ML17265A393

Request for Consent to Corporate Reorganization.Rg&E Is Restructuring to Adopt Holding Company Form of Corporate Organization as Authorized by New York State PSC

ML17265A393
Person / Time
Site:	Nine Mile Point, Ginna
Issue date:	07/31/1998
From:	NIXON, HARGRAVE, DEVANS & DOYLE, ROCHESTER GAS & ELECTRIC CORP.
To:	NRC
Shared Package
ML17265A391	List: ML17265A390 ML17265A393
References
NUDOCS 9808050257
Download: ML17265A393 (369)

Text

UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION ROCHESTER GAS AND ELECTRIC ) Docket Nos. 50-410 and 50-244 CORPORATION ) Facility Operating Licenses Nos. NPF-69 and DPR-18 REQUEST FOR CONSE<NT TO CORPORATE REORGANIZATION NIXON, HARGRAVE, DEVANS dk DOYLE u,p Attorneys for Rochester Gas and Electric Corporation Clinton Square P.O. Box 1051 Rochester, New York 14603-1051 Telephone: (716) 263-1000 Facsimile: (716) 263-1600 July 31, 1998 9808050257 0 5000244 PDR ADOCK pDR H

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UNITED STATES OF AMERICA BEFORE THE NUCLEARREGULATORY COMMISSION ROCHESTER GAS AND ELECTRIC ) Docket Nos. 50-410 and 50-244 CORPORATION ) Facility Operating Licenses Nos. NPF-69 and DPR-18 REQUEST FOR CONSE<NT TO CORPORATE REORGANIZATION I. INTRODUCTION Rochester Gas and Electric Corporation ("RG&E," the "Company" ) hereby requests the

~ consent of the Nuclear Regulatory Commission (the "Commission" ), pursuant to 10 C.F.R.

Section 50.80, to the indirect transfer of control of two licenses granted by the Commission:

RG&E's possessory license for its 14% ownership interest in the Nine Mile Point Nuclear Station, Unit No. 2 ("Nine Mile 2") located in Scriba, New York; and the Company's operating license for its wholly-owned nuclear generating facility, the R.E. Ginna Nuclear Power Plant

("Ginna").

RG&E is a New York corporation engaged principally in the generation, purchase, transmission, distribution and sale of electric power, and the purchase, transportation, I

distribution and sale of natural gas in service territories in western New York State, under the general regulatory supervision of the New York State Public Service Commission (the "NYPSC"). RG&E also sells electricity on the wholesale bulk power market, transmits electricity in interstate commerce, and operates hydroelectric generating facilities, all of which R182280. I

activities are subject to regulation by the Federal Energy Regulatory Commission (the "FERC").

RG&E is an "electric utility"within the meaning of the Commission's regulations (10 C.F.R.

Section 50.2).

In conjunction with the restructuring of its regulated electric service business pursuant to the policy direction of the NYPSC, and in accordance with the provisions of the Amended and Restated Settlement Agreement, dated October 23, 1997 (the "Settlement" ),'roviding for such restructuring, RG&E proposes to pursue a corporate reorganization, in which RG&E would become a wholly-owned subsidiary of a holding company (the "Holdco" ). This formal change in corporate structure would, in light of prior Commission determinations, be deemed to involve a change in control of RG&E, and accordingly an indirect transfer of the licenses to Holdco as the new owner of RG&E. Thus, the Company seeks the Commission's approval for this transaction, and for the indirect transfer of RG&E's licenses that it would entail.

This application will set forth the regulatory background for, and the purposes and framework of, the proposed reorganization; it will also address a number of matters to which the Commission has directed particular attention in considering similar applications in the past.

RG&E believes that the proposed reorganization would not affect its qualification for the licenses granted to it by the Commission, would not affect its status as an "electric utility"for the Amended and Restated Settlement Agreement, dated October 23, 1997, resolving issues with respect to RG&E in proceedings before the NYPSC, Cases 94-E-0952, Matter of Com etitive 0 ortunities Re ardin Electric Service, and 96-E-0898, Matter of Rochester Gas and Electric Co oration's Plans for Electric Rate/Restructurin Pursuant to 0 inion No. 96-12. A copy of the Settlement is attached hereto as Exhibit A.

Thereafter the N YPSC issued two orders, the first approving the Settlement subject to certain modifications, and the second setting forth in detail the rationale for its decisions set forth in the earlier order. See Order Adopting Terms of Settlement Subject to Conditions and Changes, issued November 26, 1997 in Case No. 96-E-0898, and Opinion No. 98-1, Opinion and Order Adopting Terms of Settlement Subject to Conditions and Changes, issued January 14, 1998 in Case No. 96-E-0898. A copy of each Order is attached hereto as Exhibit B and Exhibit C, respectively.

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Commission's purposes, and would in all other respects be consistent with law, regulations and 4 Commission orders. The Company further believes that the information set forth herein should satisfy any concerns that the Commission might have on these points. Should it appear, however, that additional information would be helpful, the Company would be pleased to provide it promptly.

II. THE PROPOSED REORGANIZATION Pursuant to orders issued by the NYPSC, and after extensive negotiations with the Staff of the Department of Public Service and other parties, RG8cE entered into the Settlement, establishing a framework for competitive retail electric service in the Company's service territory,'and otherwise providing for the restructuring of the Company's electric utility business consistent with the NYPSC's directives. The proposed corporate reorganization, as described hereinafter, is explicitly contemplated in the Settlement.

0 The reorganization that RGB'roposes to undertake, subject to shareholder and regulatory approvals, is substantially similar to reorganizations pursued by other electric utilities in recent years, likewise involving the indirect transfer of control of licenses for nuclear generating facilities, and which the Commission has approved. In accordance with a plan for (Footnote continued from previous page)

"Holdco" is used herein to indicate the proposed holding company solely for purposes of this application; RG&E intends, in conjunction with the creation of the holding company, to adopt an official corporate name for it.

See Settlement (Exhibit A) Pars. 62, 67, at pp. 50, 52-53; see also Settlement Schedule J, "Form of Petition to Form Holding Company."

For example, the other non-operating licensees for the Nine Mile 2 facility have similarly sought authorization to transfer their licenses in connection with their corporate restructurings: New York State Electric & Gas Corporation (application granted as of March 30, 1998); Long Island Lighting Company (application granted as of January 12, 1998); and Central Hudson Gas & Electric Corporation (application dated April 8, 1998).

See, ~e, Letter from NRC to Illinois Power Company, regarding Corporate Restructuring of Illinois Power Company (TAC No. M88222), dated January 31, 1994; Letter from NRC to Pennsylvania Power and Light Company, regarding Approval of Proposed Corporate Restructuring of Pennsylvania Power and Light Company (TAC Nos. M90079 and M90080), dated December 26, 1994; Letter from NRC to Detroit Edison ootnote continued on next page)

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4 exchange of shares pursuant to Section 913 of the New York Business Corporations Law, all the outstanding shares of the common stock of RG&E would be exchanged on a share-for-share basis for the shares of common stock of Holdco (subject to any exercise by shareholders of dissenters'ights). Upon consummation of the share exchange, each holder of RG&E common stock immediately prior to the share exchange would thereafter own a corresponding number of shares of Holdco common stock, and Holdco would own all the outstanding shares of RG&E common stock. The 100 organizational shares of Holdco common stock held initially by RG&E would either be canceled or retained by RG&E, depending upon certain income tax consequences.

As a wholly-owned subsidiary of Holdco, RG&E would retain its separate existence. It would continue to be an "electric utility"under Section 50.2 of the Commission's regulations, engaged in the business of generating, transmitting and distributing electric power. It would 0

continue to be subject to ratemaking and other regulation by the NYPSC and FERC. It would also continue to be the owner of, and actual licensee for, its present interests in Nine Mile 2 and Ginna. It would, moreover, continue to recover its investment in those facilities through its rates for service, subject to the provisions of the Settlement during its term, and thereafter subject to the ratemaking authority of the NYPSC.

Holdco, and not RG&E, would be the owner of any non-utility subsidiaries engaged in unregulated business activities. Moreover, the Settlement does not call for the divestiture of any utility assets. While it establishes certain financial incentives for the Company to sell generating facilities, and in particular offers the Company a greater share of any gains on such sales if (Fooinoic continued from previous page)

Company, regarding Approval of Proposed Corporate Restructuring of Detroit Edison Company by Establishment of a Holding Company (TAC Nos. M91890 and 92343), dated August 30, 1995.

