ML17309A639
| ML17309A639 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point, Ginna  |
| Issue date: | 08/18/1998 |
| From: | Bird R NIXON, HARGRAVE, DEVANS & DOYLE, ROCHESTER GAS & ELECTRIC CORP. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9808200296 | |
| Download: ML17309A639 (87) | |
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REGULAJ. RY INFORMATION DISTRIBUTI O'YSTEM (RIDS)
A ACCESSION NBR:9808200296 DOC.DATE: 98/08/18 NOTARIZED: NO DOCKET FACIL:50-244 Robert Emmet Ginna Nuclear Plant, Unit 1, Rochester G 05000244 50-410 Nine Mile Point Nuclear Station, Unit 2, Niagara Moha 05000410 AUTH.NAME AUTHOR AFFILIATION BIRD,R.8'. Nixon, Hargrave, Devans S Doyle BIRD; R J
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RECIP.NAME Rochester Gas & Electric Corp.
RECIPIENT AFFILIATION Ae+~
Records Management Branch (Document Control Desk)
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SUBJECT:
Forwards complete copies of RG&E Securities 6 Exchange Commission Form 10-K for 1997.Form 10-K for FY97 was incomplete due to error in photocopying.
DISTRIBUTION CODE: M004D COPIES RECEIVED:LTR ENCL SIZE:
TITLE: 50.71(b) Annual Financial Report E NOTES:License Exp date in accordance with 10CFR2,2.109(9/19/72). 05000244 RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD1-1 LA 1 1 PD1-1 PD 1 1 VISSING,G 1 1 HOOD,D 1 1 INTERNA FIL CE 1 1 NRR/DRPM 1 1 RPM/PGEB 1 1 EXTERNAL: NRC PDR 1 1 U
N NOTE TO ALL "RIDS" RECIPIENTS:
PLEASE HELP US TO REDUCE WASTE. TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD) ON EXTENSION 415-2083 TOTAL NUMBER OF COPIES REQUIRED: LTTR 8 ENCL 8
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¹ixon. Hargrave, Devans Bc Doyle LLp Attorneys and Counselors at, Lave ONK KKYCORP PLAZA CLINTON SC}UARE CITYPLACE ALBANY, NKW YORK 12207 POST OFFICE BOX 1051 155 ASYLUM STREET (518) 427.2650 HARTFORD, CONNECTICUT 05105 ROCHESTER, NEW YORK 14603-1051 (560) 275 5620 (710) 2BS 1000 1500 MAIN PLACK TOWER BUFFALO. NEW YORK 14202 FAX: (710) 2SS-1500 457 MADISON AVENUE (716) SSS e100 NKW YORK, NKW YORK 10022 WRITER'S DIRECT DIALNUMBER: PI 6) 262 IBSS (212) Q40 5000 QQO STEWART AVENUE OARDEN CITY, NKW YORK 11550 SUITE 700 ONE THOMAS CIRCLE (516) S52 7500 August 18, 1998 WASHINOTON D.C. 20005 (202) 457 5500 United States Nuclear RegulatoryCommission ATTN.: Document Control Desk Washington, D.C. 20555 RE: Docket Nos. 50-410 and 50-244 Facility Operating Licens'es Nos. NPF-69 and DPR-18
Dear Commissioners:
On July 31, 1998 we submitted for filing the application of Rochester Gas and Electric Corporation ("RG&E") for the consent of the Commission to the transfer of control over RG&E as the holder of licenses for facilities as to which the Commission has issued Licenses Nos. NPF-69 and DPR-18. The transactions to which the application pertains are planned in connection with RG&E's proposed restructuring to adopt a holding company form of corporate organization as authorized by the New York State Public Service Commission.
Due to an error in photocopying, Exhibit D to RG&E's application, a copy of RG&E's Annual Report to the Securities and Exchange Commission on Form 10-K for the fiscal year ended December 31, 1997, was incomplete. Enclosed please find complete copies of RG&E's Form 10-K for 1997.
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Nixon, Hargrave, Devans S Doyle m United States Nuclear Regulatory Commission August 18, 1998 Page 2 Ifyou should have any questions about this application, please contact counsel for RG&E in this matter, Ernest J. Ierardi, at (716) 263-1526, or at the law firm of Nixon, Hargrave, Devans
& Doyle LLP at the above mailing address.
Respectfully submitted,
",Ro ert J. Bird, Jr; NIXON, HARGRAVE, DEVANS & DOYLE LLP Attorneys for Rochester Gas and Electric Corporation CC: Mr. Hubert J. Miller Regional Administrator United States Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406-1415 Mr. Guy Vissing Mail Stop 14B2 Project Directorate I-1 Division of Reactor Projects I/II Office of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D.C. 20555 R203 913.1
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EXHIBITD l9808200296
SECUR1T1ES 2') EXCH2QIGE COMMlSS1ON'ASHTNGTON, D.C. 20549 IP(ECE)QFO ZOHM 10-K FEB 30 1998 Nixon, rlal piavs, ucvhll> oL poy@~
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1'934 For the fiscal year ended: December 31, 1997 OR
] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (6) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 1-672-2 Rochester Gas and Electric Corporation (Exact name of registrant as specified in its charter)
New York 16-0612110 (State or other jurisdiction of (I. R. S. Employer incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649 (Address of principal execu"ive o=='.ces) (Zip Code)
Registrant's telephone numbe , including a"ea code: (716) 546-2700 Securities registered pu suant to Sec"ion 12(b) of the Act:
Name of each exchange Title of each class on which registered Common Stock, $5 par value=" New York Stock Exchange
SECURITIES -2') EXCEGQTQE COMMISSION NASHINGTON, D.C. 20549 FORM 10"K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE.-ACT OF 1934 Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, $ 100 par value 4% Series F 4.95't Series K 4.10% Series H 4.55% Series M 4.75% Series I 4.10t Series J 405 Indicate by check mark if disclosure of delinquent filers pursuant to Item of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in def'nitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Fo"v 10-K. [x)
On January 1, 1998 the aggregate market value of the voting stock held by nonaff'iates of the Registrar;" was, approximately $ 1,312,000,000.
'ndicate by check mark whether the Registrant (1) has filed all reports requ'red to be f'led 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 Reg'strant was required to file such repo" s), and (2) has been subject to such fing requirements for the past 90 days.
s x NO Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest prac"'cable date.
Common Stock, $5 par value. a" Jar;uary '. '998. 38,862,347.
Documents Incor orated b Reference Part o. Form 10-K Definitive proxy statement in connection with annual meeting of shareholders to be held April 15, 1998.
ROCHESTER GAS AND ELECTRIC CORPORATION Information Required on Form 10-K ltern Number Description Paae Part I Item 1 Business 1'2 Item 2 Properties Item 3 Legal Proceedings 14 Item 4 Submission of Matters to a Vote of Security Holders 14 Ztem 4A Executive Officers of the Registrant 14 Part IZ I
Item 5 Market for the Registrant's Common Equity aire Related Stockholder Matters 16 Item 6 Selected Financial Data 17 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 20 Item 8 Financial Statements and Supplementary Data 34 Item 9 Changes in and Disagreements with Accountants on Account'ng and F'nancia'isclosure 68 pavo T.~
Item 10 Directors and Executive Of icers of the Registrant 69 Ztem 11 Executive Compensation 69 tern 12 Security Ownersh'p of Certa'.. Beneficial Owners and Managemen" 69
'tern '3 Certain Rela 'onsh'ps and Re atec .ra..sactions 69 Part ZV Item 14 Exhibits, F'inane'a S"a:e."..en" Schedules and Reports on Form 8-K 70 Signatures 75
PART I Item 1. BUSINESS The following are discussed under the general heading of "Business".
Reference is made to the various other Items as applicable.
CAPTION PAGE General 1.
Regulatory Matters 2 Electric Operations 3, Gas Operations 5 Fuel Supply 6 Financing and Capital Requirements Program 7 Environmental Quality Control 8 Research and Development 9 Operating Statistics 10 GENERAL Incorporated in 1904 in the State of New York, the Company Supplies electric and gas service wholly within that State. It produces and distributes electricity and distributes gas in parts of nine counties centering about the City of Rochester. At December 31, 1997 the Company had 1,958 employees.
The Company's service area has a population of approximately one million and is well diversified among residen" ial, commercial and industrial consumers.
In addition to the City of Rochester, which is the third largest city and a major industrial center in New York State, it includes a substantial suburban area with commercial growth and a large and prosperous farming area. A majority of the industrial firms in the Company's service area manufacture consumer goods. Many of the Company's industrial customers are nationally known, such as Xerox Corporation, Eastman Kodak Company, General Motors Corporation, and Bausch & Lomb Incorporated.
The business of the Company is seasonal. With respect to electricity, winter peak loads are attained due to spacehea 'ng sales and shorter daylight hours and summe peak loads are reached due to the use of air-conditioning and other cooling equipment. With respect to gas, the greatest sales occur in the winter months due to spaceheating usage. The Company also plans to enter into unregulated businesses that wi,ll bring energy products and services to the marketplace both within and outside the Company's franchise area.
In each of the communities in which it renders service, the Company, with minor exceptions, holds the necessary municipal franchises, none of which contains burdensome restrictions. The franchises are non-exclusive, and are either unlimited as to time or run for terms of years. The Company anticipates renewing franchises as they expire on a basis substantially the same as at present.
Information concerning revenues, operating profits and identifiable assets for significant industry segments is set forth in Note 4 of the Notes to the Company's financial statements under Item 8. Information relating to the principal classes of service from which electric and gas revenues are derived and other operating data are included herein under "Operating Statistics". A discussion of the causes of significant changes in revenues is presented in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of
Operations. Percentages of the Company's operating revenues derived from electric and gas operations for each of the last three years are as follows:
1997 1996 1995 Electric 67.6% 67.1% 71.1%
Gas 32.4% 32.9% 28.
100 0+o '00 9tI'00.0%
0+o The Company is operating in a rapidly changing competi'tive marketplace for electric and gas service. This competitive environment includes a federal and State trend toward deregulation and promotion of open-market choices for consumers. In November 1997 the New York State Public Service Commission (PSC) approved a Settlement Agreement among the Company, PSC staff and other parties which sets the framework for the introduction and development of open competition in the electric energy marketplace in New York State over the next five years.
Regarding the Company's electric business, in early 1996 the Federal Fnergy Regulatory Commission (FERC) issued new rules to facilitate the development of competitive wholesale markets. In 1997 the Company together with other New York utilities filed with FERC a "Comprehensive Proposal to Restructure the New York Wholesale Market" and requested approval of their'.restructuring plan in early 1998. At the State level, the PSC endorsed a fundamental'estructuring of the electric utility industry in the State in its "Competitive Opportunities Proceeding". The Company's Competitive Opportunities Settlement in 1997, including its proposed retail access program called "Energy Choice", allows for a phase-in to open electric markets while lowering customer prices and es-ablishing an opportun'y for competitive returns on shareholder investments.
Although the Company is jus" beginn'ng to receive applications from potential cor,",petitors under its dis" ibution tariff, i- expects more to be filed, particularly from companies with strong retailing and customer service capabi"ies and wholesale power tracing exper 'se.
Nith the unbundling of services as directed by FERC Order 636, primary esponsibility for reliable natural gas has shifted from interstate pipeline companies to local distribution companies, such as the Company. All gas customers have a choice of suppliers s'nce November 1996, subject to certain 1997 the Company commenced negotia=ions with the sta 'f phase-in limitations through 1998 for loss of gas commodity sales. Some of these companies a e large, nationay known, publiclv he d markete"*s or suppliers.
the PSC and other parties with the objective of developing a m'ti -year settlement of issues perta'n'ng to the Company's gas business.
In See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 'under the heading "Competition" for further information on the Competitive Opportunities Settlement and the competitive challenges the Company faces in its electric and gas business and how it is responding to those challenges.
REGULATORY MATTERS The Company is subject to pSC regulation of rates, service, and sale of securities, among other matters. The Company is also regulated by the FERC on a limited basis, in the areas of interstate sales and exchanges of electricity, intrastate sales of electricity for resale, transmission wheeling service for other utilities, and licensing of hydroelectric facilities. As a licensee and operator of nuclear facilities, the Company is also subject to regulation by the
3 Nuclear Regulatory Commission (NRC) . The impact of regulation is discussed throughout this report.
See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Rates and Regulatory Matters" for summaries of recent PSC rate decisions and its flexible pricing tariff for major industrial and commercial electric customers.
ELECTRIC OPERATIONS Electric System. The total net generating capacity of the Company's electric system is 1,239,000 Kw. In addition the Company purchases 120,000 Kw of firm power under contract and 35,000 Kw of non-contractual peaking power from the New York power Authority, 150,000 Kw of a 1,000,000 Kw pumped storage plant owned by the Power Authority in Schoharie County, New York, 50,000 Kw of firm power from the Power Authority's 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York and 20,000 Kw of firm power from Hydro-Quebec purchased through the Power Authority. The Company's net peak load of 1,425,000 Kw occurred on August 15, 1995.
The percentages of electricity actually generated and purchased for the years 1993-1997 are as follows:
1997 1996 1995 1994 ' 1993 Sources of Generated Energy:
Nuclear 61.6t 49.4t 52.8t 55 3't
~ 57.6t Foss' 20.0 18.2 18.6 18.1 19.5 Hydro and Other 2 7 3.0 2.0 2.7 2.6 Total Generated Net 84. 3 70.6 73.4 76.1 79.7 Purchased 15.7 29.4 26.6 23.9 20.3 To"al Electric Energy 100.0% 300.00 300.0% 100.0% 100.00 The Company, six other New York utilities and the Power Authority are members of the New York Power Pool (NYPP) . The p imary purposes of the NYPP are to coordinate inter-utility sales of bulk power, long range planning of generation and transmission fac'ities, and 'nter-utility operating and emergency procedu es in order to better assure reliable, adequate and economic electric service throughout the State. For a d'scussion on potential changes to the NYPP, see Item 7, Management's Discuss'on anc Analysis of F'nancial Condition and Results of Operations - " FERC Open Transm'ssion Orders apd Company filings".
Generating Facilities. The Company's five major generating facilities are two nuclear units, the Ginna Nuclear Plant (Ginna Plant) and the Company's 14t share of Nine Mile Point Nuclear Plant Unit No. 2 (Nine Mile Two), and three fossil fuel generating stations, the Russell and Beebee Stations and the Company's 24t share of Oswego Unit Six. In terms of capacity these comprise 39t, 13t, 20t, 7t and 15t, respectively, of the Company's current electric generating system.
On December 1, 1997 Niagara Mohawk Power Corporation (Niagara) announced a plan to sell its fossil-fueled and hydroelectric generating stations by auction in 1998. This plan was agreed to as part of Niagara's Power Choice Settlement currently under review by the PSC. The Company intends to include its 24 percent share of Niagara's Oswego Steam Station Unit 6 (Oswego 6) for sale as part of Niagara's auction. Any gains or losses realized by the Company from the sale of its share of Oswego 6 would be treated in accordance with the terms of the Settlement under the Competitive Opportunities Proceeding. The Company would
include its share of Oswego 6 in these efforts as well. The gross and net book cost of the Company's share of Oswego 6 as of December 31, 1997 are $ 99 million and $ 58 million, respectively On January 21, 1998 the Company decided to retire Beebee Station by mid-1999. Factors such as the plant's age, location in an area no longer consistent with the surrounding development, lack of a rail/coal delivery system and more stringent clean air regulations made the plant uneconomical in the developing competitive generation business. The retirement of Beebee Station is not expected to have a material effect on the Company's financial position or esults of operations. The plant will be fully depreciated at the time of retirement.
The Settlement provides that all prudently incurred incremental costs associated with the shut down and decommissioning of the plant are recoverable through the Company's distribution access tariff. The eXectric capability and energy currently provided by the plant is expected to be replaced by purchased power as needed.
Nine Mile Two, a nuclear generating unit in Oswego County, New York with a designed capability of 1, 143 megawatts (Mw) as estimated by Niagara, was completed and entered commercial service in Spring 1988. Niagara is operating the Unit on behalf of all owners pursuant to a full power operating license which the NRC issued on July 2, 1987 for a 40-year term beginning October 31, 1986.
Under arrangements dating from September 1975, ownership, output and cost of the project are shared by the Company (14%), Niagara (41%) Long 1slan'd Lighting Company (18%), New York State Electric & Gas Corporation (18'tW'.and Central Hudson Gas & Electric Corporation (9%). Under the operating Agreement, gi'agara serves as operator of Nine Mile Two, but all five cotenant owners share certain policy, budget and managerial oversight functions. The base term of the Operating Agreement is 24 months from its effective date, with automatic extension, unless terminated by written notice of one or more of the cotenant owners to the other cotenant owners; such termination becomes effective six months from the receipt of any such notice of terminat'on by all the cotenant owners receiving such not'ce. .he gross and net book cost of the Company's share of Nine Mile Two including $ 374 million of disallowed costs previously written off, as of December 31, '997 are $ 879 million and $ 399 million, respec ively.
.he Company's Ginna Plant, wh'ch has been in commercial operation since
" ly 1, 1970, provides 480 Mw of the Company's electric generating capacity. In August '991 the NRC approved the Company's app'cation for amendment to extend the G'na Plant operating license expi a"'on date from Apr' 25, 2006 to Septembe" 18, 2009.
The gross and net book cost of the Ginna Plant as of Decembe" 31. 1997 are
$ 560 million and $ 309 million, respec"ively. From t'me to time the NRC issues directives requiring all or a cer:ain group of reactor licensees to perform analyses as to their ability to meet spec'fied cr'teria, guidelines or operating objectives and where necessary to modify faci'i ties, systems o" procedures to conform thereto. Typically, these direc"ives are premised on the NRC's obligation to protect the public health and safety. The Company reviews such directives and implements a variety o modif'cations based on these directives and resulting analyses. Expenditures at the Ginna Plant, including the cost of these modifications, are estimated to be $ 10.1 million, $ 10.4 million and $ 6.4 million for the years 1998, 1999 and 2000, respectively, and are included in the capita) expenditure amounts presented under Item 7 Management's Discussion and Analysis of Financial Condition and Re'suits of Operations.
The Company has four licensed hydroelectric generating stations with an aggregate capability of 47 megawatts. Although applications for renewal of those licenses were timely made in 1991, the FERC was unable to complete processing of many such applications by the December 31, 1993 license expiration. The FERC, therefore, issued annual licenses that essentially extend the terms of the old licenses year-to year until processing of the new ones can be completed. The
Company received final licenses for Stations 2 and 5 in February of 1996.
license for Station 26 was received in October, 1997; Overly stringent environmental conditions, governmental requirements and high property taxes have nullified the economic viability of the fourth station, number 160 (less than one megawatt net capacity). It will not be relicensed.
Joint Nuclear Operating Company. See item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under Competition
,Nuclear Operating Company regarding formation of a joint nuclear operating company to support and manage the operations of nuclear plants in New York State including Nine Mile Two and the Company's Ginna Plant described below.
Insurance. The Price-Anderson Act estab/,ishes a federal program insuring against public liability in the event of a nuclear accident at a licensed U.S.
reactor. Under the program, claims would first be met by insurance which licensees are required to carry in the maximum amount available (currently $ 200 million) . If claims exceed that amount, licensees are subject to a retrospective assessment up to $ 79.3 million per licensed facility for each nuclear incident, payable at a rate not to exceed $ 10 million per year. Those assessments are subject to periodic inflation-indexing and a surcharge for New York State premium taxes. The Company's interests in two nuclear units could thus expose it potential liability for each accident of $ 90.4 million through retrospectiveto a assessments of $ 11.4 million per year in the event of a sufficiently serious nuclear accident at its own or another U.S. commercial nuclear'reactor.
As a licensee of a commercial nuclear power plant in the Uniied States, the Company is required to have and maintain financial protection to cover radiation injury claims of certain nuclear workers. The Company purchases primary insurance to meet this requirement. On January 1, 1998, a new insurance policy was issued that applies to claims first reported on or after January 1, 1998.
.his policy has a limit of $ 200 miion (reinstated annually if certain conditions are met) for radiation injury cia'ms against the Company, or against other licensees who are insured th's policy. If these claims exceed the $ 200 milon limit of primary coverage,by tne provisions of the Price-Anderson Act (d'scussed above) would apply. Since reserves for outstand'ng claims under ormer po'cies could be insu"icient and certa'n claims may s ill be made under former policies due to a discovery pe 'od, the Company could be assessed under these fo mer policies along with the other policyholders. The Company's share co" c be up to $ 3.0 million in any one year.
The Company is a membe" of Nuc ea" ="'ec"r'c nsu"ance Limited, which provides insurance coverage for the cost of "eplacement powe" during certain prolonged accidental outages of nuclear generat'ng un'"s and coverage for property losses in excess of $ 500 mil ion a nuc'ar generat'ng units. If an
'nsur'ng p ogram's losses exceeded '"s othe" reso rces available to pay claims, the Company could be subject to maximum assessments in any one policy year of approximately $ 3.0 million and $ 10.9 mill'on '.". the event o'osses under the replacement power and property damage coverages. respec ively.
GAS OPERATIONS As of December 31, 1997 the Company's daily city gate resource capability is 4,380,000 therms and its daily contracted transportation capacity is 4,080,000 therms (where one Therm is equivalent to 100,000 British Thermal Units). The Company optimizes its assets by contracting for gas resources that align with its system requirements.'he Company experienced on January 19, 1994, its maximum daily throughput of approximately 4,740,000 therms, (3,910,000 therms sold to retail customers and 830,000 therms delivered for transportation customers) .
The Company purchases all of its required gas supply from numerous marketers and producers under contracts containing various terms and conditions.
See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the caption "Energy Management and Costs - Gas" for a discussion of that topic.
1 The Company continues to provide new and additional gas service. Of 243,264 residential gas spaceheating customers at December 31, 1997, 2,579 were added during 1997.
Approximately 31% of the gas delivered to customers by the Company during 1997 was purchased directly by commercial, industrial and municipal customers from brokers, producers and pipelines. The Company provided the transportation of gas on its system to these customers'remises.
FUEL SUPPLY Nuclear. Generally, the nuclear fuel cycle consists of the following: (1}
the procurement of uranium concentrate (yellowcake), (2) the conversion of uranium concentiate to uranium hexafluoride, (3} the enrichment of the uranium .,
hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of the nuclear fuel in generating station reactors and (6) the appropriate storage or disposition of spent fuel and radioactive wastes. Arrangements for nuclear fuel materials and services for the Ginna Plant and Nine Mile Two.have been made to permit operation of the units through the years indicated:
Ginna Plant Nine'Mile Two'"
Uranium Concentrate 2000 2002<"
Conversion o'000<<~
2002'~'6)
Enrichment (5)
Fabrication 2001 2003 (1) Information was supplied by Niagara Mohawk Power Corporation.
(2) Arrangements have been made for procuring the majority of the uranium and conversion requirements through 2002, leaving the remaining portion of the requirements uncommitted.
(3) The Company has a contract under which the annual Ginna Plant uranium requirements.
it may procure up to 80 percent of A second contract is in place to supply about 30% of the annual requirements for 1998 through '999, and 100% of requirements in 2000. The remaining requirements are uncommitted.
(4) Seventy percent of the conve sion requirements have. been procured through 1997 under one contract. A second contract is in place covering 70% of requi ements in 1998 and 1999, and 100% in 2000. Twenty percent of requirements for 1998 are covered by a contract for delivery of UP6 (uranium plus conversion) . Ten percent of requirements for 1998 will be filled f rom inventory.
(5) The Company has a contract with United States Enrichment Corporation (USEC) for nuclear fuel enrichment services which assures provision of 70% of the Ginna Plant's requirements through 1999. A second enrichment contract is in place which assures 30% of the Ginna Plant's requirements through 1999 and 100% of requirements in 2000 and 2001.
(6) Nine Mile Two is. covered for 100% of requirements through 1998 and for 75%
(with an option to increase to 100%) from 1999 through 2003.
7 With appropriate lead times, the Company will pursue arrangements for the supply of uranium requirements and related services beyond those years for which arrangements have been made as shown above.
