6,715
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Gas Operations (000's) $ 17,140 $ 18,481 $ 7,525 $ 23,642 $ 24,543 $ 10,213
---------- ---------- ---------- ---------- ---------- ----------
Gas Sales - Therms (000's)
Residential 5,887 5,887 3,599 5,773 6,455 7,167
Residential spaceheating 264,047 264,047 239,740 285,395 299,085 280,763
Commercial 43,179 43,179 53,552 65,675 70,543 68,380
Industrial 4,541 4,541 6,079 7,828 9,334 9,560
Municipal 5,749 5,749 6,388 7,331 8,086 8,219
---------- ---------- ---------- ---------- ---------- ----------
Total retail sales 323,403 323,403 309,358 372,002 393,503 374,089
Transportation of customer-owned gas 199,997 199,997 163,575 166,060 167,779 146,149
Other unregulated sales 12,450 7,101 1,163 ---- ---- ----
---------- ---------- ---------- ---------- ---------- ----------
Total gas sold and transported 535,850 530,501 474,096 538,062 561,282 520,238
---------- ---------- ---------- ---------- ---------- ----------
Gas Customers at December 31
Residential 16,341 16,341 16,944 16,265 16,718 17,443
Residential spaceheating 240,308 240,308 249,684 243,264 240,685 238,267
Commercial 15,904 15,904 18,633 19,118 19,045 18,978
Industrial 586 586 778 829 857 879
Municipal 739 739 965 1,117 961 981
Transportation 11,190 11,190 1,900 836 744 655
Unregulated gas customers 8,717 ---- 821 ---- ---- ----
---------- ---------- ---------- ---------- ---------- ----------
Total gas customers 293,785 285,068 289,725 281,429 279,010 277,203
---------- ---------- ---------- ---------- ---------- ----------
RGE, Gas - Therms (000's)
Purchased for resale 200,036 200,036 203,677 274,430 279,353 237,728
Gas from storage 126,158 126,158 111,164 104,317 122,843 152,852
Other 2,151 2,151 1,496 1,410 1,082 1,800
---------- ---------- ---------- ---------- ---------- ----------
Total gas available - RG&E 328,345 328,345 316,337 380,157 403,278 392,380
---------- ---------- ---------- ---------- ---------- ----------
Total Daily Capacity - RG&E
Therms at December 31** 4,493,000 4,493,000 4,380,000 4,380,000 4,480,000 5,230,000
---------- ---------- ---------- ---------- ---------- ----------
Max. daily throughput, Therms - RG&E 4,008,200 4,008,200 3,583,500 4,114,290 4,022,600 3,980,000
Degree Days (Calendar Month)
For the period 6,289 6,289 5,666 6,916 6,998 6,535
Percent colder (warmer) than normal (6.6) (6.6) (15.9) 2.8 3.9 (3.0)
</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>
14
Item 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of RG&E's electric generating plants in operation as of
December 31, 1999 and the net generation of each plant for the year ended
December 31, 1999, and the year each plant was placed in service are as set
forth below:
<TABLE>
<CAPTION>
Electric Generating Plants
Net Net
Year Unit (Nameplate) Generation
Type Placed in Capability thousands
of Fuel Service (Mw) (KWH)
- ---------------------------- ---------- ---------- ---------- ------------
<S> <C> <C> <C> <C>
Allegany Station
(Gas Turbine) Gas 1998 63 43,662
Beebee Station(1)
(Steam) Coal 1959 - 144,662
Beebee Station
(Gas Turbine) Oil 1969 14 705
Russell Station
(Steam) Coal 1949-1957 257 1,414,365
Ginna Station
(Steam) Nuclear 1970 480 3,527,998
Oswego Unit 6(2)
(Steam) Oil 1980 - 89,916
Nine Mile Point
Unit No. 2(3)
(Steam) Nuclear 1988 158 1,206,705
Station No. 9
(Gas Turbine) Gas 1969 14 629
Station 5
(Hydro) Water 1917 39 107,130
Other Stations
(Hydro) Water 1906-1960 8 26,187
----- ---------
6,561,959
Pumped Storage(net)(4) (116,557)
---------
1,033 6,445,402
===== =========
</TABLE>
(1) Shutdown on May 1, 1999 and Unit retired.
(2) 24% share of jointly-owned facility was sold in October 1999.
(3) Represents 14% share of jointly-owned facility.
(4) Owned and operated by NYPA.
<PAGE>
15
RG&E owns 148 distribution substations having an aggregate rated
transformer capacity of 2,213,054 Kva, of which 139, having an aggregate rated
capacity of 2,033,888 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. RG&E also has 69,528 line
transformers with a capacity of 2,790,953 Kva. RG&E also owns 23 transmission
substations having an aggregate rated transformer capacity of 3,335,617 Kva of
which 22, having an aggregate rated capacity of 3,260,950 Kva, were located on
land owned in fee and one, having a rated capacity of 74,667 Kva, was located on
land under easements. RG&E's transmission system consists of approximately 716
circuit miles of overhead lines and approximately 405 circuit miles of
underground lines. The distribution system consists of approximately 16,266
circuit miles of overhead lines, approximately 3,927 circuit miles of
underground lines and 357,371 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 RG&E 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 consist of 4,280 miles of gas mains and
297,217 installed meters. (See Item 1 - Business, "Gas Operations" and "Gas
Department Statistics".
UNREGULATED SUBSIDIARIES
Griffith, including its subsidiaries, owns or leases 50 properties for use in
its business operations. These properties consist of:
- (3) Pipeline Terminal facilities: these major bulk petroleum storage
facilities are primarily supplied by pipeline and have an aggregate
storage capacity of approximately 475,000 barrels.
- (11) Bulk Plant Facilities: these bulk petroleum facilities are primarily
supplied by truck and have an aggregate storage capacity of 105,000
barrels.
- (14) Service Stations: these retail sites are sublet to a dealer who
provides various services at retail to the general public.
- (22) Other properties: there are a mixture of other properties including
office buildings, warehouses and garage facilities used in the general
operation of the business.
OTHER PROPERTIES
RG&E owns a ten-story office building centrally located in Rochester and
other structures and property. RG&E also leases approximately 453,000 square
feet of facilities for administrative offices and operating activities in the
Rochester area.
RG&E 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
<PAGE>
16
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 RG&E's outstanding bonds
is a first lien on substantially all the property owned by RG&E (except cash and
accounts receivable). Mortgages securing RG&E's revolving credit agreement and
a long term note are also liens on substantially all the property owned by RG&E
(except cash and accounts receivable) subject and subordinate to the lien of the
First Mortgage. RG&E has credit agreements with a domestic bank under which
short-term borrowings are secured by RG&E's accounts receivable.
Item 3. LEGAL PROCEEDINGS
RG&E-OWNED WASTE SITE ACTIVITIES. As part of its commitment to
environmental excellence, RG&E is conducting proactive Site Investigation and/or
Remediation (SIR) efforts at seven Company-owned sites where past waste handling
and disposal may have occurred. Remediation activities at five of these sites
are in various stages of planning or completion and the Company is conducting a
program to restore the other two sites. RG&E has recorded a total liability of
approximately $21.9 million which it anticipates spending on SIR efforts at the
seven Company-owned sites. Through December 31, 1999 the Company has incurred
aggregate costs of $4.3 million for these sites.
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 seven RG&E-
owned sites three are listed in this inventory. These are East Station, Front
Street and Brooks Avenue, all located in Rochester, NY. In addition to these
three sites, the inventory includes Ambrose Yard and Lindberg Heat Treating.
These two sites are owned by RG&E (and are in addition to the seven mentioned
above) however, RG&E does not believe that additional SIR work for which it is
responsible is required at either site. At this time, RG&E is unable to predict
what action will be necessitated as a result of the listing.
In June, 1999, RG&E was named as a codefendant in a legal action brought by
a party who purchased a portion of its Ambrose Yard property. The party has
claimed that the RG&E's historic activities on the property resulted in the
presence of residual contaminants that have adversely impacted the party's use
of the property. RG&E is just beginning to investigate the claim and does not
know whether the claim has any merit. There is insufficient information
available at this time to predict the economic impact of the claim on RG&E.
Manufactured Gas Sites. RG&E and its predecessors formerly owned and
operated five manufactured gas facilities for which SIR costs are estimated to
be approximately $20 million. Three sites, located in the Rochester area are
known as West Station, East Station and Front Street. Cleanup activities on a
portion of the West Station site were concluded in July 1996 under a voluntary
agreement with the NYSDEC. RG&E 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 site 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. RG&E has informed the
NYSDEC of the results of the samples taken. A supplemental remedial
<PAGE>
17
investigation and feasibility study was undertaken and a draft report is in
preparation at this time.
At the third site (Front Street), RG&E signed a consent order to perform
limited remedial activities. That work was completed in late 1998. Additional
investigative work and remedial action is expected to occur under separate
agreement now under negotiation.
Another property owned by RG&E 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 NYSDEC
is awaiting the Company's proposal for supplemental remedial investigation.
A preliminary phase 1 investigation was completed in 1998 on a 3/4 acre site
located in Brockport, New York. Evidence of residuals from gas manufacturing
operations suggest further investigation is necessary and may ultimately warrant
remedial action. No estimates can be made based on available information at
this time.
Other Sites. On another portion of RG&E's property in Rochester, NY
(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 waste materials (the materials) found there. In a November 1997 letter,
the County claimed that RG&E was the original generator of the materials and
asserted that the Company was liable to the County for 50% of all County costs
incurred to date to excavate, treat and dispose of the materials placed in the
ponds and to implement whatever further cleanup activities may be required by
the NYSDEC. RG&E and the County have reached a settlement agreement. Pursuant
to the settlement, RG&E will bear 20% of the remediation costs and has committed
to be responsible for the construction management function. RG&E's overall costs
are estimated to be approximately $1.3 million, excluding a 20% share of ongoing
long-term operation and maintenance work which is judged to be insignificant at
this time. There is a mutual waiver and release as to all past claims
regarding this property.
Monitoring wells installed at another Company facility (Brooks Avenue)
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 of additional costs are not expected to exceed
$400,000.
SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as a
potentially responsible party at eight sites not owned by it and has recorded
estimated liabilities of approximately $.5 million in connection with SIR
efforts at these sites. RG&E has signed orders on consent for five of these
sites.
In one site, known as the Quanta Resources Site, RG&E signed a consent
order with the Environmental Protection Agency (EPA) and paid its $27,500 share
of remedial cost. RG&E was again contacted by EPA in late August, 1996. The
EPA informed RG&E 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. RG&E,
along with most of those PRPs, has agreed (through an Administrative Order on
Consent) to conduct the required study. On May 12, 1997, RG&E 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, RG&E'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 site any remedial
measures which federal or State authorities may require, but RG&E does not
expect its additional costs to exceed $150,000.
<PAGE>
18
On May 21, 1993, RG&E was notified by NYSDEC that it was considered a PRP
for the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY.
RG&E 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 RG&E's share of additional site remediation costs
are not expected to exceed $500,000. RG&E is participating with the group to
allocate costs among the PRPs. Subsequent work has indicated that the final
cost is likely to be lower.
RG&E 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. RG&E 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 $211,000.
RG&E has been named as a PRP at three other sites and has been associated
with two other sites for which RG&E's share of total additional projected costs
is not expected to exceed $30,000. Actual expenditures for these sites are
dependent upon the total cost of investigation and remediation and the ultimate
determination of RG&E's share of responsibility for such costs as well as the
financial viability of other identified responsible parties.
RG&E is negotiating with its past insurance carriers seeking to obtain
coverage for environmental remediation costs at some locations.
GRIFFITH OWNED SITES. In connection with its Big Flats, New York terminal,
Griffith has been complying with the Unilateral Administrative Order issued by
the EPA. Pursuant to a cost sharing agreement with Sun Pipe Line Company,
Griffith continues to undertake one-half of the costs necessary to comply with
the order. To date Griffith has spent $1.8 million on this compliance.
Griffith continues to disclaim that it is either the owner or operator of a
failed spur where petroleum was discharged, and compliance is proceeding on this
basis accordingly.
Since February 1996, Griffith has been involved in a legal proceeding in
New York State Supreme Court for Steuben County, related to the environmental
matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company,
Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation
for property damage associated with petroleum discharge at Big Flats. The
parties have engaged in depositions and disclosure activities. Such disclosure
has not revealed any facts that have altered Griffith's position that the other
parties reimburse Griffith for costs, expenses and damages associated with site
remediation at Big Flats.
In May 1998, the State of New York (State of New York v. Griffith Oil Co.,
Inc.) commenced an action against Griffith in New York State Supreme Court for
Albany County, for statutory penalties in connection with the discharge of
petroleum at Big Flats, New York. The complaint alleges Griffith failed to
report the discharge within two hours of discovery, and further alleges a
violation of Griffith's Major Oil Storage Facility License for failure to report
such discharge. Griffith has answered the complaint and denied the allegations.
Griffith's position is that it complied with practice established with DEC, and
promptly reported the discharge upon confirmation of the presence of subsurface
petroleum. Griffith has offered to settle this matter for $15,000 subject to a
mutually acceptable agreement of settlement. Griffith continues to deny
responsibility for this matter and unless otherwise settled will defend this
matter in the usual course.
In April 1998, the State of New York commenced an action against Griffith
and other parties (State of New York v. Griffith Oil Co., Inc., Sugar Creek
Stores, Inc. and Mahl Bros. Oil Co., Inc. [Springville Bulk Plant]) in New York
State Supreme Court for Erie County, for reimbursement of the sum of $180,962 to
<PAGE>
19
the New York Environmental Protection and Spill Compensation Fund in connection
with subsurface petroleum contamination in the vicinity of Springville, New
York. Until December 1997, Griffith leased a petroleum bulk storage facility at
the location. Cross-claims also exist among the defendants related to causes of
action associated with the contamination and lease of the property. While the
presence of subsurface contamination is evident, an analysis of the
contamination is substantially associated with a parent product produced no
later than 1985. This date precedes the interest of Griffith. Griffith will
continue to vigorously defend this matter.
In connection with the acquisition of Griffith by Energetix, a stock
purchase agreement obligates the Seller to pay for environmental claims or
remedial action on Griffith property once the amount of environmental losses
incurred by Energetix exceeds $3.5 million less any reserve reflected on the
balance sheet at the time of acquisition. At December 31, 1999 approximately
$700 thousand has been spent and $1.8 million is estimated to be spent.
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, 1999.
Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information about the officers of RGS
and RG&E as of January 1, 2000. Unless otherwise indicated all positions and
offices listed are at RG&E.
Age Positions, Offices and Business Experience
Name 1/1/00 1995 to date
- ---- ------ --------------------------------------------------
Thomas S. Richards 56 Chairman, President and Chief Executive Officer of
RGS - August 1999 to date.
Chairman, 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 - 1995 to August 1995.
<PAGE>
20
Age Positions, Offices and Business Experience
Name 1/1/00 1995 to date
- ---- ------ ----------------------------------------------
Michael J. Bovalino 44 Senior Vice President of RGS - August 1999 to
date.
President and Chief Executive Officer, Energetix,
Inc (a wholly owned subsidiary of RGS) 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.
J. Burt Stokes 56 Senior Vice President and Chief Financial Officer
of RGS - August 1999 to date.
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 62 Senior Vice President and General Counsel of
RGS - August 1999 to Date.
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.
Paul C. Wilkens 52 Senior Vice President of RGS - August 1999 to
Date.
Senior Vice President, Generation - March 1998 to
Date.
Director, Gas Services - January 1996 -
March 1998.
Principal Consultant - May 1995 - January 1996.
Department Manager - Nuclear Engineering
Services - 1995 - May 1995.
<PAGE>
21
Age Positions, Offices and Business Experience
Name 1/1/00 1995 to date
- ---- ------- ----------------------------------------------
William J. Reddy 52 Controller of RGS - August 1999 to Date.
Vice President and Controller - August 1999 to
Date.
Controller - April 1997 to August 1999.
Group Manager, Public Affairs Services -
January 1995 to April 1997.
Division Manager, Public Affairs Services -
January 1995.
The term of office of each officer extends to the meeting of the Board of
Directors following the next election of Directors of their company and until
his or her successor is elected and qualifies.
<PAGE>
22
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
<TABLE>
<CAPTION>
COMMON STOCK AND DIVIDENDS
RGS
Earnings/Dividends 1999 1998 1997 Shares/Shareholders 1999 1998 1997
- --------------------------- ----- ----- ----- ------------------------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Earnings per share Number of shares (000's)
- basic $2.44 $2.32 $2.30 Weighted average - basic 36,665 38,462 38,853
- diluted $2.44 $2.31 $2.30 - diluted 36,757 38,600 38,909
Dividends paid Actual number at
per share $1.80 $1.80 $1.80 December 31 35,943 37,379 38,862
Number of shareholders
at December 31 27,258 28,995 31,337
</TABLE>
RGS ENERGY GROUP, INC.
On August 2, 1999, Rochester Gas and Electric Corporation (RG&E) was
reorganized into a holding company structure pursuant to an Agreement and Plan
of Share Exchange (Exchange Agreement) between RG&E and RGS Energy Group, Inc.
(RGS). As part of the reorganization, all of the outstanding shares of RG&E
common stock were exchanged on a share-for-share basis for shares of RGS and
RG&E became a subsidiary of RGS. Certificates for shares of RG&E common stock
are automatically valid as certificates for RGS and do not have to be replaced.
The transfer does not affect the value of the stock or RGS's dividend policy.
RGS trades on the New York Stock Exchange under the symbol "RGS". RG&E
shareholders approved the Exchange Agreement on April 29, 1999.
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1999, 1998 and 1997 were 100 percent taxable for
federal income tax purposes.
DIVIDEND POLICY
RG&E has paid cash dividends quarterly on its Common Stock without
interruption since it became publicly held in 1949. Since its formation in
August 1999, RGS has continued this historic trend of dividend payments.
The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the
largest of the subsidiaries, it is expected that for the foreseeable future the
funds required by RGS to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS by RG&E. In the future, dividends
from subsidiaries other than RG&E may also be a source of funds for dividend
payments by RGS. RG&E's ability to make dividend payments to RGS will depend
upon the availability of retained earnings and the needs of its utility
business. RG&E's Certificate of Incorporation provides for the payment of
dividends on Common Stock out of the surplus net profits (retained earnings) of
the Company. In addition, pursuant to the PSC order approving the formation of
RGS, RG&E may pay dividends to RGS of no more than 100% of RG&E's net income
calculated on a two-year rolling basis. The calculation of net income for this
purpose excludes non-cash charges to income resulting from accounting changes or
certain PSC required charges as well as charges that may arise from significant
unanticipated events. This condition does not apply to dividends that would be
used to fund the
<PAGE>
23
remaining portion of the $100 million authorized for RG&E's unregulated
operations (about $42 million at December 31, 1999). The level of future cash
dividend payments on Common Stock will be dependent upon RGS's future earnings,
its financial requirements, and other factors.
Quarterly dividends on Common Stock are generally paid on the twenty-fifth
day of January, April, July and October. In January 2000, RGS paid a cash
dividend of $.45 per share on its Common Stock. The January 2000 dividend
payment is equivalent to $1.80 on an annual basis.
Common Stock - Price Range 1999 1998 1997
- ---------------------------- ---- ---- ----
High
1st quarter 31 9/16 33 1/4 20 3/8
2nd quarter 28 7/16 32 3/4 21 7/16
3rd quarter 27 5/16 32 7/16 24 15/16
4th quarter 25 1/2 33 1/4 34 1/2
Low
1st quarter 25 7/16 29 1/2 18 7/8
2nd quarter 25 1/4 29 5/16 18
3rd quarter 24 1/16 28 3/8 20 5/8
4th quarter 20 28 9/16 23 3/4
At December 31 20 9/16 31 1/4 34
<PAGE>
24
ITEM 6 - SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
<TABLE>
<CAPTION>
RGS
Consolidated RG&E
(Thousands of Dollars) Year Ended December 31 1999 1999 1998* 1997* 1996* 1995*
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues
Electric $ 702,751 $ 700,194 $ 687,622 $ 700,329 $ 707,768 $ 722,465
Gas 284,476 281,555 274,657 336,309 346,279 293,863
Other 220,310 108,699 71,212 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues 1,207,537 1,090,448 1,033,491 1,036,638 1,054,047 1,016,328
Operating Expenses
Fuel Expenses
Fuel for electric generation 49,297 49,297 53,954 47,665 40,938 44,190
Purchased electricity 54,337 53,046 27,024 28,347 46,484 54,167
Gas purchased for resale 151,458 148,983 155,497 196,579 202,297 167,762
Unregulated fuel expenses 189,465 91,505 59,490 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fuel Expenses 444,557 342,831 295,965 272,591 289,719 266,119
---------- ---------- ---------- ---------- ---------- ----------
Operating Revenues Less Fuel Expenses 762,980 747,617 737,526 764,047 764,328 750,209
Other Operating Expenses
Operations and maintenance excluding fuel expenses 297,890 297,890 301,625 315,109 313,157 308,433
Unregulated operating and maintenance expenses
excluding fuel 26,464 14,236 13,524 - - -
Depreciation and amortization 118,695 117,289 116,102 116,522 105,614 91,593
Taxes - local, state and other 114,639 112,613 117,973 121,796 126,868 133,895
Federal income tax - current 72,873 73,074 69,392 69,812 65,757 65,368
- deferred (8,620) (8,620) (9,156) (4,533) 3,744 847
---------- ---------- ---------- ---------- ---------- ----------
Total Other Operating Expenses 621,941 606,482 609,460 618,706 615,140 600,136
---------- ---------- ---------- ---------- ---------- ----------
Operating Income 141,039 141,135 128,066 145,341 149,188 150,073
Other (Income) and Deductions
Allowance for other funds used during construction (657) (657) (408) (351) (684) (585)
Federal income tax (1,134) (1,144) 1,665 (3,704) (3,450) (16,948)
Regulatory disallowances - - - - - 26,866
Other, net (8,178) (8,111) (13,370) 3,308 (712) 9,631
---------- ---------- ---------- ---------- ---------- ----------
Total Other (Income) and Deductions (9,969) (9,912) (12,113) (747) (4,846) 18,964
Interest Charges
Long term debt 53,681 53,067 43,306 44,615 48,618 53,026
Other, net 4,798 4,543 3,388 6,676 9,328 9,056
Allowance for borrowed funds used during construction (1,051) (1,051) (653) (563) (1,423) (2,901)
---------- ---------- ---------- ---------- ---------- ----------
Total Interest Charges 57,428 56,559 46,041 50,728 56,523 59,181
Preferred Stock Dividend Requirements 4,083 4,083 4,842 5,805 7,465 7,465
Net Income Applicable to Common Stock $ 89,497 $ 90,405 $ 89,296 $ 89,555 $ 90,046 $ 64,463
========== ========== ========== ========== ========== ==========
Earnings per Common Share - Basic $ 2.44 $ 2.32 $ 2.30 $ 2.32 $ 1.69
Earnings per Common Share - Diluted $ 2.44 $ 2.31 $ 2.30 $ 2.32 $ 1.69
Cash Dividends Declared per Common Share $ 1.80 $ 1.80 $ 1.80 $ 1.80 $ 1.80
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
25
CONDENSED CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
RGS
Consolidated RG&E
(Thousands of Dollars) At December 31 1999 1999 1998 1997* 1996* 1995*
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Assets
Utility Plant $3,253,731 $3,231,082 $3,326,995 $3,234,077 $3,159,759 $3,068,103
Less: Accumulated depreciation and amortization 1,876,198 1,873,577 1,863,475 1,714,368 1,569,078 1,518,878
---------- ---------- ---------- ---------- ---------- ----------
1,377,533 1,357,505 1,463,520 1,519,709 1,590,681 1,549,225
Construction work in progress 95,862 95,862 98,554 74,018 69,711 121,725
---------- ---------- ---------- ---------- ---------- ----------
Net Utility Plant 1,473,395 1,453,367 1,562,074 1,593,727 1,660,392 1,670,950
Current Assets 219,837 202,506 202,963 242,371 250,461 292,596
Investment in Empire - - - - - 38,879
Intangible Assets 21,232 - 21,062 - - -
Deferred Debits and Other Assets 748,410 746,996 666,836 432,191 450,623 453,726
---------- ---------- ---------- ---------- ---------- ----------
Total Assets $2,462,874 $2,402,869 $2,452,935 $2,268,289 $2,361,476 $2,456,151
- --------------------------------------------- ========== ========== ========== ========== ========== ==========
Capitalization and Liabilities
Capitalization
Long term debt $ 815,465 $ 796,000 $ 758,226 $ 587,334 $ 646,954 $ 716,232
Preferred stock redeemable at option of Company 47,000 47,000 47,000 47,000 67,000 67,000
Preferred stock subject to mandatory redemption 25,000 25,000 25,000 35,000 45,000 55,000
Common shareholders' equity:
Common stock 700,268 700,268 699,730 699,031 696,019 687,518
Retained earnings 153,186 137,854 129,484 109,313 90,540 70,330
Less: Treasury stock at cost 83,252 83,252 46,433 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total common shareholders' equity 770,202 754,870 782,781 808,344 786,559 757,848
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization $1,657,667 $1,622,870 $1,613,007 $1,477,678 $1,545,513 $1,596,080
========== ========== ========== ========== ========== ==========
Long Term Liabilities 126,352 125,011 123,920 110,352 106,578 101,561
Current Liabilities 169,356 149,855 183,369 175,691 145,391 171,664
Deferred Credits and Other Liabilities 509,499 505,133 532,639 504,568 563,994 586,846
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization and Liabilities $2,462,874 $2,402,869 $2,452,935 $2,268,289 $2,361,476 $2,456,151
- --------------------------------------------- ========== ========== ========== ========== ========== ==========
</TABLE>
*Reclassified for comparative purposes.