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consummated earlier rather than later in the Settlement term, it does not require the divestiture of any of RG&E generation assets, including its interest in the Nine Mile 2 and the Ginna facilities. Nor does the Settlement permit the transfer of any utility assets by RG&E unless necessary approvals are granted by the NYPSC under Section 70 of the New York Public Service Law.

The adoption of the holding company structure in the manner described would accomplish the clear separation of regulated public utility functions (including the transmission and distribution of electricity, and the continued provision of regulated retail electric service for customers.not served by competitive retailers) from unregulated, competitive non-utility operations, consistent with regulatory policy directions at both the federal and State levels for the restructuring of the electric service industry. Moreover, the holding company structure represents a common and well-established form of business organization for companies engaged e I in multiple lines of business, particularly where some of the activities are regulated and others are conducted on a competitive basis. The holding company structure would afford increased financial, managerial and organizational flexibilityto enhance RG&E's position in the changing environment of the electric industry, in particular by enabling a speedier response to competitive opportunities than is possible for a regulated business. It would accommodate the creation of unregulated subsidiaries, and thereby facilitate greater flexibilityin financing competitive activities. At the same time, it would protect the legally separate regulated utility business and all of its customers from the risks attending competitive business enterprises. The transfer of direct equity ownership of RG&E to Holdco would constitute a legal change of control subject to Foomotc continued from previous page)

The Company's preferred stock and existing debt would remain outstanding securities of RG&E.

See Settlement (Exhibit A) at Par. 20, pp. 26-27.

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Commission approval. However, the proposed restructuring would have minimal effect on the 4 actual control of the Company, since its existing shareholders would become the owners of Holdco and thereby would indirectly control RG&E, as the regulated utility subsidiary of Holdco and the licensee for Nine Mile 2 and Ginna.

In approving the Settlement, the NYPSC endorsed in principle the proposed restructuring, subject to the Company's filing of a petition substantially in the form attached as Schedule J to the Settlement. RG&E intends to file such a petition presently, as well as petitions to the FERC (under the Federal Power Act) for approval of the reorganization, and to the Securities and Exchange Commission (under the Public Utilities Holding Company Act of 1935

("PUHCA")) for a determination that the proposed holding company structure would be exempt from the provisions of PUHCA. The Company will submit to the Commission copies of these petitions when filed.

III. EFFECT OF PROPOSED REORGANIZATION ON RG&E'S FINANCIAL CONDITION The proposed reorganization would have no adverse effect on RG&E's financial health, and in particular would not impair the availability to RG&E of funds needed to carry out its activities and responsibilities under the Nine Mile 2 and Ginna licenses. A copy of RG&E's Annual Report to the Securities and Exchange Commission on Form 10-K, attached hereto as Exhibit D, demonstrates that the Company has reasonable assurance of obtaining necessary funds for ongoing operations. As previously stated, after the proposed reorganization RG&E would remain subject to jurisdiction of the NYPSC with respect to rates for retail electric service, among other matters. Under the Settlement, the Company's costs of implementing the proposed See Form 10-K (Exhibit D) at p. 26, "Competition and the Company's Prospective Financial Position", and pp.

27-30, "Liquidityand Capital Resources".

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c orporate reorganization will not affect rates for service during the term of the Settlement, and may be deferred for subsequent recovery only to the extent of any excess of overall restructuring 9

implementation costs over a specified threshold in a given rate year. Any changes in the Company's arrangements for bulk power sales on the wholesale market, or in its rates for transmission of electric energy in interstate commerce, would remain subje'ct to review and approval by FERC. The proposed corporate reorganization would not involve the sale of RG&E stock, or the sale or lease of the Company's facilities or other assets. It would have no effect on the Company's capital structure, or on its costs of obtaining financing. Nor would the adoption of a holding company structure alter the source of RG&E's funds for conducting its utility operations. The Company's costs of operating its nuclear facilities, the costs of any necessary capital improvements, and the funding of eventual decommissioning activities with respect to both of those facilities, would continue to be derived from customer payments for utility services 0

subject to regulated rates, in the same manner as before the adoption of a holding company structure.

In sum, the proposed reorganization is expected to bring about no change in the sources of RG&E's funds for continued plant operations, capital investments, and eventual plant decommissioning. Nor is it expected to alter the regulatory processes establishing rates and other terms and conditions of service from which those revenues are derived. Accordingly, RG&E believes that the proposed restructuring will not adversely affect its financial resources for the conduct of future activities under the licenses issued by the Commission for the Nine Mile 2 and Ginna facilities.

IV. EFFECT OF PROPOSED REORGANIZATION ON MANAGEMENTAND OPERATION OF NUCLEAR FACILITIES 0

See Settlement (Exhibit A) at Par. 17, p. 24.

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As noted above, RG&E has a 14% ownership interest in the Nine Mile 2 facility, sharing ownership with several other New York State electric utilities; the owner of the largest interest, Niagara Mohawk Power Corporation ("Niagara Mohawk"), has responsibility for operation of the plant, pursuant to a license issued by the Commission. RG&E's license for Nine Mile 2 is for the possession, rather than the operation, of its share of that facility. In contrast, RG&E is sole owner and operator of the Ginna plant, and it has an operating license for that facility .

authorizing both possession and operation.

The reorganization proposed herein will have no effect on the management and operation of either facility. Niagara Mohawk will continue to be responsible for the ongoing on-site control, maintenance and operation of Nine Mile 2, subject to oversight in budget and planning matters in which RG&E and the other owner utilities will continue to participate. Niagara 0 Mohawk's continued maintenance of all necessary technical qualifications, and its compliance in all other respects with the Nine Mile 2 operating license, will not be affected by the adoption of a holding company structure for RG&E.

As discussed above, under the proposed reorganization RG&E would retain its wholly discrete and legally separate identity as a subsidiary of the holding company, and would continue to exercise its public utility functions as heretofore. The functions of management at the Holdco level would be directed chiefly toward the strategic development of its business enterprises, and toward administrative and financial matters. Joint management oversight with respect to Nine Mile 2, and all aspects of the operation of Ginna, would remain, as today, the responsibility of RG&E as a regulated utility. The Company's existing management functions, reporting channels, programs, policies and procedures with respect to its activities pursuant to its nuclear RI 82280. i

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licenses would continue unaltered by the proposed reorganization. A chart showing the 0 Company's nuclear operations organization is attached hereto as Exhibit E.

Thus, with respect to Nine Mile 2, RG&E will continue to participate with the other owner utilities in oversight of that facility, and in other non-operational responsibilities allocated to the non-operating owners by the governing contracts. Likewise, the Company's ownership and operational responsibilities for the Ginna plant, and its resources and arrangements to fulfill those responsibilities, would not be changed by the proposed reorganization. In sum, the Company's adoption of a holding company structure would in no way affect its management of nuclear operations, or its technical qualifications to conduct those operations. RG&E would continue to fulfillits obligations under the Commission's licenses as it has in the past.

V. EFFECT OF PROPOSED REORGANIZATIONON DOMESTIC OWNERSHIP AND CONTROL OF RG&E Under the proposed reorganization, as described above, shares of Holdco would be exchanged on a one-for-one basis for publicly held shares of RG&E common stock. RG&E, which would continue to be a licensee for Nine Mile 2 and the licensee for Ginna, would become the wholly-owned subsidiary of Holdco. Upon the reorganization, therefore, Holdco would be owned by the former holders of RG&E's stock, in the same proportions as their prior ownership of RG&E. Currently available information indicates that only about 10,000 of approximately 39,000,000 outstanding shares of RG&E common stock significantly less than 1% are held by foreign persons or entities. Implementation of the proposed reorganization, such that RG&E is owned by a publicly held holding company, is not expected to bring about any change in the tt proportion of foreign ownership. Accordingly, the reorganization will not result in the ownership, control or domination of RG&E by an alien, a foreign corporation or a foreign 0

government.

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VI EFFECT OF PROPOSED REORGANIZATIONON COMPETITION A further matter addressed by the Commission, in its consideration of similar applications in the past, has been the potential effect of the proposed indirect license transfer on I

competition, and in particular the potential for the exercise of increased market power by the

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licensee as a result of the transaction. The adoption of the holding company structure, while facilitating the Company's entry into competitive business activities, would also effect the legal and structural separation of such activities from regulated utility businesses. The reorganization would therefore not enable the exercise of market power, either vertical or horizontal, by Holdco (the indirect transferee of control over the RG&E licenses) or by the licensee, RGB', itself.