The average annual cost of nuclear fuel per million BTU used for electric generation for the last five years is as follows:
1997 1996 1995 1994 1993 Ginna Plant $ . 46,1 $ .424 $ .410 $ .403 $ .400 Nine Mile Two $ .485 $ .512 . $ .503 $ ,481 $ .515 See Note 10 of the Notes to Financial Statements under Item 8 for additional information regarding nuclear fuel disposal costs, nuclear plant decommissioning and DOE uranium enrichment facility decontamination and decommissioning.
Coal. The Company's 1998 coal requirements are expected to be approximately 800,000 tons. In 1997 100't of its requirements were purchased under contract.
To meet the additional coal burn requirements and meet its current reserve supply i
of coal ranging from 30-60 days supply at maximum burn rates, t;'is anticipated that the Company will purchase spot market coal to supplement-it contract supply.
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The sulfur content of the coal utilized in the Company's existing coal-fired facilities ranges from 1.0 to 1.9 pounds per million BTU. Under existing New York State regulations, the Company's coal-fired facilities may not burn coal which exceeds 2.5 pounds per m'lion BTU, and must average no higher than 1.7 pounds per mil)ion BTU over a 12-month pe iod or 1.9 pounds per million BTU over a three-month period.
The average annual delivered cost o= coal used for electric generation was as follows:
1997 1996 '995 1994 1993 Pe" Million BTU $ '.34 $ '.34 $ 1.3'1.38 $ 1.42 FINANCING AND CAPITAL REQUIREMENTS PROGRAM A discussion of the Company's capita rec 'rements, financial objectives and the resources available to mee" s ch requ'rements may be found in Item 7 Management's Discussion and Analysis of F'narcial Condi"ion and Results of Operations. The sale of additional sec iv.ies depends on regulatory approval and the Company's ability to meet certa'n requ rements conta'ned in its mortgage and Restated Certificate of Incorporation.
Under the New York State Public Serv'ce Law, the Company is required to secure authorization from the Public Service Commission of the State of New York (PSC) prior to issuance of any stock or any debt having a maturity of more than one year.
The Company's First Mortgage Bonds are issued under a General Mortgage dated September 1, 1918, between the Company and Bankers Trust Company, as Trustee, which has been amended and supplemented by thirty-nine supplemental indentures. Before additional First Mortgage Bonds are issued. the following financial requirements must be satisfied:
The First Mortgage prohibits the issuance of additional First Mortgage Bonds unless earnings (as defined) for a period of twelve months ending not earlier than sixty days prior to the issue date of the additional bonds are at least 2.00 times the annual interest charges on First Mortgage Bonds, both those outstanding and those proposed to be outstanding. The ratio under this test for the twelve months ended December 31, 1997 was 6.99.
(b) The First Mortgage also provides that, if additional First Mortgage Bonds are being issued on the basis of property additions (as defined), the principal amount of the bonds may not exceed 60% of available property additions. As of December 31, 1997 the amount of additional First Mortgage Bonds which could be issued on that basis was approximately $ 398,393,000.
In addition to issuance on the basis of property additions, First Mortgage Bonds may be issued on the basis of 1004 of the princ'ipal amount of other First Mortgage Bonds which have been redeemed, paid at maturity, or otherwise reacquired by the Company. As of December 31, 1997, the Company could issue $ 321,669,000 of Bonds against Bonds that have matured or been redeemed.
The Company's Restated Certificate of Incorporation (Charter) provides that, without consent by two-thirds of the votes entitled to be cast by the preferred stockholders, the Company may not issue additional preferred stock unless in a 12-month period within the preceding 15 months: (a) unct earnings applicable to payment of dividends on preferred stock, after'axe's, have been at least 2.00 times the annual dividend requirements on preferred s'tock, including the shares both outstanding and proposed to be issued, and'(b) net; 'earnings available for interest on indebtedness, after taxes, have been at least 1.50 times the annual interest requirements on indebtedness and annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued. For the twelve months ended December 31, 1997, the coverage ratio under (b) above (the more restrictive provision) was 2.83.
For information with respec" to shor"-term borrowing arrangements and limitations see Item 8, Note 9 - Sho" -Term Debt.
.he Company's Charter does not conta'n any financial tests fo" the issuance o= pre erence o" common stock.
.he Company's secur'ties ratings at December 31, 1997 were:
Mor"gage Pre'erred Bones Stock Standard & Poor's Corporation BBB>> BBB Moody's Investors Service Baal baa2 Duff & Phelps BBB+ BBB The securities ratings set forth in the'able are subject to revision and/or withdrawal at any time by the respective rating organizations and should not be considered a recommendation o buy, sell o" hold securities of the Company.
ENVIRONMENTAL QVALZTY CONTROL Operations at the Company's facilities are subject to various federal, state and local environmental standards. To assure the Company's compliance wi th these requirements, the Company expended approximately $ 0.6 million on a variety of projects and facility additions during 1997.
The federal Low Level Radioactive waste Policy Act (Act), as amended in 1985, provides for states to join compacts or individually develop their own low level radioactive waste disposal sites. The Company can provide no assurance as to what disposal arrangements, if any, New York will have in place. The State has not passed legislation that would designate a site for the disposal of low level radioactive waste. The Company has interim storage capacity at the Ginna Plant through 2002. Efforts are being pursued to extend storage capacity beyond 2002, if necessary, at this plant. A low level radioactive waste management and contingency plan is currently ongoing to provide assurance that Nine Mile Two will be properly prepared to handle interim storage of low level radioactive waste for the next ten years and beyond, if necessary.
The Company has wastewater discharge permits from NYSDEC for its Ginna, Beebee and Russell Stations, which were renewed in July 199'7, February 1994, and June 1994, respectively. These permits are each effective for a period of five years. Consistent with these permits, no significant changes to the wastewater discharge treatment systems are currently required, nor anticipated.
The Company believes that additional expenditures and costs made necessary by mandated environmental protection programs will be fully allowable for ratemaking purposes under cost of service rate regulation. Capital expenditures for meeting various federal, State and local environmental standards are estimated to be g9 million for the year 1998, $ 2 million for the year 1999 and $ 1 million for the year 2000. These expenditures are included.ended item 7 Management's Discussion and Analysis of Financial Condition ad@ Results of Operations, in the table entitled "Capital Requirements".
See Xtem 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Note 10 - Commitments and Other Matters, with respect to other environmental matters.
RESEARCH AND DEVELOPMENT The Company's research act'vi='es are ces'g..ed to 'mprove existing energy technologies and to develop new technologies fo" "he production, distribution, utilization and conservation of energy wh'le preserving env'ronmental quality.
Research and development expencitures '.". '997, '996 and '995 were $ 4.5 million, S4.9 million, and $ 5.2 million, respec"'ve y. .hese expend'"ures represent the Company's contribution to research ad.-..'n's=e"ec b, E'ec"r'c Power Research Institute Empi re State Elec=ric E..ergy Research Corpora='on and an assessment fo" state government sponsorec research by =.-.e '..'e York State Energy Research and Development Authority, as we as .n=erna "esca"ch projec=s.
10 ectric Department Statistics Year Ended December 31 1997 1996~ 19954 1993~ 1992 Elec 'c Revenue (000's) 1994'43,961 Residential $ 252,464 $ 254,885 $ 256,294 $ 234,866 $ 222,210 Commercial 210,643 215,763 215, 696 206.545 196,100 187,262 144,305 153,337 157,464 150.372 148,084 141.507
)Cunicipal and Other 66,898 67,128 57,270 59,905 57,288 72,06'79,473 Flectric revenue from our customers 690,883 696,582 658,148 638,955 608,267 0 ne" elec= ic utili ies 20,856 16,885 25,883 16,605 16,36 25,541 Total electric revenue 700,329 707.768 722,465 674,753 '55.316 633,808 Electric Experse (000's)
Fue used in electric generation 47,665 40. 938 4C,190 44,961 45,871 48.376 Purchased elec ricity 28,347 46,484 54, 167 37,002 31.563 29,706 0 he" operation 205,058 204,746 199,524 192,360 192,749 183,118 Maintenance 41,217 41,429 44,032 47,295 52,464 53,714 Depreciation and amortization 103,395 92,615 78,812 75,211 72,326 73,213
.axes - local, state and other 91,111 95,010 102,380 97,919 96,043 94,841 Total electric expense 516,793 521,222 523,105 494,748 491,016 482,968 Opera ing Income before Federal Ircome Tax 183,536 186, 546 199.360 180, 005 164,300 '50 840 Federal income tax 61,837 61,901 59,500 52,842 43, 845 38,046 Operating Zncome from Electric Operations (000's) $ 121,699 124.645 $ 139,860 $ 127, 163." $ 120,455 $ 112,794
~ >>L r Electric Operating Ratio 4 46.0 47. 1 47.3 47.7 49.2 49.7 Electric Sales . KNH (000's)
Residential 2, 139,064 2,132,902 2,144,718 2,117.168 2.123,277 2,084,705 breccial 2,118.991 2,061, 625 2,064.813 2,028,611 1.986,100 1.938,173 2,010,613 2.010.963 1,96C,975 1,860,833 1,892,700 1,929,720 cipa anc 0 he" 537,051 520.885 53 ,31' 513,675 504.987 503,388
.o al c stones sales 6,805.719 6>>726.375 6,705,817 6,520.28'7 6,507,064 6,455,986 Other e ectr c "tilities 1.218.794 994.842 ;. C84, 196 1.02',733 7C3,588 1,062,738
.ota'. electric sales 8,024,513 7 72 ~ 2 I B.:90,0:3 7, 542,020 7,250,652 7,518,724 "lectric ""stcmers at December 31 Resident a. 308,909 307.: 8: 306.601 30C,C94 302,219 300,344 30,940 30.520 30,425 29,984 29.635 29,339
- 1. 300 :.325 :,347 :.36: 382 1.386 2,824 2.588 2.7:- 2.570 2,638 2,605
.ota electr'c custome s 3C3.973 34:. BC: 34:. 085 338.S04 335,874 333.674 P rchased DPii (000's)
Foss 2,4 3 434 '>>4 '>h -,520.936 2, 197,757 N c ear '7,SIC 4, ~,441, 54 5 445 >5 4,495,C57 4.191,035 Hydro >>7: 86- 885 2:B.:29 '99,239 278,318 P mped storage 238.900
'ss energy for pumping (358.350) 245. 725
- 370.047) 247,550 (37
- .383) 233,477 (355.725) 226,391 (344,2CS)
Other 890 935 s55 , 245 2.559 811
.ota. cenera ed ne 6,893.765 340 1
,790 5.100.839 6. 095,943 6,550,067
- l. )43
~ ~
P rchasec 1,301,636 2.437.4 33 :,998 '82 1,6C6,244 1,389,875 To al electric energy 8.195.401 B.:70. 773 8.67:.274 8 '99.72 7,742,187 7,939.942 Sys em Net Capability KN at December 31
-oss 526,000 529.000 529.000 532,000 5C1.000 541,000 Nuclear 638,000 638.000 640,000 6.7,000 620,000 617,000 Hydro 47,000 47.000 47,000 47,000 47,000 47,000 0 he>>
Purchased 28,000 375.000
~. 000 375. 000 28,000 375.000 29.000 375.000 29,000 347.000 29,000 348,000 Total sys em net capability 1,614,000 1,617.000 1.619,000 ',600,000 1,584,000 1,582,000 Peak Load ~ KW 1,421,000 1.305,000 1,425,000 1.374,000 1,333,000 1,252,000 al Load Factor ~
Net 0, 56.1 61.9 57.6 58.8 59.1 62.5
~ Reclassified for comparative purposes.
11 Gas Department Statistics Year Ended Decembe.
Gas Revenue (000's) 31 1997 1996 '995 '994 '993~ 1992 Residential $ 5,852 8 6,010 $ 4,081 5,935 5,526 6,456 Residen ial spaceheating 249, 101 246,945 230,934 215,974 201, 129 186,710 Commercial 51,893 52,073 51, 117 49, 115 46,321 44.395 Indus rial 5,800 6, 175 6,686 7,088 6,368 6,284 Municipal and othe 23.663 35,076 1,045 47.949 34,36C 17, 879 Toral gas revenue 336,309 346,279 293,863 326,061 293,708 261,724 Gas Expense (000's)
Gas purchased for resale 196,579 202,297 167,762 194,390 166,884 141,291 Other operation 63,416 61,348 59,684 49. 312 47,593 43,506 Maintenance 5,418 5,634 5,194 ~ '7,774 9,229 9,006 Depreciation Taxes - local, state and other 13, 127 30,685 12,999 31,858 12,781 31,514 12,250 31,859 ll, 851 30,849 11.815 29,411 Total gas expense 309,225 31C r 136 276,935 295,585 266,406 235,029 Operating Income before Federal Income Tax 27.084 32,143 16,928 30,476 27.302 26,695 Federal income tax 3.442 7,600 6,715 8,403 5,485 5,545 Operating Income fron Gas Operations (000's) $ 23,642 $ 24,543 9 10,213 22,073 S 21, 817 $ 2, 150 Gas Operatirg Ratio % 78.9 77.8 79.2 77.1 76.2 74.1 Gas Sales . Therms (000's)
Resider. ial 5,773 6,455 7. 167 6,53S 6, 871 8,780 Residential spaceheating 285,395 299,085 280,763 283,039 295,093 287,623 Commercial 65,675 70,543 68,380 72,410 78,887 78,996 Industrial 7,828 9,33C 9,560 11,420 12,030 12,438 Muricipal 7.331 8,086 8,219 10,230 12,188 11,41 Tora. gas sales 372,002 393.503 374,089 383,634 405,069 399,247 Transportatior. of cus ome .owned gas 166.060 167,779 146, 1C9 136,372 124,436 126,140 Tora. gas sold and transported 538.062 56'.282 520,238 520,006 529,505 525.387 Gas C stomers at December 3 Resicent;a 16,265 6,7 8 17,443 17,836 18,389 19,114 Residential spacehea" ng 243.264 240,685 238.267 235,3.3 231,937 228,096
- 19. '18 19. 045 18,978 18.742 18,636 18. 378 Ind strial 829 857 879 905 924 932 Mu >ic pa 1. 1'7 981 988 1,001 1,010
~-aaspo--a'o" 836 96I
' 655 558 466 424
.ota gas c "s omers 281,429 279.0 0 277.203 274.342 271.353 267,954 Gas ~
Therms (000's)
P""chased 'or resa:e 274.430 279.353 237.728 262.267 3C7.778 Gas from storage 104.3:7 '22.843 i
360,493
- 52.852 134.802 76.378 53,757 Other ',4 0 :.082 .800 2.959 '-, 039 1,061
.o a gas available 380.157 403.278 392.380 400.028 425,195 415,311 Cos of gas per berm 51.70c 52.30c CS.BOc 50.00c 36.79c 35.35c
.otal Day Capacity Therms a December 3' 4 '80 F 000 4.480 000F 5 '30 F 000 5.625,000 5,625,000 C .485,000 Max'mum daily hroughput ~
Therms C.11C,290 4,022.600 3.980.000 4.735,690 3,864,850 3 ,768,470 Degree Days (Calendar Month)
For the period Percent colder (warmer) than normal 6,921 2.8 6 '98 6.535 6. 699 7,044 6,981 3.9 (3.0) (0.6) C.C 3.4 Reclassified for comparative purposes.
~~ Method for determining daily capacity, based on current network analysis, reflects the maximum demand which the ransmission systens can accept without a deficiency.
12 Item 2. PROPERTIES ELECTRIC PROPERTIES The net capability of the Company's electric generating plants in operation as of December 31, 1997 the net generation of each plant for the year ended December 31, 1997, and the year each plant was placed in service are as set fo th below: ~
Electric Generating Plants Net Year Unit Net Generation Placed in Capability thousands T e of Fuel Service (Mw) (kwh)
Beebee Station (Steam) Coal 1959 80 418,139 Beebee Station (Gas Turbine) Oil 1969 14 425 Russell Station (Steam) Coal 1949.1957 257:--',237,958 Ginna Station (Steam) Nuclear 1970 480 3,894,652 Oswego Unit 6'"
(Steam) Oi) 1980 189 8,817 Nine M'le Point Uni" No. 2'~'Steam)
Nuclear '988 158 1,224,892 Stat'on No. 9 (Gas Turbine) Gas 1969 465 Station 5 (Hydro) Water g9'17 39 173,487 5 0 he" Stations (Hydro) Water '906.1960 54,380 P mped Storage 238,900 cess: energy for pumping (358,350) 239 i~~EK (1) Represents 24'4 share of jointlv-ownec 'ac'lity.
(2) Represents 14% share of jointly-owned fac'li y.
(3) Owned and operated by the Powe" Authority.
13 The Company owns 147 distribution substations having an aggregate rated transformer capacity of 2,149,754 Kva, of which 138, having an aggregate rated capacity of 1,970,588 Kva, were located on lands owned in fee, and nine of which, having an aggregate rated capacity of 179,166 Kva, were located on land under easements, leases or license agreements. The Company also has 72,881 line transformers with a capacity of 2,903,304 Kva. The Company also owns 24 transmission substations having an aggregate rated capacity of 3,052,017 Kva of which 23, having an aggregate rated capacity of 2,977,350 Kva, were located on land owned in fee and one, having a rated capacity of 74,667 Kva, was located on land under easements. The Company's transmission system consists of approximately 716 circuit miles of overhead lines and approximately 400 circuit miles of underground lines. The distribution system consists of approximately 16,262 circuit miles of overhead lines, approximately 3,857 circuit miles of underground lines and 353,220 installed meters. The electric transmission and distribution system is entirely interconnected and, in the central portion of the City of Rochester, is underground. The electric system of the Company is directly interconnected with other electric utility systems in New York and indirectly interconnected with most of - the electric utility systems in the United States and Canada. (See Item 1 Business, "Electric Operations".)
GAS PROPERTIES The gas distribution systems consists of 4,257 miles of gas mains and 292,392 installed meters. (See Item 1 - Business, "Gas Opera'tions" and "Gas Department Statistics".
OTHER PROPERTIES The Company owns a ten-story office building centrally located in and other structures and property. The Company also leases approximatelyRochester 475,000 square feet of facilities for adm'nistrative offices and operating activities in the Rochester area.
The Company has good title in fee, with mino" exceptions, to its principal plants and important units, except rights of way and flowage rights, subject to rest ictions, reservations, rights of way, leases, easements, covenants, contracts, sim'ar encumbrances and mino" defects of a character common properties of the size and nature of those of the Company. The electric toand gas transmission and distribution lines and ma'ns are located public streets and highways and in part on private property,in part either in or upon pursuant to easements granted by the apparent owne" containing in some instances removal and relocat'on provisions and time lim'ations, o" without easements but without objection of the owners. The First Mortgage secur'ng the Company's outstanding bonds is a first lien on substantially all the property owned by the Company (except cash and accounts receivable). A mortgage securing the Company's revolving credit agreement is also a lien on substantially all the property owned by the Company (except cash and accounts receivable) subject and subord'nate to the lien of the First Mortgage. The Company has credit agreements with a domestic bank under which short-term borrowings are secured by the Company's accounts receivable.
Item 3. LEGAL PROCEEDINGS See item 8, Note 10 - Commitments and Other Matters.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the fourth quarter of the fiscal year ended December 31, 1997.
Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT Age Positions, Offices and Business Experience Name 1/1/99 1993 to date Thomas S. Richards Chairman of the Board, President and Chief Executive Officer - January 1998 to date.
President and chief operatinq officer - March 1996 to December 1997.
Senior Vice President, Energy'Services August 1995 to March 1996.
Senior Vice President, Corporate Services and General Counsel - August, 1994 to August 1995.
Senior Vice President, Finance and General Counsel - October 1993 to August, 1994.
General Counsel -'anuary, 1993 to October, 1993.
Michael J. Bovalino President, Energetix, Inc (a wholly owned subsidiary of the Companyf January 1998 to date.
Sen'or Vice President, Energy Services January 1997 to December 1997.
Vice P"esiden, Retail Se"vices fo" Plum Street Enterprises (a wholly owned subsidiary of Niagara Mohawk Power Corporation, 300 Erie Boulevard West, Syracuse, NY 13202) prior to joining the Company.
Robert E. Smith 60 Senior Vice President, Energy Operations August 1995 to date.
Senior Vice President, Customer Operations August, 1994 to August, 1995.
Senior Vice President, Production and Engineering - 1993 to August, 1994.
15 Age Positions, Offices and Business Experience Name 1/1/98 1993 to date J. Burt Stokes 54 Senior Vice President, Corporate Services and Chief Financial Officer - January 1, 1996 to date.
Chief Financial Officer and acting Chief Executive Officer for General Railway Signal Corporation, 150 Sawgrass Dr., Rochester, NY 14692 prior to joining the Company.
Michael T. Tomaino 60 Senior Vice President and General Counsel October, 1997 to Date.
Vice President, General Counsel and Secretary for Goulds Pumps, Inc., 300 Willowbrook Office Park, Fairport, NY 14450 prior to joining the Company.
William J. Reddy 50 Controller - May, 1997 to Date.
I Group Manager, Public Affairs Services
~
January 1995 to April 1997:
Division Manager, Public Affairs Services October 1994 to January 1995.
Department Manager, Forecasts and Budgets 1993 to September 1994.
The term of office of each off'cer extends to the meeting of the Board of Directors following the next annual meeting of shareholders and until his or her successor is elected and qualifies.
16 PART II Item 5 ~ MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS COMMON STOCK AND DIVIDENDS Earnings/Dividends 1997 1996 1995 Shares/Shareholders 1997 1996 1995 arnxngs pe" snare u.".~er or snares 00's)
- basic 82.30 $ 2. 32 Sl . 69 Weighted average - basic 38,853 38,762 38,113
~
di)u ed 82.30 $ 2.32 81.69 diluted 38,909 38,762 38, 113 Dividends paid Actual number at per share $ 1.80 $ 1.80 $ 1.80 december 31 38,862 38,851 38,453 Number of shareholde.s at December 31 31 337 33 675 35 356 TAX STATUS OF CASH DIVIDENDS Cash dividends paid in 1997, 1996 and 1995 were 100 percent taxable for federal income tax purposes.
DIVIDEND POLICY The Company has paid cash dividends quarterly on its Comn4a".Stock without interruption since it became publicly held in 1949. The level of-'future cash dividend payments will be dependent upon the Company's future earnings, I its financial requirements and other factors. The Company's Certificate of
~ ~
~
~ ~
Incorporation Iv provides for the payment of dividends on Common Stock out of the
~ ~
surplus net profits (retained earnings) of the Company.
~ ~
~
~
I~ ~
I~
~t~
Quarterly Iv dividends on Common S IIock are generally paid on the twenty-fifth day
~
~
o'anuary, r April, III~
~ Iv
~
July and October.Iv XnI January
~ r 1998,I the Company paid a cash ~
c'vidend of $ .45 per share on its Common Stock. The January 1998 dividend payment is ecuivalent to $ 1.80 on an annual basis.
COMMON STOCK TRADING Shares of the Company's Common Stock are traded on the New York Stock Exchange neer the symbol "RGS".