<PAGE>
26
<TABLE>
<CAPTION>
FINANCIAL DATA
RGS RG&E
At December 31 1999 1999 1998 1997 1996 1995
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Capitalization Ratios (a) (percent)
Long-term debt 51.9 51.8 49.8 43.0 44.7 47.4
Preferred Stock 4.1 4.2 4.2 5.2 6.9 7.3
Common shareholders' equity 44.0 44.0 46.0 51.8 48.4 45.3
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
Book Value per Common Share - Year End $21.43 $21.00 $20.94 $20.80 $20.24 $19.71
Rate of Return on Average Common Equity (b)
(percent) 11.53 11.76 11.22 11.00 11.41 8.37
Embedded Cost of Senior Capital (percent)
Long-term debt 7.20 7.21 7.20 7.32 7.33 7.38
Preferred stock 5.24 5.24 5.56 5.80 6.26 6.26
Effective Federal Income Tax Rate (percent) 40.3 40.1 39.7 39.2 40.4 40.7
Depreciation Rate (percent) - Electric 3.14 3.14 3.09 3.12 2.99 2.76
- Gas 2.54 2.54 2.64 2.60 2.60 2.59
Interest Coverages
Before federal income taxes (incld. AFUDC) 3.68 3.74 4.41 4.06 3.82 2.95
(excld. AFUDC) 3.65 3.71 4.38 4.04 3.79 2.90
After federal income taxes (incld. AFUDC) 2.60 2.64 3.06 2.86 2.68 2.16
(excld. AFUDC) 2.57 2.61 3.03 2.84 2.65 2.10
Interest Coverages Excluding Non-Recurring
Items (c)
Before federal income taxes (incld. AFUDC) 3.68 3.74 4.41 4.06 3.82 3.66
(excld. AFUDC) 3.65 3.71 4.38 4.04 3.79 3.61
After federal income taxes (incld. AFUDC) 2.60 2.64 3.06 2.86 2.68 2.62
(excld. AFUDC) 2.57 2.61 3.03 2.84 2.65 2.57
</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%.
(c) Coverages in 1995 exclude the economic effect of the 1995 Gas Settlement
($44.2 million, pretax).
<PAGE>
27
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of RGS Energy Group,
Inc. and its subsidiaries over the past three years. The Consolidated Financial
Statements and the Notes thereto contain additional data. For the twelve months
ended December 31, 1999, 58 percent of the Company's operating revenues were
derived from electric service, 23 percent from natural gas service, and 19
percent from unregulated businesses.
SELECTED ABBREVIATIONS and GLOSSARY
Cooling degree days The extent to which the daily outdoor average
temperature exceeds a base of 65 degrees Fahrenheit.
One degree day is counted for each degree day falling
above the assumed base for each calendar day.
Company or RGS RGS Energy Group Inc., a holding company formed August
2, 1999,which is the parent company of Rochester Gas
and Electric Corporation, RGS Development Corporation,
and Energetix, Inc.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by the Company
Heating degree days The extent to which the daily outdoor average
temperature falls below a base of 65 degrees
Fahrenheit. One degree day is counted for each degree
day falling below the assumed base for each calendar
day.
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which the
Company currently owns a 14% share
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned
subsidiary of the Company
Settlement Competitive Opportunities Case Settlement among the
Company, PSC and other parties which provides the
framework for the development of competition in the
electric energy marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
<PAGE>
28
FORWARD LOOKING STATEMENTS
- --------------------------
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant effect on whether the forward
looking statements ultimately prove to be accurate include:
1. uncertainties related to the regulatory treatment of nuclear generation
facilities including the proposed sale of the Nine Mile Point nuclear
generating facilities by Niagara Mohawk Power Corporation (Niagara Mohawk)
and New York State Electric and Gas Corporation and the exercise of RG&E's
right of first refusal;
2. any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding certain gas
restructurings) that affect the cost or recovery of investments necessary to
provide utility service in the electric and natural gas industries. Such
initiatives could include, for example, changes in the regulation of rate
structures or changes in the speed or degree to which competition occurs in
the electric and natural gas industries;
3. any changes in the ability of RG&E to recover environmental compliance costs
through increased rates;
4. the determination in the nuclear generation proceeding initiated by the PSC,
including any changes in the regulatory status of nuclear generating
facilities and their related costs, including recovery of costs related to
spent fuel and decommissioning;
5. any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
6. the development of any new technologies which allow customers to
generate their own energy or produce lower cost energy;
7. any unusual or extreme weather or other natural phenomena;
8. the ability of RGS to manage profitably new unregulated operations;
9. certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;
10. the timing and extent of changes in commodity prices and interest rates; and
11. any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS and RG&E.
<PAGE>
29
Shown below is a listing of the principal items discussed.
RGS ENERGY GROUP, INC. Page 29
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Page 30
PSC Competitive Opportunities Case Settlement
Energy Choice
Proposed Purchase of Nuclear Plants
PSC Proceeding on Nuclear Generation
Fossil Units Status
FERC Open Access Transmission Orders and
Company Filings
Prospective Financial Position
Rates and Regulatory Matters Page 38
PSC Gas Restructuring Policy Statement
Gas Proposal and Interim Settlement
Flexible Pricing Tariff
LIQUIDITY AND CAPITAL RESOURCES Page 40
Capital and Other Requirements
Financing
Redemption of Securities
Stock Repurchase Plan
Environmental Issues
Year 2000 Readiness Information
EARNINGS SUMMARY Page 43
RESULTS OF OPERATIONS Page 44
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDEND POLICY Page 49
RGS ENERGY GROUP, INC.
On August 2, 1999, RG&E was reorganized into a holding company structure
pursuant to an Agreement and Plan of Share Exchange (Exchange Agreement) between
RG&E and RGS. As part of the reorganization, all of the outstanding shares of
RG&E common stock were exchanged on a share-for-share basis for shares of RGS
and RG&E became a subsidiary of RGS. Certificates for shares of RG&E common
stock are automatically valid as certificates for RGS and do not have to be
replaced. The transfer does not affect the value of the stock or RGS's dividend
policy. RGS trades on the New York Stock Exchange under the symbol "RGS". RG&E
shareholders approved the Exchange Agreement on April 29, 1999.
The holding company structure was formed so that RGS could respond quickly
to changes in the evolving competitive energy utility industry. The new
structure permits the use of financing techniques that are better suited to the
particular requirements, characteristics and risks of non-utility operations
without affecting the capital structure or creditworthiness of RG&E. This
<PAGE>
30
increases RGS's financial flexibility by allowing it to establish different
debt-to-equity ratios for each of its individual lines of business.
RGS is not an operating entity. RGS's operations are being conducted
through its subsidiaries which include RG&E, and two unregulated subsidiaries -
RGS Development Corporation and Energetix, Inc.
RG&E will continue to offer regulated electric and natural gas utility
service in its franchise territory. Energetix, Inc. provides energy products and
services throughout upstate New York. RGS Development Corporation offers energy
systems development and management services.
Unregulated Subsidiaries. It is part of RGS's financial strategy to seek
growth by entering into unregulated businesses. The Settlement allowed RG&E to
provide the funding for RGS to invest up to $100 million in unregulated
businesses. The first step in this direction was the formation and operation of
Energetix, Inc. (Energetix) effective January 1, 1998. Energetix is an
unregulated subsidiary that brings energy products and services to the
marketplace both within and outside of RG&E's regulated franchise territory.
Energetix markets electricity, natural gas, oil, gasoline, and propane fuel
energy services in an area extending in approximately a 150-mile radius around
Rochester.
In August 1998, Energetix announced the acquisition of Griffith Oil
Company, Inc. (Griffith), the second largest oil and propane distribution
company in New York State. This $31.5 million acquisition was accounted for
using purchase accounting and the results of Griffith's operations are reflected
in the consolidated financial statements of RGS since its acquisition on August
2, 1998.
Griffith gives Energetix access to 70,000 new customers, 65,000 of which
are outside of RG&E's regulated franchise territory. Griffith has approximately
350 employees and operates 18 customer service centers.
In September 1999, Griffith acquired Bobbett Gas Service, a provider of
propane gas and service in the Central New York area. The acquisition adds
2,600 customers to the current Griffith customer base. The acquisition was
accounted for using purchase accounting and their results of operations are
reflected in the consolidated financial statements of RGS since acquisition.
In December 1999, Griffith acquired Clark Oil, a provider of fuel oil in
the Central New York area. This acquisition adds 600 customers to the Griffith
customer base. The acquisition was accounted for using purchase accounting and
their results of operations are reflected in the consolidated financial
statements of RGS since acquisition.
Additional information on Energetix operations (including Griffith) is
presented under the headings Operating Revenues and Sales, Operating Expenses,
and is contained in Note 4 of the Notes to Financial Statements.
During the second quarter of 1998, the Company formed RGS Development to
pursue unregulated business opportunities in the energy marketplace. Through
December 31, 1999, RGS Development operations have not been material to RGS's
results of operations or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997, RG&E,
the staff of the PSC and several other parties negotiated an agreement which was
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approved by the PSC in November 1997 (the "Settlement"). The Settlement sets
the framework for the introduction and development of open competition in the
electric energy marketplace and lasts through June 30, 2002. Over this time,
the way electricity is provided to customers will fundamentally change. In
phases, RG&E will allow customers to purchase electricity, and later capacity
commitments, from sources other than RG&E through its retail access program,
Energy Choice. These energy service companies will compete to package and sell
energy and related services to customers. The competing energy service companies
will purchase distribution services from RG&E who will remain the sole provider
of distribution services, and will be responsible for maintaining the
distribution system and for responding to emergencies.
The Settlement sets RG&E's electric rates for each year during its five-
year term. Over the five-year term of the Settlement, the cumulative rate
reductions for the bundled service will be as follows: Rate Year 1 (July 1, 1997
to June 30, 1998) $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.
In the event that RG&E earns a return on common equity in its regulated
electric business 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,
Accounting for the Effects of Certain Types of Regulation). 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 RG&E or any other party to the Settlement would have the
right to petition the PSC for review of the Settlement and appropriate remedial
action.
The Settlement requires unregulated energy retailing operations be
structurally separate from the regulated utility functions. Although the
Settlement provides incentives for the sale of generating assets, it does not
require RG&E to divest generating or other assets or write-off stranded costs.
Additionally, RG&E will be given a reasonable opportunity to recover
substantially all of its prudently incurred costs, including those pertaining to
generation and purchased power.
RG&E believes that the Settlement has not adversely affected its
eligibility to continue to apply certain accounting rules applicable to
regulated industries. In particular, RG&E believes it continues to be eligible
for the treatment provided by SFAS-71 which allows RG&E to include assets on its
balance sheet based on its regulated ability to recoup the cost of those assets.
However, this may not be the case with respect to certain operational costs
associated with non-nuclear generation (see Note 10 of the Notes to Financial
Statements under the heading Other Matters, EITF Issue 97-4, Deregulation of the
Pricing of Electricity).
RG&E's retail access program, Energy Choice, was approved by the PSC as
part of the Settlement and went into effect on July 1, 1998. Details of the
Energy Choice Program are discussed below.
One party to the Settlement negotiations has commenced an action for
declaratory and injunctive relief as to certain provisions of the Settlement and
the PSC's approval of it. RG&E is unable, at this time, to predict the outcome
of this action.
ENERGY CHOICE. On July 1, 1998, RG&E officially began implementation of its
full-scale electric retail access Energy Choice program. As of July 1, 1999,
RG&E entered its second year of this program. There are five basic components of
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the sale of energy: (1) the sale of electricity which is the amount of energy
actually used by the consumer, (2) the sale of capacity which is the ability,
through generating facilities or otherwise, to provide electricity when it is
needed, (3) the sale of transmission services, which is the physical
transportation of electricity to RG&E's distribution system, (4) the sale of
distribution services, which is the physical delivery of electricity to the
consumer, and (5) retail services such as billing and metering. Historically,
RG&E has sold all five components bundled together for a fixed rate approved by
the PSC. The implementation of the Energy Choice program included a four year
phase-in process to allow RG&E and other parties to manage the transition to
electric competition in an orderly fashion. During the first year of the
program, participation in Energy Choice was limited to no more than 10 percent
of RG&E's total annual retail electric kilowatt-hour sales (670,000 annualized
megawatt-hours). Essentially, until this 10 percent limit was achieved, RG&E's
electric retail customers could seek out or be approached by alternative energy
service companies for electricity to be resold and then delivered over RG&E's
distribution system. By February 1, 1999, only six months into the Energy
Choice program, this 10 percent limit was achieved by qualified competitive
energy service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent. By December 31, 1999, approximately 14.8 percent of
total RG&E sales had shifted to competitive energy service companies. On July
1, 2001, all retail customers will be eligible to purchase energy from
alternative energy service companies. The phase-in of the Energy Choice program
over the next few years eventually will give retail electric customers the
opportunity to purchase energy, capacity and retailing services from competitive
energy service companies. Existing RG&E customers may also continue to purchase
fully bundled electric service from RG&E.
Energy Choice adopted the single-retailer model for the relationship
between RG&E as the distribution provider, qualified energy service companies,
and retail (end-use) customers. In this model, retail customers have the
opportunity for choice in their energy service company and receive only one
electric bill from the company that serves them. Except for providing emergency
services, satisfying requests for distribution services, and scheduling outages,
which remain RG&E's responsibility, the retail customer's primary point of
contact for billing questions, technical advice and other energy-related needs,
is with their chosen energy service company.
Under the single-retailer model, energy service companies are responsible
for buying or otherwise providing the electricity their retail customers will
use, paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).
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 such service.
During the initial "Energy-Only" stage of the Energy Choice program, energy
service companies were able to choose their own sources of energy supply, while
RG&E continued to provide to them, through its bundled distribution rates, the
generating capacity (installed reserve) needed to serve their retail customers.
In addition, during the "Energy-Only" stage, energy service companies had the
option of purchasing "full-requirements" (i.e. delivery services plus energy)
from RG&E.
The "Energy and Capacity" stage, the second stage of the phase-in, was
scheduled to begin this past Fall. In this stage, energy service companies may
purchase both energy and capacity in the open market. As a result of a delay in
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establishing an Independent System Operator entity in New York State, RG&E, with
the consent of the energy service companies participating in the Retail Access
Program, reserved capacity for the 1999-2000 winter capability period and will
provide energy and capacity for the energy service companies through that
period. Essentially, energy service companies will purchase "full-requirements"
(delivery services plus energy and capacity) from RG&E.
During the initial "Energy Only" stage of the retail access program, RG&E's
distribution rate was set by deducting 2.305 cents per kilowatt-hour from its
full service ("bundled") rates. The 2.305 cents per kilowatt-hour was comprised
of 1.905 cents per kilowatt-hour (an estimate of the wholesale market price of
electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing
services. During the "Energy and Capacity" stage, RG&E's distribution rates
will equal the bundled rate less RG&E's cost of the electric commodity and
RG&E's non-nuclear generating capacity. During this stage of the program,
RG&E's distribution rates will be set by deducting 3.0712 cents per kilowatt-
hour from its full service ("bundled") rates. The 3.0712 cents per kilowatt-
hour is comprised of 2.6712 cents per kilowatt-hour (an estimate of the
wholesale market price of electric energy and capacity) plus 0.4 cents per
kilowatt-hour for its avoided cost of retailing services.
As of December 31, 1999, eight energy service companies, including
Energetix, the Company's unregulated subsidiary, are qualified by RG&E to serve
retail customers under the Energy Choice program. In addition to Energetix,
these companies are Columbia Energy Power Marketing Corporation, DukeSolutions,
Inc., Northeast Energy Services, Inc.(NORESCO), North American Energy, NYSEG
Solutions, Inc., Select Energy Inc., and TXU Energy Services, Inc. In addition,
the County of Monroe has been qualified to act as its own energy service company
to service its own facilities. As of December 31, 1999, all energy service
companies had opted to purchase "full-requirements" from RG&E to serve their
retail customers.
With the commencement of the "Energy and Capacity" stage and the
implementation of the New York Independent System Operator on November 18, 1999
(see FERC Open Access Transmission Orders and Company Filings), the
responsibility for purchasing not only energy, but also capacity, shifted to the
energy service companies. However, these energy service companies, as "full-
requirements" customers of RG&E during the winter capability period, will be
purchasing energy and capacity from RG&E at 2.6712 cents per kilowatt-hour.
The cost impact on RG&E of providing "full requirements" energy and capacity for
this time period will be determined by prices in the New York State wholesale
market. The PSC has approved a request by RG&E to extend "full-requirements"
availability to November 1, 2000.
Once RG&E no longer provides "full requirements" to the energy service
companies, they will assume responsibility for obtaining their own supplies.
There will be a revenue decrease when RG&E no longer collects the $2.6712 cents
per kilowatt-hour for energy and capacity. This will be offset to some extent
by decreased costs resulting from no longer acquiring energy and capacity for
the energy service companies. The extent of this offset will be determined by
market prices.
On December 3, 1999, New York State Electric and Gas Corporation (NYSEG)
petitioned the PSC to accelerate the implementation of retail access in RG&E's
service territory. NYSEG filed the petition pursuant to the terms of its
electric restructuring agreement, whereby NYSEG may petition the PSC to deny
permission to a New York State utility-affiliated competitive energy service
company to participate in NYSEG's retail access program if the service area of
the energy service company's affiliated utility is not comparably open to retail
access. However, NYSEG does not seek to deny RG&E's affiliate, Energetix, the
ability to participate in NYSEG's retail access program, stating that such a
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motion would be inconsistent with the PSC's efforts to create competitive
opportunities in the electric industry. Instead, NYSEG requests the PSC to
order RG&E to accelerate its retail access implementation schedule, claiming
that RG&E's introduction of retail access is occurring at an extremely slow
rate. RG&E's retail access program and implementation schedule was approved by
the PSC in November 1997, as part of a comprehensive electric restructuring
agreement. RG&E is in the process of preparing a response to NYSEG's petition,
and cannot determine at this time what course of action the PSC may take.
On December 14, 1999, a group of marketers and energy service companies
submitted a petition to the PSC to initiate an inquiry into the effectiveness of
RG&E's retail access program. The petitioners are NYSEG Solutions, Inc.,
Advantage Energy, Leveraged Energy Purchasing Corporation, Empire Natural Gas
Corporation, and Salerni & Boyd, Inc. The petitioners make the following claims
concerning RG&E's retail access program: (1) RG&E's operating agreement creates
significant obstacles to development of retail competition in RG&E's territory
because of the obligations the energy service companies now have to serve the
retail customers. The petitioners have asked the PSC to exercise its authority
to investigate the effectiveness of the terms and conditions of RG&E's operating
agreement, and order RG&E to either reduce the customer service obligations or
offer a higher backout credit or other reasonable economic incentives to offset
the costs of these obligations, and (2) the shopping credit (i.e., backout rate)
offered by RG&E inhibits retail access and competition. The petitioners ask the
PSC to order RG&E to provide additional credits, to at least 3.7 cents per
kilowatt-hour, while maintaining the price of energy to the energy service
companies at 2.8 cents per kilowatt-hour in order to provide a reasonable
opportunity for the energy service companies to enter and compete in RG&E's
territory, and (3) the phase-in approach to retail access in RG&E's relatively
small service area discriminates against energy service companies and marketers
and inhibits competition. The petitioners request the PSC to order RG&E to open
its service territory to full retail access as soon as possible, but no later
than July 1, 2000. RG&E is in the process of preparing a response to this
petition, and cannot determine at this time what course of action the PSC may
take.
The PSC is conducting proceedings that are intended to bring more
administrative consistency among New York State utilities and potentially offer
additional services for energy service companies to provide. These proceedings
include uniform business practices, standardized billing and competitive
metering. RG&E continues to assess the scope and impact of such changes on its
operations.
PROPOSED PURCHASE OF NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and
NYSEG announced their intention to sell their interests in the Nine Mile Two
nuclear plant to AmerGen Energy Company, L.L.C.(AmerGen), a joint venture of
PECO Energy of Philadelphia and British Energy. Niagara Mohawk owns 41 percent
and NYSEG owns 18 percent of Nine Mile Two. The financial terms of the
transaction include purchase prices to be paid to Niagara Mohawk of $63.6
million and to NYSEG of $27.9 million.