Quite to the contrary, RG&E's restructuring under the terms of the Settlement can be expected to facilitate the growth of unprecedented competition in the provision of energy services in RG&E's service territory. Over its term, the Settlement provides for the introduction e

of competitive electric service for increasing proportions of RG&E's market; retail customers in the Company's service area will be able for the first time to purchase energy and capacity from competitive suppliers. At the same time, during the Settlement term RG&E will remain subject to an obligation to provide regulated retail electric service to all customers that, by choice or otherwise, do not take service from competitive suppliers.'he indirect transfer of control over the licenses that would occur with the adoption of a holding company structure could have no material effect on the Company's ability to exercise market power, either within or without its service territory, whether in retail or in wholesale markets. The consequences of the Company's restructuring are pro-competitive, and the 0

See Settlement (Exhibit A) at Par. 65, pp. 51-52.

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contemplated indirect transfer to Holdco of control of the licenses for Nine Mile 2 and Ginna presents no impediment whatever to vigorous competition in any. market, retail or wholesale VII. SUBSEQUENT TRANSFERS OF RG&E ASSETS RG&E undertakes to inform the Director of Nuclear Reactor Regulation sixty days before the transfer from it to Holdco, or to any direct or indirect subsidiary of Holdco, of facilities for the production, transmission or distribution of electricity (but excluding grants of security interests or liens) having a depreciated book value, in total as determined during any twelve-month period, in excess of ten percent of the depreciated book value of RG&E's consolidated net utility plant, as recorded on the Company's books of account.

VIII. CONCLUSION RG&E believes that the information set forth in this application, and in the Exhibits attached hereto, is sufficient for the Commission to grant its consent to the proposed 0'.

reorganization, and to the indirect transfer of RG&E's licenses in the manner described above.

The proposed reorganization will not impair RG&E's qualifications as a licensee for the Nine Mile 2 and Ginna facilities, nor its ability to carry out its obligations under those licenses.

Moreover, the transaction described would be consistent with applicable laws and regulations of the Commission. RG&E respectfully requests that the Commission review and approve this application so as to enable the Company to proceed promptly with further steps necessary for its restructuring in the manner contemplated in the Settlement.

RG&E is planning to hold its annual shareholders'eeting in mid-April 1999, and would prefer to bring the proposed holding company reorganization before the shareholders at that time.

In order to enable the Company to complete the substantial preparations necessary before the submission of such a proposal for shareholder approval, including but not limited to formal R I 82280.1

action by the Company's Board of Directors and the preparation and dissemination of appropriate disclosure materials, RG&E respectfully requests that the Commission act upon the present application as soon as practicable, but in any event by February 1, 1999. RG&E would be pleased to provide promptly any further information that the Commission may require for its consideration of this application.

Respectfully submitted, ROCHESTER GAS AND ELECTRIC CORPORATION By:

Paul C. Wilkens Title: Senior Vice President Generation Dated: July 30, 1998 Rochester, New York RI 822 80.1

STATE OF NEW YORK COUNTY OF MONROE Paul C. Wilkens, being duly sworn, deposes and says: I am the Senior Vice President- Generation of ROCHESTER GAS AND ELECTRIC CORPORATION, the applicant herein; I have read the foregoing application and know the contents thereof; the same is true to the best of my knowledge except as to those matters therein stated to be alleged on information and belief, and as to those matters I believe them to be true.

Sworn to before me this 30'h day of July, 1998 Notary Public, State of New York LORETTA MARSHALLPARKER Notary Public iu the State ot New York MONROE COUNTY Commission Expires Dec. 12, 19.iL, Rt82280.1

0 EXHIBITA

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STATE OF NEW YORK BEFORE THE PUBLIC SERVICE COMMISSION CASE 94-E-0952 - In the Matter of Competitive Opportunities Regarding Electric Service CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/ Restructuring Pursuant to Opinion No. 96-12 AME<NDED AND RESTATED SE<TTLEMENT AGREEMENT October 23, 1997

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TABLE OF CONTENTS Page INTRODUCTION 1 Parties

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1 Subject 2 Background.... ".... 4 Negotiations 8 AGREEMENT ~ ~ ~ ~ 10 Term ($ 1) I 10 Rates ($$ 2-9) 11 Return on Equity (g 10) 17 Kamine (tt ll) .......................... 18 Inflation (tj 12) 19 Property Taxes ($ 13) ..................... ~ ~ 20 "System Benefits Charge" (fjfj 14, 15) ~ ~ ~ 20 Mandates, Catastrophic Events and Competition Implementation Costs (fj$ 16, 17) ........ 23 Securitization ($ 18) ...................... 25 Sunk Costs ($ 19)........................ 25 Sale of Generating Assets ($ 20).............. 26 To-Go Costs ($ 21)....................... 28 Nuclear Facilities (tttt 22, 23) ................ ~ ~ ~ 29 Shut-Down and Decommissioning Costs ($ 24).... 30 System Reliability and Market Power ($ 25)...... 31 Amortizations ($ 26)...................... 32 Post-Employment Benefits (tt 27) 32 Ginna Outage Costs (tt 28).................. 33 Excess Earnings ($ 29) 33 Environmental Remediation Costs (g 30) ........ 33 Amounts Due Customers ($ 31) 34 Incentives Owed RG&;E and Amounts Owed Cust omers Under Settlements ($ 32).............. 34 Flexible Tariff Discounts ($ 33) 35 Legal Services ($ 34) 35 Regulated Rate Design (fj$ 35-41)............. I ~ ~ 36 Large Customer Credit Program ($ 42) ~ ~ 37 Low-Income Program (fj 43) 37 44).....................

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Service Quality ($ 38 Retail Access Generally (fj$ 45-52) ............ 39 Distribution Access Charges (tttI 53-57) ......... 44 Reciprocity ($ 58) 47

e' TABLE OF CONTENTS Page Return to RLSE ($ 59) .... 48 Environmental Information ($ 60).... 49 Dairylea Program ($ 61) . .. 49

.......;......

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Corporate Structure (fj 62) .... 50 DISCO (0 63) .... 51 GENCO (fj 64) .... 51 RLSE (tt 65) .... 51 ULSE (tt 66) .. 52 HOLDCO and Capitalization of Unregulated Operations (tj 67)............ .. 52 Petition for Relief (tjg 68-70)............ .... 53 Filing Requirements (g 71-73) .... 55 Dispute Resolution ($ 74) .... 56 Binding Effect of Settlement (tt 75).......,. .... 56 Superseding Prior Settlements ($ 76)....... .... 57 Modification of Settlement ($ 77) ......... .... 57 Effect of Agreement (fj 78) .... 57 Withdrawal from Litigation (fj 79) .... 60 SCHEDULES A Rates B Amortizations C Manufacturing Classifications D Nuclear Decommissioning E Large Customer Credit Program F Low Income Program G Service Quality Performance Program H Retailing Functions I Standards Pertaining to Affiliates and the Provision of Information J Form of Petition to Form Holding Company K SBC Program Costs

STATE OF NEW YORK BEFORE THE PUBLIC SERVICE COMMISSION CASE 94-E-0952 - In the Matter of Competitive Opportunities Regarding Electric Service CASE 96-E-OS98 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/ Restructuring Pursuant to Opinion No. 96-12 SETTLEMENT AGREEMENT INTRODUCTION

' Parties This, Amended and Restated Settlement Agreement ("Settlement" ) is entered into this 23rd day of October, 1997 by and among the Staff of the Department of Public Service ("Staff', Rochester Gas and Electric Corporation ("RGB.E" or "the Company" ), The Joint Supporters ("Joint Supporters" ), the National Association of Energy Service Companies

("NAESCO"), and Multiple Intervenors ("MI"), hereinafter collectively referred to as "the Parties."

~Sub'ect As more specifically described herein, this Settlement is intended to resolve all issues in the above-captioned proceedings as they pertain to RGAE.-" Consistent with the vision articulated by the Public Service Commission ("the Commission" or "the PSC") in its 1996 Opinion in the Competitive Opportunities Proceeding,-" this Settlement will, upon approval by the Commission, set electric rates for a five-year period (July 1, 1997 through June 30, 2002) at levels that are, overall, substantially below their current levels. While rates for all customer classes will be reduced, large industrial and commercial customers will receive the most significant price decreases. Such decreases are in keeping with the Commission's goal of fostering economic development and job retention in the State by stabilizing and reducing electricity prices.-"

In addition to providing for lower prices for the next five years, the Settlement effects a major restructuring of RGB.E's operations to open up the Company's service area to increased customer choice. On July 1, 1998, the Company will begin to allow customers to As noted elsewhere herein, certain issues remain the subject of generic consideration and are, therefore, not resolved in their entirety by this Settlement. See, ~e footnote 123, infra.