Common Stock - Price Range 1997 1996 1995 High 1st quarte" 20 3/8 23 3/4 23 2nd quarter 21 7/16 21 7/8 22 5/8 3rd quarter 24 15/16 21 3/8 24 1/8 4th quarter 34 1/2 19 5/8 24 1/8 Low 1st quarter 18 7/8 21 1/4 20 3/8 2nd quarter 18 19 7/8 20 1/8 3rd quarter 20 5/8 18 20 4th quarter 23 3/4 17 7/8 22 3/8 At December 31 19 1/8 22 5/8
17 ITEM 6 - SELECTED FINANCIALDATA CONSOLIDATED
SUMMARY
OF OPERATIONS (Thousands ol Dollars) Year Ended December 31 1997 1996 1995'994 1993'992 Operating Revenues Electric $ 679,473 $ 690.883 $ 696,582 $ 658.148 $ 638 955 $ 608.267 Gas 336.309 346,279 293.863 326.061 293 708 261 724 1.015.782 1.037,162 990.445 984.209 932.663 869.991 Electric sales to other utilities 20.856 16.885 25,883 16.605 16.361 25,541 Total Operating Revenues 1,036,638 1.054,047 1,016.328 1,000.814 949,024 895.532 Operating Expenses FuelExpenses Fuel for electric generabon 47.665 40.938 44,190 44,961 45.871 48.376 Purchased electricrty 28.347 46.484 54.167 37,002 31.563 29.706 Gas purchased lor resale 196.579 202.297 167.762 194,390 166.884 141.291 Total Fuel Expenses 272.591 289.7\9 266 ii9 276.353 244.318 219,373 Operating Revenues Less Fuel Expenses 764.047 764.328 750.209 724.461 704.706 676,159 Other Operating Expenses Operations excluding fuel expenses 268,474 266,094 259.207 241.672 240.342 226,624 Maintenance 46.635 47.063 49.226 55,069 i 61,693 62.720 Depreciation and amortization Taxes - local. state and other 116.522 105.614 91.593 87~ i 84.177 85.028 121.796 126,868 133.895 129,i'() 126,892 124,252 Federal income tax ~ current
~ deferred
~4. 69.812 53~3 65.757 3 744 65.368 847 25.587
'5.658 33,453 15.877 36.101 7.490 Total Other Operating Expenses 618.706 615,140 600,136 575.225 562.434 542.215 Operating tncome 145.341 149.188 150.073 149.236 142.272 133,944 Other (Income) and Deductions AIIOwanCe for Other Iunds used during construction (351) (684) (585) (396) (153) (164)
Federal income tax (3.704) (3.450) (16.259)
'16,948)
(9.827) (4,195)
Regutatory disatlowances 26.866 600 1.953 8.215 Pension Plan Cunaiiment 33.679 8.179 Other. net 3,308 (712) 9.631 2.113 To',at Other rlncomel and Deductiotls (747) (4.846) 18.964 16.701 2.265 (2.299)
Interest Cnarges Long term debt 44.615 48.618 53.026 53.606 56.451 60.810 Snon term debt 47 21 398 1.808 1.487 1.950 Other, net 6.629 9.307 8.658 4,758 5.220 5.228 Allowance lor borrowed funds used ounng construction (563) I 1.423 l (2.90 I) (2.012)
Total Interest Charges 50.728 56.523 59.18 58,160 61,444 1 65,804 Net Income 95.360 97.511 71.928 74.375 78.563 70.439 DividendS On Preferred Stock at required rates 5.805 7.465 7.465 7.369 7.300 Earnings Apphcable to Common Stock ~~9 555 $ 90,046 $ 64,463 $ 67,006 $ 7~1263 Earnings per Common Share - Basic $ 2.30 $ 2.32 $ 1.69 $ 1.79 $ 2.00 $ 1.86 Earnings per Common Share - Diluted $2.30 $ 2.32 $ 1.69 $ 1.79 $ 2.00 $ 1.86 Cash Dividends Declared per Common Share $ 1.80 $ 1.80 $ 1.80 $ 1.77 $ 1.73 $ 1.69 Reclassified lor comparative purposes.
18 CONDENSED CONSOLIDATED BALANCE SHEET phousands of Dollars)
Assets At December 31 1997 1996 1995 '994 '993 1992 Utility Plant $ 3,234,077 $ 3,159,759 $ 3,068,103 $ 2,981,151 $ 2,890,799 $ 2,798,581 Less: Accumulated depreciation and amonizatfon 1,714.368 1,569,078 1.423.098 1.335.083 1.253,117
'.518.878 1,519,709 1,590,681 1,549,225 1,558,053 1.555.716 1,545,464 Construction work in progress 74.018 69.711 121,725 128.860 112.750 83.834 Net utility plant 1.593,727 1,660,392 1,670,950 1,686,913 1,668.466 1,629,298 Current Assets 242,371 250,461 292,596 236,519 248.589 209.621 Investment in Empire 38,879 38,560 38.560 9,846 Deferred Debits 432,191 450.623 453.726 484.962 488.527 181.434 Total Assets $ 2.268.289 $ 2.361.476 $ 2.456.151 $ 2.446.954 $ 2.444.142 $ 2.030.199 CAPITALIZATIONAND LIABILITIES Capitalization Long term debt $ 587,334 $ 646,954 $ 716,232 $735,178 $ 747.631 $ 658.880 Preferred stock redeemable at option of Company 47,000 67,000 67,000 67,000 67,000 67,000 Preferred stock subject to mandatory redemption 35,000 45,000 55,000 55,000 42,000 54,000 Common shareholders'quity:
Common stock 699,031 696,019 687,518 670.569 652,172 591,532 Retained earnings 109,313 90,540 70.330 74.566, 75.126 66.968 Total common shareholders'quity 808,344 786,558 757 848 745.135. ~ 727.298 658 500 Total Capitalization 1,477 678 1.545,513 1,596,080 1,602.3t3'1,583,929 1,438,380 Long Term Liabilities (Department Energy) 96,726 93,752 90,887 87,826 89.804 94.602 ent Liabilities 189,317 158.217 182,338 181.327 234.530 267,276 rred Credits and Other Liabilities 504 568 563.994 586.846 575.488 535,879 229.941 Total Capitalization and Liabilities $ 2.268.289 $ 2.361.476 $ 2.456.151 $ 2.446.954 $ 2.444.142 $ 2.030.199 Reclassified for comparative purposes.
19 FINANCIAL DATA At December 31 1997 1996 1995 1994 1993 1992 Capitalization Ratios (a) (percent)
Long-term debt 43.0 44.7 47.4 48.2 49.4 48.2 Preferred Stock 5.2 6.9 7.3 7.3 6.6 8.0 Common shareholders'quity Total l~
51.8 48.4 15%5 45.3 44.5 44 '
l~
43.8 Book Value per Common Share . Year End $ 20.80 $ 20.24 $ 19 71 $ 19.78 $ 19 70 $ 18.92 Rate of Return on Average Common Equity (b)
(percent) 11.00 11.41 8.37 8.92 10. 25 9.94 Embedded Cost of Senior Capital (percent)
Long-term debt 7.32 7.33 7.38 7.40 7.36 7.91 P.eferred stock 5.80 6.26 6.26 . 6.26 6.69 6.98 Effective Federal Income Tax - Rate (percent) 39.2 40 4 40.7 37.7 33.5 35.9 Depreciation Rate (percent) Elect ic 3.12 2.99 2.76 2.69 2.62 2.69
- Gas 2.60 2.60 2.59 2.62 2.60 2.78 Interest Coverages Before federal income taxes (incld. AFUDC) 4.06 3.82 2.95 2.98 2.87 2.62 (exc1d. AFUDC) 4. 04 3.79 2.90 2.94 2.84 2.58 After federal income taxes (incld. AFUDC) 2.86 2.68 2. 16 2.24 2.24 2.04 (excld. AFUDC) 2.84 2.65 2. 10 2.20 2.21 2.00 Interest Coverages Excluding Non.Recurring Items (c)
Before federal income taxes (incld. AFUDC) 4.06 3. 82 3.66 3.55 2.74 (excld. AFUDC) 4.04 3.79 3.61 3.51 2.70 After f ederal income taxes (incld. AFUDC) 2.86 2.68 2.62 2.61 2.12 (excld. AFUDC) 2.84 2.65 2.57 2.57 2.08
\
(a) Includes Company's long-term liability to the Department of.energy (DOE) for nuclear waste disposal. Excludes DOE long-term liability for uranium enrichment decommissioning and amounts due or redeemable within one year.
(b) The return on average common equity for 1995 excluding effects of the 1995 Gas Settlement is 12. 10%. The rate of return on average common equity excluding effects of retiremen. enhancement programs recognized by the Company in 1994 and 1993 is 11.90% and 11.20'4, respectively.
(c) Recognition by the Companv ir. '992 of d'sallowed ice storm costs as approved by the PSC has been excluded from 1992 coverages. Coverages for "994 and 1993 exclude the effects of retirement enhancement programs recognized by the Company dur'rg each yea" and certain gas purchase undercharges written off in 1994 and 1993. Coverages in 1995 exclude the economic effect of the 1995 Gas Settlemert (S44.2 million, pretax).
20 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is Management's assessment of certain affecting the financial condition and operating results of significant factors the Company. This assessment contains forward-looking statements which are subject to various isks and uncertainties. The Company's actual results could differ from those anticipated in such forward-looking statements as a result of numerous factors which may be beyond the Company's control by reason of factors such as electric and gas utility restructuring, future economic conditions, and developments in the legislative, regulatory and competitive environments in which the Company operates. Shown below is a listing of the principal items discussed.
Earnings Summary Page 20 Competition Page 21 PSC Competitive Opportunities Case Settlement Business and Financial Strategy PSC Position Paper on Nuclear Generation FERC Open Transmission Orders Gas Restructuring and PSC Negotiations Prospective Financial Position Rates and Regulatory Matters Page 27 1996 Electric Rate Settlement 1995 Gas Settlement Flexible Pricing Tariff Liquidity and Capital Resources Page 27 Capital and Other Requirements Redemption of Securities Financing Results of Operations Page 30 Operating Revenues and Sales Fossil Unit Ratings anc Status Operating Expenses D'vidend Policy Page 33 EARNINGS
SUMMARY
Despite rate reductions in July 1996 and 1997, earn'ngs applicable to Common Stock were nearly unchanged 'r. 1997 due, ir. par=, to the increased ava'lability of the Company's Girna nuclear generating facility following the 1996 refueling and steam generator replacemen: outage. 1'ncreased generation allowed the Company to reduce purchased electric expenseCompany , while increasing available power for customer consump ion and resale. A decrease in financing costs as a result of discretionary redemptions and refinancing ac"ivities during the year also helped to increase earnings. In addition reductions, offsetting a gain in 1997 ea nings were a warmer heating seasonto rate during the first quarter of the year coupled with a cooler summer which affect,ed a' conditioning load.
Basic and dilutive earnings per share of $ 2.30 in 1997 are down two cents compared to a year ago. In February 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128 ("SFAS-128"),
"Earnings per Share," which changes the methodology of calculating earnings per share. The Company adopted SFAS No. 128 during the fourth quarter of 1997.
impact on earnings per share for prior periods is not material. A discussion The the calculation of earnings per share is presented in Note 1 to the Notes to of Financial Statements.
Basic and dilutive earnings per share of 1.69 reported in 1995 reflect a pretax reduction of $ 44.2 million, or $ .75 per $share net-of-tax, in connection
21 w'th a negotiated settlement (see 1995 Gas Settlement discussed below) reached between the Company, Staff of the New York State Public Service Commission (PSC) and other parties resolving various proceedings to review issues affecting the Company's gas costs.
The impact of developing competition in the energy marketplace will affect future earnings. The Competitive Opportunities Case Settlement (the "Settlement",
see description below) allows for a phase-in to open electric markets while lowering customer prices and establishing an opportunity for competitive returns on. shareholder investments. The nature and magnitude of the potential impact of the Settlement on the business of the Company will depend on the availability qualified energy suppliers, the degree of customer participation and ultimate of selection of an alternative energy supplier, the Company's ability to be competitive by controlling its operating expenses, and the Company's ultimate success in development of its unregulated business opportunities as permitted under the Settlement.
Future earnings will also be affected, in part, by the Company's degree of success in remarketing its excess gas capacity as set under the terms of the 1995 Gas Settlement and in controlling its local gas distribution costs'he Company believes it will be successful in meeting the 1995 Gas Settlement targets over the remaining year of the Settlement period, although no assurance may be given.
COMPETITION
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Overview. During 1996 and 1997, the Company, the Staff. M. the PSC, and several other parties negotiated an agreement which was approved by; the PSC in November 1997. This agreement sets the framework for the introduction and development of open competition in the electric energy marketplace and lasts through the year 2002. Over this time, the way electricity is delivered to customers will fundamentally change. Zn phases, the Company will open its electric system to othe" suppliers. The sys em will be fully open to competitors by July of 2001. These suppliers will compe=e to package and sell energy and related services to customers. The Company anc its subsid'aries will be among the supplier choices. Competing electric distribution system and supp iers wav the Company a fee,to use its the Company w'll "emain responsible fo" main aining it and responcing to mos" emergenc'es.
PSC COMPETETZVE OPPORTUNETEES CASE SETTLEMENT. Through its "Competitive Opportunities Proceeding," the PSC has embarkec on a undamental restructuring of tne electric utility industry in the S ate. A.-..ong other elemen"s, the PSC's goa's inc'uded lower rates fo" cons mers and 'ncreasec cus"orner choice in obta'ning electr'city and o her ene=gy se"v'ces.
The Company's proceeding was co.-..p e=ec on .':ovember 26, 1997 with the PSC approval of a Settlement Agreemen= among '.".e Compan". the PSC Staf and other parties. The PSC's November 26, 1997 order o'pprova'as confirmed by a full Opinion and Order (No. 98-') 'ss ec an a"y 4, 1998.
Summary. The Settlemen" prov'des fo" a transition to competition during i"s five-year term (July 1, '997 through June 30. 2002) and establishes the Company's electric rates for each annual per.od. A Retail Access Program will be phased in, allowing customers to purchase e'ec"r'city, and later electricity and capacity commitments, from sources o=he" than the Company. The Company will be provided a reasonable opportunity to recove" prudently incurred costs, including those pertaining to generation and purchased power.
The Settlement also requires the Company to functionally separate its component operations: distribution, and retailing. Any unregulated retail operations must be structurallygeneration, separate from the regulated utility functions but may be funded with up to $ 100 million. En addition, the Company would have the option after receiving the necessary regulatory approvals to establish a holding company structure. Although the Settlement provides incentives for the sale of generating assets, i" requires neither divestiture of generating or other assets, nor write off o "stranded costs" (the above-market costs, presumed to result from competition).
22 The Company believes that the Settlement will not adversely affect its eligibility to continue to apply Statement of
("SFAS-71>>), with the exception of certain Financial Accounting Standards No.
"to-go costs associated with non-71 nuclear generation. If, contrary to the Company's view, such eligibility were adversely affected, a material write-down of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Over the five year term of the Settlement, the cumulative rate reductions wil) be as follows: Rate Year 1: $ 3.5 million; Rate Yea" 2: $ 12.8 million; Rate Year 3: $ 27.6 million; Rate Year 4: $ 39.5 million; anc Rate Year 5: $ 64.6 million.
The Rate Plan permits the Company to offset against the foregoing total reductions certain inflation-related expenses, and certain amounts related to a power purchase agreement with Kamine/Besicorp: Allegany L.P.'(Kamine), including seven-eighths of any difference between Kamine costs currently included in rates and any increased amount resulting from enforcement of such agreement with any balance not recovered during the term of the Settlement subject to deferral for recovery after such term. The agreement is subject to litigation, as discussed in Note 10 of the Notes to Financial Statements. In the event of a settlement of the Kamine matter, the Settlement permits the Company to offset against rate reductions, the following amounts: Rate Year 2, $ 3.5 million; Rate Year 3, $ 8.4 m'llion; Rate Year 4 and continuing until Settlement payments are complete or July 1, 2002, whichever is later, $ 10.5 million.
In the event that the Company earns a return on common, equity in excess of an effective rate of 11.50 percent over the entire five-year'tprm of the Settlement, 50 percent, of such excess will be used to write doMh deferred costs accumulated during the term. The other 50 percent of the excess w'all 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 's permitted by SFAS-71). If certain ex"raordinary events occur, including a rate of return on common equity below 8.5 percent or above 14.5 percent, or a p e"ax interest coverage below 2.5 t'mes, "hen either the Company or any other party =o the Settlement would have the r'gh" to petition the PSC fo review of
=he Se" lement and appropriate remec'al ac='on.
Retail Access. RG&E's Energy Choice Program w 1 be ava'able to all of its c s=omers, w'thout regard to cus=ome" class, on an equa'asis up to certa'n "sage caps. On Ju'y 1, 1998, cus=omers whose e'ec=r'c 'oads reoresen" approx'mately 10 percent of the Company's rota'nnual reta'I sales will be e ig'ble to purchase electricity (bu= rot capac'=v commi:men"s) from alternative s ppers. On July 1, 1999, customers w'"..". 20 pe"cen" o= total sales will be e'.'gible and as of July 1, 2000, 30 percen= o= "o:al sales w'll be eligible. As o= ' 1, 2001, all reta'1 cus:omers capac'=y from alternative supp 'ers.
w'e eg b e to purchase energy and Dur'ng the 'nitial. energy on'. s=age o= he Re=a'I Access Prog am, th Company's d's tr'bution rate wil be se" b; cec c= ng 2.3 cen=s per kilowatt hour
("kAH") from its full service ("bunc'ed"] ra=es anc Load Serv'ng Entities acting as retailers in the Company's serv'ce area wi oe en"'ec e'ectr'city f rom the Company, at a ra=e o= '.9 cen=s pe" 'iGPi-'.. :o During the energy purchase anc capac'ty stage, the rate w:I ge.".era y e= a =he b'd ec "'ate less the cost o= the electr ic commodity and the Co;..pany's no.".-n c.ear generating capacity.
These commodi ty and capacity costs, gene"al'; "e:erred to as "contestable costs,"
are estimated to be 3.2 cents per KW:-:, incve o= gross receipts taxes.-
Generating Assets. The Company w' no= be req ired to civest any of its generation facilities. To the extent tha" he Company sells any generating assets during the term of the Settlement, ga'ns on such sales will be shared between the Company and customers. With regard to losses on such sales, the Settlement acknowledges an intent that the Company will be permitted to recover such losses through distribution rates during the term of the Settlement. Future rate treatment is to be consistent with the pr'nciple that the Company is to have a reasonable opportunity to recover such costs.
"To-go costs" of the Company's non-nuclear resources (i.e., capital costs incurred after February 28, 1997, operation and maintenance expenses, and property, payroll and other taxes) are to be recovered through the distribution
access 23 tariff. The fixed portion of To-Go Costs would be recovered in full through the distribution access tariff until July 1, 1999 and subject to the market thereafter in accordance with the phase-in schedule for the Retail Access 0
Program described above. The variable portion of non-nuclear to-go costs would also be subject to the market in accordance with the phase-in Schedule described above. Upon extension of eligibility, for the Retail Access Program to all retail customers on July 1, 2001, the Company would be authorized to distribution access rates, so as to hold constant the degree tomodify its which its to-go costs are at risk for recovery through the market. Thus, while the recovery of non-nuclear to-go Costs would continue to be through the market, recovery of nuclear costs would remain recoverable through regulated rates. No change in such treatment of nuclear facilities would be implemented prior to the PSC's resolution of the issues raised in its Staff Report on nuclear generation (see PSC Position Paper on Nuclear Generation). Shutdown and decqmmissioning costs would be recovered during the term of the Settlement in a manner consistent with past ratemaking treatment.
Pilot Program. Consistent with a PSC order issued June 23, 1997 in a separate proceeding involving establishment of pilot programs for farmers and food processors, the Settlement that the Company's Retail Access Program will commence on February 1, 1998provides for those groups within the Company's service area.
Tariff Filing. On December 1, 1997, the Company submitted to the PSC its proposed tariffs and a Distribution Operating Agreement to establish "Energy Choice", the Company's proposed retail access program to implemept the terms of the Settlement. In an order issued January 21, 1998, the PSC.ayproved certain provisions of the December 1, 1997 tariff filing and required the Cpmpany to revise others. ln late January 1998 the Company filed revisions tb the tariff to incorporate the changes required by the PSC's order.
Miscellaneous. After approval of the Settlement becomes final and non-appealable, the Company will withdraw legal appeals which challenge various PSC 0 ders regarding the PSC Competitive Opportunities Proceeding, establishment of a p'lot program pursuant to those proceed'ngs. and certain provisions of the 1996 E'ectric Rate Settlement.
The present Settlement supersedes the 1996 Rate incentive and penalty provisions in he 1996 E'ectric Settlement. Various Rate Settlement are elim'nated.
BUSINESS AND FINANCIAL STRATEGY: THE COMPANY'S RESPONSE. Under the terms of the Se"tlement, the Company will func"ionally separate d'stribution, and regulated energv services bus'nesses.
'ts generation, As perm'ted by the Settlement. the Company has estab'shed a separate unregulated subsidiary called Energet'x which will be able to compe"e 'o" energy services and products bo"h in and outside the Company's existing e..ergy.ranchise se"v'ce territory. The Company has also developed an in egra"ed 'inane'al strategy which includes new bus'ness development initiat'ves and a Common Stock share repurchase program.
Energy Choice. Within the framework of he Energy Choice Program, the Company wi 1 unbundle traditional ut'=y se"vices. Reta'1 electric customers in the Company's service territory will have the opportun' to purchase energy, capacity, and retailing services from compet i='ve energy service companies, referred to as Load Serving Entities (LSEs). They may also continue to purchase fully-bundled electric service from the Company under existing retail tariffs.
General Structure. Energy Choice adopts the "single-retailer" model for the relationship between RGRE, the LSEs and retail customers. the "single-retailer" model the regulated-utility's customer is the Under LSE, whose customers are the retail customers. The relationship between the regulated utility and retail customers is substantially eliminated.
0 The LSE assumes responsibility for providing its retail customers with bundled energy and delivery services, and for virtually all related retailing functions, including direct contact and communications with retail customers. With the exception of transmission and distribution service, the LSE will procure for its customers, or will itself create and provide them with, all necessary components of fully bundled service on a competitive basis.
24 Throughout the term of the Settlement, RG&E will continue to provide regulated and fully bundled electric service under its retail service tariff to customers who choose to continue with or return to such service', and to customers to whom no competitive alternative is offered.
Until the development of a wholesale market for generating capacity, there will be no suitable mechanism for the reallocation, from the regulated utility to the LSE, of responsibility for ensuring adequate installed reserve capacity.
Accordingly, during the initial "Energy Only" stage of the Energy Choice Program (July 1, 1998 to July 1, 1999), LSEs will be able to choose the'" own sources of energy supply, while RGGE will provide to LSEs, and will be compensated for, the generating capacity (installed reserve) needed to serve their retail customers reliably. During the "Energy and Capacity" stage commencing July 1, 1999, the LSEs will be able to select, and will be responsible for procuring, generating capacity, as well as energy, to s'erve the loads of their retail customers, and distribution charges will be accordingly reduced as hereinafter described. If by July 1, 1998 there is not a functioning Statewide energy and capacity market (see discussion under FERC Open Transmission Orders),
the Company may petition the PSC for deferral of the scheduled commencement of the Energy and Capacity stage.
Summary. The availability of LSEs to serve eligible customers and how quickly they decide to become involved cannot be determined. Likewise, the Company is not able to predict the number of customers that may chose to no longer be served under the Company's regulated tariffs.
tariffs filed by the
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The proposed for Energy Choice as .<otppany are expected to become effective February 1, 1998 for the pilot program. Th'e PSC has not set a decision'-making date for the full-scale program. The Company is'nable to what final rules or regulations will ultimately be adopted by the PSC 'redict for th's program.
Unregulated Energy Services Company. It is part of the Company's financial strategy to stimulate growth by entering into unregulated businesses. The first step 'n this direction was the fo mation and operation of Energetix effective January 1, 1998. Energetix is an unregulated subsidiary of the Company that will br'ng energy products and services to the marketplace both w'thin and outside the Company's franchise area.
The Settlement approved by the PSC in Novembe" allows for the investment of up to $ 100 million in unregulated businesses during the next five years. During 1998, the Company expects to determine the actual level of the initial investments to be made in unregulatec business opportunities.
On July 1, 1997 the Company and Ene ge='x led with the, Federal Energy Regulatory Commission (FERC) seeking autnor'za"'on to engage in the wholesale sale of electric energy and capac'ty a" marke:-basec rates. These applications were accepted by FERC on September 2, 1997. .he Company mus" seek separate authorization in order to se)l elec"ric energy to Energetix at market-based rates.
Stock Repurchase Plan. In December 997 the Company's Board of Directors approved a Stock Repurchase Plan h's p'an. which is subjec" to approval by the PSC, provides for the repurchase over the nex: th ee years of up to 4.5 million shares of Common Stock, representing approximately 11.5 percent of the Company's outstanding shares of Common Stock a Decembe 31, 1997. The Company expects a PSC decision in early 1998.