RG&E's 14 percent interest in Nine Mile Two was not included in the current
proposal. As an original part owner, RG&E generally had three options: the first
option was to retain its ownership interest on the same basis that it does now;
the second option was to sell its 14 percent interest in Nine Mile Two to
AmerGen on substantially the same terms as Niagara Mohawk and NYSEG; and the
third option was to exercise its right-of-first-refusal and buy the Niagara
Mohawk and/or NYSEG interests on terms at least as favorable as those offered by
AmerGen. Niagara Mohawk took the position that an exercise of the right to buy
its interest in Nine Mile Two must necessarily include matching the terms of the
agreement between AmerGen and Niagara Mohawk ($72 million) to buy the Nine Mile
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Point One Nuclear Plant (Nine Mile One), which is 100 percent owned by Niagara
Mohawk.
On December 22, 1999, RG&E announced it had exercised its legal right-of-
first-refusal to acquire a controlling interest in Nine Mile Two and to acquire
the interests of Niagara Mohawk in Nine Mile One. As a result of the regulatory
process discussed below, the status of RG&E's acquisition pursuant to its right-
of-first-refusal is in question.
RG&E has contracted with Entergy Nuclear Nine Mile, L.L.C. (Entergy Nine
Mile) to operate and maintain the plants upon RG&E's acquisition under its
right-of-first-refusal. Under the terms of an operating agreement, Entergy Nine
Mile will be responsible for operating the plants, for certain operating costs
and risks during a transition period and most operating costs and risks
thereafter. RG&E will be responsible for substantial operating costs and risks
during the transition period and these costs and risks will be significantly
reduced after the transition period. RG&E will pay Entergy Nine Mile a fixed
price (periodically adjusted by certain appropriate price indices) per kilowatt-
hour of power actually generated and delivered to RG&E. The contract with
Entergy Nine Mile expires in September 2009.
RG&E intends to finance its acquisition through the issuance of long-term
debt. Depending on when transfer of ownership takes place, RG&E currently
expects to pay between $180 million and $210 million, including the cost of fuel
at the plants. The transfer of ownership of the plants to RG&E and transfer of
operation of the plants to Entergy Nine Mile will require State and federal
regulatory approvals, including the PSC, the Nuclear Regulatory Commission (NRC)
and the FERC.
In this transaction, RG&E will continue to own the rights to its original
approximately 160 megawatts of electric generating capacity from Nine Mile Two
and acquire the rights to approximately an additional 670 megawatts of capacity
from that plant. At the conclusion of its purchase, RG&E would own 73% of Nine
Mile Two. The Long Island Lighting Company, which is wholly-owned by the Long
Island Power Authority, and Central Hudson Gas & Electric Corporation are the
other non-operating owners of Nine Mile Two and will retain their interests in
the plant. RG&E would also acquire the entire capacity from Nine Mile One,
about 615 megawatts.
Niagara Mohawk and NYSEG will purchase the power produced by their previous
ownership shares in the Nine Mile Point plants from RG&E under long-term
contracts that run for a period of three to five years. These terms are the
same as those agreed to by AmerGen. After that period of time, available power
is expected to be sold into the wholesale energy market.
Under the terms of a decommissioning agreement, Entergy Nuclear, Inc. will
be responsible for decommissioning the plants at a fixed price after they are
both taken out of service. For Nine Mile One, Niagara Mohawk, as the former sole
owner, will contribute the entire present cost of decommissioning to a fund.
For Nine Mile Two, Niagara Mohawk and NYSEG will contribute payments
proportionate to their former ownership interests.
At December 31, 1999 the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $376 million.
On August 30, 1999 the PSC began a proceeding to review the proposed sale
of the Nine Mile Point nuclear facilities by Niagara Mohawk and NYSEG to AmerGen
to determine if the sale would be in the public interest. RG&E has intervened in
that proceeding. In early January 2000, at the request of PSC Trial Staff, that
proceeding was suspended to give the interested parties time for settlement
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negotiations. In late January 2000, the PSC Trial Staff expressed its intention
to move to dismiss the proceeding since it believes that the sale to AmerGen, as
filed, is not consistent with the public interest standard in Public Service Law
Section 70; Trial Staff said that it intends to immediately explore, in
conjunction with the utilities and interested parties, other scenarios for
future ownership and operation of the Nine Mile nuclear plants; and Trial Staff
proposed that the parties dispense with formal evidentiary hearings in this
proceeding. AmerGen has asked that the Judge reject Staff's request to dispense
with formal evidentiary hearings and instead set a schedule for testimony and
hearings in this proceeding.
A separate proceeding to consider RG&E's acquisition of the Nine Mile
nuclear facilities has not yet been commenced. At this time, RG&E is uncertain
what the outcome of the PSC regulatory process will be but expects that it will
continue for some time. RG&E intends to continue to pursue all of its
alternatives and evaluate any modifications to the current proposed transaction
and any new proposed transaction.
PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated
a proceeding to examine a number of issues raised by a Staff position paper on
nuclear generation and the comments received in response to it. In reviewing
the Staff paper and parties' comments, the PSC:
(1) adopted as a rebuttable presumption the premise that nuclear power should
be priced on a market basis to the same degree as power from other sources,
with parties challenging that premise having to bear a substantial burden
of persuasion;
(2) characterized the proposals in the Staff paper as by and large consistent
in concept with the PSC's goal of a competitive, market-based electricity
industry;
(3) questioned Staff's position that would leave funding and other
decommissioning responsibilities with the sellers of nuclear power
interests and;
(4) indicated interest in the potential for a New York Nuclear Operating
Company (NYNOC) proposal to benefit customers through efficiency gains and
directed pursuit of that matter in this nuclear generating proceeding or
separately upon the filing of a formal NYNOC proposal.
RG&E has worked with other New York nuclear generation operators on the
development of a NYNOC but no substantial further work on its implementation is
anticipated until completion of this proceeding and the outcome of any proposed
sales by current New York nuclear plant owners is determined.
RG&E's potentially strandable assets in nuclear plant could be impacted by
the outcome of this proceeding. The initial collaborative conference for this
proceeding was held on January 20, 1999. The parties in this proceeding
developed a collaborative, non-binding interim report entitled "Nuclear
Generation and the Competitive Electric Market" which was issued in July 1999.
RG&E is actively involved in this proceeding which is continuing. RG&E is
unable to determine when this proceeding may conclude.
FOSSIL UNITS STATUS. In 1999, RG&E ceased operations at and retired its
Beebee Station (80 Megawatt) generating facility. The retirement of Beebee
Station did not have a material effect on the financial position or results of
operations of RGS or RG&E. The Competitive Opportunities Settlement provides
that all prudently incurred incremental costs associated with the retirement and
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decommissioning of the plant are recoverable through RG&E's distribution access
rates.
In early June 1999 the Allegany Station, a combined-cycle unit fueled by
natural gas, began generating electricity. The 63 megawatt capacity unit is
expected to generate electricity during the peak demand summer months and when
the economics of producing electricity for sale are favorable. The plant is
being operated and maintained for RG&E by Bell Harbert Energy L.L.C. Allegany
Station, which was built as a co-generation facility in the early 1990s, was
obtained by RG&E as part of a legal settlement in December 1998 with General
Electric Capital Corporation, Kamine/Besicorp Allegany L.P. (Kamine) and other
Kamine affiliates.
Oswego Unit Sale. On October 22, 1999, RG&E and Niagara Mohawk sold their
respective 12% and 88% interests in the Oswego Generation Facility to Oswego
Harbor Power L.L.C., a wholly-owned affiliate of NRG Energy, Inc. (collectively,
the Buyer) for approximately $91 million. Additionally, the Buyer agreed to
assume RG&E's obligations under a June 8, 1998 transmission services agreement
(Exit Agreement) as it pertains to the Oswego Generation Facility. This
assumption represents a net present value of approximately $25 million, which
was deducted from RG&E's approximately $11 million share of the sale proceeds.
Accordingly, upon closing, RG&E was required to make a net payment of
approximately $14 million to Niagara Mohawk. Under the terms of the Competitive
Opportunities Settlement, RG&E is permitted to recover any losses and related
costs on a sale of generation through distribution rates. Pursuant to an
October 21, 1999 PSC order, RG&E was required to file with the PSC a detailed
calculation of its net book loss after tax impacts. RG&E made this filing with
the PSC on December 21, 1999. Including the impact of the $25 million relating
to the Exit Agreement, RG&E's net loss and associated costs are approximately
$79 million. In the filing, RG&E indicated that $2.2 million of depreciation
charges and $4.3 million of transmission contract payments, currently included
in rates, will be used to amortize the net loss during the remaining term of the
Competitive Opportunities Settlement.
FERC OPEN ACCESS TRANSMISSION ORDERS AND COMPANY FILINGS. On January 31,
1997, the New York electric utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the New York Power Pool (NYPP) then in effect would be dissolved and an
independent system operator (NYISO) would administer a Statewide open access
tariff and provide for the reliable operation of the bulk power system in the
State.
On June 30, 1998, the FERC issued an Order that conditionally authorized the
establishment of the NYISO by the member systems of the NYPP (Member Systems).
The order addressed areas of governance, standards of conduct and reliability.
On April 30, 1999, the FERC issued an order which addressed several issues,
including its rejection of the Member Systems' settlement on governance issues,
and its acceptance of the Section 203 filing to transfer jurisdictional
transmission facilities to the NYISO. On September 15, 1999, the FERC issued an
Order approving the agreement on governance.
On January 27, 1999 the FERC issued an Order conditionally accepting the
proposed NYISO tariff and the proposed market rules of the NYISO. The Order also
granted the Member Systems' request for market-based rates for energy, ancillary
services and installed capacity sold through the NYISO. On July 29, 1999, the
FERC issued an Order, approving the NYISO Open Access Transmission Tariff, the
NYISO Services Tariff, and each of the related ISO Agreements submitted by the
Member Systems.
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On November 18, 1999 the NYISO implemented a competitive wholesale market for
the sale, purchase and transmission of electricity and ancillary services in New
York State. After a two-week cutover period, the NYISO officially assumed
control and operation of the New York State electric transmission system from
the NYPP. With the implementation of day-ahead and real-time markets, RG&E is
provided with additional flexibility, beyond bilateral contracts, in marketing
its excess generation and in purchasing energy to supply retained retail load.
A settlement proceeding was established during 1999 to resolve an issue
involving the disposition of certain pre-ISO transmission agreements. On June
17, 1999, the Member Systems and other intervenors filed a Settlement Agreement
with FERC. On July 21, 1999, the presiding administrative law judge certified
the uncontested settlement to the Commission. On November 26, 1999, the
Commission approved the settlement. On January 5, 2000, the Commission certified
a partial uncontested settlement that included changes to the revenue
requirement as well as the divisor used to compute the transmission service
charge, setting the rate that RG&E and the other New York State utilities will
charge under the NYISO.
Currently, it is unclear what effect the above changes may have once other
regulatory changes in New York State are implemented. At the present time, RG&E
cannot predict what effects regulations ultimately adopted by FERC will have, if
any, on future operations or the financial condition of RGS or RG&E.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. With PSC
approval, RG&E 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 and RG&E's Balance Sheet and a discussion and summary 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
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 RG&E for full
service, leaving RG&E 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, 1999 RG&E believes that its regulatory assets are probable
of recovery. The Settlement in the Competitive Opportunities Proceeding does
not impair the opportunity of RG&E to recover its investment in these assets.
However, the PSC issued an Opinion and Order Instituting Further Inquiry on
March 20, 1998 to address issues surrounding nuclear generation. The initial
meeting in this Inquiry was held in January 1999 (see PSC Proceeding on Nuclear
Generation). The ultimate determination in this proceeding or any proceeding to
consider RG&E's proposed purchase of nuclear plants as discussed under Proposed
Purchase of Nuclear Plants could have an impact on strandable assets and the
recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC
issued a gas restructuring policy statement ("Gas Policy Statement") announcing
its conclusion that, among other things, the most effective way to establish a
competitive gas supply market is for gas distribution utilities to cease selling
gas. The PSC established a transition process in which it plans to address
three groups of issues: (1) individual gas utility plans to implement the PSC's
vision of the market; (2) key generic issues to be dealt with through
collaboration
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39
among gas utilities, marketers, pipelines and other stakeholders, and (3)
coordination of issues that are common to both the gas and the electric
industries. The PSC has encouraged settlement negotiations with each gas utility
pertaining to the transition to a fully competitive gas market. RG&E, the PSC
Staff and other interested parties have been participating in settlement
discussions in response to the specific requirements of the Policy Statement.
GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of the
PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement above),
RG&E had commenced negotiations with the PSC staff and other parties to develop
a comprehensive multi-year settlement of various issues, including rates and the
structure of RG&E's gas business. Because the negotiation of a comprehensive
settlement was not anticipated to conclude until mid-1999, the parties to the
negotiations agreed to an Interim Settlement, effective November 1998 through
June 1999, that dealt with such issues as rates, transportation and storage
capacity costs, assignment of capacity, and retail access. Significant features
of the Interim Settlement include a freeze on base rates at the current levels
(which were fixed at July 1994 levels), the imputation of $11.9 million in
revenues from the remarketing of capacity and a limit on RG&E's exposure to
costs associated with the migration of customers from RG&E to marketers for
sales and service.
Discussions following the expiration of the Interim Settlement resulted in
a September 14, 1999 filing to address issues pertaining to the cost of upstream
capacity and other matters pertaining to restructuring pursuant to the PSC's
Policy Statement. The proposal calls for: (1) a continued reduction in capacity
costs of $11.9 million, comprised of $10.2 million relating to upstream capacity
release transactions for the period September 1, 1999 through August 31, 2000
and $1.7 million from the expiration of a Texas Eastern capacity contract; (2) a
report to PSC staff, within 60 days of approval of the proposal, of the plans
and progress RG&E has made to reduce its upstream capacity costs; (3) a
resumption of the multi-year settlement discussions calling for RG&E to make a
public filing addressing the rate and restructuring issues addressed in the
PSC's Policy Statement within 120 days of approval of the proposal; and (4) RG&E
continuing to work on retail access program improvements. The proposal was
subsequently approved by the PSC and RG&E began implementation of its proposal
in the fourth quarter of 1999. As required, the report on upstream capacity
costs was submitted on November 29, 1999, under trade secret status. The public
filing addressing the rate and restructuring issues was made on January 28,
2000. This filing is intended to provide the basis for negotiations with the
PSC and other interested parties on RG&E's proposal to implement a fully
competitive marketplace for natural gas. Settlement negotiations pertaining to
RG&E's gas rate and restructuring proposal will begin as early as 30 days after
filing pursuant to the Gas Policy Statement. RG&E is unable to predict the
ultimate outcome from this proceeding, or when the PSC will issue a final order.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution
companies to assign to marketers the pipeline and storage capacity held by RG&E
to serve their customers. In its Gas Policy Statement issued in November 1998,
the PSC ordered that the mandatory assignment of capacity, permitted by the
March 1996 Order, be terminated effective April 1, 1999. According to the Gas
Policy Statement, however, the utilities are to be afforded a reasonable
opportunity to recover resulting strandable costs, if any. On March 24, 1999,
the PSC issued an Order Concerning Assignment of Capacity for all gas utilities
in the State of New York, generally requiring the removal of restrictions on
customer migration from utility service to service from marketers. RG&E has
complied with the PSC's directives.
FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, RG&E may negotiate competitive
electric rates at discount prices to compete with alternative power sources,
such
<PAGE>
40
as customer-owned generation facilities. Pursuant to the terms of the Settlement
under the Competitive Opportunities Proceeding, RG&E 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 24 percent of all regulated electric sales to customers are made
under long-term contracts, primarily to large industrial customers. These
contracts represent approximately 49 percent of RG&E's revenues from its
commercial and industrial customers.
LIQUIDITY AND CAPITAL RESOURCES
During 1999, RGS's and RG&E's cash flow from operations (see Statements of
Cash Flows) provided the funds for construction expenditures and the payment of
dividends and short-term debt. In addition, RG&E completed a long-term financing
in October 1999 (see "Financing" below). Cash used for investing activities in
1999 was lower due to the acquisition of Griffith in August 1998 and there were
no acquisitions of comparable size in 1999. Cash used in financing activities
for 1999 was higher due mainly to the redemption of short-term debt. Capital
requirements of the Company during 2000 are anticipated to be satisfied from the
combination of internally generated funds and short-term credit arrangements.
In addition, RG&E expects to issue long-term debt to finance its proposed
acquisition of the Nine Mile Two facilities (see Proposed Purchase of Nuclear
Plants). RG&E may also refinance long-term securities obligations during 2000
depending on prevailing financial market conditions.
CAPITAL AND OTHER REQUIREMENTS. RGS's and RG&E'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, the repayment of existing debt and the
repurchase of outstanding shares of Common Stock. Additional baseload
generation is expected to be available once RG&E completes its acquisition of
the Nine Mile Two facilities as discussed above. RG&E has no further plans to
install additional baseload generation.
1998 Labor Day Storm. At approximately midnight, Monday morning, September
7, 1998, a severe lightning and windstorm struck RG&E's franchise area. The
storm damaged RG&E's electrical system at several hundred different locations.
Several counties within RG&E's franchise area were declared State and federal
disaster areas.
RG&E has deferred approximately $8.5 million of costs and carrying charges
associated with this storm. Under the Competitive Opportunities Settlement with
the PSC, if incremental costs resulting from a "catastrophic event" exceed $2.5
million, such costs could be deferred. RG&E submitted a petition to the PSC for
deferral of costs associated with this storm and this petition is currently
pending.
Settlement with Co-generator. In May 1998 RG&E entered into a Global
Settlement Agreement regarding the termination of a power purchase contract with
Kamine/Besicorp Allegany L.P. (Kamine). In August 1998 the PSC approved the
Global Settlement Agreement, and on December 1, 1998, the Agreement became
effective. Under the terms of the Global Settlement Agreement, the Power
Purchase Agreement was terminated in consideration of payment by RG&E of $168
million over 16 years, without interest, with an initial payment of $10 million.
Also, under the terms of the Global Settlement Agreement, RG&E paid an
additional $15 million for the purchase of the Kamine generation facility. In
June 1999 the plant began generating electricity (see Fossil Units Status).
RG&E does not expect the terms of the Global Settlement Agreement to have any
material effect on its earnings or the earnings of RGS. Pursuant to a PSC order
approving the terms of the Global Settlement Agreement, regulatory assets have
been established by RG&E to account
<PAGE>
41
for the initial payment, the facility purchase, and future payments. RG&E has no
other long-term obligations to purchase energy from other cogeneration
facilities.
Capital Requirements - Summary. Excluding the potential acquisition by
RG&E of Nine Mile One and the additional investment in Nine Mile Two as
discussed above, capital requirements for the Company over the three-year period
1997 to 1999 and the current estimate of capital requirements through 2002 are
summarized in the Capital Requirements table. RG&E's portion of total
construction requirements as presented in the Capital Requirements table for
2000, 2001, and 2002 are $151 million, $137 million, and $112 million,
respectively.
The Company's capital expenditures program is under continuous review and
could be revised for any number of issues. Also, RG&E may consider, as
conditions warrant, the redemption or refinancing of certain outstanding long-
term securities.
<TABLE>
<CAPTION>
Capital Requirements - RGS
- -------------------------------------------------------------------------------------------
Actual Projected
1997 1998 1999 2000 2001 2002
Type of Facilities (Millions of Dollars)
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Electric Property
Production $ 9 $ 16 $ 14 $ 14 $ 14 $ 15
Energy Delivery 28 41 42 67 80 50
----- ----- ----- ----- ----- ----
Subtotal 37 57 56 81 94 65
Nuclear Fuel 19 14 14 25 9 19
----- ----- ----- ----- ----- ----
Total Electric 56 71 70 106 103 84
Gas Property 22 21 19 25 23 17
Common Property 9 21 20 22 13 13
----- ----- ----- ----- ----- ----
Total 87 113 109 153 139 114
Carrying Costs
Allowance for Funds Used During
Construction 1 1 2 1 1 1
----- ----- ----- ----- ----- ----
Total Construction Requirements 88 114 111 154 140 115
Securities Redemptions, Maturities
and Sinking Fund Obligations* 182 66 10 30 -- 100
----- ----- ----- ----- ----- ----
Total Capital Requirements $ 270 $ 180 $ 121 $ 184 $ 140 $215
----- ----- ----- ----- ----- ----
</TABLE>
* Excludes prospective refinancings.
FINANCING. On October 27, 1999 RG&E issued $100 million of 7.60% First
Mortgage Bonds, Designated Secured Medium-Term Notes, Series B. The net
proceeds from this financing were used to repay short-term debt and pay for
capital expenditures.
RG&E generally utilizes 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 RGS's and RG&E's short-term
borrowing arrangements and limitations, see Note 9 of the Notes to Financial
Statements. As financial market conditions warrant, RG&E may also, from time to
time, redeem higher-cost senior securities.
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 $152 million in 1997 and $25.5 million in 1998.
Included in discretionary redemptions for 1997 and 1998 were over $127 million
of
<PAGE>
42
tax-exempt securities, which were refinanced with tax-exempt debt. There were no
discretionary redemptions of securities in 1999.
STOCK REPURCHASE PLAN. In April 1998, the PSC approved a Stock Repurchase
Plan for RG&E providing for the repurchase of Common Stock having an aggregate
market value not to exceed $145 million. RG&E began the repurchase program in
May 1998 and 2,942,600 shares of Common Stock have been repurchased for
approximately $83.3 million through December 31, 1999. The average cost per
share purchased during 1999 was $25.65.
ENVIRONMENTAL ISSUES. The production and delivery of energy are
necessarily accompanied by the release of by-products subject to environmental
controls. RGS and RG&E have 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.
RGS and RG&E have recorded liabilities to reflect specific issues where
remediation activities are currently deemed to be probable and where the cost of
remediation can be estimated. Estimates of the extent of the Company's degree of
responsibility at a particular site and the method and ultimate cost of
remediation require a number of assumptions for which the ultimate outcome may
differ from current estimates. While RGS and RG&E do not anticipate that any
adjustment would be material to its financial statements, it is reasonably
possible that the result of ongoing and/or future environmental studies or other
factors could alter this expectation and require the recording of additional
liabilities. The extent or amount of such events, if any, cannot be estimated
at this time.
Additional information concerning RGS's and RG&E's environmental matters
can be found in Note 10 of the Notes to Financial Statements.
YEAR 2000 READINESS INFORMATION. As the year 2000 (Y2K) approached, RGS and
RG&E, like most companies, faced potentially serious information and operational
systems (computer and microprocessor-based devices) problems because many
software applications and embedded systems programs created in the past would
not properly recognize calendar dates beginning with the year 2000 or that the
year 2000 is a "leap-year".
On and after January 1, 2000, the Company and RG&E have experienced normal
operations of their computer and microprocessor-based devices with no loss or
interruption of energy generation or delivery and no operating difficulties of
its mission critical internally developed applications or critical devices.
RG&E's two major electric power plants, Ginna and Russell Station, performed
without any difficulties. Likewise, operations at the Nine Mile Two electric
power plant proceeded normally and there has been no major impact on gas
service. RG&E is not aware of any regional or statewide power systems that
failed to perform as the result of Y2K-related problems. The Company has
experienced no major problems related to applications and devices of critical
external parties. The Company will continue to monitor the operation of its
computers and microprocessor-based devices for any Y2K-related problems.