Cases 94-E-0952 et al., In the Matter of Com etitive 0 ortunities Re ardin Electric Service, Opinion No. 96-12, Opinion and Order Regarding Competitive Opportunities for Electric Service, issued May 20, 1996.

See, ~e, id. at 1.

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choose their own supplier of electric energy.'-' year later, assuming implementation of a Statewide Independent System Operator ("ISO") and Power Exchange ("PE"),-" customers will begin to be able to choose their own supplier of energy and capacity.-" During this time, RGkE will restructure its operations so as to functionally separate its generation, distribution, retailing and overall administrative functions. While certain functions, such as distribution, will remain as regulated monopoly services, others, including retail service, will be open to competition from third parties.-" Recognizing that not all customers will be able (or perhaps willing) to select alternative suppliers of energy and/or capacity, the Settlement provides for continued service to such customers by a Commission-regulated functional unit of RG&E.

This Settlement also provides for continuation of a program to assist low-income customers-" and a service quality program intended to maintain safe and reliable service despite the cost-cutting pressures that accompany increased competition.-" Further, this resolution of issues in the Competitive Opportunities Proceeding responds to the See paragraph 46, infra.

The ISO and PE (also referred to as the "market exchange") are described by the Commission. See Opinion No. 96-12 at 63, footnotes 1 and 2.

See ibid.

See paragraphs 62 through 67, infra.

See paragraph 43, infra.

See paragraph 44, infra.

4 Commission's directive '" to introduce retail access to farm and food processor customers on

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an expedited basis. Finally, this Settlement resolves three pending cases involving judicial review of Commission decisions as they pertain to RG&E. '"

Except as expressly provided otherwise herein, this Settlement will, upon approval by the Commission, supersede the current Settlement dated May 10, 1996 ("the 1996 Settlement" ) approved with modifications by the Commission on June 27, 1996. '" In addition, upon approval by the Commission, this Settlement will supersede the initial Settlement in these proceedings dated April 8, 1997 ("Initial Settlement" ).

Baclc~round

' Opinion No. 96-12 is grounded in the Commission's desire to bring to New York State consumers the innovations and efficiencies of competitive markets, together 10!

Cases 96-E-0948 et al., Petition of Dair lea Coo erative Inc. to Establish an 0 en-Access Pilot Pro ram for Farm and Food Processor Electricitv Customers, Order Establishing Retail Access Pilot Programs, issued June 23, 1997.

See paragraph 61, infra.

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'See paragraph 79, infra.

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Cases 95-E-0673 et al., Rochester Gas and Electric Cor oration, Order Approving Terms of Settlement Agreement With Changes, issued June.27, 1996. The Commission restated its approval with modification in Opinion No. 96-27, Opinion and Order Concerning Revenue Requirement and Rate Design, issued September 26, 1996. The Commission's modification of the 1996 Settlement is the subject of an Article 78 proceeding, Rochester Gas and Electric Cor oration v. Public Service Commission (Sup. Ct. Albany Co. Index No. 6616-96), that will be withdrawn upon approval of this Settlement. See paragraph 79, infra.

with economic development, lower electric prices and greater customer choice, while, at the same time, maintaining the safety and reliability of electric service. Toward these ends the Commission's Opinion called upon the State's utilities to take certain actions and make.

certain filings.

The Commission adopted a "two-prong approach" to implementation of the policy directions identified in Opinion No. 96-12. The first prong, an ongoing collaborative effort among the utilities and other parties, was to continue to "accomplish technical studies (including addressing market power concerns, the role of energy service companies, and reporting requirements), necessary FERC [Federal Energy Regulatory Commission] filings, and public educational forums by October 1, 1996."-'" The second implementation prong consisted of individual utility filings also to be submitted by October 1, 1996. These filings 0

were "to address, at a minimum, the utilities'tructure, retail access proposals, long-term rate

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plans, public programs, market power and energy services." The Commission described the subject matter of the individual filings in greater detail as follows: '"

(1) the structure of the utility both in the short and long term, the schedule and cost to attain that structure, a description of how that structure complies with our vision'nd, in cases where divestiture of generation is not proposed, effective mechanisms that adequately address resulting market power concerns; Opinion No. 96-12 at 91.

Ibid.

l6'd. at 75-76.

(2) a schedule for the introduction of retail access to all of the utility's customers, and a set of unbundled tariffs that is consistent with the retail access program; (3) a rate plan to be effective for a significant portion of the transition that incorporates our goal of moving to a competitive market, including mechanisms to reduce rates and address strandable costs; (4) identification of the public policy programs, whose funding is not recoverable in a competitive market, that need special rate treatment and competitively neutral mechanisms to recover such costs; (5) an examination of the load pockets unique to the utility, identification of potential market power problems, and proposals to mitigate market power; and (6) a plan for the provision of energy services, including

' addressing the continued provision of customer protections consistent with an emerging competitive market.

In its October

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1, 1996 submission to the Commission, entitled "Competitive Initiative,"'" RGB:E addressed the topics identified by the Commission, stating what the The Company joined with the Energy Association of New York State and six other utilities in an Article 7S proceeding for judicial review of Opinion No. 96-12. That proceeding was commenced on September 18, 1996. The Ener Association of New York State et al. v. Public Service Commission (Albany Co. Index No. 5S30-96). The case is currently pending before the Appellate Division, Third Department.

ia.

Also referred to herein as the "October 1 Submission." In August 1996, during development of the Submission, the Company had held two Public Forums, open to all customers, and an Issues Forum, for elected officials, to address matters pertaining to competition and deregulation in the electric industry. See October 1 Submission at I I-21.

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Company's proposals would be in the event that it were required to implement the Commission's policies. '"

On October 9, 1996, the Commission instituted Case 96-E-0898 for the purpose of examining RG&E's October 1 Submission. '" Under the procedural schedule established by the October 9 Order, the parties would have a 90-day negotiation period during which they were encouraged to reach a settlement in lieu of litigation. In the event that negotiations proved unsuccessful, a litigation schedule would follow and the record would close within 150 days of issuance of the October 9 Order. To encourage settlement, the Commission waived certain elements of its 1992 Procedural Guidelines for Settlements.=""

Public Education Forums and Public Statement Hearings regarding RG&E's

'ctober 1 Submission were held on December 2, 1996 in Canandaigua and on December 4, 1996 in Rochester.='-"

The only element of the Competitive Initiative that was not contingent upon the outcome of the Article 78 proceeding (see footnote 17, ~su ra was the Company's proposal to institute a separate, identified "Public Policy Charge" ("PPC") for the costs of public policy programs the Company is expected to undertake.

Case 94-E-0952 et al., Order Establishing Procedures and Schedule ("October 9 Order" ).

21/

Case 90-M-0255 et al. Proceedin on Motion of the Commission Concernin its Procedures for Settlement and Sti ulation A reements filed in C 11175, Opinion, Order and Resolution Adopting Settlement Procedures and Guidelines, issued March 24, 1992.

The Stenographic Minutes of the Public Statement Hearings consist of pages 1-150.

Ne otiations Between October 22, 1996 and December 4, 1996, RG&E personnel met on 13 occasions with interested parties.-'" These meetings began with informational sessions at which Company representatives explained the October 1 Submission in detail and answered questions. Discussions progressed to settlement negotiations, which included exchanges of proposals and counter-proposals. These "all-party" meetings were conducted pursuant to the provisions of the Commission's regulations regarding settlements.-"'n early December, with the then-current deadline for filing testimony just weeks away and the parties'etermination that they were not sufficiently close to achieving a settlement, the all-party negotiations were suspended in order to prepare testimony. Staff and the Company, however, maintained a dialogue, exploring alternative approaches that ultimately led to the instant Settlement.

Although these discussions were suspended at various points, the effort continued throughout January, February and March. During this period, input on certain aspects of the proposals under discussion was sought and received from the Consumer Protection Board and Multiple Intervenors.

On March 27, 1997, a nearly complete draft '" together of the Initial Settlement, with a summary thereof, was distributed to all parties to Case 96-E-0898. On the same day, 23/

These meetings included ten all-day meetings held in Rochester and Albany and three lengthy conference calls in which the parities were invited to participate.

24!

16 NYCRR $ 3.9.

151 Including draft Schedules.

0,

.

0,

'

Staff, with assistance from RG&E, made a presentation to the parties in Albany. '" Staff and the Company fielded questions on the draft and solicited further comments. Additional all-party meetings were held on April 1, 2, and 3, 1997. These negotiations were productive, resulting in the consideration of comments and suggestions provided by those who participated in these meetings.