Nuclear Operating Company. In October 1996, the Company and Niagara Mohawk Power Corporation (Niagara) announced glans to establish a nuclear operating company to be known as the New York Nuclear Operating Company (NYNOC). Since that time NYNOC has been organized as a New York Limited Liability Company and the Consolidated Edison Company of New York and -New York Power Authority have announced their desire to move forward with the Company and Niagara with plans to implement NYNOC. It is envisioned that NYNOC would eventually assume responsibility for operation of all the nuclear plants in New York State, including the Company's totally owned Ginna Nuclear Plant and jointly owned Nine Mile Two. The Company believes that NYNOC could contribute to maintaining a high level of operational performance, contribute to continued satisfactory Nuclear
25 Regulatory Commission (NRC) compliance, provide opportunities for continued cost reduction and provide the basis for satisfactory economic regulation the PSC.
various groups are now involved in the detailed studies and analyses by required before a definitive decision to proceed with NYNOC can be made. The organizing utilities have submitted comments on the PSC Staff position paper on nuclear generation (discussed below under the heading PSC Position Paper on Nuclear Generation) noting that the Staff proposal would nullify the potential benefits of NYNOC.
PSC POSITION PAPER ON NUCLEAR GENERATION. On August 27, 1997, the PSC requested comments from interested parties on a PSC Staff position paper concerning the treatment of nuclear generation after a transition period. The Staff paper concludes that (1) nuclear generation should operate on a competitive basis, (2) sale of generation plants at auction to third parties is the preferred means of determining market value and offers the greatest potential for mitigation of stranded costs and the elimination of anti-competitive subsidies, and (3) where third party sales are not feasible, "to-go" costs (fuel, other operating costs, prospective capital additions, property taxes andlabor and insurance) must be recovered in the wholesale market price of power.
On October 15, 1997, the Company and four other utilities jointly responded to the PSC. The utilities believe that the inherent operating characteristics nuclear generation and the implications of NRC regulation require that nuclear of plants have access to an adequate revenue stream and that such plants should be treated for dispatch purposes as baseload, must run units. ytilities urge the PSC to adopt a process that would enable all parties to The fully necessary facts and analyses and to invite the NRC to participate develop the ip addressing the future of nuclear generation in New York State. Certain other .parties filed comments on the position paper, some of which oppose full recovery ofhave "stranded costs" that could result from sales of plants at less than book costs.
The Company is unable to predict the outcome of the PSC's consideration.
I rules to facilitate the development of competitive early FERC OPEN TRANSMISSION ORDERS AND COMPANY FILINGS. In 1996 FERC issued new wholesale markets by requiring electric utilities to offe" "open-access" transmission service on a non-d'scriminatory basis in tariffs. The Company filed its required transmission serv'ce tar'ff on July 9, 1996. The new tariff would apply to wholesale purchases and sales made by the Company and the inancial impact will depend on prevailing energy prices in the wholesale market. The near-term of this tariff are not expected to be significant. On March 6, 1997, the impacts Company reached a settlement 'n principle with the othe" parties respecting rate issues. FERC approval of the settlement was granted on June 25, 1997.
On January 31, 1997, the utilit'es filed a "Comprehensive Restructure the New York Wholesale Electric Market" with the FERC. Proposal To As proposed, the existing New York Power Pool (NYPP) will be dissolved and an independent system operator (ZSO) will administer' state-wide open access tariff and provide for the short-term reliable operation of the bulk power system in the state. Zn addition to proposing a FERC-endorsed ISO, the proposal calls for creation of a New York Power Exchange and a New York S ate Reliability Council. An additional supplemental filing with FERC was made on December 19,1997 which lays out a specific timeframe for the implementation of a competitive wholesale market in New York State. The utilities have requested FERC approval electricity restructuring plan no later than March 31, 1998, which would allow the ofZSOtheir operational by June 30, 1998. The timetable for retail competition will be to be determined for each utility in accordance with individual settlements in the Competitive Opportunities Proceeding.
Significant changes to pricing procedures now in effect within NYPP are expected, but it is unclear what effect these changes regulatory changes in New York State are implemented. may have once other At the present time, the Company cannot predict what effects regulations ultimately adopted by FERC will have, if any, on future operations or the financial condition of the Company.
GAS RESTRUCTURING AND PSC NEGOTIATIONS. Zn March 1996 the PSC issued an Order and approved utility restructuring plans designed to open up the local
26 natural gas market to competition and thereby allow residential, small business and commercial/industrial users the same ability to purchase their gas supplies from a variety of sources, other than the local utility, that larger industrial customers already have. During a three-year phase-in period the State's gas utilities would be permitted to requireforcustomers converting from sales service which the utilities had originally to take associated pipeline capacity contracted. The PSC has indicated that it will address the issue of how the costs of such capacity would be recovered after the three-year period during the third year of the phase-in period. The PSC Staff has recently issued a position paper on The Future of the Natural Gas Industry in which the Staff proposes that local distribution companies (such as the Company) exit the merchant function in five years. Treatment of existing pipeline capacity contracts and Provider of Last Resort responsibilities are substantial issues to be worked out between the PSC, the local gas distribution companies and other stakeholders. See Note 10 of the Notes to Financial Statements for further:information about the PSC gas restructuring proceedings and the PSC Staff position paper.
Gas customers have had a choice of suppliers since November 1, 1996. Under separate transportation tariffs, the Company distributes the gas and charges for the distribution as well as associated services. The Company believes its position in the market is such that it will maintain its distribution system margins. Under a phase-in limitation, loss of gas commodity sales may be limited to five percent of the Company's annual gas volume the first year, and then five additional percent for each of the following two years. The phase-in will be reviewed as experience is gained with the program. The Company anticipates that the use of transportation gas service will increase. Through December 31, 1997, 150 customers were being served under this service Zn July 1997, the Company commenced negotiations with the PSC Staff and other parties with the objective of developing a multi-year settlement of issues pertaining to the Company's gas business that would take effect upon expiration of tne current 1995 Gas Settlement (see Rates and Regulatory Matters) on June 30, 1998. A further objective of these negotiations is to maximize the efficiencies o he entire business by structuring a settlement that will be as consistent as poss'ble with the provisions of the Settlement in the Competitive Opportun'ies Proceeding, as discussed earlier. Negotiations are at an early stage; accord'ngly, the Company can make no prediction as to their outcome.
COMPETITION AND THE COMPANY' PROSPECTIVE FINANCIAL POSITION. With PSC approval, the Company has deferred certa'n costs rathe" than recognize them on
'=s books when incurred. Such deferred costs are then recognized as expenses when they are included in rates and recoverec from customers. Such deferral accounting is permitted by SFAS-71. These deferred costs are shown as Regulatory Assets on the Company's Balance Sheet and a discussion and summarization of such Regulatory Assets is presented in No"e 10 o the Notes to Financial Statements.
Xn a competitive electric market, s" ancable assets would arise when investments are made in facilities, or costs are incurred to service customers, and such costs are not fully recoverable in market-based rates. Estimates of such strandable assets are highly sensitive to the competitive wholesale market price assumed in the estimation. Zn a competitive natural gas market, strandable assets would ar'se where customers m'grate away from dependence on the Company fo" full service, leaving the Company with surplus pipeline and storage capacity, as well as natural gas supplies, unde. con ract. A discussion of strandable assets is presented in Note 10 of the Notes to Financial Sta"ements.
At December 31, 1997 the Company bel'eves that its regulatory and strandable assets, if any, are not impaired and are probable of recovery. The Settlement in the Competitive Opportunities proceeding does not impair the opportunity of the Company to recover -'its investment in these assets. However, the PSC has published a Staff paper to address issues surrounding nuclear generation, including the determination of fair market value for facilities after a five year restructuring transition period. It appears that the PSC may seek to apply similar principles to other types of generating facilities. A determination in this proceeding could have an impact on strandable assets.
RATES AND REGULATORY MATTERS 27 0
1996 ELECTRIC RATE SETTLEMENT. The PSC approved a Settlement Agreement (1996 Rate Settlement) among the Company, PSC Staff and several other parties which set rates for a three-year period commencing July 1, 1996. The Competitive Opportunities Settlement (Settlement) supersedes the 1996 Rate Settlement. A rate reduction for the first rate year under the Settlement of 0.5 percent ($ 3.5 million) commencing July 1, 1997 is equal to the previously approved planned reduction under the 1996 Rate Settlement. After approval of the Settlement becomes final and non-appealable, the Company will terminate its petition seeking judicial review of the 1996 Rate Settlement.
1995 GAS SETTLEMENT. Zn October of 1995, a settlement of various gas rate and management issues was finalized (the 1995 Gas Settlement) . This settlement affects the rate treatment of various gas costs through October 31, 1998.
Highlights of the 1995 Gas Settlement are:
The Company will forego, for three years ending in mid-1998, gas rate increases exclusive of the cost of natural gas and certain cost increases imposed by interstate pipelines.
The Company has agreed not to charg'e customers for pipeline capacity costs in 1996, 1997 and 1998 of $ 22.5 million, $ 24.5 million,'apd $ 27.2 million, respectively. The Company may sell its excess transportee~on capacity in the market under FERC rules.
The Company agreed to write off excess gas pipeline capacity and other costs incurred through 1995.
The economic effect of the 1995 Gas Settlement on the Company's 1995 results of operations was to reduce earn'ngs by $ .75 per share.
The Company has entered into several agreements to help manage its p'pel'ne capacity costs and has successfu'y met settlement targets for capacity remarketing for the twelve months'eriods ending October 31, 1997 and October 31, 1996, thereby avoiding negative financial impacts for those periods. The Comoany believes that it will also be successful in meeting the Settlement targets in the remaining year of the Settlement period, although no assurance may be given.
FLEXZBLE PRZCZNG TARZFF. Under its lex'ble prie'ng tariff for major industr'al and commercial electric customers, the Company may negotiate competitive electric rates a" discount p ices to compete with alternative power sources, such as customer-owned generation fac'ities. Pursuant to the terms of the Settlement under the Competitive Opportunities Proceeding, the Company will absorb, as it has done since the inception of these rates, the difference between the discounted rates paid under these individual contrac"'s and the rates that would otherwise apply. Approximately 27 percen of all electric sales (KWHs) to customers are made under long-term con racts, primarily to large industrial customers. These contracts represent approximately 42 percent of the Company's revenues from its commercial and industrial customers. The Company has not experienced any significant customer loss due to competitive alternative arrangements. Certain provisions of a flexible rate contract with the University of Rochester have been challenged by the Antitrust Division of the United States Department of Justice as discussed in Note )0 to the Financial Statements under the heading Litigation.
LIQUIDITY AND CAPITAL RESOURCES d Cash flow, mainly from operations, provided the funds for construction expenditures, debt reductions, redemption of Preferred Stock and the payment of dividends during 1997 (see Consolidated Statement of Cash Flows). 4
28 CAPITAL AND OTHER REQUIREMENTS. The Company's capital requirements relate primarily to expenditures for energy delivery, including electric transmission and distribution facilities and gas mains and services as well as nuclear fuel, electric production and the repayment, of existing debt. In 1996 the Company completed replacement of the two steam generators at the Ginna Nuclear Plant which resulted in improved plant efficiency. The Company spent approximately $ 46 million on this project in 1996 and $ 29 million in 1995. The Company has no plans to install additional baseload generation.
Purchased Power Requirement. Under federal and New York State laws and regulations, the Company is required to purchase the electrical output of unregulated cogeneration facilities which meet certain criteria (Qualifying Facilities). The Company was compelled by regulators to enter into a contract with Kamine for approximately 55 megawatts of capacity, the. circumstances of which are discussed in Note 10 of the Notes tb Financial Statements. The Company has no other long-term obligations to purchase energy from Qualifying Facilities.
Year 2000 Computer Issues. As the year 2000 approaches many companies face a potentially serious information systems (computer) problem because most software application and operational programs written in the past will not properly recognize calendar dates beginning with the year 2000. At this time, the Company believes that the problem is being addressed properly to prevent any adverse operational or financial impacts. The Company believes approximately $ 15 million of costs through January 1, 2000, associated it will incur with making the necessary modifications identified to date. Total costs incurred in 1997 were approximately $ 1.4 million.
ENVIRONMENTAL ISSUES. The production and delivery of energy are necessarily accompanied by the release of by-products to environmental controls. The Company has taken a variety of measures subject (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 ene gy operations. A more detailed discussion env'ronmental matters, including a discussion ofconcerning the Company's the federal Clean Air Ac-Amendments, can be found in Note 10 of he Notes to Financial Statements.
REDEMPTION OF SECURITIES. In addition to first mortgage bond matur'ties anc mandatory sinking fund ob'igat'ons ove" the past three years, discret'onary redemption of securities totaled $ 1 million in 1995, $ 49 million in 1996, and approximately $ 152 million in 1997. Inc'uded in discretionary redemptions 1997 were nearly $ 102 million of tax-exempt securities which were refinancedfor with new mul '-mode tax-exempt bonds as d'scussed unde" F'nanc'ng.
29 CAPITAL REQUIREMENTS -
SUMMARY
. Capital requirements for the three-year period 1995 to 1997 and the current estimate of capital requirements through 2000 are summarized in the Capital Requirements table.
The Company's capital expenditures program is under continuous review and could be revised for any number of issues. The Company also may consider, as conditions warrant, the redemption or refinancing of certain outstanding long-term securities.
Ca ital Re irements Actual Projected 1995 1996 1997 1998 1999 2000 e of Facilities (Millions of Dollars)
Electric Property Production 48 $ 57 9 19 $ 17 13 Energy Delivery 25 23 28 43 32 28 Subtotal 73 80 37 62 49 41 Nuclear Fuel 17 16 19 15 16 27 Total Electric 90 96 56 77 65 68 Gas Property 14 17 22 23 17 18 Common Property 4 6 9 24 18 Total )08 119 87 124 100 92 Carrying Costs Allowance for Funds Used During Construction Total Construction Requirements Securities Redemptions, Maturities and Sinking Fund Obligations~
121 67 88 182 125 40 101 10 30 Total Capital Requirements $ 112 $ 188 $ 270 $ 165 $ 111 $ 123
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Excludes prospective refinancings.
FINANCING. Capital requirements in 1997, 'ncluding the discretionary redempt'on of $ 49.7 million of securities, were satisfied primarily
'nternally generated funds. Zn addition, the Company at its option with refinanced
$ 10 .9 million of outstanding tax-exempt securi"ies with the proceeds from sale on August 19, 1997 of $ 10'.9 million of New York State Energy Research the and Development Authority (NYSERDA) mult'-mode tax-exempt bonds due August 1, 2032.
".. crest rates on these bonds may be set weekly o" may be set for varying periods based on market conditions at the t'me. The we'ghted average interest rate on these bones was 3.65 percent for '997.
On September 16, 1997, the Company completed arrangements for the delivery in September 1998 of $ 25.5 million o= 5.95% NYSERDA tax-exempt bonds due September 1, 2033. Proceeds will be used to redeem an issue of tax-exempt first mortgage bonds which is not redeemab e until December 1998.
Under the Company's Performance Stock Option Plan, options for 403,605 shares of Common Stock became exerc'sable due to Common Stock performance during 1997. During 1997, Common Stock shares outstandingprice market by 10,883 shares as a result of those options which were actually exercised increased during the year. These were the only shares of Common Stock issued by the Company during 1997.
The Company foresees modest near-term financing requirements. With an increasingly competitive environment, the Company believes maintaining a high degree of financial flexibility is critical. Zn this regard, the Company's long-te m objective is to control capital expenditures. Moreover, in 1998 the Company may begin funding a stock repurchase program and investments in unregulated businesses as discussed under Competition.
30 Capital and other cash requirements during 1998 are anticipated to be satisfied primarily from a combination of internally generated funds and the use of short-term credit arrangements. The Company may refinance maturing long-term debt and Preferred Stock obligations during 1998 depending on prevailing financial market conditions.
The Company anticipates utilizing its credit agreements and unsecured lines of credit to meet any interim external financing needs prior to issuing any long-term securities. For information with respect to short-term borrowing arrangements and limitations, see Note 9 of the Notes to Financial Statements. As financial market conditions warrant, the Company may also, from time to time, redeem higher cost senior securities.
RESULTS OF OPERATIONS The following financial review identifies the causes of significant changes in the amounts of revenues and expenses, comparing 1997 to 1996 and 1996 to 1995.
The Notes to Financial Statements contain additional information.
OPERATING REVENUES AND SALES. Operating revenues in 1997 were lower than 1996 with the effect of electric base rate decreases in July 1996 and 1997 and lower therm sales of gas due to milder weather than last year partially offset by higher customer electric kilowatt-hour sales resulting from increased customers and higher electric sales to other utilities. Despite lower qpyrating 'revenues, operating revenues less fuel expenses were nearly unchanged rig/ecting primarily a decline in purchased electricity expense as a result of increased availability of the Company's generating facilities.
The effect of weather variations on operating revenues is most measurable in the Gas Department, where revenues from spaceheating customers comprise about 90 to 95 percent of total gas operating revenues. Compared to a year earlier, weathe" in the Company's service area was 9.0 percent warmer during the first three months of 1997 and 1.1 percent warmer for the entire year on a calendar month heating degree day basis. ln contrast, weather during 1996 was 7.1 percent colder than 1995 on a calendar month heating degree day basis. With elimination of a weather normalization clause in the Company's gas tariff effective November 1995, abno mal weather variations may have a more pronounced effect on gas revenues. Cooler than normal summer weather during 1997 and 1996 hampered the demand or air conditioning usage, with a more pronounced effect in 1997 with the 1997 weather being approximately 27 percent cooler'han 1996.
Compared with a year earlier, kilowatt-hour sales of energy to retail customers were up 1.2 percent in 1997, following a 0.3 percent increase in 1996.
Sales to commercial customers achieved the largest gain in 1997. Sales to industrial customers led the increase in 1996 compared to a year earlier and were driven by one large industrial. customer who purchased more electric power as an alternative to power produced at its own plant. Decreased electric demand for air conditioning usage caused by cooler summer weather had an. impact on kilowatt-hour sales in 1996 and 1997.
Fluctuations in revenues from electric sales to other utilities are generally related to the Company's customer energy requirements, the wholesale energy market, availability of transmission, and the availability of electric, generation from Company facilities. Revenues from electric sales to o"her utilities rose in 1997 due to increased sales resulting from greater market availability of our combined nuclear and fossil generation, a favorable wholesale in the second half of the year, and increased marketing of available capacity. Zn contrast to 1997, revenues from sales xw other electric utilities declined in 1996 reflecting decreased kilowatt-hour sales to such utilities and less generation from the Company's Ginna Nuclear Plant.
The transportation of gas for large-volume customers who are able to purchase natural gas from sources other than the Company is an important component of the Company's marketing mix. Company facilities are used to distribute this gas, which amounted to 16.6 million dekatherms in 1997 and 16.8 million dekatherms in 1996. These purchases by eligible customers have caused decreases in Company revenues, with offsetting decreases in purchased gas
31 expenses and, in general, do not adversely affect earnings because transportation customers are bil'led at rates which, except for the cost of buying and transporting gas to the Company's city gate, approximate the rates charged the Company's retail gas service customers. Gas supplies transported in this manner are not included in Company therm sales, depressing reported gas sales to non-residential customers.
Therms of gas sold and transported were down 4.1 percent in 1997, after increasing nearly eight percent in 1996. These changes reflect, primarily, the effect of weather variations on therm sales to customers with spaceheating. Zf adjusted for normal weather conditions, residential gas sales would have decreased about 1.5 percent in 1997 over 1996, while non-residential sales, including gas transported, would have increased approximately two percent in 1997. The average use per residential gas customer, when adjusted for normal weather conditions, showed a modest decrease.4n 1996 and 1997.
FOSSIL UNIT RATINGS AND STATUS. Several of the Company's fossil-fueled generating units have been temporarily derated since February 1997 to maintain acceptable opacity levels while the Company investigates additional engineering solutions to address the opacity of the Units'missions ( see Note 10 of the Notes to Financial Statements under the heading "Environmental Matters, Opacity Issue" ). The financial impact of the deratings includes the lost opportunity associated with energy sales and, at times, the need to make additional purchases to meet system requirements. While the deratings have decreased earnings, and will continue to do so, the amount is not expected to be materia/.
The NYPP is in the process of evaluating new rules for Zth system load regulation. Opacity limitations are expected to reduce the ability of the Company to react to changes in load and provide system load regulation services when called upon by the NYPP, resu'lting in additional costs. Depending on the new NYPP requirements, and whether the deratings remain in effect the revised rules could result in the Company having to purchase additional regulation se vices which may cost between $ 500,000 and $ 2,500,000 annually. The Company
'ntends to make a $ 2.7 million cap'tal upgrade to the precipitator of one of its fossil-fueled generating units which is expected to remove a substantial portion of the opacity exceedance which lec to the derating.
On January 21, 1998 the Company dec'ded to ret're Beebee Station by mid-
'999. Factors such as the plant's age, 'oca=ion 'n an area no longer consistent w' the surrounding development, lack o>> a rail/coal delivery system and more stringent clean air regulations made the plant uneconomical in the developing compe"itive generation business. The ret'rement of Beebee Sta"ion is not expected to have a material effec" on the Co'pany's financial pos'ion or results of operations. The plant w'll be fully deprec'a ed a" the t'me of retirement.
The Settlement provides tha" all pruden ly inc rred 'ncremental costs associated i"
w'th the shu" down and decommission'ng of the p an" are recoverable through the Company's distribution access ta . The elec="'c capabil'ty and energy currently provided by the plant is expected to be replaced by purchased power as needed.
On December 1, 1997 Niagara anno .need a plan to se'1 ' fossil-fueled and hydroelectric generating stations by a c=ion '.". '998. This plan was agreed to as part of Niagara's Power Choice Settlemen: currently under review by the PSC. The Company intends to include its 24 percen= share of the Oswego Steam Station Unit 6 (Oswego 6) for sale as part of Niagara's auc"ion. Any gains or losses realized by the Company from the sale of i"s share o'swego 6 would be treated in accordance with the terms of the Se"tlement under the Competitive Opportunities Proceeding.
OPERATING EXPENSES Energy Costs - Electric. Higher fuel expense for electric generation in 1997 compared with a year earlier reflects increased generation from both fossil and nuclear-fueled plants. Total Company electric generation was up approximately 21 percent in 1997 over 1996 For the 1996 comparison period, lower
~
electric fuel costs resulted from less electric generation. The fuel cost adjustment clause has been eliminated effective July 1, 1996. Company
32 shareholders will assume the full benefits and detriments realized from actual with PSC-approved forecast electric fuel costs and generation mix compared amounts.
The Company normally purchases electric power to supplement its own generation when needed to meet load or reserve requirements, and when such power is available at a cost lower than the Company's production cost. Increased availability and efficiencies following the 1996 installation of new steam generators at the Ginna nuclear plant resulted in lower kilowatt-hour purchases
.of electricity in 1997 which led to a decline in purchased electric powe expense. Despite an increase in kilowatt-hours purchased in 1996, electric purchased power expense was also down in 1996 reflecting, in part, lowe purchases from the higher-cost Kamine facility as discussed below.
Unde a contract with Kamine, the Company has been required to purchase unneeded energy at uneconomical rates (see Note 10 of the Notes to Financial Statements). The Company purchased 337 thousand megawatt-hours of energy rom Kamine at a total price of $ 16.6 million in 1995. The Kamine facility has been out of service since the middle of February 1996 which helped to lower the unit cost for purchased electricity in 1996 compared to 1995.
Energy Management and Costs - Gas. The Company acquires gas supply and transportation capacity based on its requ'rements to meet peak loads which occur in the winter months. The Company is committed to transportation capacity on the Empire State Pipeline (Empire) and the CNG Transmission Corporation (CNG) pipeline systems, as well as to upstream pipeline transportation,and storage services. The combined CNG and Empire transportation capacity'-1's adequate to meet the Company's current requirements.
For the 1997 comparison period, gas purchased for resale expense declined driven by a reduced volume of purchased gas resulting from a warmer heating season. Higher commodity costs and increased volumes of purchased gas caused an increase in gas purchased for resale expense in 1996 compared to 1995.