RG&E funded its Y2K Project internally and has incurred $9.3 million of
incremental costs through December 31, 1999 associated with making the necessary
modifications identified to applications and devices. Energetix, including
Griffith Oil, incurred less than $100,000 of incremental costs. Neither RGS or
RG&E have deferred any major corporate information technology projects due to
this effort.
<PAGE>
43
EARNINGS SUMMARY
The impact of developing competition in the energy marketplace may affect
future earnings. The Competitive Opportunities Settlement 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 RG&E will
depend on several factors, including the availability of qualified energy
suppliers in RG&E's service territory, the degree of customer participation and
ultimate selection of an alternative energy supplier, RG&E's ability to be
competitive by controlling its operating expenses, and RGS's ultimate success in
the development of its unregulated business opportunities as permitted under the
Settlement.
Although RG&E does not earn a return on the gas commodity it acquires for
distribution, under the current regulatory environment future earnings may be
affected, in part, by the ultimate outcome of implementation of the November
1998 Gas Policy Statement (see Rates and Regulatory Matters). That policy
statement concludes that the most effective way to establish a robust
competitive gas supply in New York State is for local gas distribution companies
(LDCs), such as RG&E, to exit the merchant function of acquiring gas, as well as
transportation and storage capacity to serve retail customers. LDCs ceased
assigning transportation capacity to customers migrating from sales to
transportation service by April 1, 1999. The nature and magnitude of the
potential impact of these policies will depend on individual negotiations that
RG&E is undertaking with the PSC Staff and other interested parties on RG&E
specific restructuring, as well as a number of Statewide collaborative efforts
that will deal with such issues as provider of last resort, reliability,
recovery of stranded costs, and market power as the transition is made to a more
competitive gas business.
RGS. RGS reported consolidated earnings of $2.44 per share in 1999 compared
to $2.32 in 1998. RGS's earnings per share in 1999 were positively affected by
increased electric sales to a combination of marketers and retail customers
during the summer months when the weather was 25% warmer than a year ago
(cooling degree day basis) and by higher gas sales in the first quarter of 1999
driven by 19% colder weather (heating degree day basis)) as compared to 1998.
Sales and revenues in 1999 also reflect a one-time adjustment during the second
quarter of the year in the methodology of calculating unbilled sales and
revenues which increased electric revenues by $7.1 million and gas revenues by
$6.1 million. In addition, non-fuel operating expenses for RGS include a $4.8
million drop in RG&E welfare expense from 1998 as discussed below. RGS's share
buy-back program also contributed to higher earnings per share in 1999 adding
$.11 per share. Having a negative effect on earnings in 1999 was a 57-day
scheduled refueling and ten-year in-service inspection outage at the Ginna plant
(there was no outage in 1998) and a 30-day unscheduled outage at the Nine Mile
Two plant. These outages contributed to increased purchased power expenses and
decreased sales of electricity to other utilities during the year. A scheduled
electric rate reduction effective July 1 and a one-time adjustment of
approximately $7 million in the second quarter of 1999 to increase RG&E's
allowance for uncollectible accounts also had an unfavorable effect on 1999
earnings.
RGS continues to grow its unregulated business through its subsidiary,
Energetix, which provides electric, natural gas, and petroleum-based energy
products and services throughout the upstate New York region. Energetix's
unconsolidated operating revenues were $275 million in 1999, of which sales from
Griffith's heating oil, gasoline and propane gas contributed approximately $220
million. These revenues from Griffith are included under "Other Revenues" on
RGS's and RG&E's Income Statements. Energetix, including Griffith, on a
consolidated basis, had a pre-tax loss of $0.1 million for 1999. These results
reflect the development expenses related to building a successful unregulated
<PAGE>
44
electric and natural gas business in an open and competitive market.
Energetix's revenues for 2000 from electric and gas operations are expected to
increase over 1999 levels as Energetix expands its customer base, although no
assurance may be given that Energetix will achieve a net operating gain in 2000.
RG&E. Earnings for RG&E in 1999 reflect the same issues discussed above for
RGS except that discussions relating to Energetix and Griffith are not
applicable. The 1999 RG&E Income Statement reflects the consolidated operations
of RG&E and its former subsidiaries, Energetix and RGS Development, through
August 2, 1999 at which time the holding company RGS was formed and RG&E,
Energetix and RGS Development then became subsidiaries of RGS. Subsequent to
that date, the RG&E Income Statement reflects only the operating results of
RG&E.
Basic earnings per share for RG&E were $2.32 in 1998, compared with $2.30
in 1997. For both 1998 and 1997, these results reflect the consolidated
operations of RG&E and its subsidiaries at that time, Energetix and RGS
Development Corporation. Operating performance of RG&E's generating plants,
expense control, the sale of electric energy to wholesale customers, and the
recognition of $17.4 million of non-recurring income during the year (see "1998
Compared to 1997", Other Statement of Income Items) allowed RG&E to keep 1998
earnings applicable to Common Stock at about the same level as 1997, despite
rate decreases and warmer temperatures during the 1998 heating seasons.
Earnings per share in 1998 were improved by approximately $.02 per share
resulting from the buyback of Common Stock under the Company's Stock Repurchase
Program.
For the twelve month period ending December 31, 1998, RG&E's unregulated
subsidiary, Energetix, had a pretax operating loss of $4.1 million, which
reduced consolidated earnings by approximately $0.06 per basic share. This loss
is primarily due to initial start-up and marketing costs. Moreover, while
Energetix was formed January 1, 1998, the first revenues were not received until
April of 1998. In addition, revenues from Griffith Oil Co., Inc., a company
acquired by Energetix, only reflect sales since acquisition in August 1998.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes in
the amounts of revenues and expenses for RGS (regulated and unregulated
business) and RG&E (regulated business), comparing 1999 to 1998 and 1998 to
1997. The operating results of the regulated business reflect RG&E's electric
and gas sales and services and the operating results of the unregulated business
reflect Energetix operations. In 1999, the majority of RGS's operating results
reflect the operating results of RG&E and the factors that affect operating
results for RG&E are the significant factors that affect comparable operating
results for RGS, unless otherwise noted. The Notes to Financial Statements
contain additional information.
1999 COMPARED TO 1998
- ---------------------
OPERATING REVENUES AND SALES. Increased electric revenues for RGS and RG&E
reflect the warmer summer weather as discussed above to meet the demand for air
conditioning usage partially offset by a base rate reduction and lower regulated
electric sales due largely to RG&E's reduced capacity to sell power to other
electric utilities because of the refueling and in-service inspection outage at
the Ginna Plant and the unscheduled outage at Nine Mile Two as discussed above
under "Earnings Summary". Regulated sales and revenues for this period compared
to last year also reflect a one-time adjustment to reflect a change in the
estimating process for unbilled sales and revenues. This adjustment increased
regulated electric revenues by $7.1 million and increased
<PAGE>
45
regulated gas revenues by $6.1 million. Regulated electric sales increased by
74,000 megawatt-hours and regulated gas sales were higher by 7,610,000 therms as
a result of this one-time adjustment. A drop in commercial and industrial
regulated electric sales reflects, in part, the opening of the electric market
under the terms of the Competitive Opportunities Settlement. RG&E, however,
sells electric energy, as well as distribution services, to qualified energy
marketers in its franchise territory which has the effect of increasing
wholesale sales to energy marketers. Included in RGS's electric operating
revenues for 1999 are $65.2 million of revenues from electric sales to energy
marketers and $ 25.3 million of revenues from wholesale sales to other
utilities. Revenues in 1999 from energy marketers were up $50.2 million compared
with 1998 reflecting the opening of the electric marketplace and increased sales
of electricity and distribution services. Revenues from the sales of electric
energy to other utilities dropped $3.7 million from 1998 due mainly to the
availability of RG&E's generating plants as discussed above, partially offset by
an increase in the average revenue per unit sold. Fluctuations in revenues from
electric sales to other utilities are generally related to RG&E's customer
energy requirements, the wholesale energy market, availability of transmission,
and the availability of electric generation from RG&E's facilities.
Regulated gas margins (revenues less cost of purchased gas) were up over
$12 million reflecting 11% cooler weather (based on heating degree days) for the
year and the change in unbilled sales methodology discussed above. Therms of
gas sold and transported for the regulated business were up 10.7 percent in
1999. The transportation of gas for customers who are able to purchase natural
gas from sources other than RG&E is an important component of RG&E's marketing
mix. In 1999, RG&E's small customer aggregate transportation market appeared as
a significant addition to RG&E's marketing mix. Company facilities are used to
distribute this gas, which in total amounted to 20.0 million dekatherms in 1999
and 16.4 million dekatherms in 1998. These purchases by eligible customers have
caused decreases in RG&E's retail gas customer revenues, with offsetting
decreases in purchased gas expenses and, in general, do not adversely affect
earnings because transportation customers are billed at rates which, except for
the cost of buying and transporting gas to RG&E's city gate, are the same as the
rates charged RG&E's retail gas service customers. Moreover, under the current
regulatory environment, RG&E does not earn a return on the gas commodity it
acquires for distribution. Gas supplies transported in this manner are not
included in RG&E's therm sales, depressing reported gas sales to non-residential
customers.
Eighty percent of Energetix total operating revenues in 1999 were from the
sale of heating oil, propane and gasoline by Griffith (see discussion under
"Earnings Summary"). For heating oil and propane, Griffith experiences seasonal
fluctuations due to the dependence on spaceheating sales during the heating
season. In addition, gasoline sales reflect seasonal fluctuations due to
increased consumer driving during the warmer months. Unregulated sales reflect
Griffith's operations since its acquisition by Energetix on August 2, 1998 and
the migration of electric and gas customers from the regulated to the
unregulated business.
OPERATING EXPENSES. Higher regulated electric fuel expenses reflect
increased purchased electricity costs driven by the effect from lower generation
from the Ginna nuclear plant, hydro plants, and the closing of Beebee Station on
April 30, 1999, in addition to an increase in the cost per unit purchased. The
cost of purchased power may fluctuate depending on the availability of electric
generation from RG&E's facilities, the wholesale energy market and the total
availability of energy, and the availability of transmission facilities. Fuel
expense for electric generation was down in 1999 reflecting lower generation
from RG&E's facilities. Since July 1996, Common Stock shareholders have assumed
the full benefits and detriments realized from actual electric fuel costs and
generation mix compared with PSC-approved forecast amounts. RG&E normally
<PAGE>
46
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 RG&E's production cost. Despite an increase in retail regulated gas therm
sales, gas purchased for resale expense declined in 1999 reflecting a lower
average cost per unit due, in part, to reduction in pipeline costs. Other fuel
expense on both RGS's and RG&E's Income Statements reflect mainly the cost of
purchased fuel for Griffith's operations since its acquisition by Energetix.
The decrease in non-fuel operating expenses for RGS and RG&E includes a
$4.8 million drop in RG&E welfare expense from 1998 due mainly to the
performance of pension assets and a change in the discount rate used to value
the aggregate pension liability (see Note 3 of the Notes to Financial
Statements), elimination in the first quarter of 1999 of property insurance and
storm reserves no longer required totaling $2.1 million, lower non-fuel net
expenses of $1.5 million associated with Ginna Station refueling outages, a
decrease of $2.8 million due primarily to the completion in 1998 of the
amortization of costs of RG&E's billing system, insurance dividends of $1.8
million, and lower employee performance incentive program costs of $1.1 million.
Offsetting these declines was a June 1999 increase in the allowance for
uncollectible accounts of approximately $7 million to better match RG&E's actual
collection history, the establishment in the fourth quarter of 1999 of a $3.0
million liability for anticipated Nine Mile Two inventory losses due to a change
in the expected ownership of that facility, and Y2K costs of $6.0 million.
The variance in unregulated non-fuel operating expenses reflects primarily
an increase in payroll expenses ($5.6 million), other operating expenses for
Griffith ($2.6 million), and general and administrative expenses ($2.1 million).
The increase in these expenses reflects twelve months of Griffith's operations
in 1999 compared with only five months of operations in 1998 following its
acquisition in August 1998.
Depreciation expense for both RGS and RG&E in 1999 includes an incremental
one-time charge in the second quarter of approximately $2.1 million associated
with the closing of Beebee Station in April 1999. Depreciation and amortization
expense for unregulated operations in 1999 was $3.2 million, up $2.1 million
from 1998.
Local, State and other taxes for RGS and RG&E declined reflecting a New
York State use tax audit refund, lower tax rates for State and local revenue
taxes, and lower assessments for property taxes. These results were partially
offset by higher unbilled revenue taxes resulting from an increase in unbilled
revenues. For unregulated operations, local, State and other taxes increased
$2.9 million to $4.0 million compared to 1998.
The difference in federal income tax expense for RGS and RG&E reflects pre-
tax earnings and, regarding RG&E, the settlement of RG&E audits in the first
quarter of 1998 and a tax reserve increase for potential disputed issues of $4.8
million in the fourth quarter of 1999.
OTHER STATEMENT OF INCOME ITEMS. The change in non-operating federal income
taxes for both RGS and RG&E results from variances in non-operating earnings
before federal income taxes.
The change in RGS's and RG&E's Other Income and Deductions, Other-net
reflects mainly the recognition of income in 1998 due to the elimination of
certain pension and other post-employment benefit deferred credits and Nine Mile
Two operating and maintenance expenses in accordance with the Competitive
Opportunities Settlement (see "1998 Compared to 1997", Other Statement of Income
Items). This variance in Other Income and Deductions, Other-net was partially
offset by non-cash carrying charges of $8.6 million related to deferral of
Kamine (Allegany Station) facility costs in 1999 for the regulated business.
These
<PAGE>
47
carrying charges, which are primarily associated with the deferred recovery of
costs associated with the Kamine settlement (see following paragraph), were
allowed under the Competitive Opportunities and Kamine settlements. In addition,
expenses associated with RG&E management performance awards were down $4.4
million in 1999 compared with 1998.
The increase in RGS's interest charges reflects mainly an increase in long-
term debt outstanding, resulting mainly from the Kamine settlement, the
acquisition of Griffith by Energetix, and the issuance of $50 million of long
term debt by RG&E in December 1998. The increase in RG&E's interest charges
reflects the same issues exclusive of the debt incurred for the Griffith
acquisition. To a lesser extent, interest expense for both RGS and RG&E
reflects the interest on $100 million of first mortgage bonds issued in October
1999 (see "Financing").
1998 COMPARED TO 1997
- ---------------------
OPERATING REVENUES AND SALES. Regulated electric revenues for 1998 were
down compared to a year earlier resulting from a decrease in electric base rates
effective July 1, 1998 and July 1, 1997 and the effect of the migration of
approximately 10% of RG&E's electric load to competitive suppliers, including
Energetix. Making a positive contribution to 1998 electric revenues was an
increased demand for air conditioning load during the summer months when the
weather was 70% warmer (on a cooling degree day basis) in contrast to the summer
of 1997 which was 35% cooler than normal. Electric revenues from sales to other
electric utilities was up largely due to the increased availability of the Ginna
Plant. The Ginna Plant experienced a 31 day scheduled refueling outage in 1997
compared with no outage in 1998. The drop in commercial and industrial regulated
electric sales reflects, in part, the opening of the electric market on July 1,
1998 under the terms of the Competitive Opportunities Settlement. RG&E,
however, sells electric energy, as well as distribution services, to qualified
energy marketers in its franchise territory which has the effect of increasing
wholesale sales to energy marketers. Included in electric operating revenues
for 1998 are $15.0 million of revenues from electric sales to energy marketers.
Regulated gas margins (revenues less cost of purchased gas) were down over
$20 million reflecting 18% warmer weather (based on heating degree days).
Therms of gas sold and transported for the regulated business were down 12.1
percent in 1998.
Included in total operating revenues for 1998 are $10.6 million of electric
and gas operating revenues received by Energetix and $71.2 million of Griffith
operating revenues. Griffith's operating revenues are reported under Other
Revenues on both RGS's and RG&E's Income Statements. Prior year comparisons for
the Company's unregulated subsidiary, Energetix, are not relevant because formal
operations began in the first quarter of 1998 and Griffith was acquired in
August 1998.
OPERATING EXPENSES. Higher fuel expenses in 1998 reflect higher fuel
expenses for electric generation resulting from increased generation to support
higher electric sales. For the 1998 comparison period, increased fuel expense
also reflects relatively more generation from RG&E's costlier fossil-fueled
units. Compared with 1997, purchased electric power expense declined in 1998
driven primarily by the effect of greater availability of RG&E's generating
facilities. The cost per unit purchased for electric energy was up about 8% in
1998 compared with a year earlier. Gas purchased for resale expense declined in
1998 driven by a reduced volume of purchased gas resulting from a warmer heating
season. Other fuel expense on both RGS's and RG&E's Income Statements reflects
<PAGE>
48
mainly the cost of purchased fuel for Griffith operations since its acquisition
in August 1998 by Energetix.
The decrease in non-fuel operating expenses for RGS and RG&E includes lower
expense of $5.3 million associated with RG&E's uncollectible accounts and a $7.9
million drop in RG&E's welfare expenses due to a favorable adjustment in pension
expense (see Note 3 to the Notes to Financial Statements). The decrease in
uncollectible accounts expense was driven by the increased level of collection
activity. Partially offsetting these lower costs were increased payroll costs
of $2.2 million. Approximately $1.6 million of Year 2000 costs were charged to
operating expenses in 1998, up $0.4 million from 1997.
The variance in unregulated non-fuel operating expenses reflects primarily
a change in payroll expenses, other operating expenses for Griffith, and general
and administrative expenses. Prior year comparisons for the Company's
unregulated subsidiary, Energetix, are not relevant because formal operations
began in the first quarter of 1998 and Griffith was acquired in August 1998.
Depreciation expense for both RGS and RG&E in 1998 remained relatively flat
compared to 1997 due to the completion of depreciation expense on certain fully
depreciated computer equipment. Depreciation and amortization expense in 1998
includes $1.1 million for unregulated operations.
Local, State and other taxes for RGS and RG&E declined reflecting mainly
lower State revenue taxes due to decreased regulated revenues. This decline was
partially offset by an additional $1.5 million of local and State taxes
associated with unregulated operations.
The difference in federal income tax expense for RGS and RG&E reflects pre-
tax earnings and, regarding RG&E, the settlement of RG&E audits in the first
quarter of 1998.
OTHER STATEMENT OF INCOME ITEMS. The change in non-operating federal income
taxes for both RGS and RG&E results from variances in non-operating earnings
before federal income taxes, as well as a $1.7 million RG&E reserve for deferred
taxes subsequent to a review of the historic balances.
The change in RGS's and RG&E's Other Income and Deductions, Other-net
reflects the recognition of income due to the reversal of certain deferred
credits in accordance with the Competitive Opportunities Settlement. In prior
years, the PSC had required RG&E to establish deferred credits to account for
certain pension and other post-employment benefit charges and Nine Mile Two
operating and maintenance expenses. In 1998, these deferred credits totaling
$17.4 million were eliminated consistent with the terms of the Settlement and
discussions with the PSC. An amount of $8.8 million associated with certain
pension charges was reflected on RG&E's books in the first quarter of 1998,
after RG&E received the written order associated with the Competitive
Opportunities Settlement. An amount of $6.0 million associated with certain
Nine Mile Two operating and maintenance expenses was reflected ratably over each
of the four quarters of 1998, consistent with Nine Mile Two accounting
practices. The remainder associated with certain other post-employment benefits
was reflected in the second quarter of 1998, after RG&E had concluded
discussions with the PSC. This income was partially offset by expenses
associated with the gas interim settlement agreement.
The decrease in RGS's and RG&E's interest charges reflects both mandatory
and optional redemptions of long term debt undertaken by RG&E during 1998 and
1997. In addition, other interest decreased in 1998 due to lower miscellaneous
interest charges on RG&E pension and other post-employment benefits. The decline
in interest charges was partially offset by an additional
<PAGE>
49
$1.0 million of interest expense associated mainly with the acquisition of
Griffith by Energetix.
DIVIDEND POLICY
The ability of RGS to pay common stock dividends is governed by the
ability of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far
the largest of the subsidiaries, it is expected that for the foreseeable future
the funds required by RGS to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS by RG&E. In the future, dividends
from subsidiaries other than RG&E may also be a source of funds for dividend
payments by RGS. RG&E's ability to make dividend payments to RGS will depend
upon the availability of retained earnings and the needs of its utility
business. In addition, pursuant to the PSC order approving the formation of
RGS, RG&E may pay dividends to RGS of no more than 100% of RG&E's net income
calculated on a two-year rolling basis. The calculation of net income for this
purpose excludes non-cash charges to income resulting from accounting changes or
certain PSC required charges as well as charges that may arise from significant
unanticipated events. This condition does not apply to dividends that would be
used to fund the remaining portion of the $100 million authorized for RG&E's
unregulated operations (about $42 million at December 31, 1999). The level of
future cash dividend payments on Common Stock will be dependent upon RGS's
future earnings, its financial requirements, and other factors.
<PAGE>
50
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
RG&E is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
RG&E manages its interest rate risk through the issuance of fixed -rate debt
with varying maturities and through economic refundings of debt through optional
redemptions. A portion of RG&E's long-term debt consists of long-term
Promissory Notes, the interest component of which resets on a periodic basis
reflecting current market conditions. See "Note 6 - Long Term Debt". RG&E was
not participating in any derivative financial instruments for managing interest
rate risks as of December 31, 1999 or December 31, 1998.
The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other petroleum-related products used for resale.
Commodity purchases and electric generation are based on projected demand for
power generation and customer delivery of electricity, natural gas and petroleum
products. RG&E enters into forward contracts for natural gas to hedge the
effect of price increases and reduce volatility on gas purchased for resale.
Owned electric generation significantly reduces RG&E's exposure to market
fluctuations in electric prices. RG&E does not hold open speculative positions
in any commodity for trading purposes.
RG&E's exposure to market price fluctuations of the cost of natural gas is
further limited as the result of the Gas Cost Adjustment (GCA), a regulatory
mechanism that transfers substantially all gas commodity price risk to the
customer. Nonetheless, RG&E does hedge approximately 70% of its gas supply price
through the purchase of futures contracts and the use of storage assets. The
balance of RG&E's natural gas requirements is procured through spot market
purchases and is subject to market price fluctuations.
Under the Competitive Opportunities Settlement, RG&E's electric rates are
capped at specified levels through June 30, 2002. As a result of owned
generation and long-term fixed rate supply contracts, RG&E is largely insulated
from market price fluctuations for procurement of its electric supply. In the
event RG&E's generation assets fail to perform as planned, RG&E is exposed to
market price fluctuations, and under the current rate agreement, fully absorbs
this operating risk.
Energetix has entered into electric and natural gas purchase commitments with
numerous suppliers. These commitments support fixed price offerings to retail
electric and gas customers. Griffith is in the business of purchasing various
petroleum-related commodities for resale to its customers. To manage the
resulting market price risk, Griffith enters into various exchange-traded
futures and option contracts and over-the-counter contracts with third parties.