The Initial Settlement was executed and filed as of April 8, 1997. In accordance with the Commission's rules and the specific procedures applicable to these proceedings, various parties filed statements and testimony in support of, or in opposition to, the Initial Settlement. Evidentiary hearings were held in Albany on June 3, 4 and 5, 1997."

Post-hearing briefs were filed on or about June 20, 1997.

On July 16, 1997, Administrative Law Judge ("ALJ") Walter T. Moynihan issued a Recommended Decision ("RD") which recommended approval of the Initial Settlement with minor changes. Briefs on exceptions and replies to exceptions were filed on August 5 and 20, 1997, respectively.

At its Public Session held in Albany on October 8, 1997, the Commission discussed the Initial Settlement and recommended that the parties to these proceedings conduct further negotiations with a view toward addressing certain concerns raised in the Commission's discussion. On notice to all active parties, further negotiations were held in In addition to Staff and the Company, ten individuals, representing seven other parties, attended in person. Two parties participated by telephone.

The Stenographic Minutes of the Evidentiary Hearings consist of pages 335-2029.

Albany on October 14, 15 and 16, 1997. Representatives of the following parties participated:

Staff, RG&E, the Joint Supporters, NAESCO, MI, the Consumer Protection Board, the Attorney General, the Public Utility Law Project, the Public Interest Intervenors, New York State Electric & Gas Corporation, Wheeled Electric Power Company, Enron Capital & Trade Resources, and the Independent Power Producers of New York, Inc. These negotiations resulted in the changes to the Initial Settlement that are reflected in this Settlement.

The Parties believe that this Settlement, which constitutes a carefully balanced resolution of diverse interests and addresses the matters raised at the Commission's October 8, 1997 Public Session, is in the public interest, and should be adopted.

AGREEMENT The Parties agree as follows:

Term

l. Except as expressly provided otherwise herein, this Settlement shall be effective for a period of five Rate Years,-'" commencing July 1, 1997 '" and terminating June 30, 2002.

For purposes of this Settlement, a "Rate Year" is the one-year period commencing on July 1st of one calendar year and terminating on June 30th of the following calendar year.

29/

Inasmuch as rates for the Rate Year commencing July 1, 1997 are comparable to those established for that period by the 1996 Settlement, approval of this Settlement after July 1, 1997 requires no adjustment to the rates in effect for that Rate Year.

Rates Except as expressly provided otherwise in this Settlement, electric rates shall be reduced, cumulatively, from the levels in effect as of July 1, 1996 as follows:-'"

July 1, 1997: $ 3.5 million; July 1, 1998: $ 12.8 million; July 1, 1999: $ 27.6 million; July 1, 2000: $ 39.5 million; and July 1, 2001: $ 51.1 million.

The total annual amounts of the foregoing reductions shall be offset by the following annual amounts, listed by commencement of Rate Year, for the recovery '" pertaining to of costs the e

Kamine/Besicorp Allegany L.P. project ("Kamine") other than those described in paragraph 11, infra:

July 1, 1998: $ 3.5 million; July 1, 1999: $ 8.4 million; and 30/

Each date listed signifies the beginning of the Rate Year to which the indicated reduction applies.

3l/

No cost referenced in this Settlement may be considered for recovery, true-up or

' deferral unless it is prudent and verifiable.

0,

~-

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- 12.-

July 1, 2000 and continuing at this level until recovery of the cost of

'any settlement or other action requiring payment is complete or June 30, 2002, whichever is later: $ 10.5 million.

shall be entitled to commence the foregoing offsets regardless

'GEcE of when any settlement or other action requiring payment to Kamine takes effect. In the event that, during the term of this Settlement, it should become certain that the total cost of any settlement or other action requiring payments to Kamine will be less than the total amount provided hereunder for Kamine recovery during such term (i.e., $ 32.9 million), the Commission may, in its discretion, require additional rate reductions; provided, however, that the total amount of such reductions shall not exceed the difference between actual Kamine costs and the amounts provided for in this paragraph. In all other cases, in the event that the foregoing amounts provided for Kamine cost recovery exceed costs actually attributable to Kamine, any such excess balance remaining as of June 30, 2002 shall be applied to Sunk Costs, as described in paragraph 19, infra.

3. The rate reduction and Kamine recovery amounts listed in paragraph 2

~su ra, include the anticipated impacts of recently enacted reductions in State gross receipts 32/

In the event that recovery is not, or will not be, complete by June 30, 2002, and RGB'.E or any other Party believes that circumstances would favor or permit more rapid recovery of Kamine costs, RG&E or such other Party shall have the right, notwithstanding any other provision of this Settlement, to request the Commission to increase the offset amount.

~ i 0

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~,

taxes ("GRT"). The anticipated average combined State and local GRT rates, listed by commencement of Rate Year, are as follows:

July 1, 1997: 5.23%

July 1, 1998: 5.04%

July 1, 1999: 4.60%

July 1, 2000: 4.23%

July 1, 2001: 4.23%

To the extent that average GRT rates are other than as anticipated, the rate reductions provided for in this Settlement will be revised accordingly.

4. The allocation of the foregoing rate decreases among customer groups shall be as described in Schedule A to this Settlement.

0

5. The allocation of the revenue decreases corresponding to the foregoing rate decreases shall be applied to the Generation Business Segment '" and shall be based upon the relative responsibility of nuclear and non-nuclear generation for Cash Operation and Maintenance ("0&M")'-"expense.

33/

RG&E's current utility operations will be functionally separated into Generation, Transmission, Distribution and Retailing, hereinafter referred fo as "Business Segments." See paragraphs 62-67, infra.

For purposes of this Settlement, "Cash O&M" shall mean non-fuel O&M expenses less the amortizations listed in Schedule B. For purposes of this'Settlement, the following allocation shall be used: 65 percent to nuclear and 35 percent to non-nuclear.

6. Except as otherwise provided by contract, beginning July 1, 1999 and continuing through June 30, 2002, Incremental Manufacturing Load '" shall be served at an average rate of $ 0.059 per KWH.

7. Except as otherwise provided in this Settlement, the rates resulting from the foregoing reductions shall not be modified during the term of this Settlement to reflect any changes in revenues or expenses, including but not limited to changes in OAM savings (both Cash O&M and Non-Cash OEM '"), State and local tax reductions,'" and asset sales.'"

8. Upon filing appropriate documentation with the Commission, the rates resulting from the foregoing reductions shall be subject to modification for the following:

' For purposes of this Settlement, "Incremental Manufacturing Load" shall mean energy sales meeting both of the following characteristics:

1. The energy is sold to a customer whose Standard Industrial Classification is in one of the groups listed in Schedule C.

2. The customer adds at least 50 KW of new load by:

(a) constructing a new facility; (b) expanding an existing facility; (c) adding facilities or equipment to an existing site; or (d) adding facilities through the redevelopment of an existing site which has been vacant for at least six months.

3+I purposes of this Settlement, "Non-Cash OAM" shall mean amortizations pursuant to Schedule B.

38'or 37/

For purposes of this paragraph, property taxes.

"taxes" shall not include the Gross Receipts Tax or Notwithstanding any previous requirement pertaining to such matters, all savings not reflected in rates as of July 1, 1996 arising from the operation of the Nine Mile Point 2 and Oswego 6 jointly owned facilities shall be retained by the Company.

a. Kamine recovery as described in paragraphs 2, ~su ra, and 11, infra.

b. Variations in the costs described in paragraphs 14 and 15, infra:

c. Securitization benefits as described in paragraph 18, infra;

d. '" pursuant to this Settlement, including but not limited Deferrals to those provided for in paragraphs 12 through 17, 24 and 30, infra; and

e. Adjustments pursuant to paragraphs 24, 68 and 69, infra.

During the term of this Settlement such modifications pursuant to paragraph 8, ~su ra, shall be made only if the net effect of all such factors would be a

\

t projected cumulative balance, either owed to customers or owed to shareholders, greater than 0

$ 30 million on a pre-tax basis. The amount projected to be greater than $ 30 million shall be recovered by adjusting rates, on the next July 1st, for the remaining term of the Settlement; provided, however, that such rate adjustments shall be subject to the following:

a. No rate adjustments shall be made in Rate Years I or 2 with the exception of adjustments pursuant to paragraphs 14 and 18, infra.

A single Rate Year rate adjustment shall not exceed $ 7.0 million for any of the final three Rate Years of the Settlement with the exception of adjustments pursuant to paragraph 18, infra.