Operations Excluding Fuel Expenses. Fo" the 1997 comparison period, the
'ncrease in operations exclud'ng fuel expenses reflects mainly higher outside serv'ces expenses, recognition of obsolete and unproductive materials 'nventory, s"orm costs, and regulatory compliance costs partially offset by lower payroll cos"s and decreased expense associatec with uncollectible accounts. For the 1996 co;..par'son period, the increase in opera 'ons excluding fuel expenses reflects
'y ma'nly h'gher payroll costs and an increase in amortization expense beginning 1, 1996 for customer information system enhancements. Higher payroll costs for this period reflects amortization of additional early retirement costs for programs concluded in October 1994 and greater employee redeployment/outplacement cos=s. An additional expense accrual fo doubtful accounts increased operating expenses by $ 15.0 million in '995.
Tne Company is continuing to =ake aggress ve steps o mprove its co'lec" ion efforts. Uncollectible expense i.. 1997 was $ 18 million, compared with
$ 20 million in 1996. In 1995, unco'ee" 'ble expense was $ 23 million.
For both comparison periods, the 'ncrease in deprecia ion expense reflects primarily results from depreciation of the new Ginna nuclear plant steam generators (approximately $ 800,000 additional expense per month) and recovery of increased nuclear decommissioning expense of approximately $ 3.2 million per quarter beginning July 1, 1996.
Taxes Charged To Operating Expenses. Local, state and other taxes decreased in 1997 reflecting mainly lower property taxes due to decreases in assessments and/or rates and lower revenue taxes due to decreases in revenues and the New York State revenue tax surcharge rate. The decrease in these taxes for 1996 reflects mainly lower property taxes due to decreases in assessments.
The decrease in federal income tax in 1997 reflects mainly the reversal of a prior provision for the in-service date of Nine Mile Two as a result of an agreement reached with the Internal,Revenue Service.
33 OTHER STATEMENT OF INCOME ITEMS. For the 1996 comparison period, the variation in non-operating federal income tax reflects mainly accounting adjustments related to regulatory disallowances.
Recorded under the caption Other Income and Deductions is the recognition of regulatory disallowances in connection with the 1995 Gas Settlement (see Rates and Regulatory Matters).
Other (Income) and Deductions, Other--net decreased in 1997 due mainly to recognition of expense associated with management performance awards and the Company's Performance Stock Option Plan. For the 1996 comparison period, Othe" (Income) and Deductions, Other -- net increased mainly due to the elimination in 1996 of two accrued expenses in 1995 related to depreciation expense for the Empire State Pipeline and amortization of certain employee early retirement costs.
Both mandatory redemptions and the optional redemptions of certain higher-cost long-term debt have helped to reduce long-term debt interest expense over the three-year period 1995-1997. Compared to the prior year, the average short-term debt outstanding was up slightly in 1997 following a decrease in 1996.
Preferred Stock dividends decreased in 1997 due to the Company's discretionary redemption in April of its 7.50% Preferred Stock, Series N and the mandatory sinking fund redemption of its 7.45% Preferred Stock, Series S in September.
DIVIDEND POLICY. The level of future cash dividend pay>5'ehts on Common Stock will be dependent upon the Company's future earnings, its fihancial requirements, and other factors. The Company's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company.
34 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA A. FINANCIAL STATEMENTS Report of Independent Accountants Consolidated Statement of Income for each of the three years ended December 31, 1997.
Consolidated Statement of Retained Earnings for each of the three years ended December 31, 1997.
Consolidated Balance sheet at December 31, 1997 and 1996.
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1997.
Notes to Consolidated Financial Statements.
Financial Statement Schedules:
The following Financial Statement Schedule is submitted as part of Item 14, Exhibits, Financial Statement Schedules and Reports on Form S-K, of this Report. (All other Financial Statement Schedules are omitted because they are not applicable, or the required information appears in, the Financial Statements or the Notes thereto.)
Schedule II - Valuation and Qualifying Accounts.
B.~ SUPPLEMENTARY DATA I I r im Financial Data.
Inter
35 REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors of Rocheste" Gas and Electric Corporation In our opinion, the consolidated financial statements listed under Item SA in the index appearing on the preceding page present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial 'statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opiinon expressed above.
/s/ PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP Rocnester, New York January 23, 1998
CONSOUDATED STATEMENT OF INCOME usands of DoLtrs) Year Ended December 31 1997 1996 1995 Operadng Revenues Eleculc $ 679.473 $ 690.883 $ 696.582 Gas 336.309 346.279 293.863 1.015.782 1,037,162 990,445 Etectiic safes to other utilities 16.885 25.883 Total Operating Revenues 1,036.638 1.054.047 1,016,328 Operating Expenses Fuel Expenses Fuel for etectnc generaten 47.665 40.938 44.190 Purchased electrfcrty 28.347 46.484 54,167 Gas purcnased for resale 196579 m.297 167762 Total Fuel Expenses 272.591 289.719 266,119 Operating Revenues Less Fuel Expenses 764,047 764328.'66.094 Other Operating Expenses Operations exdudrng tuel expenses 268,474 259W7 Maintenance 46.635 47,063 49.226 Depreciation and amoruzation 1'I 6.522 105.614 91,593 Taxes. local. state and other 121,796 126.868 133,895 Federal income tax 65 279 69.501 66.215 Total Other Operating Expenses 61 8 706 615,1 40 600.1 36 Operating Income 145341 149.188 150.073 Other (Income) and Deductions AIJOWanCC Ior other funds used during construction (351) (684) (585)
Federal income tax (3.704) (3.450) (16.948)
Regulatory disatlowances 26.866 Other. net 3308 (712) 9.631 Total Other (Income) and Deductions (747) (4.846) 18,964 st Charges tenn debt 44.615 48.618 53.026 er. nel 6.676 9.328 9.056
~sowance Ior borrowed funds used dunng constructen (563) (1.423I (2.901)
Total Interest Charges 50.728 56.523 59,181 Nel InCOme 95360 97.511 71.928 Divxfends on Prefened Stock 5.805 7.465 7.465 Earrxngs Apphcable to Common Stock $ 89.555 $ 90.046 $ 64.463 Earnings per Common Share ~ Base $ 2.30 $ 2.32 $ 1,69 Earnings per Common Share ~ Dsuted $ 2.30 $ 232 st 69 CONSOLIDATED STATEMENT OF RETAINED EARNINGS (Thousands ot Dollars) Year Ended December 31 1997 1996 1995 BalanCe at Beginnrng Ol PenOd $ 90.540 $ 70.330 $ 74.566 Add Net Income 95,360 97,51 1 71.928 AdiuStment ASSOCiated Wrth SIOCk RedemPten f846}
Total 185.054 167.841 146.494 Deduct Drvxtends declared on catxtat stock Cumutatrve prefened stock ~ at required rates 5.805 7.465 7.465 Common Stock 69.936 69.836 68.699 Total 75.741 77.301 76.164 Balance al End ol Period $ 109.313.'90 540 $ 70.330 Cash Dividends Declared per Common Share $ 1.80 $ 1.80 $ 1.80 ccompanying notes are an integral part ol the finanCial statements.
37 CONSOLIDATED BALANCE SHEET thousands of Dollars) ~
At December 31 1997 1996 Assets Utility Plant Electric $ 2,439,108 $ 2.413,881 Gas 416,989 391,231 Common 134,938 129,946 Nuclear fuel 243,042 224,701 3.234.077 3,159,759 Less: Accumulated depreciation 1.510,074 1,381,908 Nuclear fuel amortization 204.294 187.170 1,519,709 1,590,681 Construction work in progress 74.018 69,711 Net Utility Plant 1,593,727 1,660.392 Current Assets Cash and cash equivalents 25,405 21,301 Accounts receivable, net of allowance for doubtful accounts:
1997 ~ $ 26,926; 1996 - $ 17,502 104,781 112,908 Unbilled revenue receivable 48,438 53,261 Matenals, supplies and fuels 39,929 39,888 Prepayments 23,818 23,103 Total Current Assets 242.371 250,461 Deferred Debits Nuclear generating plant decommissioning fund 132,540 91,195 Nine Mile Two deferred costs 30,309 31,360 Unamortized debt expense 16,943 14,820 Other deferred debits 20,411 28,759 Regulatory assets 231~988 284,489 Total Deferred Debits 432,191 450,623 Total Assets $ 2.268.289 $ 2.361.476 Capitalization and Liabilities Capitalization Long term debt - mortgage bonds $ 485.434 $ 555.054
- promissory notes 101,900 91,900 Preferred stock redeemable at option of Company 47.000 67,000 Preferred stock subject to mandatory redemption 35.000 45.000 Common shareholders'quity:
Common stock 699.031 696.019 Retained earnings 109.313 90.540 Total Common Shareholders'quity 808.344 786.559 Total Capitalization 1.477,678 1.545,513 Long Term Liabilities (Department of Energy)
Nuclear waste disposal 83.261 79.057 Uranium enrichment decommissioning 13.465 14.695 Total Long Term Liabilities 96.726 93.752 Current Liabilities Long term debt due'within one year 30.000 20.000 Preferred stock redeemable within one year 10,000 10,000 Short term debt 20.000 , 14.000 Accounts payable 53,195 49,462 Dividends payabte 18,791 19.349 Taxes accrued 5.041 4,694 Interest accrued 8.593 10,317 Other 43.697 30,395 Total Current Liabilities 189.317 158,217 Deferred Credits and Other Liabilities Accumulated deferred income taxes 344,969 370,028 Pension costs accrued 67,361 69,806 Other 92.238 124,160 Total Deferred Credits and Other Liabitities 504.568 ~
563.994 Commitments and Other Matters Total Capitatization and Liabitities $ 2.268.289 $ 2.361.476 The accompanying notes are an integral part of the financial statements.
CHESTER GAS AND ELECTRIC CORPORATION ONSOLIDATED STATEMENT OF CASH FLOWS (Thousands of Dollars) Year Ended December 31 1997 1996 1995 CASH FLOW FROM OPERATIONS Net income 95,360 97,511 $ 71,928 Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization 133,942 121,824 109,575 Deferred fuel 489 (6,501) 3,432 Deferred income taxes (10,064) 6,391 (8,047)
Allowance for funds used during construction (914) (2,107) (3,486)
Unbilled revenue, net 4,823 10,908 (9,899)
Stock option plan 2,399 Nuclear generating plant decommissioning fund (20,331) (11,732) (8,837)
Pension costs accrued (3,398) (2,494) 6,280 Post employment benefit internal reserve 6,189 6,626 4,636 Regulatory disallowance 26,866 Provision for doubtful accounts 5,078 4,987 14,893 Changes in certain current assets and liabilities:
Accounts receivable 3,049 3,228 (25,599)
Materials, supplies and fuels '41)
~" (1,238) 6,837 Taxes accrued 347 =.'13,944) 15,167 Accounts payable 3,733 (3',116) 9,644 Other current assets and liabilities, net 7,344 (5,186) 9,639 er, net 6,847 28,762 Total Operating 234.852 201.226 251.791 CASH FLOW FROM INVESTING ACTIVITIES Net additions to utility plant (84,068) (114,274) (109,547)
Other, net (1) 9,204 11,124 Total Investing CASH FLOW FROM FINANCING ACTIVITIES Proceeds from:
Sale/Issuance of common stock 272 8.612 17,074 Issuance of long term debt 101,900 Short term borrowings, net 6.000 14,000 (51,600)
Retirement of long term debt (151,568) (67,332) (1,000)
Retirement of preferred stock (30.000)
Dividends paid on preferred stock (6.366) (7,465) (7,465)
Dividends paid on common stock ~
(69.933) (69,657) (68,347)
Other. nel Total Financing Increase (Decrease) in cash and cash equivalents 3,016 (146,679) 4,104 $
2,866 (118.976)
(22,820)
~1 12,05/7 41,311 Cash and cash equivalents at beginning of year 21,301 $ 44,121 2,810 Cash and cash equivalents at end of year 25 405 $ 21.301 $ 44.121 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Thousands of Dollars) Year Ended December 31 1997 1996 1995 Cash Paid During the Year Interest paid (net of capitalized amount) 50,681 55,545 $ 56,592 me taxes paid 70.500 76.890 $ 43.500 The accompanying notes are an integral part of the financial statements.
39 NOTES TO FINANCIAL STATEMENTS Note 1. SUIQfARY OF ACCOUNTING PRINCIPLES GENERAL. The Company supplies electric and gas services .wholly within the State of New York. Zt produces and distributes electricity and distributes gas in parts of nine counties centering about the City of Rochester. The Company is subject to regulation by the public Service Commission of the State of New York (PSC) under New York statutes and by the Federal Energy Regulatory Commission (FERC) as a licensee and public utility under the Federal Power Act. The Company's accounting policies conform to generally accepted accounting principles as applied to New York State public utilities giving effect to the ratemaking and accounting practices and policies of the PSC...
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
A description of the Company's principal accounting policies follows.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries Roundel (now "Energetix") and Energyline. All intercompany balances and 'tg~sactions have been eliminated.
Energyline was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. Zn late 1996, Energyline sold its investment in the Empire State Pipeline.
The Roxdel (now "Energetix") activity is insignificant to the Company's financial position and results of operation.
RATES AND REVENUE. Revenue is recorded on the basis of meters read. Zn addition, the Company records an es imate of unbilled revenue for se vice rendered subsequent to the mete"- ead date "hrough the end of the accounting per'od.
Through June 30, 1996, tarif s for electr'c 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 connec=ion with a rate settlement agreement w' the PSC.
In prior years, retail customers who used gas fo spaceheating were subject to a weather normalization adjustment to eflect the impact o variations from normal weather on a billing month basis for ne months of Oc ober through May, inclusive. On January 25, 1995, the Company suspended thd weathe" normalization adjustment in an effort to mitigate high bi'lings due to the warm weather, and the suspension became permanen". This decreased 1995 pre-tax earnings from gas operations by $ 5.8 million.
The Company continues to use gas cost deferral accounting. A reconciliation of recoverable gas costs with gas evenues is done annually as of August 31, and the excess or deficiency is refunded to or recove ed 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 unde" 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
40 lowance for Other Funds Used During Construction, a part of Other Income. The rate approved by the PSC for purposes of computing AFUDC was 5.0% during the three-year period ended December 31, 1997. Replacement of minor items of property is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage', are charged to the accumulated depreciation reserve.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and short-term commercial paper. These investments have original maturity not exceeding three months. Such investments are stated at cost, which approximates fair value, and are considered cash equivalents for financial statement purposes.
INVESTMENTS ZN DEBT AND EQUITY SECURITIES. The Company's accounting policy, as prescribed by the PSC, with respeot to its nuclear decommissioning trusts is to reflect the trusts'ssets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability.
GAS SUPPLY. The Company periodically enters into agreements to m'nimize price risks for natural gas in storage. Gains or losses resulting from these agreements are deferred until the corresponding gas is withdrawn from storage and delivered to customers.
RESEARCH AND DEVELOPMENT COST. Research and Development costs were charged to expense as incurred. Expenditures for the years 1997, 1996,,and 1995 were
$ 4.5 million, $ 4.9 million and $ 5.2 million respectively.
ENVIRONMENTAL REMEDIATION COSTS. The Company accrues for lo'sses 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 feas'b'lity study.
Such acc uals are adjusted as further information develops or circumstances change. Costs of future expenditures fo" environmental remediation obligations are not d'scounted to their presen= value.
MATERIALS SUPPLIES AND FUELS. Ma"er'als and supplies inventories are va'uec a" the lower of cost or market us'ng the f'rst-in, first-out method. Fuel inventories are valued at average cost. The Company periodically enters into agreements to minimize price risks for natural gas in storage. Gains or losses resulting from these agreements are deferred until the corresponding gas is w'hdrawn from storage and delivered to customers.
STOCK-BASED COMPENSATION. F'nancial Accounting Standards Board Statement No. 123 (SFAS-123), Accounting fo" S"ock-Basec Compensation, was adop"ed by the Company in the first quarter o. '996. I reco.-....ends he use of a fai value based method of accounting for compensation cos=s associa"ed with stock-based compensation. The Company currently "..as S ock Apprec'ation Rights plans cover'ng certain employees and directors. Fo" these p'ans, the Company's accounting policy has been to use a fai" value method o" comput'ng periodic compensation expense. SFAS- 123 was applied to the valuation of the 1996 Performance Stock Option Plan (PSOP), which became effect've on January 22, 1997. The aggregate amount charged to expense as a result of these plans approximates $ 1.0 million annually in 1996 and 1995, and approximates $ 8.2 m'llion in 1997. Additional information on the PSOP is included 'n Note 8.
RECLASSZFZCATZONS. Certain amounts in the prior years'inancial statements were reclassified to conform with curren year presentation.
EARNINGS PER SHARE. SFAS-128, Earn'ngs Per Share, was adopted by the in the fourth quarter of 1997. This statement replaces the presentation 'ompany of primary Earnings Per Share with Basic Earnings Per Share, and also requires presentation of Diluted Earnings Per Share. Basic Earnings Per Share (EPS) is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding. for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue
41 common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the Company.
The following table illustrates the calculation of both Basic and Diluted EPS for the year ended December 31, 1997:
Income Shares Per-Share (Numerator) (Denominator) Amount Basic EPS:
Net Income $ 95,360 Less:
Preferred Stock Dividends (5,805)
Income available to Common Shareholders 89,555 38,853 2.30 Diluted EPS:
Effect of Dilutive Securities Stock Option Plan 56 Income available to Common Shareholders plus assumed conversions $ 89,555 38,909 ~2. 30 As there were no dilutive shares in prior years, basic and dilutive ea nings per share were the same for 1996 and 1995.
e
42 Note 2. FEDERAL INCOME TAXES The provision for federal income taxes is distributed between operating expense and other income based upon the treatment of the various components of the provision in the rate-making process. The following is a summary of income tax expense for the three most recent years.
(Thousands of Do'lars) 1997 1996 1995 Charged (Credited) to operaring expenser Currerc $ 69,812 $ 65,757 $ 65,368 Deco""ed (4.533) 3.744 847 Total K~, ZB .
~
Kg/H Charged (Credited) to other income:
Curren 1,828 (6,097) (9,996)
Defer ed (3, 100) 5, 079 (4,520)
Dofe red investnent ax credit (2.432) (2.432) (2,432)
Total lY. TOiT 73. <E67 (~JUG Total federal income tax expense $ 61,575 66,051 $ 49,267 The following is a reconciliation of the difference between the amount of federal income tax expense reported in the Consolidated Statement of I()c'ome.and the amount computed at the statutory tax rate of 35%.
(Thousands of Dollars) 1997 1996 1995
$ 95,360 $ 97,511 $ 71,928 Adc: feaera. income tax expense 61,575 66 49.267 Zr.come before fede al incone tax $ 156,935 05'163.562 21, '95 Comp ".ed cax expense a. scarucory tax race $ 54.927 $ 57,247 $ 42, 418 ncreases (decreases) in cax resulting from:
Difference between tax depreciation and amo .".= deferred 10,772 10,796 7, 197 Deferred investment ax credit (2,432) (2,432) (2,432)
Y..sce laneous items, nec (1,692) 440 2. 084
.o a federa! !rear..e tax expense $ 61.575 $ 66.051 $ C9.267 A summary of the components of the ne" deferred tax liability is as fo'ows:
(.housards of Dollars) 1997 1996 1995
'.r clear deco-...".,issioring $ (20. 807) S (17. 880) $ (1C,797)
Accelerated depreciacion 2!6,70C 213,907 197,952 Deferred investment tax credit 27.98! 29,562 31, 143 Deprecia ion previously flowed through 157.538 169.562 183,077 Pension (23,166) (24,570) (24,241)
Ocher ( 3.281) (553) C. 518 To a! $ 34C,969 $ 370,028 $ 377,652
43 SFAS-109 "Accounting for Income Taxes" requires that a deferred tax liability must be recognized on the balance sheet for tax differences previously flowed through to customers. Substantially all of these flow-through adjustments relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation of these accounts. The net amount of the additional liability at December 31, 1997 and 1996 was $ 160 million and 4175 million, respectively. In conjunction with the recognition of this liability, a corresponding regulatory asset was also recognized.
44 Note 3. PENSION PLAN AND OTHER POST EMPLOYMENT BENEFITS The Company has a defined benefit pension plan covering substantially all of its employees. The benefits are based on years of service and the employee's compensation. The Company's funding policy is to contribute annually an amount consistent-with the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. These contributions are intended to provide for benefits attributed to service to date and for those expected to be earned in the future.
The plan's funded status and amounts recognized on the Company's balance sheet are as follows:
(Millions) 1997 1996 Accumulated benefit obligation, including vested benefits of $ 384.7 in 1997 and
$ 374.6 in 1996 404.0
- 392.6
- Projected benefit obligation for service rendered to date $ (499.3) * $ (480.2) +
Less: Plan assets at fair value, primarily I listed stocks and bonds 638.4 567.1 Plan assets Un in excess of projected benefits ecognized net loss (gain) from past 139.1 ~ '6.9 f experience different from that assumed and effects of changes in assumptions ( 219.0) (170.7)
Prior service cost not yet recogn'zed in net periodic pension cost 10 ' 11.6 U..recogn'zed net obligation at December 31 2.4 Pension costs accrued 67.4 $ 69.8 Actuarial present value.
Ne" pens'on cost included the follow'ng components:
(Millions) 1997 1996 1995 Service cost - benefits earned during the per'od $ 6.2 $ 7.4 $ 6.0 In"crest cost on projected benefit obligation 33.0 33.4 35.4 Actual return on plan assets" (104.3) (80.8) (101.1)
Net amortization and deferral 63.1 39.0 56.1 Net periodic pension (credit) cost CZ~Z The projected benefit obligation at December 31, 1997 and December 31, 1996 assumed discount rates of 6.75% and 7-.25%, respectively, and a long-term rate of increase in future compensation levels of 5.00%. The assumed long-term rate of return on plan assets was 8.50%. The unrecognized net obligation is being amortized over 15 years beginning January 1986.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to retired employees and health care coverage for surviving spouses of retirees. Substantially all of the Company's employees are eligible provided that they retire as employees of the Company. In
45 1997, the health care benefit consisted of a contribution of up to $ 200 per retiree per month towards the cost of a group health policy provided by the Company. The life insurance benefit consists of a Basic Group Life benefit, covering substantially all employees, providing a death benefit equal to one-half 0
of the retiree's final pay. In addition, certain employees and retirees, employed by the Company at December 31, 1982, are entitled to a Special Group Life benefit providing a death benefit equal to the employee's December 31, 1982 pay.
SFAS-106, "Accounting for Postretirement Benefits Other than Pensions",
allows the Company to amortize the initial unrecognized, unfunded Accumulated Postretirement Benefit Obligation at January 1992 estimated at $ 56 million over twenty years. The Company intends to continue funding these benefits as the benefit becomes due.
The plan's funded status reconciled with the Company's balance sheet is as follows:
(Millions) 1997 1996 Accumulated postretirement benefit obligation:
Retired employees $ (73 9)
~ $ (65 6)~
Active employees (15.1) (13.5)
Less - Plan assets at fair value 0.0' -"
.~i 0.0 Accumulated postretirement benefit obligation (in excess of) less than fair value of assets (89.0) (79. 1)
Unrecognized net loss (gain) from past experience different from that assumed and e fects of changes in assumptions 3.7 Pr'or service cost not yet recogn'zed in ne" pe iodic pension 8.9 7 1 net obligation at December 3 cost'nrecognized 39.5 42.3 Accrued postretirement benefit cos= 32.2 26.0 Net periodic postret'emen= bene='= cos: 'nc'ec he following components (M':1'ons) 997 '996 Service cost - benefits a tribu ed o he pe='oc $ 0.9 $ 1.0 Interest cost on accumulated pos="e= remen=
benefit obligation 5.8 5.4 Actual return on plan asse=s 0.0 0.0 Net amortization and deferral 3 5 4.2 Net periodic postretirement bene: cos" The Accumulated Postretirement Bene i Obligation at December 31, 1997 and 1996 assumed discount rates of 6.75%, and 7.25%, respectively, and long-term rate of increase in future compensation levels of 5.00%.
SFAS-112, "Employers'ccounting for Postemp)oyment Benefits", requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employmen: but before retirement. The Company has been allowed to recover this cost in rates.