All hedge contracts are accounted for under the deferral method with gains and
losses from the hedging activity included in the cost of sales as inventories
are sold or as the hedge transaction occurs. Commodity instruments not
designated as effective hedges are marked to market at the end of the reporting
period, with the resulting gains or losses recognized in cost of sales. These
contracts are closely monitored on a daily basis to manage the price risk
associated with inventory and future sales commitments. At December 31, 1999 and
1998 Griffith's net deferred gains on open hedge contracts were immaterial.
<PAGE>
51
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
The financial statements listed below are shown under Item 8 of this
Report.
Report of Independent Accountants.
RGS Consolidated Statement of Income for each of the three years ended
December 31, 1999.
RGS Consolidated Statement of Retained Earnings for each of the three
years ended December 31, 1999.
RGS Consolidated Balance sheet at December 31, 1999 and 1998.
RGS Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1999.
RG&E Statement of Income for each of the three years ended December 31,
1999.
RG&E Statement of Retained Earnings for each of the three years ended
December 31, 1999.
RG&E Balance sheet at December 31, 1999 and 1998.
RG&E Statement of Cash Flows for each of the three years ended December 31,
1999.
RGS and RG&E 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 of RGS and RG&E.
B. SUPPLEMENTARY DATA
Interim Financial Data.
<PAGE>
52
Report of Independent Accountants
To the Shareholders and Board of Directors of
RGS Energy Group, Inc and the
Shareholders and Board of Directors of
Rochester Gas and Electric Corporation
In our opinion, the accompanying consolidated financial statements listed under
Item 8A in the index appearing on the preceeding page present fairly, in all
material respects, the financial position of RGS Energy Group, Inc. and its
subsidiaries ("RGS") at December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999 and the accompanying 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
("RG&E") at December 31, 1999 and 1998, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 1999
in conformity with accounting principles generally accepted in the United
States. These financial statements are the responsibility of the RGS and RG&E
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 auditing standards generally accepted in the United States,
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.
[PricewaterhouseCoopers LLP (signed)]
Rochester, New York
February 1, 2000
<PAGE>
53
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31, 1999 1998* 1997
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $ 702,751 $ 687,622 $ 700,329
Gas 284,476 274,657 336,309
Other 220,310 71,212 -
------------- ------------- -------------
Total Operating Revenues 1,207,537 1,033,491 1,036,638
Operating Expenses
Fuel Expenses
Fuel for electric generation 49,297 53,954 47,665
Purchased electricity 54,337 27,024 28,347
Gas purchased for resale 151,458 155,497 196,579
Unregulated fuel expenses 189,465 59,490 -
------------- ------------- -------------
Total Fuel Expenses 444,557 295,965 272,591
Operating Revenues Less Fuel Expenses 762,980 737,526 764,047
Other Operating Expenses
Operations and maintenance excluding fuel expenses 297,890 301,625 315,109
Unregulated operating and maintenance expenses excluding fuel 26,464 13,524 -
Depreciation and amortization 118,695 116,102 116,522
Taxes - local, state and other 114,639 117,973 121,796
Federal income tax 64,253 60,236 65,279
------------- ------------- -------------
Total Other Operating Expenses 621,941 609,460 618,706
Operating Income 141,039 128,066 145,341
Other (Income) and Deductions
Allowance for other funds used during construction (657) (408) (351)
Federal income tax (1,134) 1,665 (3,704)
Other, net (8,178) (13,370) 3,308
------------- ------------- -------------
Total Other (Income) and Deductions (9,969) (12,113) (747)
Interest Charges
Long term debt 53,681 43,306 44,615
Other, net 4,798 3,388 6,676
Allowance for borrowed funds used during construction (1,051) (653) (563)
------------- ------------- -------------
Total Interest Charges 57,428 46,041 50,728
------------- ------------- -------------
Preferred Stock Dividend Requirements 4,083 4,842 5,805
Net Income Applicable to Common Stock $ 89,497 $ 89,296 $ 89,555
============= ============= =============
Earnings per Common Share - Basic $ 2.44 $ 2.32 $ 2.30
Earnings per Common Share - Diluted $ 2.44 $ 2.31 $ 2.30
============= ============= =============
</TABLE>
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31, 1999 1998* 1997*
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at Beginning of Period $ 129,484 $ 109,313 $ 90,540
Add
Net Income 89,497 89,296 89,555
------------- ------------- -------------
Total 218,981 198,609 180,095
------------- ------------- -------------
Deduct
Dividends declared on Common Stock 65,594 68,927 69,936
Other Adjustments 201 198 846
------------- ------------- -------------
Total 65,795 69,125 70,782
------------- ------------- -------------
Balance at End of Period $ 153,186 $ 129,484 $ 109,313
============= ============= =============
Cash Dividends Declared per Common Share $ 1.80 $ 1.80 $ 1.80
============= ============= =============
</TABLE>
The accompanying notes are an integral part of the financial statements.
* Reclassified for comparative purposes.
<PAGE>
54
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility Plant
Electric $ 2,399,532 $ 2,477,077
Gas 453,634 435,318
Common 130,118 158,038
Nuclear 270,447 256,562
------------- ------------
3,253,731 3,326,995
Less: Accumulated depreciation 1,636,955 1,640,645
Nuclear fuel amortization 239,243 222,830
------------- ------------
1,377,533 1,463,520
Construction work in progress 95,862 98,554
------------- ------------
Net Utility Plant 1,473,395 1,562,074
------------- ------------
Current Assets
Cash and cash equivalents 8,288 6,523
Accounts receivable, net of allowance for doubtful accounts:
1999 - $34,026; 1998 - $26,554 90,239 89,291
Unbilled revenue receivable 58,005 37,922
Materials, supplies and fuels 38,206 43,024
Prepayments 24,576 25,950
Other current assets 523 253
------------- ------------
Total Current Assets 219,837 202,963
------------- ------------
Intangible Assets
Goodwill, net 13,894 14,681
Other Intangible Assets 7,338 6,381
------------- ------------
Total Intangible Assets 21,232 21,062
------------- ------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 220,815 183,502
Nine Mile Two deferred costs 28,206 29,258
Unamortized debt expense 17,984 17,241
Other deferred debits 13,137 18,531
Regulatory assets 466,231 416,320
Other assets 2,037 1,984
------------- ------------
Total Deferred Debits and Other Assets 748,410 666,836
============= =============
Total Assets $ 2,462,874 $ 2,452,935
============= =============
</TABLE>
The accompanying notes are an integral part of the financial statements
<PAGE>
55
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 580,070 $ 510,002
- promissory notes 235,395 248,224
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Common stock
Authorized 50,000,000 shares; 38,885,813 shares
issued at December 31, 1999 and at December 31, 1998 700,268 699,730
Retained earnings 153,186 129,484
---------------------------------
853,454 829,214
Less: Treasury stock at cost (2,942,600 shares at December 31, 1999
and 1,507,000 shares at December 31, 1998) 83,252 46,433
---------------------------------
Total Common Shareholder's Equity 770,202 782,781
---------------------------------
Total Capitalization 1,657,667 1,613,007
---------------------------------
Long Term Liabilities
Nuclear waste disposal 91,743 87,566
Uranium enrichment decommissioning 10,911 12,197
Site remediation 23,698 24,157
---------------------------------
126,352 123,920
---------------------------------
Current Liabilities
Long term debt due within one year 37,643 427
Preferred stock redeemable within one year - 10,000
Short term debt 10,500 57,000
Accounts payable 54,221 52,454
Dividends payable 17,078 17,937
Equal payment plan 10,529 11,025
Other 39,385 34,526
---------------------------------
Total Current Liabilities 169,356 183,369
---------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 318,694 326,972
Pension costs accrued 48,628 58,677
Kamine deferred costs 58,738 65,799
Post employment benefits 48,653 42,909
Other 34,786 38,282
---------------------------------
Total Deferred Credits and Other Liabilities 509,499 532,639
---------------------------------
Commitments and Other Matters
- -
---------------------------------
Total Capitalization and Liabilities $ 2,462,874 $ 2,452,935
- ----------------------------------------------------------------------------- ---------------------------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
56
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1999 1998 * 1997 *
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 93,580 $ 94,138 $ 95,360
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 135,094 135,289 133,942
Deferred recoverable fuel costs 1,401 (3,565) 489
Income taxes deferred 9,901 (9,141) (10,064)
Allowance for funds used during construction (1,708) (1,061) (914)
Power contract termination costs - (10,000) -
Electric transmission contract termination costs (26,935) - -
Unbilled revenue (20,083) 10,516 4,823
Post employment benefit/pension costs 4,911 2,798 2,791
Provision for doubtful accounts 7,472 (372) 5,078
Changes in certain current assets and liabilities:
Accounts receivable (8,420) 27,549 3,049
Materials, supplies and fuels 4,818 141 (41)
Taxes accrued 4,095 (1,448) 347
Payroll accrued 712 54 433
Accounts payable 1,767 (7,031) 3,733
Other current assets and liabilities, net 1,299 (817) 6,911
Other, net (14,553) (13,527) 9,246
--------- --------- --------
Total Operating 193,351 223,523 255,183
- ------------------------------------------------------------------------------------- --------- --------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (108,339) (129,286) (84,068)
Nuclear generating plant decommissioning fund (20,736) (20,827) (20,331)
Acquisitions, net of cash (3,152) (30,977) -
Proceeds from sale of Oswego #6 10,920 - -
Other, net (147) 484 (1)
--------- --------- --------
Total Investing (121,454) (180,606) (104,400)
- ------------------------------------------------------------------------------------- --------- --------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock - 586 272
Issuance of long term debt 100,000 99,422 101,900
Short term borrowings, net (46,500) 30,500 6,000
Retirement of long term debt - (55,500) (151,568)
Retirement of preferred stock (10,000) (10,000) (30,000)
Repayment of promissory notes (5,958) (7,790) -
Dividends paid on preferred stock (4,274) (5,031) (6,366)
Dividends paid on common stock (66,262) (69,592) (69,933)
Payment for treasury stock (36,819) (46,433) -
Equal Payment Plan (495) 2,090 3,385
Other, net 176 (51) (369)
--------- --------- --------
Total Financing (70,132) (61,799) (146,679)
--------- --------- --------
Increase (Decrease) in cash and cash equivalents $ 1,765 $ (18,882) $ 4,104
Cash and cash equivalents at beginning of year $ 6,523 $ 25,405 $ 21,301
--------- --------- --------
Cash and cash equivalents at end of year $ 8,288 $ 6,523 $ 25,405
- ------------------------------------------------------------------------------------- --------- --------- --------
</TABLE>
<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars) Year Ended December 31 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 54,059 $ 43,793 $ 50,681
--------- --------- --------
Income taxes paid $ 58,750 $ 75,600 $ 70,500
--------- --------- --------
Transfer from utility plant to regulatory asset, net $ 54,255 $ - $ -
- ------------------------------------------------------------------------------------- --------- --------- --------
</TABLE>
* Reclassified for comparative purposes
The accompanying notes are an integral part of the financial statements.
<PAGE>
57
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF INCOME
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31, 1999 1998* 1997
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $700,194 $687,622 $700,329
Gas 281,555 274,657 336,309
Other 108,699 71,212 -
-------------- -------------- --------------
Total Operating Revenues 1,090,448 1,033,491 1,036,638
Operating Expenses
Fuel Expenses
Fuel for electric generation 49,297 53,954 47,665
Purchased electricity 53,046 27,024 28,347
Gas purchased for resale 148,983 155,497 196,579
Unregulated fuel expenses 91,505 59,490 -
-------------- -------------- --------------
Total Fuel Expenses 342,831 295,965 272,591
Operating Revenues Less Fuel Expenses 747,617 737,526 764,047
Other Operating Expenses
Operations and maintenance excluding fuel expenses 297,890 301,625 315,109
Unregulated operating and maintenance expenses excluding fuel 14,236 13,524 -
Depreciation and amortization 117,289 116,102 116,522
Taxes - local, state and other 112,613 117,973 121,796
Federal income tax 64,454 60,236 65,279
-------------- -------------- --------------
Total Other Operating Expenses 606,482 609,460 618,706
Operating Income 141,135 128,066 145,341
Other (Income) and Deductions
Allowance for other funds used during construction (657) (408) (351)
Federal income tax (1,144) 1,665 (3,704)
Other, net (8,111) (13,370) 3,308
-------------- -------------- --------------
Total Other (Income) and Deductions (9,912) (12,113) (747)
Interest Charges
Long term debt 53,067 43,306 44,615
Other, net 4,543 3,388 6,676
Allowance for borrowed funds used during construction (1,051) (653) (563)
-------------- -------------- --------------
Total Interest Charges 56,559 46,041 50,728
-------------- -------------- --------------
Net Income 94,488 94,138 95,360
-------------- -------------- --------------
Dividends on Preferred Stock 4,083 4,842 5,805
-------------- -------------- --------------
Net Income Applicable to Common Stock $ 90,405 $ 89,296 $ 89,555
-------------- -------------- --------------
</TABLE>
STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31, 1999 1998* 1997*
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at Beginning of Period $ 129,484 $ 109,313 $ 90,540
Add
Net Income 94,488 94,138 95,360
-------------- -------------- --------------
Total 223,972 203,451 185,900
-------------- -------------- --------------
Deduct
Dividends declared on capital stock
Cumulative preferred stock - at required rates 4,083 4,842 5,805
Common Stock 65,594 68,927 69,936
Adjustment Associated with RGS Energy Group Formation 16,243 - -
Other Adjustments 198 198 846
-------------- -------------- --------------
Total 86,118 73,967 76,587
-------------- -------------- --------------
Balance at End of Period $ 137,854 $ 129,484 $ 109,313
-------------- -------------- --------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
* Reclassified for comparative purposes.
<PAGE>
58
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility Plant
Electric $ 2,399,532 $ 2,477,077
Gas 453,634 435,318
Common 107,469 158,038
Nuclear 270,447 256,562
------------ ------------
3,231,082 3,326,995
Less: Accumulated depreciation 1,634,334 1,640,645
Nuclear fuel amortization 239,243 222,830
------------ ------------
1,357,505 1,463,520
Construction work in progress 95,862 98,554
------------ ------------
Net Utility Plant 1,453,367 1,562,074
------------ ------------
Current Assets
Cash and cash equivalents 6,443 6,523
Accounts receivable, net of allowance for doubtful accounts:
1999 - $33,365; 1998 - $26,554 70,388 89,291
Affiliate receivable 13,197 -
Unbilled revenue receivable 55,661 37,922
Materials, supplies and fuels 33,378 43,024
Prepayments 23,294 25,950
Other current assets 145 253
------------ ------------
Total Current Assets 202,506 202,963
------------ ------------
Intangible Assets
Goodwill, net - 14,681
Other Intangible Assets - 6,381
------------ ------------
Total Intangible Assets - 21,062
------------ ------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 220,815 183,502
Nine Mile Two deferred costs 28,206 29,258
Unamortized debt expense 17,984 17,241
Other deferred debits 13,760 18,531
Regulatory assets 466,231 416,320
Other assets - 1,984
------------ ------------
Total Deferred Debits and Other Assets 746,996 666,836
============ ============
Total Assets $ 2,402,869 $ 2,452,935
============ ============
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
59
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 580,070 $ 510,002
- promissory notes 215,930 248,224
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Authorized 50,000,000 shares; 38,885,813 shares
issued at December 31, 1999 and at December 31, 1998 700,268 699,730
Retained earnings 137,854 129,484
----------- -----------
838,122 829,214
Less: Treasury stock at cost (2,942,600 shares at December 31,1999
and 1,507,000 shares at December 31, 1998) 83,252 46,433
----------- -----------
Total Common Shareholders' Equity 754,870 782,781
----------- -----------
Total Capitalization 1,622,870 1,613,007
----------- -----------
Long Term Liabilities
Nuclear waste disposal 91,743 87,566
Uranium enrichment decommissioning 10,911 12,197
Site remediation 22,357 24,157
----------- -----------
125,011 123,920
----------- -----------
Current Liabilities
Long term debt due within one year 33,781 427
Preferred stock redeemable within one year - 10,000
Short term debt - 57,000
Accounts payable 42,263 52,454
Affiliate payable 12,961 -
Dividends payable 17,078 17,937
Equal payment plan 10,529 11,025
Other 33,243 34,526
----------- -----------
Total Current Liabilities 149,855 183,369
----------- -----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 314,683 326,972
Pension costs accrued 48,628 58,677
Kamine deferred costs 58,738 65,799
Post employment benefits 48,653 42,909
Other 34,431 38,282
----------- -----------
Total Deferred Credits and Other Liabilities 505,133 532,639
----------- -----------
Commitments and Other Matters - -
----------- -----------
Total Capitalization and Liabilities $ 2,402,869 $ 2,452,935
- --------------------------------------------------------------------------------- ------------ ------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
60
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1999 1998 * 1997 *
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 94,488 $ 94,138 $ 95,360
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 131,903 135,289 133,942
Deferred recoverable fuel costs 1,401 (3,565) 489
Income taxes deferred 5,889 (9,141) (10,064)
Allowance for funds used during construction (1,708) (1,061) (914)
Power contract termination costs - (10,000) -
Electric transmission contract termination costs (26,935) - -
Unbilled revenue (17,739) 10,516 4,823
Post employment benefit/pension costs 4,911 2,798 2,791
Provision for doubtful accounts 7,066 (372) 5,078
Changes in certain current assets and liabilities:
Accounts receivable (10,248) 27,549 3,049
Materials, supplies and fuels 7,164 141 (41)
Taxes accrued 2,822 (1,448) 347
Payroll accrued (2) 54 433
Accounts payable (3,298) (7,031) 3,733
Other current assets and liabilities, net 1,160 (817) 6,911
Other, net (12,687) (13,527) 9,246
-------- -------- --------
Total Operating 184,187 223,523 255,183
- ------------------------------------------------------------------------- -------- -------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (106,359) (129,286) (84,068)
Nuclear generating plant decommissioning fund (20,736) (20,827) (20,331)
Acquisitions, net of cash - (30,977) -
Proceeds from sale of Oswego #6 10,920 - -
Other, net 467 484 (1)
-------- -------- --------
Total Investing (115,708) (180,606) (104,400)
- ------------------------------------------------------------------------- -------- -------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock - 586 272
Issuance of long term debt 100,000 99,422 101,900
Short term borrowings, net (50,500) 30,500 6,000
Retirement of long term debt - (55,500) (151,568)
Retirement of preferred stock (10,000) (10,000) (30,000)
Repayment of promissory notes (2,449) (7,790) -
Dividends paid on preferred stock (4,274) (5,031) (6,366)
Dividends paid on common stock (66,262) (69,592) (69,933)
Payment for treasury stock (36,819) (46,433) -
Equal payment plan (495) 2,090 3,385
Corporate restructuring to establish holding company (6,824) - -
Other, net 9,064 (51) (369)
-------- -------- --------
Total Financing (68,559) (61,799) (146,679)
-------- -------- --------
(Decrease) Increase in cash and cash equivalents $ (80) $(18,882) $ 4,104
Cash and cash equivalents at beginning of year $ 6,523 $ 25,405 $ 21,301
-------- -------- --------
Cash and cash equivalents at end of year $ 6,443 $ 6,523 $ 25,405
- ------------------------------------------------------------------------- -------- -------- --------
</TABLE>
<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars) Year Ended December 31 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 53,061 $ 43,793 $ 50,681
-------- -------- --------
Income taxes paid $ 58,750 $ 75,600 $ 70,500
-------- -------- --------
Transfer from utility plant to regulatory asset, net $ 54,255 $ - $ -
- ------------------------------------------------------------------------- -------- -------- --------
</TABLE>
* Reclassified for comparative purposes
The accompanying notes are an integral part of the financial statements.
<PAGE>
61
NOTES TO FINANCIAL STATEMENTS
Note 1. SUMMARY OF ACCOUNTING PRINCIPLES
HOLDING COMPANY FORMATION. On August 2, 1999, RG&E was reorganized into a
holding company structure in accordance with the Agreement and Plan of Exchange
between RG&E and RGS Energy. RG&E's common stock was exchanged on a share-for-
share basis for RGS Energy's common stock. RG&E's preferred stock was not
exchanged as part of the share exchange and will continue as shares of RG&E.
GENERAL. The Company supplies regulated electric and gas services wholly
within the State of New York. The unregulated portion of the Company provides
products and services as discussed in Note 4. 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.
BASIS OF PRESENTATION. This is a combined report of RGS Energy and RG&E, a
regulated Electric and Gas subsidiary. The Notes to Financial Statements apply
to both RGS Energy and RG&E. RGS Energy's Consolidated Financial Statements
include the accounts of RGS Energy and its wholly owned subsidiaries, including
RG&E, and two non-utility subsidiaries, RGS Development and Energetix. RGS
Energy's prior period consolidated financial statements have been prepared from
RG&E's prior period consolidated financial statements, except that accounts have
been reclassified to reflect RGS Energy's structure. RG&E's financial
statements reflect the operations of RG&E, Energetix and RGS Development prior
to August 1, 1999. Subsequent to that date only RG&E operations are reflected.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
the accounts of the Company and its wholly-owned subsidiaries RG&E, Energetix,
Energyline and RGS Development. All intercompany balances and transactions have
been eliminated. Energetix's financial statements are consolidated with its
wholly-owned subsidiary Griffith.
Energyline was dissolved in January 2000. It 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.
During the second quarter of 1998, the Company formed a new unregulated
subsidiary, RGS Development Corporation ("RGS Development"). RGS Development
was formed to pursue unregulated business opportunities in the energy
marketplace. Through December 31, 1999, RGS Development operations have not
been material to the Company's results of operation or its financial condition.
<PAGE>
62
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.
GOODWILL AND OTHER INTANGIBLE ASSETS. Goodwill presented on the
consolidated balance sheet, represents the excess of cost over the net tangible
and identifiable intangible assets of acquired businesses. It is stated at cost
and is amortized, principally on a straight-line basis, over the estimated
future periods to be benefited (20 years). On an annual basis the Company
reviews the recoverability of goodwill based primarily upon an analysis of
undiscounted cash flows from the acquired businesses. Other intangible assets
include dealer improvements and are being amortized over varying periods.
Accumulated amortization amounted to $1.7 million and $0.7 million at December
31, 1999 and December 31, 1998 respectively.
ACQUISITIONS. In August 1998, Energetix acquired Griffith Oil, Co., Inc.
("Griffith"), for $31.5 million. Griffith sells oil, propane, electricity,
gasoline, natural gas and other services offered by Energetix to its existing
customers. The acquisition was accounted for as a purchase resulting in
goodwill as reflected on the consolidated financial statements. The principal
tangible assets acquired were vehicles, tanks, pumps, buildings and commodity
inventory.
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.
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 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, 1999. Replacement of minor
items of property is included in maintenance expenses. Costs of depreciable
units of plant retired are eliminated from utility plant accounts, and such
costs, plus removal expenses, less salvage, are charged to the accumulated
depreciation reserve.