All amounts deferred pursuant to this Settlement shall bear carrying charges at the rate of 9.0 percent.

c. A rate adjustment shall not be for less than $ 3.5 million, subject to Item d.

d. The cumulative effect of all rate increases shall not exceed

$ 12.1 million per Rate Year.

e. Any amount attributable to items for which changes in cost are permitted to be recovered pursuant to this Settlement, but which are not recovered by the end of the term of this Settlement as a consequence of this paragraph shall be deferred for recovery beyond the end of such term and the timing of such recovery shall be determined by the Commission.

4 C hanges due to the "System Benefits Charge" 'nd Securitization shall be reflected without regard to the foregoing limitations.

The "System Benefits Charge" is described in paragraph 14, infra.

Return on E uitv

10. In the event that RGB:E achieves a return'-" on common equity in excess of 11.80 percent, as determined for the entire'" five-year term of this Settlement,'" the.

amount in excess of 11.80 percent shall be treated as follows:

a. Fifty (50) percent shall be used to write down deferrals accumulated during term 'of this Settlement. Any remaining amount of this fifty (50) percent portion shall be retained as earnings by the Company.

b. The first $ 800,000 of the other fifty (50) percent portion shall be used to reduce rates for subclasses pri-pri, subtra-sec, subtra-commercial and industrial, as listed in Schedule A. The remaining amount of this fifty (50) percent portion shall be used to write down accumulated deferrals or Sunk Costs. To the

'"

As used in this Settlement, "return" means the return on a regulatory basis for regulated operations ~e, it does not reflect tax benefits statutorily reserved for the benefit of investors or any disallowed assets for unrealized tax benefits.

42/

The actual return on common equity shall be computed annually. See paragraph 71, infra. At the end of the five-year Settlement period, annual amounts of over-or-under-earnings shall be netted for purposes of determining any sharing pursuant to this paragraph.

43/

150 basis points (30 basis points per year) shall be added to the computation of earnings for this five-year period to reflect a sharing of earnings from the Rate Year ended June 30, 1997.

44/

For purposes of this Settlement, "Sunk Costs" shall have the meaning described in footnote 66, infra.

extent that any portions of this amount shall remain after writing down all such deferrals and Sunk Costs, the Commission shall determine the disposition of such portion.

Kamine

11. In the event that RG&E becomes obligated to make actual payments to Kamine or any other party pursuant to either the purported Power Purchase Agreement

("PPA") or any litigation pertaining to the Kamine project or the purported PPA, RG&E shall be entitled, subject to paragraphs,8 and 9, ~su ra, to recover on a current basis in electric rates

"

an additional amount" not to exceed, on a Rate-Year basis,-'" the "Net PPA Amount," which shall consist of: seven-eighths (7/8) of the difference between (i) the amount that would be payable to Kamine if the purported PPA were enforced and Kamine generated and sold to RG&E the maximum output permitted under the purported PPA,'-" and (ii) any amount attributable to Kamine that was included in the rates that were effective as of July 1, 1996; provided that such Net PPA Amount shall be reduced by:

a. amounts accrued for Kamine costs pursuant to paragraph 2,

~su ra; and 45/

I.e., in addition to the amount attributable to Kamine ($ 9.6 million) that was included in the rates that were effective as of July 1, 1996.

Prorated, as necessary, to reflect commencement of recovery at any time other than the first day of a rate year.

Whether Kamine actually produces and sells electricity to RG&E or not.

0

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b. any Securitization benefits otherwise permitted to be used to mitigate Kamine costs.

Any Kamine costs not recovered currently shall be deferred for recovery in the subsequent Rate Years of the term of this Settlement-'nd, if not recovered by the end of such term, shall be deferred for recovery beyond the end of such term and the timing of such recovery shall be determined by the Commission.

Inflation

12. If, in any Rate Year, inflation, as measured by the actual GDP Chain-Weighted Price Deflator, exceeds 4.0 percent, RG&E shall be permitted to defer for future I recovery the amount by which any inflation-based increase in Cash O&M exceeds such 0

4.0 percent increase up to the percentage increase determined by the GDP Chain-Weighted Price Deflator." 'eferral and recovery of such increased costs pursuant to this paragraph shall not require further petition to or approval by the Commission other than filing of appropriate workpapers showing the calculation of the amount to be deferred.

During the term of this Settlement, however, such deferral and recovery shall not cause any increase attributable to Kamine costs to exceed the Net PPA Amount that would apply to the year of recovery.

49/

For purposes of this paragraph, Cash O&M shall be assumed to be $ 201 million until the implementation of the Energy and Capacity stage of the Retail Access Program, described at paragraph 46, infra, at which time Cash O&M will be assumed to be $ 176 million. These amounts shall be reduced by any amounts recovered through the "System Benefits Charge," as described in paragraph 14, infra. The deferral shall be calculated as the product of Cash 0&M and the difference between actual inflation and 4.0 percent.

Pro ertv Taxes

13. Changes in property taxes shall be addressed as follows:

a. Fifty (50) percent of any property tax increases over the Base Level,'" described in subparagraph c, below, shall be deferred for future recovery.

b. Fifty (50) percent of any property tax decreases from the Base Level shall be likewise deferred for future passback to customers.

c. The Base Level shall be equal to actual property tax expenditures over the twelve (12) months ended February 28, 1997, less taxes

' related to any assets sold after June 30, 1997.

"S 'stem Benefits Char e"

14. The Parties agree that the costs of certain mandated programs will be recovered through rates applicable to all customers, 'whether or not these costs are included in a separate System Benefits Charge ("SBC").-'" The programs are as follows:

Property taxes pertaining to non-nuclear generating facilities shall be deducted from the Base Level pursuant to the schedule stated in paragraph 55, infra.

The institution of such a charge is currently under consideration in Case 94-E-0952.

a. Research and Development: mandated research and development programs, excluding New York State Energy Research and Development Authority contributions;

b. Energy Efficiency: mandated energy efficiency programs, including DSM bidding programs undertaken in accordance with Commission orders; ""

c. Low Income: mandated low-income programs, whether new, existing or expanded, including low-income energy efficiency programs; and

d. Environmental Protection: mandated environmental protection

' programs, including programs designed to mitigate the environmental impacts of electric industry restructuring programs, excluding environmental remediation costs. '"

The revenue levels included in this Settlement are deemed to include funding for such programs at the levels listed in Schedule K and, unless different expenditure levels are approved, the net impact on customers would be zero. The Company will continue to administer existing contracts and the funds required to comply therewith. To the extent that the costs related to the above described SBC programs change from the levels listed in One way of disbursing funds for energy efficiency programs covered by this charge would be by means of a standard performance contract with stipulated pricing approved by the Commission.

53r See paragraph 30, infra.

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Schedule K during the term of this Settlement, those changes will be reflected in an adjustment to rates to take effect each July 1st during the term of this Settlement. Costs not recovered during any particular Rate Year will be reflected in rates in a future Rate Year,-"'s soon as practicable. Such cost changes shall be allocated to voltage classes in proportion to the "Rate Reductions" listed in Schedule A. The Company shall have no further obligation pursuant to the 1996 Settlement or the 1997 Eighteen-Month DSM Plan to implement or administer DSM programs and the Company shall have no further obligation to prepare or file future DSM plans or evaluation reports. '"

15. The costs described as Public Policy Costs in Section VII of RG8cE's October 1 Submission, to the extent permitted to be billed separately as part of an SBC, or as a Public Policy Charge, under the terms of the Commission's Order establishing an SBC, may be included in RGAE's SBC. To the extent that any of such costs are not recovered through an SBC or similar charge, as described in paragraph 14, ~su ra, such costs shall be otherwise recovered through distribution access rates. Changes in such costs due to governmental action of any kind will be considered Mandates, as described in paragraph 16,'infra. The materiality Which may include the period immediately following the term of this Settlement.

In addition, there shall be no denial of recovery of actual DSM expenditures pursuant to Schedule F to the 1996 Settlement. Due to contractual commitments under existing DSM programs, discontinuance of the Company's obligations will not result in immediate cessation of all expenditures.

~.

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threshold of $ 2.5 million'- will be applied to aggregated cost changes within each of the seven categories of Public Policy '" excluding SBC items.

Costs, Mandates Catastro hic Events and Com etition Im lementation Costs

16. In the event that, after the date upon which this Settlement is executed by the Company and on or before June 30, 2002, one or more Mandates 's implemented'"

and/or one or more Catastrophic Events' " occurs and, during any Rate Year covered by this 56/

A zero ($ 0) materiality threshold shall apply to items included in the SBC.