46 Note 4. DEPARTMENTAL FINANCIAL INFORMATION The Company's records are maintained by operating departments, in accordance with PSC accounting policies. The following is the operating data for each of the Company's departments, and no interdepartmental adjustments are required to arrive at the operating data included in the Consolidated Statement of Income.
(Thousands of Dollars) 1997 1996 1995 Electric Operating Information Operating revenues 700,329 $ 707,768 $ 722,465 Operating expenses, excluding provision for income taxes 516,793 521,222 523,105 Pretax operating income 183,536 186,546 199,360 Provision for income taxes 61,837 61,901 59,500 Net operating income $ 121,699 $ 124,645 $ 139,860 Other Information Depreciation and amortization $ 103,395 &2.> 615 78,812 Nuclear fuel amortization 17,419 16;209; $ 17,982 Capital expenditures $ 58,522 95, 334' 93,634 Investment Information, Identifiable assets (a} $ 1,783,825 $ 1,877,224 $ 1,913,762 Gas Opera"'ng Information Opera"'ng revenue S 336,309 S 346,279 $ 293,863 Opera"'ng expenses, excluding prov's'on for income taxes 309,225 314,136 276,935 Pre=ax operating income 27,084 32,143 16,928 Prov'sion for income taxes 3,442 7,600 6,715 Ne" ope at'ng income S 23,642 S 24,543 S 10,213 0"her nforma=ion Deprec ation S 3, 27 S 2,999 $ 12,781 Capital expenditures S 25,546 S '8,940 $ 15,913 Investment Information Iden"ifiable assets (a) S 44 ,849 S 447,865 $ 477,758 (a) Excludes cash, unamortized debt expense, anc other common items.
47 Note 5. JOINTLY-OWNED FACILITIES The following table sets forth the jointly-owned electric generating facilities in which the Company is participating. Both Oswego Unit No. 6 and Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated by. Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share of direct expenses associated with these two units is included in the appropriate operating expenses in the Consolidated Statement of Income. Various modifications will be made throughout the lives of these, plants to increase operating efficiency or reliability, and to satisfy changing environmental and safety regulations.
Oswego Nine Mile Point Unit No. 6 Nuclear Unit No. 2 Net megawatt capability (summer> 788 1,128 RG&E's share - megawatts 189 158
- percent 24 14 Year of completion 1980 1988
) 1
~ ~
(Millions of. Do3;lars)
December 31, '1997 Plant Zn Service Balance .
$ 98.9 $ 879.3 Accumulated Provision For Depreciation $ 41.4 $ 478.7 Plant Under Construction $ 0.6 3.3 The Plant in Service and Accumulated Provision fo" Depreciation balances for Nine Mile Point Nuclear Uni" No. 2 shown above include disallowed costs of S374.3 mlion. Sucn costs, net of 'ncome tax effects, were previously written o'f in 1987 and 1989.
48 Note 6. LONG-TERM DEBT FIRST MORTGAGE BONDS (Thousands of Dollars)
Principal Amount December 31 Series Due 1997 1996 6 1/4 W Sept. 15, 1997 20,000 6.7 X July 1, 1998 30,000 30,000 8.00 Y Aug. 15, 1999 ,29,668 6 1/2 EE Aug. 1, 2009 10,000 8 3/8 OO(al Dec. 1, 2028 25,500 25,500 9 3/8 PP Apr. 1, 2021 100,000 100,000 8 1/4 QQ(b) Mar. 15, 2002 100,000 100,000 6.35 RR(a> May 15, 2032 10,500 10,500 6.50 SS (al May 15, 2032 50,000 50,000 7.00 (b) (c) Jan. 14, 2000 30,00Q 3Q,OOQ 7.15 (b) (c) Feb. 10, 2003 39,000 39,000 7.13 (b) (c) Mar. 3, 2003 1,000 1,000 7.64 (c) Mar. 15, 2023 33,000 33,000 7.66 (c) Mar. 1S, 2023 5,000 5,000 7.67 (c) Mar. 15, 2023 12,000.'0,000 12,000 6.375 (b) (c) July 30, 2003 40,000 7.45 (c) July 30, 2023 40,000 40,000 45T~K sFT5, 6Uf Net bond discount (566) (614)
Less: Due within one year Total 30,000
~l(E l~ 20,000
~~184 (a) The Series OO, Series RR and Series SS First Mortgage Bonds equal the principal amount of and provide fo" all payments of pr'ncipal, premium and interest corresponding to the Pollutior. Control Revenue Bonds, Series C, and Pol)ution Control Refunding Revenue Bonds, Series 1992 A, Series 1992 B (Rochester Gas and Electric Corporatior. Projec s), respectively, issued by tne New York State Energy Research and Development Authority (NYSERDA) through a participation agreement with the Company. Payments of the pr'ncipal of, and irterest on the Series 1992 A 'and Series 1992 B Bonds are guaranteed under a Bond insurance Pol'cy by MB:A Insurance Corporation.
(b) The Series QQ F'rst Mortgage Bonds and he 7%, 7.15(', 7. 13% and 6.375~
medium-term notes descr'bed be ow are genera lv no" redeemable prior to maturity.
(c) Xn 1993 the Company issued $ 200 mon nder a medium-term note program entitled "First Mortgage Bonds. Designa ed Secured Medium-Term Notes, Series A" with maturities that range =rom seve.-. years to thirty years.
The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by the Company (except cash and accounts receivable).
Sinking and improvement fund requirements aggregate $ 333,540 per annum the First Mortgage, excluding mandatory sinking funds of individual series. 'nder Such requirements may be met by certification of additional property or by depositing cash with the Trustee. The 1997 and 1996 requirements were met with funds deposited with the Trustee, and these funds were used for redemption of outstanding bonds of Series Y.
On May 1, 1997 the Company redeemed all its outstanding First Mortgage 8't Bonds, Series Y, due August 15, 1999 and all its outstanding First Mortgage 6)(%
Bonds, Series W, due September 15, 1997. On October 15, 1997, the Company redeemed all its outstanding First Mortgage 68(t Bonds, Series EE.
49 Sinking fund requirements and bond maturities for the next five years are:
(Thousands of Dollars) 1998 1999 2000 2001 2002 Series X $ 30,000 7% Series $ 30, 000 Series QQ $ 100,000
$ ~KU PROMESSORY NOTES (Thousands of Dollars}
December 31 Xssued Due 1997 1996 November 15, 1984'" October 1, 2014 $ 51,700 December 5, November 15, 2015 40,200.
19, 1985"'ugust August 1, 2032 101,900 1997'~'otal 1
9101 900 . ='. 991 900 (d) The $ 51.7 million Promissory Note was issued in connection with NYSERDA's Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1984. On October 1, 1997, the Company redeemed all the outstanding Series 1984 Bonds. The average interest rate was 3.43% through September 30, 1997, 3.38% for 1996 and 3.68% for 1995..
(e) The $ 40.2 million Promissory Note was issued in connection with NYSERDA's Adjustable Rate pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1985. On November 15, 1997 the Company redeemed all the outstanding Series 1985 Bonds. The annual interest rate was adjusted to 3.60% effective November 15, 1996 and to 3.75% effective November 15, 1995.
(f) Multi-mode pollution control notes totaling the principal amoun of $ 101.9 m'llion were issued in connection with NYSERDA's Pollution Control Revenue Bonds (Rochester Gas and Electric Corporat'n 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 MBEA Insurance Corporation. At December 31, 1997, the Multi-mode Revenue Bonds bore interest at the weekly rate and the average annual interest rate for all three series was 3.65%.
The Company is obligated to make payments of principal, premium and interest on each Promissory Note which correspond to the payments of principal, premium, if any, and interest on certain Pollution Control Revenue Bonds issued by NYSERDA as described above.
Based on an estimated borrowing rate at year-end,1997 of 6.62% for long-term debt with similar terms and average maturities (13 years}, the fair value of the Company's long-term debt outstanding (including Promissory Notes as described above) is approximately $ 655 million at December 31, 1997.
50 Based on an estimated borrowing rate at year-end 1996 of 7.30% for long-term debt with similar terms and average maturities (13 years), the fair value of the Company's long-term debt outstanding (including Promissory Notes as described above) is approximately $ 670 million at December 31; 1996.
On September 16, 1997, the Company completed arrangements for the delivery in September 1998 of $ 25.5 million of 5.95't NYSERDA tax-exempt bonds due September 1, 2033. Proceeds are expected to be used to redeem the Ser'es OO, tax-exempt, first mortgage bonds which are not redeemable until December 1998.
Note 7. PREFERRED AND PREFERENCE STOCK Par Shares Shares T e b Order of Seniorit Value 'uthorized Outstandin Pref erred Stock (cumulative) $ 100 2,000,000 920,000*
Pre f erred Stock (cumulative) 25 4,000,000 Preference Stock 1 5,000,000
- See below for mandatory redemption requirements.
No shares of preferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.
A. PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION:
Shares (Thousands) Optional Outstanding December 31, Redemption Series December 31. 1997 1997 1996 ( er share) ¹ 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 4.55 100,000 10,000 10,000 101 7.50 N 20,000 102 PlO4 a 470 000 ~47 000 ~67 000 Mav be redeemed at any time at the option of the Company on 30 days min'mum no".ice, plus accrued dividends in all cases. The Series N were redeemed on April 22, 1997.
B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
Shares (Thousands) Optional Outstanding December 31, Redemption Series December 31, 1997 1997 1996 er share) 7.45 S $ $ 10, 000 Not applicable 7.55 T 100,000 D0,000 10, 000 Not applicable
- 7. 65 U 100,000 10,000 10,000 Not applicable 6.60 V 250,000 25,000 25,000 Not Before 3/1/04+
Total ,mm $ ~4, UVU $ 55, mm Less: Doe 56fthin one year 100, 000 10,000 10,000 Total 350 000 ~35 000 ~45 000
+ Thereafter at $ 100.00
51 MANDATORY REDEMPTEON PROVISIONS Zn the event the Company should be in arrears in the sinking fund requirement, the Company may not redeem or pay dividends on any stock subordinate to the Preferred Stock.
'Series T, Series U. All of the shares are subject to redemption pursuant to mandatory sinking funds on September 1, 1998 in the case of Series T and September 1, 1999 in the case of Series U; in each case at $ 100 per share.
Series V. The Series V is subject to a mandatory sinking fund sufficient to redeem on each March 1 beginning in 2004 to and including 2008, 12,500 shares at $ 100 per share and on March 1, 2009, the balance of the outstanding shares.
The Company has the option to redeem up to an'additional 12',500 shares on the same terms and dates as applicable to the mandatory sinking fund.
Based on an estimated dividend rate at year-end 1997 of 5.67% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (5.92 years), the fair va)ue of the Company's preferred Stock, subject to mandatory redemption, is approximately $ 48 million at December 31, 1997.
Based on an estimated dividend rate at year-end 1996 of 6.50'4 for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (5.66 years), the fair value of the Company's preferred Stock, subject to mandatory redemption, is approximately $ 57 million at December 3P, 1996.
52 Note 8. COMMON STOCK AND STOCK OPTIONS In December 1997, the Board of Directors of the Company authorized the repurchase of up to 4.5 million shares of the Company's Common Stock on the open market. None of the shares were purchased prior to year end.
At December 31, 1997, there were 50,000,000 shares of $ 5 par value Common Stock authorized, of which 38,862,347 were outstanding. No shares of Common Stock are reserved for warrants, conversions, or other rights. There were 1,445, 141 shares of Common Stock reserved for employees under the 1996 Performance Stock Option Plan, as further described below. There were 1,026,840 shares of Common Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan .and 129,664 shares reserved and unissued for employees under the RG&E Savings" Plus Plan.
COMMON STOCK Shares Amount Outstanding (Thousands)
Balance, January 1, 1995 37,669,963 $ 670,569 Shares Issued through Stock Plans 783,200 17,074 Decrease (Zncrease) in Capital Stock Expense ( 125)
Balance, December 31, 1995 38,453,163 $ 687,518 Shares Issued through Stock Plans 398,301 8,612 Decrease (Increase) in Capital Stock Expense ( 111)
Ba ance, December 31, 1996 38,851,464 $ 696,019 Shares Issued through Stock Plans 10,883 272 Additional Paid in Capital 2,399 Decrease (Increase) in Capital Stock Expense Balance, Decembe" 31, 1997 38,862,347 699,031 PERFORMANCE STOCK OPTION PLAN Effective January 22, 1997, the Company adopted a Performance Stock Option Plan which provides for the granting of op ions to purchase to 2,000,000 authorized but unissued shares or treasury shares of $ 5 par up value Common Stock to executive officers and other key employees. No participant shall be granted options for more than 200,000 shares of Common Stock during any calendar year.
The options would be exercisable for a period to be determined by the Committee on Management (the Committee). The Committee may in its sole discretion grant the right to receive a cash payment upon any exercise of an option equal to the quarterly dividend payment per share of Common Stock paid from the date the option was granted to the date of exercise.
In 1997, the Board of Directors granted 504,700 options at an exercise price of $ 19.0625 per share. These options are vested closes at $ 25 per share, 75% at $ 30 per share and 100% at 50% when the stock at $ 35 per share.
Also in 1997, the Board of Directors granted options at an exercise price of $ 24.75 per share. These options are vested50,159at 25% when the stock closes
53 at $ 25 per share, 50'4 at $ 30 per share, 75% at $ 35 per share, and 100% at $ 40 per share.
In order for the options to become vested, the closing prices must be sustained at or above the levels indicated above for a minimum of five consecutive trading days.
Since the Company adopted FAS 123, compensation expense associated with the options granted is reflected in 1997 net income. For calendar 1997, the compensation expense recorded was $ 2.4 million. In applying FAS 123, the fair value of each option granted is estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions: risk-free rate of return ranging between 6.39% and 6.56%, expected dividend yield of 9.44'4,- and expected stock volatility of 17%.
A summary of the Company' stock option activity is presented below:
Weighted
~Otions 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 Availab'e for future grant at 12/31/97 1,445,141
Note 9. SHORT-TERM DEBT On December 31, 1997, the Company had short-term debt outstanding of $ 20.0 million. At December 31, 1996 the Company had short-term debt outstanding of
$ 14.0 million. The weighted average interest rate in 1997 on short-term debt outstanding at year end was 6.64% and was 6.07% for borrowings during the 'year.
The weighted average interest rate on short-term debt borrowed during 1996 was
- 5. 86~o.
In December 1997 the Company's $ 90 million revolving credit agreement was amended extending its term to five years, terminating December 31, 2002.
facility
~
Commitment fees related to this amounted to $ 113,000 in 1997 and 1996, and $ 165,000 in 1995. '
The Company's Charter provides that the Company may not issue unsecured debt if immediately after such issuance the total amount of unsecured debt outstanding would exceed 15 percent of the Company's total secured indebtedness, capital, and surplus without the approval of at least a of outstanding Preferred Stock. As of December 31, 1997,majority of the holders the Company would be able to incur approximately $ 103.8 million of additional unsecured debt under this provision. The Company has unsecured lines of credit totaling $ 27 million available from several banks, at their discretion.
In order to be able to use its $ 90 million, revolving credit agreement, the Company has created a subordinate mortgage which secures borr'owings under its revolving credit agreement that might otherwise be restricted this provision of the Company's Charter. In addition, the Company has a Loan by- and.Security Agreement to provide for borrowings up to $ 10 million for the exc2usive purpose of financing Federal Energy Regulatory Commission Order 636 transition costs(636 Notes) and up to $ 30 million as needed from time to time for other working capital needs. Borrowings under this agreement,'which can be renewed annually, are secured by a lien on the Company's accounts receivable.
At December 31, 1997, borrowings outstanding were 4.34 million of 636 Notes (recorded on the Balance Sheet as a liability under$ Deferred Credits and Other Liab'lities).
55 Note 10. COMMITMENTS AND OTHER MATTERS COMPETITION OVERVIEW. The PSC, through its Competitive Opportunities Proceeding, has embarked on a fundamental restructuring of the electric utility industry in the state. Among other elements, the PSC's goals included lower rates fo consumers and increased customer choice in obtaining electricity and other energy services.
During 1996 and 1997, the Company, the Staff of the PSC, and several other parties negotiated a Settlement Agreement (the "Settlement" ) which was approved, by the PSC in November 1997. The Settlement sets the framework for the introduction and development of open competition in the electric energy marketplace.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. The Settlement provides for a transition to competition during its five year term (July 1, 1997 to June 30, 2002) and establishes the Company's electric rates for each annual period. A Retail Access Program will be phased in, allowing customers to purchase electricity, and later electricity and capacity commitments, from sources other than the Company. The Company will be given a reasonable opportunity to recover prudently incurred costs, including those pertaining to generation and purchased power. The Settlement also requires the Company to functionally separate its component operations: distribution, generation, and retailing, Any unregulated retail operations must be structurally separate from the reguF4<ed .utility functions but may be funded with up to $ 100 mil)ion. Although the 'Settlement provides incentives for the sale of generating assets, it requires neither divestiture of generating or other assets nor write off of stranded costs. The Company believes that the Settlement will not adversely affect its eligibility to continue to apply SFAS 71 with the exception of certain to-go costs associated with non-nuclear generation. If, contrary to the Company's view, such eligibility were adversely affected, a mace ial w ite-down of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Over the five yea" term o the Settlement, cumulative rate reduc ions will be: Rate Year 1: $ 3.5 mil'io..; Rate Yea 2: $ 12.8 million; Rate Year 3: $ 27.6 million; Rate Year 4: $ 39.5 m'1'ion; and Rate Year 5: $ 64.6 million. The Rate Plan permits the Company to offse against the foregoing reductions certain inflation-related expenses and certain amounts related to a pu chase power agreement with Kamine. In the event that the Company earns a return on common equity in excess of 11.50% ove" the en"'e five yea" term of the Settlement, 50% of such excess wil'ewe accumulated during the term, and 50%
usec to wr'te down deferred costs used to write down accumulated deferrals o" investment in electr' plan" or reg la=ory assets.
Retail Access. The Company's Energy Cho'ce Program will be ava'able to all of its customers on an equal bas's up to certa'n usage caps. On July 1, 1998, customers whose electric loacs represen= approximately 10% o the Company's total annual retail sales will be elig'ble to purchase electricity (but not capacity commitments) from alternat've supp 'ers. On July 1, 1999, the percent of total sales moves to 20%, and customers would purchase both electricity and capacity commitments. On July 1, 2000, tne percent moves to 30%, and on July 1, 2001, all retail customers will be eligible to purchase energy and capacity from alternative suppliers.
During the initial, energy only stage of the Retail Access Program, the Company's distribution rate will be set by deducting 2.3 cents per kilowatt hour
("KWH") from its full service ("bundlecP) rates and Load Serving Entities acting as retailers in the Company's service area will be entitled to purchase electricity from the Company at a rate of 1.9 cents per KWH. During the energy and capacity stage, the rate will generally equal the bundled rate less the cost of the electric commodity and the Company's non-nuclear generating capacity.
These commodity and capacity costs, generally referred to as "contestable costs,"
are estimated to be 3.2 cents per KWH, inclusive of gross receipts taxes.
Generating Assets. The Company will not be required to divest any of its generation facilities. To the extent that the Company sells any generating
56 assets during the term of the Settlement, gains on such sales will be shared between the Company and customers. With regard to losses on such sales, the Settlement acknowledges an intent that the Company will be permitted to recover such losses through distribution rates during the term of the Future rate treatment is to be consistent with the principle that the Settlements Company is to have a reasonable opportunity to recover such costs.
"To-go costs" of the Company's non-nuclear resources (i.e., capital costs incurred after February 28, 1997, operation and maintenance expenses, and property, payroll and other taxes) are to be initially recovered through distribution rates. The fixed portion of to-go costs would be recovered in full until July 1, 1999, and be subject to the market thereafter in accordance with the phase-in schedule for the Retail Access program. The variable portion of non-nuclear to-go costs would also be subject to the market in accordance with the phase-in schedule. Under the Settlement,-nuclear costs'would remain recoverable through regulated rates.
Miscellaneous. The present Settlement supersedes the 1996 Rate Settlement. Various incentive and penalty provisions in the 1996 Rate Settlement are eliminated.
EZTF ISSUE 97 DEREGULATION OF THE PRICING OF ELECTRICITY. Zn July, 1997, the Financial Accounting Standards Board's Emerging Issues Task Force (EZTF) reached a consensus on accounting for moving to more competitive environmentsrules for utilities'ransition and provided guidance, on when plans utilities with transition plans will need to discontinue the aj43.ication of SFAS-71, "Accounting for the Effects of Certain Types of Regulation".
The major EITF consensus was that the application of SFAS-71 to a segment (e.g. generation) which is subject to a deregulation transition plan'should cease when the legislation or enabling rate order contains sufficient detail for the utility to reasonably determine what the transition plan will entail. The EITF also concluded that a decision to continue to carry some or all of the regulatory assets ('ncluding stranded costs) and liabilities of the separable portion of the bus'ness that is discontinuing the application of SFAS-71 the basis of where the regulated cash flows to realize and should settle be determined on them will be de 'ec. Zf a transition plan provides for a non-bypassable fee for the recovery of stranded costs, there may not be any significant d'scont'ued for a segment.
write-off if SFAS-71 is The Company's application of the EITF 97-4 consensus has not affected its inancial position or results of operations because any above-market generation cos"s, regulatory assets and regulatory liabilities with the genera"'on portion of its business will be recove ed associated the regulated portion of "he Company through its d'tributio.. rates, g'ven the bySettlement provisions. The Settlement provides for recovery of all prudently inc rred sunk costs (all
'nvestment in electric plant and elec=ric regulatory assets) as of March by inclusion in rates charged pursuant to the Company's distribution access1, 1997 tariff. The Settlement also states tha "the Parties that the provisions of this Settlement will allow the Company to continue intend to .recover such costs, during the term of the Settlement, under SFAS-7', and that "such treatmen" shall be consistent with the principle that the Company shall have a reasonable opportunity beyond July 1, 2002 to recover all such costs". As noted previously, the fixed portion of the non-nuclear gene ation to-go costs af ter July 1999 and the variable portion of the non-nuclear generation to-go costs after1, July 1, 1998 are subject to market forces and would no longer be able to apply SFAS-71.
The Company's net investment at December 31, 1997 in nuclear generating assets is
$ 698.4 million and in non-nuclear generating assets is $ 122.0 million.
REGULATORY AND STRANDABLE ASSETS With PSC approval the Company has deferred certain costs rather than recognize them on its books when incurred. Such deferred costs are then recognized as expenses when they are included in rates and recovered from customers. Such deferral accounting is permitted by SFAS-71. These deferred costs are shown as Regulatory Assets on the Company's Balance Sheet. Such cost
57 deferral is appropriate under traditional regulated cost-of-service rate setting, where all prudently incurred costs are recovered through rates. In a purely competitive pricing environment, such costs might not have been incurred and could not have been deferred. Accordingly, if the Company's rate setting was changed from a cost-of-service approach, and it was no longer allowed to defer-.
these costs under SFAS-71, these assets would be adjusted for any impairment recovery (pursuant to SFAS-121). In certain cases, the entire amount could beto written off.
SFAS-121 requires write-down of assets whenever events or circumstances occur which indicate that the carrying amount of a long-lived asset may not be fully recoverable.
Below is a summarization of the Regulatory Assets as of December 31, 1997 and 1996:
(Millions of 1997 1996 Income Taxes Uranium Enrichment Decommissioning Deferral $ 159.6 0'ollars)
$ 174.6 16.4 17.7 Deferred Ice Storm Charges 11.5 14.0 FERC 636 Transition Costs 11.0 32.3 Demand Side Management Costs Deferred 8.4 Gas Deferred Fuel 7.7 Other, net '2Z7 3.
0 29.8 Total - Regulatory Assets 0232. 284. 5 Income Taxes: This amount represents the unrecovered benefits from accelerated depreciation and other imingportion of tax differences which were used to reduce tax expense 'n pas: years. recovery of th's deferral is anticipated over the remaining life The of the related property when the effect of the pas" decuctions reverses in future yea s.
Uranium Enr'chment Decommissioning De=erral: The Energy Policy Act of 1992 requires utilities to contrib "e such amoun"s based o.. the amount uranium enriched by DOE fo" each u"i=y. Th's amount is mandated ofto be paid to DOE through the year 2007. .he recovery of these costs is through base rates of fuel.