Depreciation in the financial statements is provided on a straight-line
basis at rates based on the estimated useful lives of property, which have
resulted in an annual regulated depreciation provision of 3.2% in the three-year
period ended December 31, 1999. The annual depreciation provision of Energetix
is 7.6% and 8.0% for 1999 and 1998 respectively.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and
short-term commercial paper. These investments have original maturity not
<PAGE>
63
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. The Company has no other debt or equity securities.
FINANCIAL/COMMODITY INSTRUMENTS. 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. The Company primarily enters
into forward contracts for natural gas through its gas brokers.
Energetix has entered into electric and natural gas purchase commitments with
numerous suppliers. These commitments support fixed price offerings to retail
electric and gas customers. Griffith is in the business of purchasing various
petroleum-related commodities for resale to its customers. In order to manage
the risk associated with market price fluctuations Griffith enters into various
exchange-traded futures and option contracts and over-the-counter contracts with
third parties. The commodity instruments are designated at the inception as a
hedge where there is a direct relationship to the price risk associated with
Griffith's inventory or future purchases and sales of commodities used in
Griffith's operation. These contracts are closely monitored on a daily basis to
manage the price risk associated with the company's inventory and future product
commitments. All hedge contracts are accounted for under the deferral method
with gains and losses from the hedging activity included in the cost of sales as
inventories are sold or as the hedge transaction occurs. Commodity instruments
not designated as effective hedges are marked to market at the end of the
reporting period, with the resulting gains or losses recognized in cost of
sales. At December 31, 1999 and 1998 Griffith's net deferred gains on open
hedge contracts were immaterial.
RESEARCH AND DEVELOPMENT COSTS. Research and Development costs were
charged to expense as incurred. Expenditures for the years 1999, 1998, and 1997
were $2.9 million, $3.4 million and $4.5 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.
MATERIALS, SUPPLIES AND FUELS. Materials and supplies inventories are
valued at the lower of cost or market using the first-in, first-out method.
Regulated fuel inventories are valued at average cost. Griffith fuel
inventories are valued at the lower of cost or market, using the first-in,
first-out method.
NUCLEAR OUTAGE COSTS. The Company levelizes estimated incremental non-fuel
expenses due to planned refueling outages at its two nuclear power plants. Such
costs are levelized between refueling outages.
STOCK-BASED COMPENSATION. The Company accounts for its stock-based
compensation using the fair value method in accordance with SFAS-123. The
aggregate amount charged to expense as a result of the Company's stock based
compensation plans for the years 1999, 1998 and 1997 approximates $2.2 million,
$5.9 million and $8.2 million respectively. Additional information on the PSOP
is included in Note 8.
<PAGE>
64
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 (EPS) with basic EPS, and also requires
presentation of diluted EPS. Basic 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 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,:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
(thousands of dollars except per share amounts)
Basic EPS:
- ----------
Net Income available to
Common Shareholders $89,497 $89,296 $89,555
Shares 36,665 38,462 38,853
Per-Share Amount $ 2.44 $ 2.32 $ 2.30
======= ======= =======
Diluted EPS:
- ------------
Effect of Dilutive Securities
Stock Option Plan 92 138 56
------- ------- -------
Income available to
Common Shareholders $89,497 $89,296 $89,555
Shares 36,757 38,600 38,909
Per-Share Amount $ 2.44 $ 2.31 $ 2.30
======= ======= =======
</TABLE>
At December 31, 1999 RGS had 177,322 of antidilutive stock options.
COMPREHENSIVE INCOME. There were no items of comprehensive income during
the two-year period ended December 31, 1999; therefore, net income is equivalent
to total comprehensive income.
RECLASSIFICATIONS. Certain amounts in the prior years' financial
statements were reclassified to conform with current year presentation.
<PAGE>
65
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 RGS Energy Group. Amounts for Rochester Gas and Electric are
not materially different.
<TABLE>
<CAPTION>
(Thousands of Dollars)
1999 1998 1997
<S> <C> <C> <C>
Charged (Credited) to operating expense:
Current $72,137 $70,541 $69,812
Deferred (7,884) (4,533) (4,533)
------- ------- -------
Total 64,253 61,385 65,279
Charged (Credited) to other income:
Current (2,614) (1,614) 1,828)
Deferred 5,703 4,562 (3,100)
Deferred investment tax credit (4,223) (2,432) (2,432)
------- ------- -------
Total (1,134) 516 (3,704)
Total federal income tax expense $63,119 $61,901 $61,575
</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)
1999 1998 1997
<S> <C> <C> <C>
Net Income prior to preferred stock
dividend requirements $ 93,580 $ 94,138 $ 95,360
Add: federal income tax expense 63,119 61,901 61,575
-------- -------- --------
Income before federal income tax $156,699 $156,039 $156,935
Computed tax expense at statutory tax rate $ 54,845 $ 54,614 $ 54,927
Increases (decreases) in tax resulting from:
Difference between tax depreciation
and amount deferred 7,103 9,366 10,772
Deferred investment tax credit (4,223) (2,432) (2,432)
Miscellaneous items, net 5,394 353 (1,692)
Total federal income tax expense $ 63,119 $ 61,901 $ 61,575
</TABLE>
A summary of the components of the net deferred tax liability is as follows:
<TABLE>
<CAPTION>
(Thousands of Dollars)
1999 1998 1997
<S> <C> <C> <C>
Nuclear decommissioning $(28,811) $(24,849) $(20,807)
Accelerated depreciation 218,001 214,521 216,704
Deferred investment tax credit 23,023 25,768 27,981
Depreciation previously flowed through 127,448 146,953 157,538
Pension (21,503) (20,161) (23,166)
Other 536 (15,260) (13,281)
-------- -------- --------
Total $318,694 $326,972 $344,969
</TABLE>
<PAGE>
66
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 of RG&E and will be amortized consistent with the depreciation of these
accounts. The net amount of the additional liability at December 31, 1999 and
1998 was $129 million and $148 million, respectively. In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.
Note 3: Pension and Other Postretirement Benefit Plans
The following table shows reconciliations of the domestic pension plan and other
postretirement plan benefits as of December 31, 1999 and 1998:
<TABLE>
<CAPTION>
(Millions)
Pension Benefits Other Benefits
1999 1998 1999 1998
-------- -------- ------- -------
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning of year $ 516.8 $ 499.3 $ 99.0 $ 89.0
Service cost 6.9 7.0 1.1 1.1
Interest cost 32.7 32.9 5.5 6.0
Plan Amendments (0.5) 0.0 0.9 4.3
Actuarial (gain) loss (48.7) 10.7 (22.0) 2.7
Benefits paid (38.3) (32.9) (4.3) (4.1)
------- ------- ------ ------
Benefit obligation at end of year $ 468.9 $ 516.8 $ 80.2 $ 99.0
Change in plan assets
- ---------------------
Fair value of plan assets at beginning of year $ 706.4 $ 638.4 $ 0.0 $ 0.0
Actual return on plan assets 99.5 100.0 0.0 0.0
Company contribution 0.7 0.9 4.3 4.1
Benefits paid (38.3) (32.9) (4.3) (4.1)
------- ------- ------ ------
Fair value of plan assets at end of year $ 768.3 $ 706.4 $ 0.0 $ 0.0
======= ======= ====== ======
Funded status $ 294.5 $ 189.5 $(80.2) $(99.0)
Unrecognized actuarial (gain) loss (352.5) (259.4) (10.8) 11.2
Unrecognized prior service cost 8.6 9.9 12.6 12.6
Unrecognized net transition obligation 0.8 1.3 29.8 32.3
------- ------- ------ ------
Accrued benefit $ (48.6) $ (58.7) $(48.6) $(42.9)
======= ======= ====== ======
Weighted-average assumptions as of December 31
Discount rate 7.50% 6.50% 7.50% 6.50%
Expected return on plan assets 8.50% 8.50%
Rate of compensation increase 5.00% 5.00%
</TABLE>
<TABLE>
<CAPTION>
(Millions)
Pension Benefits Other Benefits
1999 1998 1997 1999 1998 1997
------- ------- ------- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic benefit cost
- ---------------------------------------
Service cost $ 6.9 $ 7.0 $ 6.2 $ 1.1 $ 1.1 $ 0.9
Interest cost 32.7 32.9 33.1 5.5 6.0 5.8
Expected return on plan assets (49.6) (44.8) (39.6) 0.0 0.0 0.0
Unrecognized transition obligation 0.5 0.5 0.5 2.5 2.8 2.9
Amortization of prior service 0.8 0.9 0.9 1.0 0.6 0.6
Recognized actuarial loss (5.5) (4.3) (3.1) 0.0 0.0 0.0
------ ------ ------ ----- ----- -----
Net periodic (benefit) cost $(14.2) $ (7.8) $ (2.0) $10.1 $10.5 $10.2
====== ====== ====== ===== ===== =====
</TABLE>
<PAGE>
67
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits on a defined dollar basis. In 1999, the
health care benefit consists of a contribution of up to $220 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 to the above plans, employees are eligible to contribute to a 401(k)
plan. The Company matches a portion of these contributions. Contributions
charged to income for this plan for 1999, 1998, and 1997 were $2.8 million, $2.5
million, and $2.3 million, respectively.
During 1999, a generation plant was shut down creating a staff reduction of 36
employees, resulting in a net curtailment charge of $4.9 million, including
$8.4 million cost of special termination benefits provided to affected employees
offset by a curtailment gain of $3.5 million. Pursuant to the Company's
settlement agreement, this charge has been deferred.
Note 4. OPERATING SEGMENT FINANCIAL INFORMATION
Under SFAS-131, information pertaining to operating segments is required to
be reported. Upon adoption of SFAS-131, the Company identified three operating
segments, driven by the types of products and services offered and regulatory
environment under which the Company primarily operates. The three segments are
Regulated Electric, Regulated Gas, and Unregulated. The Regulated segments'
financial records are maintained in accordance with generally accepted
accounting principles (GAAP) and Public Service Commission (PSC) accounting
policies. The Unregulated segment's financial records are maintained in
accordance with GAAP.
During the reported periods, substantially all revenues are from United
States sources, and all assets are located in the United States. No single
customer represents more than 10% of the overall Company revenue.
The Regulated Electric segment supplies electric distribution services
wholly within New York State. It produces electricity, and distributes and
sells electricity to retail customers within a franchise area centering about
the City of Rochester. It also sells electricity on a wholesale basis to other
electric utilities throughout the Northeast and to energy marketers who resell
that electricity to retail customers.
The Regulated Gas segment supplies gas services wholly within New York
State. Gas is purchased and distributed to retail customers and distributed on
behalf of other large or aggregated customers who purchase their own gas supply.
The Unregulated segment includes Energetix, RGS Development Corporation and
Energyline. Energetix brings energy products and services to the marketplace
both within and outside of the Company's regulated franchise area. These energy
products and services include electricity, gasoline, natural gas, oil, propane,
and appliance warranty and repair. RGS Development Corporation was formed to
pursue unregulated business opportunities in the energy marketplace.
<PAGE>
68
<TABLE>
<CAPTION>
(thousands of dollars)
Regulated Electric 1999 1998* 1997*
---------- ---------- ----------
<S> <C> <C> <C>
Operating Income $ 120,599 $ 119,937 $ 121,699
Revenues from External Customers $ 698,745 $ 687,100 $ 700,329
Revenues from Intersegment Transactions $ 44,510 $ 8,974 $ -
Interest Revenue $ 10,799 $ 1,694 $ 3,379
Depreciation and Amortization $ 102,946 $ 102,123 $ 103,395
Regulatory Amortization $ 14,287 $ 15,080 $ 23,409
Nuclear Fuel Amortization $ 15,622 $ 18,138 $ 17,419
Interest Expense $ 45,653 $ 36,122 $ 40,583
Operating Income Tax Expense $ 55,752 $ 61,477 $ 61,837
Capital Expenditures, net $ 78,599 $ 96,206 $ 58,522
Total Identifiable Assets $1,925,809 $1,941,622 $1,783,825
Regulated Gas 1999 1998* 1997*
---------- ---------- ----------
Operating Income $ 19,343 $ 10,393 $ 23,642
Revenues from External Customers $ 278,659 $ 274,540 $ 336,309
Revenues from Intersegment Transactions $ 420 $ 594 $ -
Interest Revenue $ 315 $ 424 $ 845
Depreciation and Amortization $ 12,548 $ 12,867 $ 13,127
Regulatory Amortization $ 220 $ 1,461 $ 1,337
Interest Expense $ 9,648 $ 9,030 $ 10,145
Operating Income Tax Expense/(Benefit) $ 8,580 $ (92) $ 3,442
Capital Expenditures, net $ 24,746 $ 28,075 $ 25,546
Total Identifiable Assets $ 438,290 $ 433,029 $ 441,849
Unregulated 1999 1998* 1997*
---------- ---------- ----------
Operating Income/(Loss) $ 543 $ (2,460) $ 618
Revenues from External Customers $ 275,063 $ 81,419 $ -
Interest Revenue $ 398 $ 158 $ 1,016
Depreciation and Amortization $ 2,450 $ 834 $ -
Goodwill Amortization $ 751 $ 278 $ -
Interest Expense $ 2,171 $ 916 $ -
Operating Income Tax Expense/(Benefit) $ (50) $ (1,255) $ 333
Capital Expenditures, net $ 4,994 $ 5,005 $ -
Total Assets $ 90,580 $ 59,946 $ 18,508
</TABLE>
There are intersegment transactions which occur between the Regulated
segments and the Unregulated segment. These transactions are governed by
guidelines established in the Competitive Opportunities Settlement and other PSC
proceedings. The Unregulated segment is charged for the provision of services
and for an allocation of other corporate costs by the Regulated Segments on a
fully loaded cost basis. The Unregulated segment buys electricity from the
Regulated Electric segment at rates established through PSC proceedings. The
Unregulated segment also pays the Regulated segments for electric and gas
distribution services at rates established through PSC proceedings. The total
amount of the revenues identified by operating segment do not equal the total
Company consolidated amounts as shown in the Consolidated Statement of Income.
This is due to the elimination of certain intersegment revenues during
consolidation. Additionally, the operations of RGS Development Corporation and
Energyline are included in Other (Income) and Deductions in the RGS Energy
Group, Inc. Consolidated Statement of Income. The total assets identified by
operating
<PAGE>
69
segment do not equal the total Company consolidated amounts as shown in the
Consolidated Balance Sheet. This is due to the elimination of certain
intersegment transactions during consolidation, and certain common assets
unidentifiable by segment. A reconciliation follows:
<TABLE>
<CAPTION>
(thousands of dollars)
Revenues 1999 1998* 1997
---------- ---------- -----------
<S> <C> <C> <C>
Regulated Electric $ 698,745 $ 687,100 $ 700,329
Regulated Gas 278,659 274,540 336,309
Unregulated 275,063 81,419 -
---------- ---------- -----------
Total $1,252,467 $1,043,059 $1,036,638
Reported on Consolidated Income Statement 1,207,537 1,033,491 1,036,638
---------- ---------- -----------
Difference to reconcile $ 44,930 $ 9,568 -
Intersegment Revenues
Regulated Electric from Unregulated $ 44,510 $ 8,974 -
Regulated Gas from Unregulated $ 420 $ 594 -
---------- ---------- -----------
Total Intersegment $ 44,930 $ 9,568 $ -
Assets 1999 1998
---------- ----------
Regulated Electric $1,925,809 $1,941,622
Regulated Gas 438,290 433,029
Unregulated 90,580 59,946
Cash and Cash Equivalents,
Regulated Operations 6,443 5,375
Unamortized Debt Expense 17,984 17,241
Other 367 266
Intersegment eliminations (16,599) (4,544)
---------- ----------
Total Assets $2,462,874 $2,452,935
</TABLE>
* Some items have been restated for comparative purposes.
<PAGE>
70
Note 5. JOINTLY-OWNED FACILITIES
The following table sets forth the jointly-owned electric generating
facility in which the Company is participating. Nine Mile Point Nuclear Plant
Unit No. 2 has been constructed and is operated by Niagara Mohawk Power
Corporation. Each participant must provide its own financing for any additions
to the facility. The Company's share of direct expenses associated with this
unit is included in the appropriate operating expenses in the Consolidated
Statement of Income. Various modifications will be made throughout the life of
this plant to increase operating efficiency or reliability, and to satisfy
changing environmental and safety regulations.
<TABLE>
<CAPTION>
Nine Mile Point
Nuclear Unit No.2
-----------------
<S> <C>
Net megawatt capability (summer) 1,128
RG&E's share - megawatts 158
- percent 14
Year of completion 1988
(Millions of Dollars)
at December 31, 1999
---------------------
Plant In Service Balance $882.4
Accumulated Provision For Depreciation $504.8
Plant Under Construction $ 1.5
</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>
71
Note 6. LONG-TERM DEBT
FIRST MORTGAGE BONDS OF RG&E
<TABLE>
<CAPTION>
(Thousands of Dollars)
Principal Amount
December 31
% Series Due 1999 1998
- --- -------- ------------- -------- --------
<S> <C> <C> <C> <C>
9 3/8 PP Apr. 1, 2021 $100,000 $100,000
8 1/4 QQ/(a)/ Mar. 15, 2002 100,000 100,000
6.35 RR/(b)/ May 15, 2032 10,500 10,500
6.50 SS/(b)/ May 15, 2032 50,000 50,000
7.00 /(a)(c)/ Jan. 14, 2000 30,000 30,000
7.15 /(a)(c)/ Feb. 10, 2003 39,000 39,000
7.13 /(a)(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 /(a)(c)/ July 30, 2003 40,000 40,000
7.45 /(c)/ July 30, 2023 40,000 40,000
5.84 /(a)(d)/ Dec. 22, 2008 50,000 50,000
7.60 /(a)(d)/ Oct. 27, 2009 100,000 -
-------- --------
$610,500 $510,500
Net bond discount (430) (498)
Less: Due within one year 30,000 -
-------- --------
Total $580,070 $510,002
======== ========
</TABLE>
/(a)/ The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7.13%, 6.375%, 5.84%
and 7.60% medium-term notes described below are generally not redeemable
prior to maturity.
/(b)/ The 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 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.
/(c)/ In 1993 RG&E 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.
/(d)/ RG&E issued $50 million in 1998 and $100 million in 1999 under a medium-
term note program entitled "First Mortgage Bonds, Designated Secured
Medium-Term Notes, Series B" 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 RG&E (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.
<PAGE>
72
On December 1, 1998 RG&E redeemed all its outstanding First Mortgage 8 1/8%
Bonds, due December 1, 2028, Series OO.
Sinking fund requirements and bond maturities for the next five years are:
<TABLE>
<CAPTION>
(Thousands of Dollars)
2000 2001 2002 2003 2004
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
7% Series $ 30,000
Series QQ $100,000
7.15% Series $ 39,000
7.13% Series 1,000
6.375% Series 40,000
-------- -------- -------- -------- --------
$ 30,000 $ - $100,000 $ 80,000 $ -
</TABLE>
PROMISSORY NOTES AND OTHER
<TABLE>
<CAPTION>
(Thousands of Dollars)
December 31
Issued Due 1999 1998
- ------ --- -------- --------
<S> <C> <C> <C>
September 2, 1998/(e)/ September 1, 2033 $ 25,500 $ 25,500
August 19, 1997/(f)/ August 1, 2032 101,900 101,900
December 1, 1998/(g)/ March 31, 2014 92,311 94,761
August 3, 1998/(h)/ August 3, 2005 - 24,563
Other Long Term Debt of Subsidiaries - 1,500
-------- --------
Total $219,711 $248,224
Less: RG&E Due within one year 3,781 -
-------- --------
Total RG&E $215,930 $248,224
August 3, 1998/(h)/ August 3, 2005 21,054 -
Other Long Term Debt of Subsidiaries 2,273 -
-------- --------
Total $239,257 $248,224
Less: RGS Due within one year 3,862 -
-------- --------
Total RGS $235,395 $248,224
</TABLE>
/(e)/ The $25.5 million Promissory Note was issued in connection with NYSERDA's
5.95% Pollution Control Revenue Bonds (Rochester Gas and Electric
Corporation Project), 1998 Series A. Payment of the principal of, and
interest on the Series A Bonds is guaranteed under a Bond Insurance
Policy by MBIA Insurance Corporation.
/(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, 1999 and December 31, 1998, the Multi-mode Revenue Bonds bore
interest at the weekly rate and the average annual interest rate for all
three series was 3.09% and 3.21%, respectively.
<PAGE>
73
RG&E is obligated to make payments of principal, premium and interest on each
Promissory Note which corresponds to the payments of principal, premium, if any,
and interest on certain Pollution Control Revenue Bonds issued by NYSERDA as
described above.
(g) The Promissory Note was issued in connection with the Kamine Global
Settlement Agreement, which resolved all litigation, released all claims
and terminated all electricity purchase obligations under a power purchase
agreement. The Promissory Note is secured by a mortgage, the lien for which
is subordinate to the lien of the First Mortgage. The liability represents
the present value at December 31, 1999 and December 31, 1998 of future
obligations under the Note assuming a discount rate of 7.5 percent. This
balance will decrease as payments are made over the term of the Note. At
December 31, 1999 and December 31, 1998 RG&E made payments totaling $9.6
million and $7.8 million, respectively. The Company expects to make future
payments totaling $10.6 million per year.
(h) The $24.6 million Promissory Note was issued in connection with the
acquisition of Griffith Oil, Inc. by Energetix and is secured by a pledge
of the stock of Griffith Oil, Inc. RGS has made a financial guarantee on
behalf of Energetix which obligates RGS in the event of a default by
Energetix in payments under the Note. Beginning in 1998 payments of
principal are made in seven annual installments and interest for the first
three years accrues at the rate of 7% per year and thereafter at rates
varying between 7%-8 1/2% per year.
Based on an estimated borrowing rate at year-end 1999 of 7.60% for long-
term debt with similar terms and average maturities (11 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $829 million at December 31, 1999.
Based on an estimated borrowing rate at year-end 1998 of 5.84% for long-
term debt with similar terms and average maturities (12 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $844 million at December 31, 1998.
Note 7. PREFERRED AND PREFERENCE STOCK OF RG&E
<TABLE>
<CAPTION>
Par Shares Shares
Type by Order of Seniority Value Authorized Outstanding
- ------------------------------ ----- ---------- ------------
<S> <C> <C> <C>
Preferred Stock (cumulative) $100 2,000,000 720,000*
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.
<PAGE>
74
A. PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION:
<TABLE>
<CAPTION>
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1999 1999 1998 (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
------- ------- -------
Total 470,000 $47,000 $47,000
======= ======= =======
</TABLE>
# May be redeemed at any time at the option of the Company on 30 days minimum
notice, plus accrued dividends in all cases.
B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
<TABLE>
<CAPTION>
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1999 1999 1998 (per share)
- ------------- ------------ ------------------ ---------- -------- -----------------
<S> <C> <C> <C> <C> <C>
7.65 U - $ - $10,000 Not applicable
6.60 V 250,000 25,000 25,000 Not Before 3/1/04+
------- ------- -------
Total 250,000 $25,000 $35,000
Less: Due within one year - - 10,000
------- ------- -------
Total 250,000 $25,000 $25,000
======= ======= =======
</TABLE>
+ Thereafter at $100.00
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 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 1999 of 6.40% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (8.25 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $26 million at December 31,
1999.