57/

These categories are:

1) DSM

2) Low-Income Assistance

3) Obligation to Serve - Incremental Expenses

~ 4) Economic Growth

5) Environmental Initiatives

6) Mandated and Public Policy Research and Development

7) Regulatory Assessments and Expenses For purposes of this Settlement, a "Mandate" shall mean (a) any governmental action, including changes in laws and regulations (including tax laws and regulations) and orders of regulatory and other agencies which result in cost changes, and (b) any changes in accounting required by generally accepted accounting principles. In the event that any such "Mandate" consists of actions in response to an asserted failure by the Company to conform to valid legal requirements, the Company shall have the burden of showing that its conduct which gave rise to such action was consistent with the best interests of customers.

59/

"Implementation," as used in this paragraph, shall not be deemed to refer only to commencement of new Mandates, but shall instead include both commencement of new Mandates and changes to existing Mandates.

For purposes of this Settlement, a "Catastrophic Event" shall mean an event that triggers the designation of part of the Company's service territory as a disaster area or as being under a state of emergency.

0

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Settlement, the cost impact of any individual Mandate or any individual Catastrophic. Event exceeds $ 2.5 million,"RG&E shall be entitled to defer the entire amount attributable to such Mandates and Catastrophic Events and to recover or pass back such amount as soon as .

possible thereafter, subject to the terms of paragraphs 8 and 9, ~su ra. Such deferral and recovery or pass-back, with the exception of Commission-imposed Mandates, shall not apply to generating facilities that, pursuant to the Energy and Capacity stage of the Company's Retail Access Program, "-'re fully exposed to market pricing.

17. RG&E shall be entitled to defer and to recover as soon as possible, subject to the terms of paragraphs 8 and 9, ~su ra, the entire amount of all Competition Implementation Costs'-" that exceed, in the aggregate in any Rate Year, $ 2.5 million.

~

Such impact shall be calculated only with reference to regulated operations. The

$ 2.5 million threshold, however, shall not apply to changes in nuclear decommissioning costs that are the result of Mandates.

63/

Described at paragraphs 45-52, infra.

63/

For purposes of this Settlement, "Competition Implementation Costs" shall mean all incremental expenditures incurred by RG&E after February 28, 1997, in connection with all regulatory proceedings, legislation, regulations, and orders pertaining to the implementation of a competitive market for electric service.

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Securitization

18. The benefits, if any, of any Securitization 'hat may become available after this Settlement is executed by RGB'.E shall, subject to paragraph 11, ~su ra, be used to increase the amounts of the rate reductions identified in paragraph 2, ~su

'" and any such ra, further rate reductions shall be allocated in a manner consistent with the legislation or Commission orders authorizing Securitization.

Sunk Costs

19. All prudently incurred Sunk Costs""as of March 1, 1997 shall be included in rates charged pursuant to RGAE's distribution access tariff. The Parties intend

' that the provisions costs, during the term of this Settlement will allow the Company to continue to recover of the Settlement, under Statement of Financial Accounting such Standards No. 71 ("SFAS 71"),' " which provides for certain accounting conventions for regulated W

64'or purposes of this Settlement, "Securitization" shall mean Commission-issued rate orders, legislatively authorized or otherwise, that are specifically intended to create added credit quality for utility borrowings, allowing assets or utility costs to be financed at more favorable terms than otherwise available. This reduced cost of borrowing is the benefit referred to in the text. Securitization'shall not be deemed to include general rate orders or financing orders issued in the ordinary course.

651 Without regard to the limitations of paragraph 9(a) and (b), ~su ra.

66!

For purposes of this Settlement, "Sunk Costs" shall mean all investment in electric plant and electric Regulatory Assets. A "Regulatory Asset" is a deferred cost whose classification on the Company's Balance Sheet as an asset is permitted pursuant to paragraph 9 of SFAS 71.

67(

Accounting for the Effects of Certain Types of Regulation.

companies subject to cost-based ratemaking. The Parties shall meet prior to July 1, 2000 to discuss future ratemaking treatment of such costs. Such treatment shall be consistent with the principle that the Company shall have a reasonable opportunity beyond July 1, 2002 to.

recover all such costs.'"

Sale of Generatin Assets

20. To the extent that any existing generating assets are sold (such as via an auction or other suitable mechanism to establish market value) during the term of this Settlement, any gains on such sales shall be shared between shareholders and customers as follows:

a. With respect to sales occurring during the first three (3) Rate

~

Years of the Settlement period, customers shall be entitled to sixty (60) percent of the first $ 20.0 million of any such gain, and the Company shall be entitled to retain the remainder.

Customers will be entitled to eighty (80) percent of any such gains over and above the first $ 20.0 million.

b. With respect to sales occurring during the final two (2) Rate Years of the Settlement period, customers shall be entitled to Such principles of cost recovery shall also apply to the negotiations referenced in paragraph 23, infra.

.

eighty (80) percent and the Company shall be entitled to retain twenty (20) percent of all gains.

The gain so shared shall be net of any losses due to generation asset sales, transaction costs, the cost of any hedging arrangements necessary to manage the Company's risk of fluctuations in the price of the electric commodity or required ancillary services, and all applicable financial statement tax effects. The Company's share of the gain shall be excluded from all calculations of regulatory earnings. The parties shall meet prior to July 1, 2000 to discuss the treatment of the customer's share of the gain and make a recommendation to the Commission with respect thereto. The Parties intend that the provisions of this Settlement will allow the Company to recover, in rates charged pursuant to RGAE's distribution tariff, any prudently incurred losses, including all applicable financial statement tax effects, resulting from the sale 0

of a generating asset, during the term of the Settlement, under SFAS 71. The Parties shall meet prior to July 1, 2000 to discuss future ratemaking treatment of such costs. Such treatment shall be consistent with the principle that the Company shall have a reasonable

'pportunity beyond July 1, 2002 to recover all such costs.

To-Go Costs

21. The fixed portion of the To-Go Costs'-" of RG&E's fossil generating units,

'" and power purchase contracts (other

'" hydroelectric generating units,-'" gas turbines,

'"

than Kamine), and the fixed portion of the To-Go Costs of the Company's share of Oswego 6 shall be recovered in full through the Company's distribution access tariff until July 1, 1999 69/

For purposes of this Settlement, "To-Go Costs" shall mean all capital costs incurred after February 28, 1997, O&M expenses and property, payroll and other taxes. The "variable" portion of such costs shall mean the costs that vary as KWH output varies at a generating plant, chiefly fuel expense. The "fixed" portion of such costs shall mean all such costs not defined as "variable."

RG&E's wholly owned fossil generating units consist of Beebee Station (Unit 12) and 0 Russell Station (Units 1-4).

Stations 2, 5, 26, 160, 170 and 172.

Stations 3 and 9.

RG&E currently has the following long-term power purchase contracts:

Contract Name Contract Capacity (KW) Expiration of Contract Niagara Firm 65,000 August, 2007 Niagara Par. "B" 35,000 August, 2007 St. Lawrence 55,000 August, 2007 Hydro Quebec 20,000 October, 1998 FitzPatrick 12 Month Notice Winter 44,000 Summer 50,000 Gilboa 150,000 June, 2002

in accordance with paragraphs 45 and 52, infra. The variable portion of such To-Go Costs'

"

shall be subject to the market for electricity in accordance with paragraphs 45 and 46, infra.

Nuclear Facilities

22. All prudently incurred costs of Ginna Station and the Company's share of Nine Mile Point 2 shall be recovered through retail rates subject to the provisions of the following paragraph, provided, however, that such costs shall not be subject to true-up or reconciliation except as otherwise provided in this Settlement.

23. RG8cE shall participate in good-faith negotiations with Staff and with the other cotenants of Nine Mile Point 2 regarding future rate treatment of such facility. The Parties anticipate that similar treatment will be applied to Ginna Station. Such negotiations and any proposed treatment resulting therefrom shall be consistent with and in furtherance of the following principles:

a. any Commission or other State solution must be consistent with Nuclear Regulatory Commission ("NRC") requirements;

b. a Statewide solution to treatment of nuclear facilities is preferable to individual utility-by-utilitysolutions and any solution pertaining to RGAE must be consistent with a Statewide solution; See footnote 69, ~su ra.

c. RG&E's nuclear facilities shall remain subject to the provisions of paragraph 16, ~su ra, during the term of this Settlement; and

d. no change in the treatment of RG&E's nuclear facilities shall be implemented until at least January 1, 2000.

In the event that the above-described negotiations should result in any change in ratemaking treatment, the Parties will meet to discuss the relationship between the potential impact on the Retail Access Program implementation schedule, the associated conditions and limitations on customer participation and the level of To-Go Costs that are subject to the market.