Deferred Ice Storm Charges: .hese cos=s res damage repair costs following =he March =99
' 'rom =he non-capital storm ce storm. The recovery of these costs has been approvec by =he PSC =hro ch =he yea" 2002.
FERC 636 Transition Cos=s: .hese cos=s are to gas supply and pipeline companies which are passing var'ous pavableres"'ucturing and other transition costs on to "he Company. as o"cerec bv FERC. The majori y of these costs will be recove"ec h=ough he Company" s gas cost adjustment by the year 2000.
Demand Side Management Costs Deferred: These cos s are Demand Side Management costs which relate :o with which electricity is usec. prog:ams initiated to increase e ficiency These cos"s are recoverable by the Company through the year 2002.
Gas Deferred Fuel: These costs resul from PSC-approved annual reconciliation of recoverable gal costs witha gas revenues in which the excess or deficiency is refunded to or recovered from customers during a subsequent period.
In a competitive electric market, s randable assets would arise when investments are made in facilities, o costs are incurred'o service customers, and such costs are not fully recoverable in market-based rates. Examples include purchase power contracts (e.g., the Kamine/Besicorp Allegany L.P. contract), or
58 high cost generating assets. Estimates of strandable assets are highly sensitive to the competitive wholesale market price assumed in the estimation. The amount of potentially strandable assets at December 31, 1997 depends on market prices and the competitive market in New York State which is still under development and subject to continuing changes which are not yet determinable, but could be significant. Strandable assets, if any, could be written down for impairment of recovery in the same manner as deferred costs discussed above.
In a competitive natural gas market, strandable assets would arise where customers migrate away from dependence on the Company for full service, leaving the Company with surplus pipeline and storage capacity, as well as natural gas supplies, under contract. The Company has been restructuring its transportation, storage and supply portfolio to reduce its potential exposure to strandable assets. Regulatory developments discussed under " GAS RESTRUCTURING PROCEEDING,"
below, may affect this exposure; but whether and to what extent there may be an impact on the level and recoverability of strandable assets cannot be determined at this time.
At December 31, 1997 the Company believes that its regulatory and strandable assets, if any, are not impaired and are probable of recovery. The settlement approved in the Competitive Opportunities proceeding does not impair the opportunity of the Company to recover its investment in these assets.
However, the PSC has published a Staff paper to address issues surrounding nuclear generation, including the determination of fair market value for facilities after a five year restructuring transition period. It appears that the PSC may seek to apply similar principles to other types of gqnerating facil'ties. A determination in this proceeding could have an impact on strandable assets.
CAPlTAL EXPENDITURES The Company's 1998 const uction expendi ures program is currently estimated a" $ "24 million. The Company nas en"erec 'nto certain commi ments fo" purchase o'aterials and equipment in connect'on w'th that program.
NUCLEAR-RELATED MATTERS DECOMMISSIONING TRUST. The Company is co lect'ng amoun s 'n its electric rates fo the eventual decommissioning of 'ts Ginna Plant anc for its 14% share o= the cecommissioning of Nine Mile Two. .he operat ng censes for these plants exp re i.. 2009 and 2026, respect've'y.
Under accounting procedures appro;ec by =he PSC, =we Company has collected decommissioning costs of approx'mate'y s 6. .-.. ion ".h"ough December 31, 1997 and 's authorized to collect approximate', $ 22 ;.. 'on annually through June 30, 2002 'or decommission'ng, covering bo".h n c'ear n.ts. The amount allowed in rates i's based on estimated ult'mate deco.-..-.. ss oning costs of $ 296.3 million for G'nna and $ 112.8 million fo" the Company's 'o share of Nine M'le Two (1995 dollars). These estimates are basec o.". s'te spec' cos" studies for each plant completed in 1995. Site specific st dies o'he anticipared costs of actual decommissioning are required to be subm'ec to the NRC at least five years prior to the expiration of the license.
The NRC requires reactor licensees to s bmi funding plans that establish minimum NRC external funding levels for reac or decommission'ng. The Company's plan, filed in 1990, consists of an excernal decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990, the Company has contributed $ 86.4 million to this fund and, including realized and unrealized
~
investment returns, the fund has a balance of $ 132.5 million as of December 31, 1997. The amount attributed to the allowance for removal of non-contaminated structures is being held in an internal reserve. The internal reserve balance as of December 31, 1997 is $ 29.7 million.
The NRC is currently considering proposals which may impact financial funding requirements for decommissioning of nuclear power plants. Under current
NRC over the estimated 59 regulations electric utilities provide for decommissioning funds-annually life of a plant. If state regulatory authorities were to adopt a program to remove electric generation (including nuclear plants) from cost-0 based rate regulation, an action which the New York PSC is currently considering, such plants would operate in a competitive electric market and would have no assured source of revenue from energy sales. Under current regulations, the NRC can require the owners of nuclear plants lacking such assured revenue streams to provide assurance that the full estimated cost of decommissioning will ultimately be available through some guarantee mechanism.
The NRC is seeking public comment on a number of questions, including the likely timetable for utility restructuring and deregulation andto tobe what extent costs will be recoverable if a large baseload plant is deemed non-competitive because of high construction costs and what funding sources will be used to shut down a plant prematurely and safely.
The NRC has released for comments a notice of proposed rulemaking (NOPR) modifying certain aspects of the financial assurance requirements for decommissioning nuclear power reactors. The NOPR includes, among other things, changes to the definition of "electric utility" for the purposes of providing financial assurance for decommissioning as well as new reporting requirements regarding each licensee's progress on external funding. The Company does not anticipate a material impact from the application of these rules in their proposed form; however it cannot predict the impact of these rules as resolution of stranded asset issues proceed in New York.
The PSC in August 1997 issued for comment a report by'it~"staff proposing norms by which nuclear plants in the state would relate to the .competitive electricity market following the period covered by electric utility restructuring agreements then pending before the PSC. Among other things, the report envisioned the sale of these plants at, auction, but with the selling utilities remaining responsible for ultimate decommissioning as well as for disposal of certain spent fuel. Recognizing that bidders may not be attracted to certain units -- which could include both the Company's Ginna plant and the Nine Mile Two plant in which it has a 14% interest, the report contemplated their early shutdown unless they could compete with othe" forms of generation. Zn Fall 1997, the- Company and others commented on these and o her facets of the report. Through m'd- January 1998, the PSC had taken no action on the repor" and comments.
The Sta f of the Financia'ccount'ng Standards Board are study'ng the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial s"atements of electric utilities. Zf current accounting practices fo. such costs were changed, the annual provisions for decommissioning costs could increase, the es imated cos for decommissioning could be reclassified as a liability a" he" "han as accumulated depreciation, the liability accounts and corresponding p'an" asse= accounts could be increased and
=rust fund income from the external ceco.-.;..;ssion'ng "rus"s could be reported as investment income rather than as a recuc=ion to decommissioning expense.
If annual decommission'ng costs increased, the Company would expect to defer the effects of such costs pending disposition by the PSC.
URANIUM ENRICHMENT DECONTAMZNATION AND DECOMMISSIONING FUND. Under the National Energy Act, utilities with nuclear generating facilities are assessed an annual fee payable over 15 years for the decommissioning of federally owned uranium enrichment facilities. The assessmen s .'or Ginna and the Company's share of Nine Mile Two are estimated to to al $ 22.1 million, excluding inflation and interest. Installments aggregating approximately $ 9.4 million have been paid through 1997. A liability has been recognized on the financial statements along with a corresponding regulatory asset For the two facilities the Company's liability at December 31, 1997 is $ 15.1 million ($ 13.4 million as a long-term liability and $ 1.7 million as a current liability). The Company is recovering costs through base rates of fuel.
In July 1996, the Company joined other utilities in a civil action against the U.S. Department of Energy (DOE), concerning these assessments. After a favorable initial decision in a parallel case, the Court of Appeals for the Federal Circuit in May 1997 reversed the lower court and held that the federal
60 government could assess licensees for the clean-up of these federal facilities.
Zn January 1998, the U.S. Supreme Court refused to hear the case, effectively upholding the dismissal of the utility claims.
NUCLEAR FUEL DZSPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear Waste Act) of 1982, as amended, requires the DOE to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high-level nuclear waste repository is not expected to be operational before the year 2010. The DOE is proposing to establish an interim storage facility which may allow title to and possession of nuclear waste prior to the establishment of a it to take permanent repository. 1996 the DOE notified the Company that the DOE will not start acceptanceZn December of Ginna spent fuel in 1998. Zn January 1997 the DOE released a draft request for proposal outlining a process for private firms to accept and transport waste from reactors until a federal facility is operational.
The Nuclear Waste Act provides for a determination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected by the Company in June 1985. .The Company 'estimates the fees, including accrued interest, owed to the DOE to be $ 83.3 million at December 31, 1997. The Company is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted quarterly. The Nuclear Waste Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of approximately one mill .001) per KWH of nuclear .energy generated and
'sold. This charge (approximately ($$ 3.6 million per year) is'c~r'ently being collected from customers and paid to the DOE pursuant to PSC 8'uthorization. The Company expects to utilize on-site storage for all spent or retire8 nuclear fuel assemblies until an interim or permanent nuclear disposal facility is operational.
There are presently no facilities in operation in the United States avai'able for the reprocessing of spent nuclear fuel from utility companies. Zn the Company's determination of nuclear fuel costs it has taken into account that nuclear fuel would not be reprocessed anc has provided fo" disposal costs in accordance with the Nuclear Waste Act. The Company has completed a conceptual study of alternatives to increase the capacity for the interim storage of spent nuclear fuel at the Ginna Plant. The preferred alternative, based on cost and safety criteria, is to install high-capacity spent area of the spent fuel pool. The additional sto agefuel racks in the existing capaci y, scheduled to be
'mplemented prior to Septembe" 2000, would allow interim storage of all spent fue'ischarged from the Ginna Plant through the end of its Operat'ng License in the yea 2009.
ENVIRONMENTAL MATTERS The following tables disposal has or lis vario s sites where pas" waste handling and may have occurred tnat are discussed below:
TABLE Z COMPANY. OWNED SZTES Estimated Site Name Location Company Cost West Station* Rochester, NY Ultimate costs have East Station Rochester-, NY not been determined.
Front Street* Rochester, NY The Company has Brewer Street Rochester, NY incur ed aggregate Brooks Avenue Rochester, NY costs for these sites Canandaigua Canandaigua, NY through December 31, 1997 of $ 4.3 million.
- Voluntary agreement signed.
61 TABLE 1Z - SUPERFUND AND NON OWNED OTHER SITES Estimated Site Name Location Company Cost Quanta Resources* Syracuse, NY Ultimate costs have Frontier Chemical- not been determined.
Pendleton* Pendleton, NY The Company has Maxey Flats* Morehead, KY incurred aggregate Mexico Milk Mexico, NY costs for these sites Byron Barrel and Drum Bergen, NY thxough December 31, Fulton Terminals* Oswego, NY 1997 of less than $ 1.0 million.
PAS of Oswego* Oswego, NY
- Orders on consent signed.
COMPANY-OWNED WASTE SITE ACTIVITIES. As part of its commitment to environmental excellence, the Company is conducting proactive Site Investigation and/or Remediation (SIR) efforts at six Company-owned sites .where past waste handling and disposal may have occurred. Remediation activit;i.yg at four of these sites are in various stages of planning or completion and the Gompany is conducting a program to restore the other two sites. The Company.'has recorded a total liability of approximately $ 13.6 million, $ 12.8 million of which anticipates spending on SIR efforts at the six Company-owned sites listed in it Table I above. Concurrently, the Company recorded a similar amount in its Regulatory Assets.
Zn 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 D'sposal Site Study" was developed to assess the number of and cost to remediate sites where hazardous chemicals, but not hazardous wastes are present. Of the six Company-owned sites listed in Table I above, three are listed in this inventory. These are East Station, Fron" Street and Brooks Avenue. Zn addi 'on to these three sites, the inventory includes Ambrose Yard and Lindberg Heat Treating. The Company does not believe tha" additional SIR work for which the Company is responsible is required at either site, however the Company is unable to predic" what action will be necessitated as a result of the listing.
The Company and its predecessors formerly owned and operated three manufactured gas facilities in the Rochester area. They are included in Table I.
Cleanup activities which were previously suspended, resumed on a portion of the West Station site and were concluded in July 1996 under a voluntary agreement with the NYSDEC. The Company received release from future liability and a covenant not to sue from the NYSDEC for this work. There remain other portions of the property where additional remedial work is expected, however, only a preliminary scope and schedule have been determined. At the second of the three manufactured gas plant sites known as East Station, an interim remedial action was undertaken in late 1993. Ground water monitoring wells were also installed to assess the quality of the ground water at this location. The Company has informed the NYSDEC of the results of the samples taken. Subsequent data evaluation indicate a wider array of potential sources of coal gasification related materials than previously thought suggesting significant remedial work may be required.
At the third Rochester area property owned by the Company (Front Street) where gas manufacturing took place, a boring placed in the Fall of 1988 for a
62 I
sewer system project showed a layer containing a black viscous material. The study of the layer found that some of the soil and ground water on-site had been adversely impacted. The matter was reported to the NYSDEC and, in September 1990, the Company also provided the agency with a risk assessment. The report of the results of this study and the NYSDEC's response to the recommendations made therein will influence the future remediation costs. The Company has signed a voluntary agreement to perform limited additional investigation at the site to determine whether certain remedial actions are necessary prior to development.
Another property, owned by the Company where gas manufacturing took place is located in Canandaigua, New York. Limited investigative work performed there during the summer of 1995 has shown evidence of both the former gas manufacturing operations and leakage from fuel tanks. The NYSDEC was informed; the fuel tanks removed; and additional investigative work continues. The SIR costs associated with these actions are included in Table I. .The NYSDEC has'ot taken any action against the Company as a result of these findings.
On another portion of the Company's property (Brewer Street), the County of Monroe has installed and operates sewer lines.. During sewer installation, the County constructed over Company property certain retention ponds which reportedly received from the sewer construction area certain fossil-fuel-based materials (the materials) found there. In July 1989, the Company received a letter from the County asserting that activities of the Company left the County unable to effect a regulatorily-approved closure of the retention pond area. The County's letter takes the position that it intends to seek reimbursement for its additional costs incurred with respect to the materials once. the, NYSDEC identifies the generator thereof and that any further cleanup-ac'tion which the NYSDEC may require at the retention pond site is the Company's'responsibility.
In a November 1997 letter, the County has claimed that the Company was the original generator of the materials. It asserts that liable for 50% of all County costs - - presently estimated it will hold the Company at a total of approximately $ 5 million - - associated both with the materials'xcavation, treatment and disposal and with effecting a retention pond area. The Company could incurregulatorily-approved closure of the costs as yet undetermined if it were to be found liable for such closure and materials handling, although prov'sions of an existing easement afford the Company rights which may serve to offset all or a portion of any such County claim. To date, the Company has agreed to pay a 20% share of the County's '995 investigation of this area, which is estimated to cost no more than $ 150,000, but no commitment has been made toward any subsequent investigations or remedial measures which may be recommended by the investigations.
Monitoring wells installed at another
'989 revealed that an undetermined amount of Company facility (Brooks Avenue) in leaded gasoline had reached the ground water. The Company has continued to monito" free product levels in the wes, and has begun a modest free It is estimated
=ha" further investigative work into this problem mayproject.
produc recovery cost up to $ 100,000. While tne cos" of corrective ac=ions cannot be de erm'ned until investigations are completed, preliminary estimates are not expected to exceed $ 500,000.
SUPERPUND AND NON-OWNED OTHER SITES. The Company has been or may be associatec as a potentially .responsible party (PRP) a- seven sites not owned by it. The Company has signed orders on consent fo" five of these sites and recorded estimated liabilities totaling approximately $ .8 million.
In one site, known as the Quanta Resources Site, the Company signed a consent order with the Environmental Protection Agency (EPA) and paid its $ 27,500 share of remedial cost. The Company was again contacted by EPA in late August, 1996. The EPA informed the Company that it believed certain additional work was required, including a study to determi'he the extent to which additional removal of waste materials was required. The EPA's list of PRPs had grown to about 80.
The Company, along with most of those PRPs, has agreed (through an Administrative Order on Consent) to conduct the required study. The Company anticipates its obligation through this phase will be less than $ 10,000. On May 12, 1997, the Company signed an Administrative Order on Consent with the NYSDEC. This agreement served to obligate the respective parties to pay NYSDEC's past costs at the Site, the Company's share of which was determined to be $ 1,500. There is as yet, no information on which to determine the cost to design and conduct at the
63 site any remedial measures which federal or State authorities may require, the Company does not expect its additional costs to exceed $ 150,000.
a PRP On May 21, 1993, the Company was for notified by NYSDEC that it was considered the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY. The Company has signed, along with other participating parties, an Administrative Order on Consent with NYSDEC. The Order on Consent obligates the parties to implement a work plan and remediate the site. The PRPs have negotiated a work plan for site remediation and have retained a consulting firm to implement the work plan. Preliminary estimates indicate the Company's share of additional site remediation costs are not expected to exceed $ 350,000. The Company is participating with the group to allocate costs among the PRPs.
Subsequent work has indicated that the final cost is likely to be lower.
The Company is involved in the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent orders to that effect. The Company has contributed to a study of the site and estimates that its share of the additional costs of investigation and remediation is not expected,to exceed $ 250,000.
The Company has been named as a PRP at three other sites and has been associated with another site for which the Company's share of total additional projected costs is not expected to exceed $ 71,000. Actual Company expenditures for these sites are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company's share of responsibility for such costs as well as the financial viability of other identified responsible parties.
FEDERAL CLEAN AIR ACT AMENDMENTS. The Company is developing strategies responsive to the federal clean air act amendments of 1990 (Amendments) which will primarily affect air emissions from the Company's fossil-fueled generating facilities. The strategy being developed is a combination of hardware solutions whicn have a capital and operation and maintenance (OGM) component and allowance trading solutions which have strictly an OGM impact. The most recent strategic developments still envision this combination of efforts as the most cost e fective means of proceeding although State legislative activity could impact theCompany's ability to rely upon the emission allowance market to meet some of i" s envi'ronmenta) commitments. The Company cannot predict the outcome of these proceedings .in the Legislature and, as a result, the Company's projections are based solely on the combination strategy. A "ange of capital costs between $ 2.9 and $ 3.5 million has been estimated fo" the imp)ementation of several potential alterations for meeting the foreseeable nitrogen oxide, opacity and sulfur cioxide requirements of the Amendmen s, as well as $ 1.0 to $ 1.5 million per year in operating expenses. These capita'os=s wou)d be incurred between and 2000. The OSM expenses would be for the yea" 1999. For he year 2000 1998 and beyond, the Company estimates that the a....ua) ope at'ng expenses would rise to between $ 2.4 million and $ 3.7 million. Any adci"iona) post-2000 capital costs and operating expense cannot be pred'cted unt'1 resolution of State and federal legislative activity enables the Company to " na)ize its comp)'ance strategy.
OPACITY ISSUE. In May 1997, the Company commenced NYSDEC to resolve a)legations of pas- opacity violations negotiations at with the the Company's Beebee and Russell Stations. The opacity standard 's a regula ion which limits the density of the smoke emitted from the Stations'mokestacks.
believes that it will reach an agreemen" with NYSDEC on this issue The Company amount of any civil pena)ty will likely include both cash and environmental and that the benefit project components which, in the aggregate, will not be material. In addition, the Stations have been temporarily derated. since February 1997 to maintain acceptable opacity levels whi')e the Company investigates additional engineering solutions to address opacity emissions. The financi'al of the deratings includes the )ost opportunity associated with energy salesimpact and, at times, the need to make additional purchases to meet system requirements. While the deratings have decreased earnings, and will continue to do so, the Company does not expect the amount .to be material. Fina)ly, the New York Power Pool (NYPP) is in the process of evaluating new rules for its system load regulation.
The current Station deratings for opacity reasons would reduce the ability of the Company to react to changes in load and provide regulation services when called
64 upon by the NYPP, resulting in additional costs. Depending on the new NYPP requirements, and whether the deratings remain in effect, the revised rules could result in the Company having to purchase additional regulation services which may cost between 0500,000 and $ 2,500,000 annually.
GAS COST RECOVERY GAS RESTRUCTURZNG PROCEEDZNG. Zn the PSC's Proceeding on Restructuring the Emerging Competitive Natural Gas Market, the PSC established a three-year period (ending March 28, 1999) during which the State's local distribution companies (LDCs) would be permitted to require customers converting from sales service to take associated pipeline capacity for which the LDCs had originally contracted.
Prior to the beginning of the third year, the" LDCs would be'equired to demonstrate their efforts to dispose of "excess" capacity. On September 4, 1997, the PSC issued an Order clarifying the March 28, 1996 Order. The September 4 Order requires, among other things, that the LDCs (a) assess strandable costs; (b) evaluate and pursue options to address strandable costs, including exploration of alternative uses and quantification of market values for the capacity that could be stranded by converting customers; (c) actively encourage competition including collaboration with marketers to expand the number of customers taking transportation service from the LDC and to provide customer education; and (d) to the extent LDCs cannot shed all their capacity as contracts expire, to continue to seek lower cost options and more flexibility and shorter contract terms, where cost-effective. LDCs are required to .fi,ly,'plans addressing the foregoing issues by April 1, 1998. Pursuant to the PSC's:6'gders, the cost of capacity defined as "excess" may not be fully recoverable in ra'test Accordingly, the Company's ability to avoid absorbing this cost will depend on 'the success of remarketing and portfolio structuring efforts and, if such efforts do not result in eliminating all "excess" capacity, on a satisfactory explanation as to why all such capacity could not be elim'nated. The Company is engaged in negotiations with the Staf of the PSC and otner parties to address these and other issues related to the future provision of gas serv'ce. At this time, no assessment of the potential impact of these requ'rements on the Company can be made.
On September 4, 1997, the PSC also issued fo" comment a Staff position pape" wh'ch proposes that LDCs ex't tne'r me chant function, i.e., cease to supply the natural gas commod'y to ne' exist'g customers, within five years anc that tney eliminate or restruc='e transporta 'on and storage capacity contracts extending beyond five years so as to eliminate obligations beyond that point, except where capacity is required to fulfill operational requirements or
=he LDC's obligations as the "supplier of last resort" to customers having no compe itive alternative. Zf adopted by the PSC, the Staff proposal could require the Company to remarket more capac'ty and to do so more rapidly than currently contemp aced. The comment period concluded on December 20, 1997, and no prediction can be made as to whether the Sta= proposal so, the extent of its potential impac" on he Company.
we adopted or, if 1995 GAS SETTLEMENT. The Company has en ered into several agreements to help manage its pipeline capacity costs and has s ccessfu'y met Settlement targets for capacity remarketing fo" the twelve months ending October 31, 1997, thereby avoiding negative financial 'mpacts fo" that period. The Company believes that it will also be successful in mee"ing the Settlement targets in the remaining year of the Settlement period, al hough no assurance may be given.
The FERC approved a change in rate design for the Great Lakes Gas Transmission Limited Partnership (Great Lakes) on which the Company holds transportation capacity. This change z-esulted in a retroactive surcharge by Great Lakes to the Company in the amount of approximately $ 8 million, including interest. Under the terms of the 1995 Gas Settlement, the Company may recover approximately one-half of the surcharge in rates charged to customers; but the remainder may not be passed through and has been previously reserved. The Company, which paid the Great Lakes assessment under protest, vigorously contested it before the FERC, but on April 25, 1996, the FERC upheld this determination that the charge to the Company is proper. The Company's petition to the U.S. Court of Appeals was denied on January 16, 1998. The Company is evaluating its next steps.
65 LEASE AGREEMENTS The Company leases five properties for administrative offices and operating activities. The total lease expense charged to operations was 4.2 million and $ 2.4 million in 1997, 1996 and 1995, respectively. $ For million, the years
$ 3.9 1998, 1999, 2000, 2001 and 2002 the estimated lease expense charged to operations will be $ 4.1 million, $ 2.4'million, $ 2.4 million, $ 2.4 million and 2.4 m'llion, respectively. Commitments under capital leases were not significant$ to tne accompanying financial statements.