Based on an estimated dividend rate at year-end 1998 of 4.75% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (6.61 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $39 million at December 31,
1998.
<PAGE>
75
Note 8. COMMON STOCK AND STOCK OPTIONS
REPURCHASE PLAN
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. A total of 1,435,600 and 1,507,000 of the shares were purchased in 1999
and 1998 respectively.
COMMON STOCK
At December 31, 1999, there were 50,000,000 shares of $5 par value Common
Stock authorized, of which 35,943,213 were outstanding. No shares of Common
Stock are reserved for warrants, conversions, or other rights. There were
1,954,767 shares of Common Stock reserved and unissued for employees under the
1996 Performance Stock Option Plan, as further described below.
<TABLE>
<CAPTION>
Shares Amount
Outstanding (Thousands)
------------ -----------
<S> <C> <C>
Balance, December 31, 1997 38,862,347 $699,031
Shares Issued through Stock Plans 23,466 586
Additional Paid in Capital 99
Repurchase Plan (1,507,000) (46,433)
Decrease (Increase) in Capital
Stock Expense 14
----------- ---------
Balance, December 31, 1998 37,378,813 $653,297
Shares Issued through Stock Plans - -
RG&E Shares (38,885,813)
RGS Shares 38,885,813
Additional Paid in Capital 486
Repurchase Plan (1,435,600) (36,819)
Decrease (Increase) in Capital
Stock Expense 52
----------- ---------
Balance, December 31, 1999 35,943,213 $617,016
</TABLE>
PERFORMANCE STOCK OPTION PLAN
The Company has 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 of the
Board of Directors (the Committee). The Committee grants 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 1999, the Board of Directors granted 177,320 options at an exercise price
of $29.689 per share. These options are exercisable for a period of 10 years,
and vest three years after the options are granted. The average grant date
option fair value and exercise prices are $3.17 and $29.689 respectively. None
of these options were exercised during 1999, and are included in the summary of
stock option activity presented on the following page.
<PAGE>
76
In 1998, the Board of Directors granted 27,984 options at an exercise price
of $33.9065 per share and 15,157 options at an exercise price of $31.0005 per
share. These options are vested at 25% when the stock closes at $35 per share,
50% at $40 per share, 75% at $45 per share and 100% at $50 per share. These
options are exercisable for a period of 10 years. The weighted average grant
date option fair value is $5.56.
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 at $25
per share, 50% at $30 per share, 75% at $35 per share and 100% at $40 per share.
These options are exercisable for a period of 10 years. The weighted average
grant date option fair value is $4.60.
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.
The weighted average contractual remaining life for all options issued is 7.02
years and exercise prices range from $19.063 to $33.907 at December 31, 1999.
Since the Company adopted SFAS-123, compensation expense associated with
the options granted is reflected in 1999, 1998 and 1997 net income. The
compensation expense recorded was $485,300 in 1999, $239,800 in 1998 and
$2,399,000 in 1997. The compensation expense was calculated using the shorter
of the anticipated or actual vesting period. In applying SFAS-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 from 4.61% to 5.16% for 1999, 5.54% to 5.65% for 1998,
and 6.39% to 6.56% for 1997, expected dividend yield of 0% for 1999, 1998 and
1997 and expected stock volatility of 19% for 1999 and 17% for 1998 and 1997.
A summary of the Company's stock option activity is presented below:
<TABLE>
<CAPTION>
Weighted
Average
Options Exercise 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
Options granted 1998 43,141 $32.886
Options exercised (23,466) $19.063
---------
Outstanding at 12/31/98 563,651 $20.627
Vested at 12/31/98 369,256 $19.449
Available for future grant at 12/31/98 1,402,000
Options granted in 1999 177,322 $29.689
Options forfeited (10,884) $19.063
---------
Outstanding at 12/31/99 730,089 $ 22.85
Vested at 12/31/99 369,256 $ 19.45
Available for future grant at 12/31/99 1,224,678
</TABLE>
<PAGE>
77
Note 9. SHORT-TERM DEBT
On December 31, 1999, RGS had total short-term debt outstanding of $10.5
million, comprised entirely of Energetix's short-term debt. At December 31,
1998, RG&E and Energetix had short-term debt outstanding of $50.5 million and
$6.5 million, respectively. The weighted average interest rate on short-term
debt outstanding at year-end 1999 for Energetix was 6.74%. The weighted average
interest rates for borrowings during the year for RG&E and Energetix were 5.44%
and 5.95%, respectively. The weighted average interest rates on short-term debt
borrowed during 1998 were 5.51% and 6.31%, respectively.
RG&E's $90 million revolving credit agreement terminates on December 31,
2001. Griffith Oil Co., Inc., a subsidiary of Energetix, has a $15 million
revolving credit agreement terminating July 31, 2002. Borrowings under this
agreement are secured by personal property of Griffith. Energetix has made a
financial guarantee on behalf of Griffith that obligates Energetix in the event
of a Griffith default.
RG&E's Charter provides that it may not issue unsecured debt if immediately
after such issuance the total amount of unsecured debt outstanding would exceed
15 percent of its 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, 1999, RG&E would be able to incur approximately $114.5
million of additional unsecured debt under this provision. RG&E 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,
RG&E has created a subordinate mortgage which secures borrowings under its
revolving credit agreement that might otherwise be restricted by this provision
of its Charter. In addition, RG&E has a Loan and Security Agreement to provide
for borrowings 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 RG&E's accounts receivable.
Note 10. COMMITMENTS AND OTHER MATTERS
REGULATORY ASSETS
With PSC approval RG&E 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, Accounting for the Effects of
Certain Types of Regulation. These deferred costs are shown as Regulatory
Assets on the Company's and RG&E's Balance Sheets. Such cost deferral is
appropriate under traditional regulated cost-of-service rate setting, where all
prudently incurred costs are recovered through rates. In a purely competitive
pricing environment, such costs might not have been incurred and could not have
been deferred. Accordingly, if RG&E was no longer allowed to defer some or a
portion of these costs under SFAS-71, these assets would be adjusted
accordingly, up to and including the entire amount being written off.
Below is a summarization of the Regulatory Assets as of December 31, 1999
and 1998:
<PAGE>
78
<TABLE>
<CAPTION>
Millions of Dollars
1999 1998
------ ------
<S> <C> <C>
Kamine Settlement $187.5 $192.8
Income Taxes 129.5 147.6
Oswego Plant Sale 78.6 -
Deferred Environmental SIR costs 20.5 20.9
Uranium Enrichment Decommissioning Deferral 13.9 15.1
Deferred Fuel-Gas 9.3 10.7
Labor Day 1998 Storm Costs 8.5 7.2
Other, net 18.4 22.0
------ ------
Total - Regulatory Assets $466.2 $416.3
====== ======
</TABLE>
- - Kamine Settlement: This amount results from a settlement resolving all
litigation, releasing all claims and terminating all electricity purchase
obligations under a power purchase agreement. Recovery will be at the rate
of approximately $10.5 million per year through June 30, 2002 and is
subject to modification, thereafter.
- - 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, which varies
from one to thirty years, when the effect of the past deductions reverses in
future years.
- - Oswego Plant Sale: This amount results from the sale of RG&E's interest in
the Oswego generation facility including closing costs and the Buyer's
assumption of RG&E's obligations under a transmission services agreement.
RG&E is currently amortizing this amount at the rate of approximately $6.5
million per year.
- - Deferred Environmental Site Investigation/Remediation Costs: These costs
represent RG&E's share of the estimated costs to investigate and perform
certain remediation activities at both RG&E-owned and non-owned sites with
which it may be associated. RG&E has recorded a regulatory asset representing
the remediation obligations to be recovered from ratepayers, subject to the
terms of the Competitive Opportunities Settlement.
- - Uranium Enrichment Decommissioning Deferral: The Energy Policy Act of 1992
requires utilities to contribute such amounts based on the amount of uranium
enriched by the United States Department of Energy (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.
- - 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.
- - Labor Day 1998 Storm Costs: These costs result from a 1998 Labor Day storm.
Under the Competitive Opportunities Settlement, RG&E is entitled to defer,
for later recovery in rates, certain costs, including those caused by
"catastrophic events", when any single event results in costs exceeding
$2.5 million. RG&E filed a petition with the PSC notifying them of the
deferral of these storm costs.
<PAGE>
79
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. An example
includes 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, 1999 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 the amount could be significant. Strandable assets, if any, could be
written down for impairment of recovery based on SFAS-121, which requires write-
down of long-lived assets whenever events or circumstances occur which indicate
that the carrying amount of a long-lived asset may not be recoverable.
In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on RG&E for full service, leaving RG&E
with surplus pipeline and storage capacity, as well as natural gas supplies
under contract. RG&E has been restructuring its transportation, storage and
supply portfolio to reduce its potential exposure to strandable assets.
Regulatory developments referred to under "Gas Cost Recovery" 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, 1999 RG&E believes that its regulatory assets are probable
of recovery. The Settlement in the Competitive Opportunities Proceeding does
not impair the opportunity of RG&E to recover its investment in these assets.
However, the PSC issued an Opinion and Order Instituting Further Inquiry on
March 20, 1998 to address issues surrounding nuclear generation. The initial
meeting in this Inquiry was held in January 1999. RG&E is unable to determine
when this proceeding may conclude (see PSC Proceeding on Nuclear Generation
under Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations). The ultimate determination in this proceeding or any
proceeding to consider RG&E's proposed purchase of nuclear plants as discussed
under "Nuclear-Related Matters" could have an impact on strandable assets and
the recovery of nuclear costs.
CAPITAL EXPENDITURES
The Company's 2000 construction expenditures program is currently estimated
at $154 million for RGS of which $151 million is for RG&E. These amounts
exclude provision for the proposed purchase of the Nine Mile nuclear generating
facilities (see below). The Company has entered into certain commitments for
purchase of materials and equipment in connection with that program.
NUCLEAR-RELATED MATTERS
PROPOSED PURCHASE OF NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and
New York State Electric and Gas (NYSEG) announced their intention to sell their
interests in the Nine Mile Two nuclear plant to AmerGen Energy Company,
L.L.C.(AmerGen), a joint venture of PECO Energy of Philadelphia and British
Energy. Niagara Mohawk owns 41 percent and NYSEG owns 18 percent of Nine Mile
Two. The financial terms of the transaction include purchase prices to be paid
to Niagara Mohawk of $63.6 million and to NYSEG of $27.9 million.
RG&E's 14 percent interest in Nine Mile Two was not included in the current
proposal. As an original part owner, RG&E generally had three options: the first
option was to retain its ownership interest on the same basis that it does now;
the second option was to sell its 14 percent interest in Nine Mile Two to
AmerGen
<PAGE>
80
on substantially the same terms as Niagara Mohawk and NYSEG; and the third
option was to exercise its right-of-first-refusal and buy the Niagara Mohawk
and/or NYSEG interests on terms at least as favorable as those offered by
AmerGen. Niagara Mohawk took the position that an exercise of the right to buy
its interest in Nine Mile Two must necessarily include matching the terms of the
agreement between AmerGen and Niagara Mohawk ($72 million) to buy the Nine Mile
Point One Nuclear Plant (Nine Mile One), which is 100 percent owned by Niagara
Mohawk.
On December 22, 1999, RG&E announced it had exercised its legal right-of-
first-refusal to acquire a controlling interest in Nine Mile Two and to acquire
the interests of Niagara Mohawk in Nine Mile One. As a result of the regulatory
process discussed below, the status of RG&E's acquisition pursuant to its right-
of-first-refusal is in question.
RG&E has contracted with Entergy Nuclear Nine Mile, L.L.C. (Entergy Nine
Mile) to operate and maintain the plants upon RG&E's acquisition under its
right-of-first-refusal. Under the terms of an operating agreement, Entergy Nine
Mile will be responsible for operating the plants, for certain operating costs
and risks during a transition period and most operating costs and risks
thereafter. RG&E will be responsible for substantial operating costs and risks
during the transition period and these costs and risks will be significantly
reduced after the transition period. RG&E will pay Entergy Nine Mile a fixed
price (periodically adjusted by certain appropriate price indices) per kilowatt-
hour of power actually generated and delivered to RG&E. The contract with
Entergy Nine Mile expires in September 2009.
RG&E intends to finance its acquisition through the issuance of long-term
debt. Depending on when transfer of ownership takes place, RG&E currently
expects to pay between $180 million and $210 million, including the cost of fuel
at the plants. The transfer of ownership of the plants to RG&E and transfer of
operation of the plants to Entergy Nine Mile will require State and federal
regulatory approvals, including the PSC, the Nuclear Regulatory Commission (NRC)
and the FERC.
In this transaction, RG&E will continue to own the rights to its original
approximately 160 megawatts of electric generating capacity from Nine Mile Two
and acquire the rights to approximately an additional 670 megawatts of capacity
from that plant. At the conclusion of its purchase, RG&E would own 73% of Nine
Mile Two. The Long Island Lighting Company, which is wholly-owned by the Long
Island Power Authority, and Central Hudson Gas & Electric Corporation are the
other non-operating owners of Nine Mile Two and will retain their interests in
the plant. RG&E would also acquire the entire capacity from Nine Mile One,
about 615 megawatts.
Niagara Mohawk and NYSEG will purchase the power produced by their previous
ownership shares in the Nine Mile Point plants from RG&E under long-term
contracts that run for a period of three to five years. These terms are the
same as those agreed to by AmerGen. After that period of time, available power
is expected to be sold into the wholesale energy market.
Under the terms of a decommissioning agreement, Entergy Nuclear, Inc. will
be responsible for decommissioning the plants at a fixed price after they are
both taken out of service. For Nine Mile One, Niagara Mohawk, as the former sole
owner, will contribute the entire present cost of decommissioning to a fund.
For Nine Mile Two, Niagara Mohawk and NYSEG will contribute payments
proportionate to their former ownership interests.
At December 31, 1999 the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $376 million.
<PAGE>
81
On August 30, 1999 the PSC began a proceeding to review the proposed sale
of the Nine Mile Point nuclear facilities by Niagara Mohawk and NYSEG to AmerGen
to determine if the sale would be in the public interest. RG&E has intervened in
that proceeding. In early January 2000, at the request of PSC Trial Staff, that
proceeding was suspended to give the interested parties time for settlement
negotiations. In late January 2000, the PSC Trial Staff expressed its intention
to move to dismiss the proceeding since it believes that the sale to AmerGen, as
filed, is not consistent with the public interest standard in Public Service Law
Section 70; Trial Staff said that it intends to immediately explore, in
conjunction with the utilities and interested parties, other scenarios for
future ownership and operation of the Nine Mile nuclear plants; and Trial Staff
proposed that the parties dispense with formal evidentiary hearings in this
proceeding. AmerGen has asked that the Judge reject Staff's request to dispense
with formal evidentiary hearings and instead set a schedule for testimony and
hearings in this proceeding.
A separate proceeding to consider RG&E's acquisition of the Nine Mile
nuclear facilities has not yet been commenced. At this time, RG&E is uncertain
what the outcome of the PSC regulatory process will be but expects that it will
continue for some time. RG&E intends to continue to pursue all of its
alternatives and evaluate any modifications to the current proposed transaction
and any new proposed transaction.
DECOMMISSIONING TRUST. RG&E 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, RG&E has collected
decommissioning costs of approximately $160.6 million through December 31, 1999
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 RG&E'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. RG&E'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, RG&E has contributed
$128.0 million to this fund and, including realized and unrealized investment
returns, the fund has a balance of $220.8 million as of December 31, 1999. 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, 1999 is $32.6 million. NRC regulations require biennial reports on the
status of Decommissioning Trust funds and RG&E reported to the NRC that both the
Ginna and Nine Mile Two decommissioning trusts exceed the NRC minimum funding
amounts required as of December 31, 1999.
The NRC has issued a policy statement relating to industry restructuring which
addresses, in part, the prospects of joint and several liability of co-owners
for nuclear decommissioning costs, such as co-owners of Nine Mile Two. The NRC
recognizes that co-owners generally divide costs and output from their
facilities by using a contractually-defined, pro rata share standard. The NRC
has implicitly accepted this practice in the past and believes that it should
continue to be the operative practice, but reserves the right, in highly unusual
situations where adequate protection of public health and safety would be
<PAGE>
82
compromised if such action were not taken, to consider imposing joint and
several liability on co-owners when one or more co-owners have defaulted.
On March 20, 1998 the PSC issued an Opinion and Order Instituting Further
Inquiry. In December 1998 the PSC issued a Notice of Collaborative Conference
to further examine the future treatment of nuclear generation. The initial
collaborative conference in this proceeding was held in January, 1999. RG&E's
potentially strandable assets in nuclear plant could be impacted by the outcome
of this proceeding. The parties in this proceeding developed a collaborative,
non-binding interim report entitled "Nuclear Generation and the Competitive
Electric Market" which was issued in July 1999. RG&E is actively involved in
this proceeding which is continuing. RG&E is unable to determine when this
proceeding may conclude.
The Staff of the Financial Accounting Standards Board is studying the
recognition, measurement and classification of certain liabilities related to
the closure or removal of long lived assets. This could affect the accounting
for the decommissioning costs of RG&E's nuclear generating stations. 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. On June 12,
1998, 16 electric utilities from across the country, including RG&E, filed
multi-count complaints against the United States government in the United States
District Court for the Southern District of New York. The suits challenge the
constitutionality of a $2.25 billion retroactive assessment imposed by the
federal government on domestic nuclear power companies to pay for the clean up
of the federal government's three uranium enrichment plants. Those plants are
located at Oak Ridge, Tennessee, Paducah, Kentucky, and Portsmouth, Ohio. The
Oak Ridge plant went into operation in 1945, and the other two plants began
operation during the 1950s. The Government has moved to dismiss the utilities'
complaints. A decision on the Government's motion is expected in early 2000.
The assessments for Ginna and RG&E's share of Nine Mile Two are estimated to
total $22.1 million, excluding inflation and interest. Installments aggregating
approximately $12.9 million have been paid through 1999. A liability has been
recognized on the financial statements along with a corresponding regulatory
asset. For the two facilities RG&E's liability at December 31, 1999 is $12.6
million ($10.9 million as a long-term liability and $1.7 million as a current
liability). RG&E is recovering these costs in rates.
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. In
December 1996 the DOE notified RG&E that the DOE would not start accepting Ginna
spent fuel in 1998. 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 RG&E in June 1985. RG&E estimates the fees, including accrued interest, owed
to the DOE to be $91.7 million at December 31, 1999. RG&E is allowed by the PSC
to recover these costs in rates. The estimated fees are classified as a long-
term liability and interest is accrued at the current three-month Treasury bill
<PAGE>
83
rate, adjusted quarterly. The Nuclear Waste Act also requires the DOE to
provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a
charge of approximately one mill ($.001) per KWH of nuclear energy generated and
sold. This charge (approximately $4.3 million per year) is currently being
collected from customers and paid to the DOE pursuant to PSC authorization.
RG&E 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
RG&E'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. In November 1998 RG&E completed
installation of seven high-capacity spent fuel racks in the Ginna spent fuel
pool. This will allow interim storage capacity of all spent fuel discharged
from the Ginna Plant through the end of its Operating License in the year 2009.
ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local laws and regulations
dealing with air and water quality and other environmental matters.
Environmental matters may expose the Company to potential liabilities which, in
certain instances, may be imposed without regard to fault or historical
activities which were lawful at the time they occurred. The Company continually
monitors its activities in order to determine the impact of its activities on
the environment and to ensure compliance with various environmental
requirements. RGS has recorded a total liability of approximately $23.7 million
in connection with Site Investigation and/or Remediation (SIR) efforts where
disposal of certain waste products may have occurred. Estimates of the SIR
costs for each of these sites range from preliminary to highly refined. RG&E
and Energetix expect to pay these SIR costs over the next ten years. These
estimates could change materially, based on facts and circumstances derived from
site investigations, changes in required remedial action, changes in technology
relating to remedial alternatives and changes to current laws and regulations.
Liability may be joint and several for certain of these sites. There may be
additional costs with respect to these and possibly other sites, the materiality
of which is not presently determinable.
RG&E-OWNED ELECTRIC AND GAS WASTE SITE ACTIVITIES. RG&E is conducting
proactive SIR efforts at seven RG&E-owned sites where past waste handling and
disposal may have occurred. Remediation activities at five of these sites are
in various stages of planning or completion and RG&E is conducting a program to
restore the other two sites. RG&E has recorded a liability of approximately
$21.9 million for SIR efforts at the seven Company-owned sites in the Rochester,
NY area.
SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as
a potentially responsible party at eight sites not owned by it and has recorded
estimated liabilities of approximately $.5 million in connection with SIR
efforts at these sites. RG&E has signed orders on consent for five of these
sites.
GRIFFITH FACILITIES. RGS's subsidiary, Energetix, acquired Griffith Oil,
Inc. in 1998. A review and audit was conducted of all Griffith facilities by a
nationally recognized engineering firm as part of the due diligence acquisition
process by Energetix. As a result of this review 35 sites were identified
which are currently undergoing evaluation and/or remediation. Using historical
New York State Department of Environmental Conservation (NYSDEC) remedial
actions as a guide, Energetix estimates the accrual of aggregate cleanup costs
discounted at 6.8% over the future five-year period for all active sites
approximates $1.3 million.
<PAGE>
84
NEW YORK INITIATIVES. The New York Attorney General sent a letter to certain
New York utilities in October, 1999 requesting historic information regarding
certain upgrades, modifications and maintenance activities at coal fired power
plants under their control. RG&E received such a letter requesting data
covering a period back to 1977 for its Russell and (the now closed) Beebee
Stations. The letter suggests that those upgrades, modifications and
improvements may have required permission from the NYSDEC prior to their
occurrence. RG&E and other letter recipients are involved in discussions with
the Attorney General's office to clarify the scope and timing of the request and
establish the role of the Attorney General and the DEC in the information
gathering effort and any subsequent potential action. On January 13, 2000, RG&E
received a formal request from the NYSDEC pursuant to its investigatory powers
under the New York Environmental Conservation Law which seeks essentially the
same documents covered by the Attorney General's letter. Commencing January 21,
2000, RG&E is providing responsive documents to the State through NYSDEC. RG&E
cannot assess the potential impact of this initiative in these early stages of
its development.
On October 14, 1999, the Governor of New York publicly proposed
modifications of the state's oxides of nitrogen (NOx) and sulfur dioxide (SO2)
control programs. The Governor's proposal suggests extending the existing NOx
control program under which RG&E's Russell Station operates to a year-round
program (it is currently in effect only for the five month ozone season). The
proposal suggests such a change should take effect in October, 2003. In
addition, the Governor is also proposing that there be a targeted reduction of
some 50% in SO2 emissions below the existing Acid Rain Phase II limits that are
required under the 1990 Clean Air Act Amendments. The proposal suggests a
phase-in period from 2003 through 2007. Since this is only a proposed rule
change and subject to review, comment and modification, no estimate of the
future economic impact on RG&E of a change in the rules can be made at this time
because the nature of the change is uncertain.
GAS COST RECOVERY
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued
a gas restructuring policy statement ("Gas Policy Statement") announcing its
conclusion that, among other things, the most effective way to establish a
competitive gas supply market is for gas distribution utilities to cease selling
gas. The PSC established a transition process in which it plans to address
three groups of issues: (1) individual gas utility plans to implement the PSC's
vision of the market; (2) key generic issues to be dealt with through
collaboration among gas utilities, marketers, pipelines and other stakeholders,
and (3) coordination of issues that are common to both the gas and the electric
industries. The PSC has encouraged settlement negotiations with each gas
utility pertaining to the transition to a fully competitive gas market. RG&E,
the PSC Staff and other interested parties have been participating in settlement
discussions in response to the specific requirements of the Policy Statement.
GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of the
PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement above),
RG&E had commenced negotiations with the PSC staff and other parties to develop
a comprehensive multi-year settlement of various issues, including rates and the
structure of RG&E's gas business. Because the negotiation of a comprehensive
settlement was not anticipated to conclude until mid-1999, the parties to the
negotiations agreed to an Interim Settlement, effective November 1998 through
June 1999, that dealt with such issues as rates, transportation and storage
capacity costs, assignment of capacity, and retail access. Significant features
of the Interim Settlement include a freeze on base rates at the current levels
(which were fixed at July 1994 levels), the imputation of $11.9 million in
<PAGE>
85
revenues from the remarketing of capacity and a limit on RG&E's exposure to
costs associated with the migration of customers from RG&E to marketers for
sales service.
Discussions following the expiration of the Interim Settlement resulted in a
September 14, 1999, filing to address issues pertaining to the cost of upstream
capacity and other matters pertaining to restructuring pursuant to the PSC's
Policy Statement. The proposal calls for: (1) a continued reduction in capacity
costs of $11.9 million, comprised of $10.2 million relating to upstream capacity
release transactions for the period September 1, 1999 through August 31, 2000
and $1.7 million from the expiration of a Texas Eastern capacity contract; (2) a
report to PSC staff, within 60 days of approval of the proposal, of the progress
RG&E has made to reduce its upstream capacity costs; (3) a resumption of the
multi-year settlement discussions calling for RG&E to make a public filing
addressing the rate and restructuring issues addressed in the PSC's Policy
Statement within 120 days of approval of the proposal; and (4) RG&E continuing
to work on retail access program improvements. The proposal was subsequently
approved by the PSC and RG&E began implementation of its proposal in the fourth
quarter of 1999. RG&E has proceeded to implement the proposal as approved. As
required, the report on upstream capacity costs was submitted on November 29,
1999, under trade secret status. The public filing addressing the rate and
restructuring issues was made on January 28, 2000. This filing is intended to
provide the basis for negotiations with the PSC and other interested parties on
RG&E's proposal to implement a fully competitive marketplace for natural gas.
Settlement negotiations pertaining to RG&E's gas rate and restructuring proposal
will begin as early as 30 days after the filing pursuant to the Policy
Statement.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution
companies to assign to marketers the pipeline and storage capacity held by RG&E
to serve their customers. In its Gas Policy Statement issued in November 1998,
the PSC ordered that the mandatory assignment of capacity, permitted by the
March 1996 Order, be terminated effective April 1, 1999. According to the Gas
Policy Statement, however, the utilities are to be afforded a reasonable
opportunity to recover resulting strandable costs, if any. On March 24, 1999,
the PSC issued an Order Concerning Assignment of Capacity for all gas utilities
in the State of New York, generally requiring the removal of restrictions on
customer migration from utility sales service to service from marketers. RG&E
has complied with the PSC's directives.
LITIGATION
SPENT NUCLEAR FUEL LITIGATION. The federal Nuclear Waste Act obligated
DOE to accept for disposal spent nuclear fuel (SNF) from utilities' powerplants
by January 31, 1998 (statutory deadline). Since the mid-1980s RG&E and other
nuclear plant owners and operators have paid substantial fees to DOE to fund
that obligation (Nuclear Waste Fund). That the DOE would not meet its
obligation was evident well prior to 1998; DOE admitted as much as the statutory
deadline approached.
DOE's failure to meet its statutory deadline has given rise to numerous
lawsuits in both the U.S. Court of Appeals for the District of Columbia and the
U.S. Court of Federal Claims.
Although the DOE has been found to have breached its obligations, it is not
possible to predict the outcome of these cases, the future course of the DOE
obligation or the resolution of the spent nuclear fuel movement and storage
concern that underlies it. Similarly, the ultimate outcome of nuclear waste
legislation in Congress, that could address these and related concerns, is
uncertain. The court rulings on the DOE's default in meeting its obligation to
remove SNF by the statutory deadline, and on its contractual liability therefor,
have been promising. The current court rulings appear to have prompted greater
<PAGE>
86
DOE effort to complete site investigations at its Yucca Mountain, NV, site for
SNF disposal and to focus greater Congressional attention on the
inappropriateness of continuing to house SNF around the nation at short-term SNF
facilities of nuclear powerplants. These developments have not yet led,
however, either to a firm schedule for DOE's movement of SNF from plant
facilities to a permanent repository or to the authorization of plant owners and
operators to withhold their Nuclear Waste Fund payments to DOE until that
schedule is established. RG&E and other nuclear utilities continue to work
toward those objectives in judicial, legislative and administrative initiatives.
OTHER MATTERS
OTHER STATEMENT OF INCOME ITEMS. The change in RGS's and RG&E's Other
Income and Deductions, Other-net reflects mainly the recognition of income in
1998 due to the elimination of certain pension and other post-employment benefit
deferred credits and Nine Mile Two operating and maintenance expenses in
accordance with the Competitive Opportunities Settlement. This variance in Other
Income and Deductions, Other-net was partially offset by non-cash carrying
charges of $8.6 million related to deferral of Kamine (Allegany Station)
facility costs in 1999 for the regulated business. These carrying charges,
which are primarily associated with the deferred recovery of costs associated
with the Kamine settlement, were allowed under the Competitive Opportunities and
Kamine settlements. In addition, expenses associated with RG&E management
performance awards were down $4.4 million in 1999 compared with 1998.
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July
1997, the Financial Accounting Standards Board's 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.
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.
RG&E'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
RG&E 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 RG&E's distribution access tariff.
The Settlement also states that "the Parties intend that the provisions of this
Settlement will allow RG&E 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 RG&E shall have a reasonable opportunity beyond July 1,
2002 to recover all such costs". The fixed portion of the non-nuclear generation
to-go costs sometime 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. These costs have been below
prevailing market prices. RG&E's net investment at December 31, 1999 in nuclear
generating assets is $634.3 million and in non-nuclear generating assets is
$58.4 million. (See
<PAGE>
87
"Proposed Purchase of Nuclear Plants" for information concerning RG&E's proposed
acquisition of the interests in Nine Mile Two owned by two co-owners and Nine
Mile One owned by Niagara Mohawk.)
LEASE AGREEMENTS. RG&E and Energetix lease a total of 15 properties for
administrative offices, operating activities and vehicles. The total lease
obligations charged to operations was $5.4 million, $4.8 million and $4.2
million in 1999, 1998 and 1997, respectively, including $1.5 million in 1999 and
$.5 million in 1998 for Energetix. RG&E's estimated annual lease obligations
for the years 2000-2004 will be $4.0 million, $2.5 million, $2.5 million, $2.7
million and $2.7 million, respectively. Energetix estimated annual lease
obligations for the years 2000-2004 will be $1.3 million, $1.0 million, $.6
million, $.4 million and $.2 million, respectively. Commitments under capital
leases after 2004 are not significant.
PURCHASE COMMITMENTS. The Company has entered into electric and natural gas
purchase commitments with numerous suppliers. Certain of these commitments
support fixed price offerings to retail electric and gas customers.
<PAGE>
88
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>
RGS
- ---
December 31, 1999 $325,788 $34,103 $23,681 $23,681 $ .65 $ .65
September 30, 1999/1/ 279,853 29,528 15,964 15,964 .44 .44
June 30, 1999 275,805 27,219 13,706 13,706 .37 .37
March 31, 1999/1/ 326,091 50,189 36,146 36,146 .97 .97
RG&E
- ----
December 31, 1999 $249,204 $33,737 $24,696 $23,394 - -
September 30, 1999/1/ 239,348 29,990 17,708 17,159 - -
June 30, 1999 275,805 27,219 14,822 13,706 - -
March 31, 1999/1/ 326,091 50,189 37,262 36,146 - -
December 31, 1998/1/ $286,507 $22,173 $15,015 $14,088 $ .37 $ .37
September 30, 1998/1/ 253,750 35,128 25,213 23,908 .62 .62
June 30, 1998/1/ 210,724 22,620 15,655 14,350 .37 .37
March 31, 1998/1/ 282,510 48,145 38,255 36,950 .95 .95
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
</TABLE>
/1/ Reclassified for comparative purposes.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
<PAGE>
89
PART III
Information required by Items 10-14 with respect to RG&E has been omitted
pursuant to General Instruction J(2)(c). Information required by Items 10-14
with respect to RGS are described below.
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 RGS's Annual Meeting of Shareholders
to be held on April 26, 2000, 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 RGS's
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 for RGS 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 RGS'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 heading "Security Ownership of Management" in RGS'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 RGS'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,
RGS will file with the Commission a definitive proxy statement pursuant to
Regulation 14A which involves the election of directors. RGS's definitive proxy
statement dated March 15, 2000 will be filed with the Securities and Exchange
Commission prior to April 30, 1999. The information required in Items 10 through
13 under the headings set forth above is incorporated 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
26, 2000 is not deemed to be filed as part of this Report.
<PAGE>
90
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.
RGS Consolidated Statement of Income for each of the three years ended
December 31, 1999.
RGS Consolidated Statement of Retained Earnings for each of the three
years ended December 31, 1999.
RGS Consolidated Balance sheet at December 31, 1999 and 1998.
RGS Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1999.
RG&E Consolidated Statement of Income for each of the three years
ended December 31, 1999.
RG&E Consolidated Statement of Retained Earnings for each of the three
years ended December 31, 1999.
RG&E Consolidated Balance sheet at December 31, 1999 and 1998.
RG&E Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1999.
RGS and RG&E Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1999.
Schedule II - Valuation and Qualifying Accounts of RGS and RG&E.
(a) 3. Exhibits - See List of Exhibits.
(b) Reports on Form 8-K
RGS and RG&E:
A report was filed on December 22, 1999 in connection with RG&E
exercising its right of first refusal to acquire a controlling
interest in the Nine Mile Point 2 Nuclear Plant and to buy the Nine
Mile Point 1 nuclear Plant.
<PAGE>
91
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 1997 - RG&E
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
FOR THE YEAR ENDED DECEMBER 31, 1998 - RG&E
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 $26,926 $ 861 $ 507 $1,740 $26,554
Materials and supplies
obsolescence 3,200 1,010 2,190
FOR THE YEAR ENDED DECEMBER 31, 1999
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>
RG&E Reserves for:
Uncollectible accounts $26,554 $7,080 $ 269 $33,365
Materials and supplies
obsolescence 2,190 636 1,554
RGS Reserves for:
Uncollectible accounts $26,554 $7,080 $ 406 $ 14 $34,026
Materials and supplies
obsolescence 2,190 636 1,554
</TABLE>
Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve. The 1998 reserves for uncollectibles
includes Energetix. The total amount written off directly to expense in 1997
was $12,912, in 1998 was $11,838 and in 1999 was $11,852. In 1997, the amounts
charged to other accounts represent a true-up of writeoff amounts during the
implementation of a new customer information system ($3.0 million) and the
forgiveness of late payment amounts which had previously been reflected as
revenue ($1.3 million). In 1998, the amount charged to other accounts reflects
consolidation of Energetix/Griffith reserve for uncollectibles ($0.3 million)
and forgiveness of late payments ($0.2 million). The deductions in 1998
represent true-ups of the estimated reserve required for uncollectibles. In
1999, the amount charged to other accounts reflects consolidation of
Energetix/Griffith reserve for uncollectibles.
<PAGE>
92
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 RG&E, as amended to date. (Filed as Exhibit 3-3 in
February 1999 on Form 10-K for the year ended December 31, 1998,
SEC File No. 1-672)
Exhibit 3-4* Certificate of Incorporation of RGS Energy Group, Inc. filed with
the Secretary of State of the State of New York on November 5,
1998. (Filed as Exhibit 3-1 in Registration Statement No. 333-
67427)
Exhibit 3-5* By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in
Registration Statement No. 333-67427)
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 RG&E, as amended to date. (Filed as Exhibit 3-3 in
February 1999 on Form 10-K for the year ended December 31, 1998,
SEC File No. 1-672)
Exhibit 4-4* Certificate of Incorporation of RGS Energy Group, Inc. filed with
the Secretary of State of the State of New York on November 5,
1998. (Filed as Exhibit 3-1 in Registration Statement No.
333-67427)
Exhibit 4-5* By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in
Registration Statement No. 333-67427)
Exhibit 4-6* 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)
Exhibit 4-7* 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 RG&E,
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)
<PAGE>
93
Exhibit 10-2* Letter amendment modifying Basic Agreement dated September 22,
1975 among RG&E, 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)
Exhibit 10-3* Agreement dated February 5, 1980 between RG&E 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)
Exhibit 10-4* Agreement dated March 9, 1990 between RG&E 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 10-5* 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)
Exhibit 10-6* (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)
Exhibit 10-7* (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)
Exhibit 10-8* (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 10-9* (A) RGS Energy Group, Inc. Executive Incentive Plan, Restatement
of January 1, 1999. (Filed as Exhibit 10 in November 1999 on
Form 10-Q for the quarter ended September 30, 1999, SEC File
No. 0-30338)
Exhibit 10-10* (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)
Exhibit 10-11* (A) Agreement dated January 1, 1999 between RG&E and Thomas S.
Richards, Chairman of the Board, President and Chief
Executive Officer. (Filed as Exhibit 10-13 in February 1999
on Form 10-K for the year ended December 31, 1998, SEC File
No. 1-672)
Exhibit 10-12* (A) Agreement dated January 1, 1999 between RG&E and Paul C.
Wilkens, Senior Vice President, Generation. (Filed as
Exhibit 10-14 in February 1999 on Form 10-K for the year
ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-13* (A) Agreement dated January 1, 1999 between RG&E and J. Burt
Stokes, Senior Vice President, Corporate Services and Chief
Financial Officer. (Filed as Exhibit 10-15 in February 1999
on Form 10-K for the year ended December 31, 1998, SEC File
No. 1-672)
Exhibit 10-14* (A) Agreement dated January 26, 1999 between RG&E and Michael J.
Bovalino, President, Energetix, Inc. (Filed as Exhibit 10-16
in February 1999 on Form 10-K for the year ended December
31, 1998, SEC File No. 1-672)
<PAGE>
94
Exhibit 10-15* 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 as Exhibit 10-18 in February 1998 on
Form 10-K for the year ended December 31, 1997, SEC File
No. 1-672)
Exhibit 10-16* (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 10-17* (A) Agreement, dated January 18, 1999, between RG&E and Michael
T. Tomaino, Senior Vice President and General Counsel.
(Filed as Exhibit 10-19 in February 1999 on Form 10-K for
the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-18* Global Settlement Agreement as amended October 29, 1998
between RG&E, General Electric Capital Corporation and
Kamine/Besicorp Allegany L.P. and other Kamine affiliates.
(Filed as Exhibit 10-21 in February 1999 on Form 10-K for
the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 21 Subsidiaries of RGS
Exhibit 23 Consent of PricewaterhouseCoopers LLP, independent
accountants
Exhibit 27-1 Financial Data Schedule of RGS, pursuant to Item 601(c) of
Regulation S-K.
Exhibit 27-2 Financial Data Schedule of RG&E, pursuant to Item 601(c) of
Regulation S-K.
* Incorporated by reference.
(A) Denotes executive compensation plans and arrangements.
RG&E 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>
95
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, each Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
By: /S/ THOMAS S. RICHARDS
------------------------------
(Thomas S. Richards)
Chairman, President and
Chief Executive Officer
DATE: February 11, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of each
Registrant in the capacities and on the dates indicated.
SIGNATURE TITLE (RGS and RG&E DATE
- --------- ------ ----
unless otherwise noted)
Principal Executive Officer:
/S/ THOMAS S. RICHARDS Chairman, President and February 11, 2000
- ---------------------------- Chief Executive Officer
(Thomas S. Richards)
Principal Financial Officer:
/S/ J. B. STOKES Senior Vice President and February 11, 2000
- ---------------------------- Chief Financial Officer of
(J. Burt Stokes) RGS; Senior Vice President,
Corporate Services and Chief
Financial Officer of RG&E
Principal Accounting Officer:
/S/ WILLIAM J. REDDY Controller of RGS; February 11, 2000
- ---------------------------- Vice President and
(William J. Reddy) Controller of RG&E
<PAGE>
96
SIGNATURE TITLE DATE
- --------- ----- ----
Directors of RGS and RG&E:
/S/ ANGELO J. CHIARELLA Director February 11, 2000
- ---------------------------
(Angelo J. Chiarella)
/S/ ALLAN E. DUGAN Director February 11, 2000
- ---------------------------
(Allan E. Dugan)
/S/ MARK B. GRIER Director February 11, 2000
- ----------------------------
(Mark B. Grier)
/S/ SUSAN R. HOLLIDAY Director February 11, 2000
- ---------------------------
(Susan R. Holliday)
/S/ JAY T. HOLMES Director February 11, 2000
- ---------------------------
(Jay T. Holmes)
/S/ G. JEAN HOWARD Director February 11, 2000
- ----------------------------
(G. Jean Howard)
/S/ SAMUEL T. HUBBARD,JR Director February 11, 2000
- ---------------------------
(Samuel T. Hubbard,Jr.)
/S/CLEVE L. KILLINGSWORTH,JR. Director February 11, 2000
- ----------------------------
(Cleve L. Killingsworth,Jr.)
/S/ ROGER W. KOBER Director February 11, 2000
- ---------------------------
(Roger W. Kober)
/S/ CORNELIUS J. MURPHY Director February 11, 2000
- ---------------------------
(Cornelius J. Murphy)
/S/ CHARLES I. PLOSSER Director February 11, 2000
- ---------------------------
(Charles I. Plosser)
/S/ THOMAS S. RICHARDS Director February 11, 2000
- ---------------------------
(Thomas S. Richards)
<PAGE>
Exhibit 21
RGS ENERGY GROUP, INC AND SUBSIDIARY COMPANIES
(Name changed from RG&E HOLDINGS, INC.)
SUBSIDIARIES OF THE REGISTRANT
Name of Company State of Organization
- --------------- ---------------------
Rochester Gas and Electric Corporation New York
(formerly Rochester Railway and Light
Company)
Energetix, Inc. (Note 1) New York
Note 1: Energetix owns Griffith Oil Company. Griffith Oil Company owns Stanbury
Propane, Clark Oil and Bobbett Oil
<PAGE>
Exhibit 23
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statement on Form S-3 (File No. 33-49805)
of Rochester Gas and Electric Corporation and in the Registration Statement on
Form S-8 (File No. 333-22139) of RGS Energy Group, Inc. of our report dated
February 1, 2000 appearing in Item 8A of the Rochester Gas and Electric
Corporation Annual Report on Form 10-K for the year ended December 31, 1999 and
of our report dated February 1, 2000 appearing in Item 8A of the RGS Energy
Group, Inc. Annual Report on Form 10-K for the year ended December 31, 1999.
PricewaterhouseCoopers LLP (Signed)
Rochester, New York
February 11, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSOLIDATED
BALANCE SHEET, CONSOLIDATED STATEMENT OF INCOME AND CONSOLIDATED STATEMENT OF
CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<CIK> 0001073353
<NAME> RGS ENERGY GROUP, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,473,395
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 219,837
<TOTAL-DEFERRED-CHARGES> 748,410
<OTHER-ASSETS> 21,232
<TOTAL-ASSETS> 2,462,874
<COMMON> 389
<CAPITAL-SURPLUS-PAID-IN> 616,627
<RETAINED-EARNINGS> 153,186
<TOTAL-COMMON-STOCKHOLDERS-EQ> 770,202
25,000
47,000
<LONG-TERM-DEBT-NET> 580,070
<SHORT-TERM-NOTES> 10,500
<LONG-TERM-NOTES-PAYABLE> 235,395
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 37,643
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 757,064
<TOT-CAPITALIZATION-AND-LIAB> 2,462,874
<GROSS-OPERATING-REVENUE> 1,207,537
<INCOME-TAX-EXPENSE> 63,119
<OTHER-OPERATING-EXPENSES> 1,002,245
<TOTAL-OPERATING-EXPENSES> 1,066,498
<OPERATING-INCOME-LOSS> 141,039
<OTHER-INCOME-NET> 8,835
<INCOME-BEFORE-INTEREST-EXPEN> 151,008
<TOTAL-INTEREST-EXPENSE> 57,428
<NET-INCOME> 93,580
4,083
<EARNINGS-AVAILABLE-FOR-COMM> 89,497
<COMMON-STOCK-DIVIDENDS> 65,594
<TOTAL-INTEREST-ON-BONDS> 46,376<F1>
<CASH-FLOW-OPERATIONS> 193,351
<EPS-BASIC> 2.44
<EPS-DILUTED> 2.44
<FN>
<F1>PRINCIPAL AMOUNT OF BONDS OUTSTANDING AT DECEMBER 31 MULTIPLIED BY ANNUAL
INTEREST RATES FOR EACH ISSUE.
</FN>
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALANCE
SHEET, STATEMENT OF INCOME AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000084557
<NAME> ROCHESTER GAS AND ELECTRIC CORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,453,367
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 202,506
<TOTAL-DEFERRED-CHARGES> 746,996
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,402,869
<COMMON> 194,429
<CAPITAL-SURPLUS-PAID-IN> 422,587
<RETAINED-EARNINGS> 137,854
<TOTAL-COMMON-STOCKHOLDERS-EQ> 754,870
25,000
47,000
<LONG-TERM-DEBT-NET> 580,070
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 215,930
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 33,781
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 746,218
<TOT-CAPITALIZATION-AND-LIAB> 2,402,869
<GROSS-OPERATING-REVENUE> 1,090,448
<INCOME-TAX-EXPENSE> 63,310
<OTHER-OPERATING-EXPENSES> 884,859
<TOTAL-OPERATING-EXPENSES> 949,313
<OPERATING-INCOME-LOSS> 141,135
<OTHER-INCOME-NET> 8,768
<INCOME-BEFORE-INTEREST-EXPEN> 151,047
<TOTAL-INTEREST-EXPENSE> 56,559
<NET-INCOME> 94,488
4,083
<EARNINGS-AVAILABLE-FOR-COMM> 90,405
<COMMON-STOCK-DIVIDENDS> 65,594
<TOTAL-INTEREST-ON-BONDS> 46,376<F1>
<CASH-FLOW-OPERATIONS> 184,187
<EPS-BASIC> 0
<EPS-DILUTED> 0
<FN>
<F1>PRINCIPAL AMOUNT OF BONDS OUTSTANDING AT DECEMBER 31 MULTIPLIED BY ANNUAL
INTEREST RATES FOR EACH ISSUE.
</FN>
</TABLE>