LITIGATION SPENT NUCLEAR FUEL LZTZGATZON. The Nuclear Waste Act (Act) obligates DOE to accept for disposal spent nuclear fuel (SNF) starting in 1998. Since the mid-1980s the Company and other nuclear plant owners and operators have paid the substantial fees to the DOE to fund its obligations under the Nuclear Waste Act.
DOE has indicated that it will not be in a position to accept SNF in 1998. Zn 1994, Northern States Power Company and other owners and operators of nuclear power plants filed suit against DOE and the U.S. in the U.S. Court of Appeals for the District of Columbia Circuit seeking a declaration that DOE's course of action was in violation of its obligations under the Act, and. requesting other relief. Zn a July 1996 decision, the court upheld the utilitiep'osition that DOE is obligated to accept and dispose of the utilities'NF beginning not later than January 31, 1998. DOE had contended in effect that it disposal until the availability of a suitable SNF repository.could,dbfer the court rejected this DOE reading of the Nuclear Waste Act, but stopped short of The providing the utilities a remedy since DOE has not yet defaulted on its obligations. By letter dated December DOE invited the parties to the proceeding to provide wr't en comments17,on 1996, how DOE's an icipated inability to meet its January 31, 1998 obl'gation to begin accepting SNF could "best be accommodated". The Company and a number of other parties responded to that invitation. By Joint Petition for Rev'ew, uti".iesdated January 31, 1997, the Company and a number of other nuclear petitioned the Unitec States Court of Appeals fo" the District of Co umbia Circuit for a declaration that the Pet'tioners were relieved of the obligation to pay fees into the Nuc:ear Waste 'nd, and authorized to place those
=ees into escrow when and until DOE commences cisposing of SNF. The Petition
'"her requested that DOE be ordered to develop a program that would enable "o begin acceptance of SNF by January it
'997. the D. C. Circuit held that DOE could 31, 1998. By Orde" dated November 14, no= exercise delay in accepting fuel on grounds that it lacked an SNF repos'ory, and that the u"ilities had a "clear r'ght to relief". Rather than gra..: funding relief anc orde" tne DOE to move fuel, however, the Court referred the ut"ies "o the remedies set forth in
-he'r con"racts with the DOE. The Company 's p rsu'ng such remedies.
DEPARTMENT OF JUSTZCE LAWSUZT. On June 24, 1997, tne Antitrust the United States Department of Jus ce f'ed a civil complain" againstDivision the of Company in the United States Distr'c: Cour" 'or the Western District of New York.
The complaint follows a Civil Znvestigative Demand inves igation. That investigation included a broad look a: the Company's activities in the electric power industry including initially, the Company's power purchase agreement with an independent power producer. i..vestigat'on then focused primarily upon the flexible rate long term contractsTheentered Company and a number of its large customers under a tariff approved by the PSC.the The between policies it implemented recognized that if large tariff and the PSC customers took their electrical load off the system, the rates for remaining custome s would have to increase to cover the fixed costs of operation.
The Division in its complaint challenged only certain provisions of one flexible rate contract, the contracthaswith the University of Rochester. The Complaint alleges that those provisions in that contract violate Section 1 of the Sherman Act by restricting the customer's right to compete with the Company in the sale of electricity and seeks an injunction enforcing that contract and from entering other prohibiting the Company from agreements that limit competition in the sale of electricity to other customers.
66 The Company believes that the investigation and the Complaint reflect the desire by the Antitrust Division to become involved in the deregulation of electric utilities, but that the proper way to do that is in the proceedings before the PSC in the Competitive Opportunities Case.
On September 3, 1997, the Company filed its answer which denied the material allegations of the Complaint. At the same time, the Company filed a Motion for Summary Judgment asking the Court to dismiss the action with prejudice on the
, grounds that the Company's actions are immune from antitrust liability unde" the State action exemption, that the Company's actions did not injure compet'tion and that the Department of Justice's claims are speculative. On November 3, 1997, the Department of Justice filed its opposition to the Company's Motion for Summary Judgment and filed its own Motion for Summary Judgement. The Company's response to the Justice Department motion was filed on December 5, 1997.
These Motions for Summary Judgment were argued on December 19, 1997. In Court, the parties agreed to a resolution of the dispute, suggested by the Judge which, in the Company's opinion,- would not have any material effect on its contract with the University. The Antitrust Division, however, has expressed its unwillingness to agree to a Consent Decree based on the agreement reached in Court and the matter is still pending.
LITIGATION WITH CO-GENERATOR. Under federal and New York State laws and regulations, the Company is required to purchase the electrical output of unregulated cogeneration facilities which meet certain criteria .(Qualifying Facilities). Under these statutes, a utility is required to y>g for electricity from Qualifying Facilities at a rate that equals the cost to Che it utility of power would otherwise produce itself or purchase from other sources (Avoided Cost).
With the exception of one contract which the Company was compelled by regulators to ente" into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts of capacity, the Company has no long-term obligations to purchase energy from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time contract with Kamine was negotiated, the Company was required to agree the to Kamine a price for power that is substantially greater than the Company's pay own cos" of production and other purchases. Since that time the State "six-cent" law mandating a minimum price higher than the Company's own costs has been repealed and PSC estimates of future costs on which the contract was based have declined dramatically.
In September 1994, the Company commenced a lawsuit in New York State Court, Mon oe County, seeking to void or, alternatively, to reform a PowerSupreme Purchase Agreement with Kamine for the purchase of the electrical output of cogeneration facility in the Town of Hume, Allegany County, New York, for a aterm of 25 years. The contract was nego"iated pursuant to the specific prie'ng requ'rement of a State statute that was later repealed, as well as estimates of Avoided Costs by the PSC that subsequently were drastically reduced. As a result, the contract requires the Company to pay prices for Kamine's electrical output that dramatically exceed current Avoided Costs and'current projections of Avoided Costs. The Company's lawsuit seeks to avoid payments to Kamine that exceed actual and currently"projected Avoided Costs. Kamine answered the Company's complaint, seeking to force the Company to take and pay for power at the higher rates called for in the contract and claiming damages in an unspecified amount alleged to have been caused by the Company's conduct. The Company received test generation from the Kamine facility during the last quarter of 1994. Kamine contends that the facility went into commercial operation in December 1994 and that the Company is obligated to pay the full contract rate for it. The Company disputes this contention and refuses to pay the full contract rate. During 1995 Kamine filed a Motion for Summary Judgment dismissing the Company's complaint and directing it to perform the Power Purchase Agreement.
The court denied that motion and Kamine appealed. After argument of that appeal Kamine filed for protection under the Bankruptcy laws and sent to the Appellate Division a notice that all further proceedings were stayed.
In addition, Kamine has filed a related complaint in the United States District Court for the Western District of New York alleging that the conduct which is the subject of the State court action violates the federal antitrust
67 laws. The complaint seeks damages in the amount of $ 420,000,000, when trebled, as well as preliminary and permanent injunctions. Subsequently, Kamine filed a motion for a preliminary injunction in the federal action to enjoin the Company from refusing to accept and purchase electric power from Kamine and enjoining the Company from terminating during the pendency of this lawsuit its performance under the contract. Xn November 1995, the Court issued a decision denying Kamine's motion for a preliminary injunction, finding, among other things, that Kamine had not established the necessary likelihood of success on the merits of its action. Kamine filed a notice of appeal from that decision but has "subsequently announced that it is withdrawing that appeal.
During 1995 the PSC invited the Company to file a petition requesting, among other things, that the Commission commence an investigation to determine whether at the time of claimed commercial operation the Hume plant was a cogeneration facility under New York law as required by the Power Purchase Agreement. The Company filed such a petition and Kamine filed papers in opposition.
During 1995 Kamine filed a petition before the FERC to waive certain requirements for federal Qualified Facility status for 1994. The Company and the PSC filed in opposition to the request. Subsequently FERC issued an order granting the waiver request and the Company's motion for rehearing was denied.
The Company filed a petition fox review with the U.S. Court of Appeals for the District of Columbia Circuit but that court denied the request for review.
ln November 1995 Kamine filed in Newark, New Jersey for protection under the Bankruptcy laws and filed a complaint in an adversary proceedingseeking, among other things, specific performance of the Agreement. Kamine filed a motion to compel the Company to pay what would be due under Kamine's view of.,the terms of the Agreement during the pendency of the Adversary Proceeding. After hearing, the Bankruptcy Court denied that motion. The Court also denied various motions made by the Company to change the venue of the proceedings to New York State and to lift the automatic stay of the pending New York State action. On appeal the Bankruptcy Court was reversed and the case sent back to the Bankruptcy Court to decide where the contract issues in the Adversary Proceeding should be acjudicated. As of June 16, 1997, the Company filed a Second Amended Complaint in tne State Court action assert'ng addit'onal claims based on subsequent occurrences.
On Ha ch 19, 1997, the Bankruptcy Cour" stayed the Adversary Proceeding pend'ng resolution of the cont ac" 'ssues in the New York State court trial.
Kam'ne has indicated it will no" appeal th's ac ion.
On June 26, 1997, the defendants f'led a Joint No ice of Removal of Action, removing the action to the United States D'str'ct Cour". for the Western District of New York. There have been no further proceedings to date.
Numerous other procedural mo"ions have been presented in the Bankruptcy Court, some of which may now be cons'dered the New York S ate court. While 'y these proceedings are pending, the Company would pay approximately two cents per kilowat .hour when the plant operates. Xt is not operating a" the present time.
GENERAL ELECTRIC CAPITAL CORPORATION LAWSUIT. On July 3, 1997, General Electric Capital Corporation (GECC) f'led a complaint against the Company in the
,United States District Court for the western Distr'ct of New York in connection with the Kamine project in Hume, New York, for which GECC provided financing.
The complaint asserts that the Company viola"ed the antitrus- laws in its dealings with Kamine and seeks injunctive rel'ef, treble damages and alleged actual damages of not less than $ 100,000,000. The claims made in the complaint filed are substantially similar to the claims made by Kamine in the same court under Kamine's version of the terms of" the Power Purchase Agreement for the Hume project. The court denied Kamine's motion for a preliminary injunction on grounds which included Kamine's failure to establish a likelihood of success on the merits of its claims. Kamine had filed a notice of appeal from a decision denying Kamine's motion for a preliminary injunction. Kamine subsequently withdrew the appeal. The Company believes the complaint by GECC is also without merit and intends to defend the action.
68 INTERIM FINANCIAL DATA In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results 'of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the availability of surplus electricity. The'um of the quarterly earnings per share may not equal the fiscal year earnings per share due to rounding.
(Thousands of Dollars)
<arnings per Common Share Operating Opera ing Net Earnings on (in dollars)
Quarter Ended Revenues Income Income Common Stock Basic Diluted 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 3i. 1997 314,845 55, 194 41,433 39,729 1.02 1.02 December 31, $ 274,431 $ 33,048 $ 22,228 $ 20,362 $ 0.52 $ .52
- 30. 1996 1996'eptember 234.843 36. 159 21,062 19,196 0.49 .49 June 30. 1996 235,577 23. 115 11,732 9.866 0.25 .25 March 31, 1996 309, 195 56,866 42,489 40,623 1.05 1.05 Decembe 31. 1995'" $ 270,518 $ 32,324 $ (387) $ (2,253) $ (.05) $ (.05)
Sep ember 30. 1995 245,145 41,738 26,934 25,068 .65 .65 June 30, 1995 219.546 29.454 14,861 12,995 .34 .34 March 31. 1995 281,119 46,557 30,520 28,653 .75 .75 Reclassified for comparative purposes.
Includes recognition of 528.7 million net-of-tax gas settlement adjustment.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None
69 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by Item 10 of Form 10-K relating to directors who are nominees for election as directors at the Company's Annual Meeting of Shareholders to be held on April 15, 1998, will be set forth under the head'ng
<<Election of Directors" in the Company's Definitive Proxy Statement for such Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Part I as Item 4-A of this Worm 10-K under the heading "Executive Officers of the Registrant".
Item 11. EXECUTIVE COMPENSATION The information required by Item 11 of Form 10-K will be set forth under the headings "Report of the Committee on Management on Executive Compensation",
"Executive Compensation" and "Pension Plan Table" in the Company'p Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Tne information required by Item 12 of Form 10-K will be set forth unde" the headings "General" and <<Sec r'y Ownersr.'p of Management" in the Company's De" n'tive Proxy Statement fo" the Annua: Meeting of Shareholders.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by "tern 3 o'orm 10-K w'1'e set forth under the heading "Election of Directo"s<< '.". the Compan,'s Def'n'tive Proxy Statement
'or the Annual Mee ing of Shareholcers.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 not been answered because, wit? n 20 days a:ter the close of its throughfiscal 13 have year the Registrant will file with he Co.-..-..'ss'on a den'tive proxy statement pursuant to Regulation 14A which involves ?:e 'e'ct.'on of d'ecto s. Regis-trant's definitive proxy statemen cared March 3, 998 w'e 'ed with Securities and Exchange Commission pr'or to Apr 30, 1998. The informationthe required in Items 10 through 13 under the'ead ngs se forth above is incorpo-rated by reference herein by this reference thereto. Except as specifically referenced herein the proxy statemen connec='on with the annual meeting of shareholders to be held April 15, '998 is not deemed to be filed as part of this
'Report.
70 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. The financial statements listed below are shown under Item 8 of this Report.
Report of Independent Accountants.
Consolidated Statement of Income for each of the three years ended December 31, 1997.
Consolidated Statement of Retained Earnings for each of the three years ended December 31, 1997.
Consolidated Balance sheet at December 31, 1997 and 1996.
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1997.
Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1997.
Schedule II - Valuation and Qualifying Accounts.
(a) 3. Exhibits - See List o Exhib'=s.
(b) Repor"s on Form 8-K Tne Company filed a Form 8.K datec Dece;.3er 5, 1997, reporting under Item 5, Other Events, approval by the PSC of the Co...pany's Competi ive Opportunities Case Settlement with the PSC staf'nc other pa""'es w'=h respect to the restructuring of the elec ric utity 'na s=ry n Ne~ York Sta"e.
71 ROCHESTER GAS AND ELECTRIC CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1995 Additions Balance at Charged to" Charged Balance Beginning Costs and To Other at End Descriptions of Period Expenses Accounts Deductions of Period Reserves for:
Uncollectible accounts $ 950 $ 14,893 $ 3,893 $ 11,950 Materials and supplies obsolescence 736 736 FOR THE YEAR ENDED DECEMBER 31, 1996 Addi tions Balance at Charged to Charged Balance Beginning Costs and To Other at End Descriptions of Period Expenses Accounts Deductions of Period Reserves for:
Uncollec"'ble accounts $ 11,950 $ 4, 987 $ 565 $ 17,502 Materials and supplies obsolescence 736 (375) 361 FOR THE YEAR ENDED DECEMBER 31, 1997 Additions Balance at Charged to Charged Balance Beginning Costs and To Other at End Descriptions of Period Expenses Accounts Deductions of Period Reserves for:
Uncollectible accounts $ 17,502 $ 5,078 $ 4,346 $ 26,926 Materials and supplies obsolescence 361 - 2,839 3,200 Beginning in 1992 the Company no longer charges uncollectible expenses through the uncollectible reserve. The total amount written off directly to expense in 1995 was $ 8,170, 'in 1996 was $ 15,039 and in 1997 was $ 12,912.
72 LIST OF EXHIBITS Exhibit 3-1* Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 3.2* Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994. .(Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarter 'ended March 31, 1994, SEC File No. 1-672.)
Exhibit 3-3* By-Laws of the Company, as amended to date. (Filed as Exhibit 3-1 in May 1996 on Form 10-Q for the quarter ended March 31, 1996, SEC File No. 1-672)
Exhibit 4-1>> Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 4-2* Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the18,quarter ended March 31, 1994, SEC File No. 1-672.)
Exhib' 4-3* By-Laws of the Company, as amended to date. (Filed as Exhibit 3-1 in May 1996 on Form 10-Q fo" the quarter ended March 31, 1996, SEC File No. 1-672)
Exh'bit 4-4>> General Mortgage o Bankers .rust Company, as Trustee, dated Septembe" 1, 1918, and s pplemen"s tnereto, dated March 1, 1921, Octobe" 23, as Ex)'ib't 4-2 'n
'928, Aug s- ', 932 and May 1, 1940. (Filed Febr a"y '99 on Form 10-K for the year ended December 31, '990, SEC Fe No. 1-672-2)
Exhibit 4-5>> Supplemental Inden ure. da=ec as of March 1, 1983 between the Company and Bankers Trus= Company, as Trustee (Filed as Exhibit 4- 1 on Form 8-K da=ec J"y 15,'993, SEC File No. 1-672)
Exhibit 10-1>> Basic Agreement dated as of September 22, 1975 among the Company, Niagara Mohawk Power Corporation, Long Island Lighting Company, New York State Elec ric 6 Gas Corporation and Central Hudson Gas & Electric Corporation. (Filed in Registration No.
2-54547, as Exhibit 5.-P in October 1975.)
Exhibit 10-2>> Letter amendment modifying Basic Agreement dated September 22, 1975 among the Company, Central Hudson Gas & Electric Corporation, Orange and Rockland Utilities, Inc. and Niagara Mohawk Power Corporation. (Filed in Registration No. 2-56351, as Exhibit 5-R in June 1976.)
73 Exhibit 10-3* Agreement dated September 25, 1984 between the Company and the United States Department of Energy, as amended. (Filed as Exhibit 10-3 in February 1995 on Form 10-K for the year ended December 31, 1994, SEC File No. 1-672-2)
Exhibit 10-4* Agreement dated February 5, 1980 between the Company and the Power Authority of the State of New York. (Filed as Exhibit 10-10 in February 1990 on Form 10-K for the year ended December 31, 1989, SEC File No. 1-672-2)
Exhibit 10-5 Agreement dated March 9, 1990 between the Company and Mellon Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on Form 10-Q for the quarter ended March 31, 1990, SEC File No. 1-672)
Exhibit 10-6* Basic Agreement dated September 22, 1975 as amended and supplemented between the Company and Niagara Mohawk Power Corporation. (Filed as Exhibit 10-11 in February 1993 on Form 10-K for the year ended December 31, 1992, SEC File No. 1-672-2)
Exhibit 10-7* Operating Agreement effective January 1, 1993 among the owners of the Nine Mile Point Nuclear Plant Unit No. 2,. (Filed as Exhibit 10-12 in February 1993 on Form 10-'K-for the year ended December 31, 1992, SEC File No. 1-672-2)
Exhibit 10-8* (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. )-672-2)
Exhibit 10.9* (A) Rochester Gas and Electric Corporation Long Term Incentive Plan, Restatement o January 1, 1994. (Filed as Exhibit 10-10 in February 1995 on Form 10-K for the year ended December 31, 1994, SEC File No. 1-672-2)
Exhibit 10-10* (A) Rochester Gas and Electric Corporation Deferred Stock Unit Plan for Non-Employee Directors, effective as of December 31, 1995. (Filed as Exhibit 10-1 in May 1996 on Form 10-Q for the quarter ended March 31. 1996, SEC File No. 1-672)
Exhibit 10-11 (A) 1996 Performance Stock Op" ion Plan. (Filed as Exhibit 10-10 in February 1995 on Form 10-K for the yea" ended December 31, 1994, SEC File No. 1-672-2)
Exhibit 10-12* (A) Rochester Gas and Elec"ric Corporation Executive Incentive Plan, Restatement of January 1, 1995. (Filed as Exhibit 10-11 in February 1996 on Form 10-K for the year ended December 31, 1995, SEC File No. 1-672.2)
Exhibit 10-13* (A) RGSE Unfunded Retirement Income Plan Restatement as of July 1, 1995. (Filed as Exhibit 10-12 in February 1996 on Form 10-K for the year-ended December 31, 1995, SEC File No. 1-672.2)
Exhibit 10-14 (A) Change of Control Agreement dated January 1, 1998 between the Company and Thomas S. Richards, Chairman of the Board, President and Chief Executive Officer.
1 74 S Exhibit 10-15* (A) Change of Control Agreement dated August 17, 1995 between the Company and Robert E. Smith, Senior Vice President, Energy Operations. (Filed as Exhibit 10-15 in February 1996 on Form 10-K for the year ended December 31, 1995, SEC File No. 1-672-2)
Exhibit 10-16" (A) Change of Control Agreement dated January 2, 1996 between the Company and J. Burt Stokes, Senior Vice President, Corporate Services and Chief Financial Officer. (Filed as Exhibit 10-16 in February 1996 on Form 10-K for the year ended December 31, 1995, SEC File No. 1-672-2)
Exhibit 10-17* (A) Change of Control Agreeme'nt dated January 2, 1997 between the Company and Michael J. Bovalino, Senior Vice President, Energy Services. (Filed as Exhibit 10-18 in February 1997 on Form 10-K for the year ended December 31, 1996, SEC File No. 1-672-2)
Exhibit 10.18 Amended and Restated Settlement Agreement dated October 23, 1997 between the Company the Staff of the New York Public Service Commission (PSC), and certain other parties (Filed as Exhibit 10-4 on Form 10-Q for the quarter ended September 30, 1997, SEC File No. 1-672) as amended pursuant to an order of the PSC issued January 14, 1998.+Excluding Appendices) filed herewith.
Exhibit 10.19*
1 (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, '997, SEC File No. 1-672)
Exh'bit 10-20* (A) Agreement, dated October 1, 1997, between the Company and Michael T. Tomaino, Senior Vice Presiden and General Counsel. (Filed as Exh'bit 10-2 in November 1997 on Form 10-Q fo" the quarter ended September 30, 1997, SEC File No.
1-672)
Exh'bit 10-21" Agreement dated as of September 23,1997 between the Company and international Bus'ness Machines Corporation. (Filed as Exhibit 10-3 in Novembe" '997 on :orm 10-Q for the quarter ended Septembe" 30, '997, SEC F'e No. 1-672)
Exhibit 23 Consent of Price Wa erhouse 'i P. 'ndependent accountants Exh'bit 27 Financial Data Scnedule. pursuant to Xtem 601(c) of Regulation S-K.
Zncorporated by reference.
(A) Denotes executive compensation plans and arrangements.
The Company agrees to furnish to the Commission, upon request, a copy of all agreements or instruments defining the rights of holders of debt which do not exceed 10% of the total assets with respect to each issue, including the e Supplemental Zndentures under the General Mortgage and credit agreements in connection with promissory notes as set forth in Note 6 of the Notes to Financial Statements.
75 S IGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION By- /S/ THOMAS S. RICHARDS T omas S. Rxc ar s Chairman of the Board, President and Chief Executive Officer DATE: February 11, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
SIGNATURE TITLE DATE Principal Executive Officer:
/S/ THOMAS S. RICHARDS Chairman of the Board, February 11, 1998 T omas S. Rxcnar s President and Chief Executive Officer Principal Financial Officer:
/S/ J. B. STOKES J. Burt Sto es Senio" Vice President Corporate Services and February ll, 1998 Chief Financial Officer Principal Accounting Officer:
/S/ WILLIAM J. REDDY Controller February 11, 1998 Wx sam J. Re y
1 f 76 S IGNATURE TITLE DATE D'rectors:
/S/ WILLIAM BALDERSTON Wx sam Ba erston III III)
Director February 11, 1998
/S/ - ANGELO J. CHIARELLA Director February 11, 1998 Ange o J. C ware a
/S/ ALLAN,E. DUGAN Director February 11, 1998 A an E. Dugan Director February , 1998 Mar B. Grier
/S/ SUSAN R. HOLLIDAY Director February 11, 1998 Susan R. Ho x ay
, /S/ JAY T. HOLMES Jay T. Ho mes Director February 11, 1998
/S/ SAMUEL T ~ HUBBARD,JR Director February 11, 1998 Samue T. Hu ar ,Jr.
/S/ ROGER W. KOBER Director February 11, 1998 Roger W. Ko er
/S/ CONSTANCE M. MITCHELL Director February 11, 1998 Constance M. Matc e
/S/ CORNELIUS J. MURPHY Director February 11, 1998 Come zus J. Murp y
/S/ CHARLES I. PLOSSER Director February 11, 1998 C ar es I.P osser
/S/ THOMAS S. RICHARDS Director February 11, 1998 T omas S. Rzc ar s
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