Shut-Down and Decommissionin Costs

24. All prudently incurred incremental costs pertaining to the shut-down and

~

decommissioning of generating facilities,-'" whether fully or partially owned by RG&E, shall be recovered through the Company's distribution access tariff. Nuclear decommissioning costs shall be as described in Schedule D. In the event that the estimates of nuclear decommissioning costs contained in Schedule D change, '" RG&E shall submit to the Commission and the Parties a revised Schedule D, showing such changes and shall, upon request of the Commission or the Parties, provide reasonable documentation therefor. The In addition to the decommissioning costs shown in Schedule D for nuclear plant, "shut down and decommissioning costs" include transmission and distribution costs associated with elimination of a particular generating facility, severance pay resulting from such elimination, and decommissioning of fossil facilities.

This provision is intended to address changes in estimates that are not the result of changes in Mandates, as defined in footnote 58, ~su ra.

0

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Company, upon Commission approval,-'" shall thereupon be permitted to change its distribution access rates to reflect such increase or decrease. Other than nuclear decommissioning costs currently included in rates, the above costs shall be deemed incremental and deferred for recovery pursuant to the provisions of paragraphs 8 and 9, ~su ra.

S stem Reliability and Market Power

25. RG&E shall maintain the reliability of its system, including those portions of the '"

system identified as Load Pockets, in the most cost-effective manner, considering a range of alternatives including but not limited to: transmission and distribution system reinforcements, maintenance of existing plant, energy efficiency and distributed generation. In connection with the petition of the Member Systems of the New York Power iO Pool ("NYPP") to the FERC to form new wholesale market institutions (the ISO, PE and the New York State Reliability Council), the Company shall file a market power mitigation plan with FERC and shall take appropriate action in accordance with the outcome of such filing.

Nothing in this Settlement shall preclude the Commission from implementing market power mitigation measures for retail service, as appropriate, after the term of this Settlement.

Such approval process shall be based upon a showing of the necessity and reasonableness of the expenditures.

For purposes of this Settlement, "Load Pockets" shall have the meaning described in Opinion No. 96-12 (at 60): "'Load pockets'xist when, due to transmission system limitations, some generation must be located within a particular location in order to continue the provision of reliable service." RG&E's Load Pockets are described in Section V of the October 1 Submission.

i ~ Amortizations

26. Schedule B to this Settlement shows the items and the amounts thereof that will be deemed to have been amortized during the term of the Settlement. RG&E shall be permitted to record amortizations and unamortized balances as it deems appropriate over the five Rate Years of the Settlement; provided, however, that, at the conclusion of the Settlement period, any unamortized balance for a particular item shall not be greater than it would have been had the amortization been recorded as shown on Schedule B. For purposes of computing RGEcE's regulatory earnings, the levels of amortization expenses shall be as indicated on Schedule B.

Post-Em lovment Benefits e

27. The parties agree that upon approval of this Settlement by the Commission, and effective as of January 1, 1997, the Commission's policy statement on accounting and ratemaking for pensions and other post-employment benefits' " shall no longer apply to RGB.E and to its accounting policies.

Case 91-M-0890, Statement of Polic and Order Concernin the Accountin and Ratemakin Treatment for Pensions and Postretirement Benefits other than Pensions, issued September 7, 1993.

e

~, Ginna Outa e Costs

28. RGAE shall be permitted, at its option, to book costs associated with Ginna Station maintenance outages on a levelized basis. Such costs shall be deemed to. have been recovered from customers on a levelized basis.

Excess Earnin s

, 29. Except as expressly provided otherwise in paragraph 10, ~su ra, any excess earnings attributable to the Rate Year ending June 30, 1997 or any prior Rate Year

"'hall be deemed to have been passed back to customers as of July 1, 1997.

Environmental Remediation Costs 0

30. RGE.E will defer on its books of account and reflect in rates as prescribed by this paragraph and pursuant to paragraphs 8 and 9, ~su ra, site investigation and remediation ("SIR") costs '" for electric operations in excess of $ 2.0 million annually. Any costs deferred under this paragraph will be net of recoveries of these costs under insurance policies or from third parties.

$ 0!

Including any amount, not exceeding $ 2.5 million, pertaining to excess collections under the Fuel Cost Adjustment.

SIR costs are the costs RGEcE incurs to investigate, remediate, or pay damages, including natural resource damages, but excluding personal injury damages, with respect to industrial and hazardous waste or contamination, spills, discharges and emissions for which RG8rE is responsible.

Amounts Due Customers

31. RGEcE shall record any Service Quality Performance Program-'~

penalties that become due to customers during the term of this Settlement. To the extent that these amounts are not offset by amounts due the Company, excluding Mandates, as described in paragraph 16, ~su ra, they shall be carried forward to the end of the term of this Settlement and the ultimate disposition of any such carry-forward balance shall be determined in a future rate proceeding.'"

Incentives Owed RGAE and Amounts Owed Customers Under Settlements

32. Any and all Electric Revenue Adjustment Mechanism ("ERAM")

deferrals and incentive amounts that were due to the Company as of June 30, 1997, including amounts derived from the electric rate settlement approved by the Commission in Opinion No. 93-19 ("the 1993 Settlement" )-"', shall be deemed to be eliminated as of the effective date of this Settlement. Any and all amounts that were due to customers as of June 30, 1997 including amounts derived from the 1993 Settlement, the "Settlement Agreement - Demand The Service Quality Performance Program is described in paragraph 44, infra.

83/

Such balance shall bear carrying charges at the annual rate ef 9.0 percent.

84!

Cases 92-E-0739 et al., Rochester Gas and Electric Cor oration, Opinion and Order Approving Settlement, issued August 24, 1993. The referenced items include DSM, Service Quality, Integrated Resource Management Incentive ("IRMI")and Ginna Steam Generator replacement cost sharing. See 1993 Settlement, paragraphs I S-20, 32.

Side Management Issues" ("the DSM Settlement" ) approved in Opinion No. 95-20,-'" the 1996 Settlement and the Nine Mile 2 Settlements shall also be deemed to be eliminated as of the effective date of this Settlement.

Flexible Tariff Discounts

33. During the term of this Settlement, RG&E shall have authority to provide discounted service pursuant to Service Classification No. 10 ("SC-10") contracts or similar flexible pricing arrangements, including the Flexible Distribution Tariff Option described in Appendix A to Schedule A. Lost margins resulting from all such sales prior to July 1, 2002 shall be deemed to have been recovered by the Company during the term of this Settlement.-"'e Le al Services

34. This Settlement resolves all issues'pertaining to the cost of legal services and is deemed to complete all the recommendations contained in the final report issued by Mitchell/Titus and Company in November 1993 in the Statewide Legal Services Cases 95-E-0673 et al., Rochester Gas and Electric Co oration, Opinion and Order Approving Settlement of DSM Issues, issued December 27, 1995.

86/

This paragraph shall not be construed as limiting RG8cE's right to seek explicit recovery of some or all of the lost margins on sales of electricity or distribution service made after June 30, 2002, regardless of when the contracts pursuant to which such sales were made were entered into.

i Study (Case 92-M-0047). Accordingly, there are no further studies, reports or actions required of the Company in regard to this matter.

Re ulated Rate Desi n

35. Except as expressly provided otherwise in this Settlement, any change in revenues pursuant to the provisions hereof shall be allocated uniformly to all service classifications ("SC").-'"

36. For SC-1, SC-2, and SC-4, Schedule I, the monthly customer charge shall be increased by $ 1.50 in each Rate Year of the term of this Settlement, with corresponding decreases in energy rates, as shown in Schedule A.

37. For SC-4, mandatory application to large customers shall be eliminated.

38. For SC-8, the difference between peak and shoulder period energy charges shall be eliminated as of July 1, 1997, with a corresponding increase in demand charges. In subsequent years, energy charges shall be reduced accordingly, as shown for illustrative purposes in Schedule A.

39. The Company is authorized to modify the eligibility criteria of SC-10 to eliminate the requirements of item A.3 (energy audits).

Reference in this paragraph and in paragraphs 36 through 40, infra, to "service classifications" shall be to the. existing service classifications in RG&E's Electric Tariff (P.S.C. No. 14), and in RG&E's Street Lighting Tariff (PSC No. 13). For the purposes of this Settlement, the projected KWH sales as presented in Schedule A shall be used.

40. The Company is authorized to modify the eligibility criteria of SC-11 to eliminate the energy audit requirement.

41. The Company is authorized to make rate design changes to its other

'hat electric service classifications are consistent with the principle of reducing marginal energy prices. Further, during the term of this Settlement, the Company may at any time petition the Commission for approval to implement revenue-neutral or de minimis rate or rate design changes, including changes to the rate design plans described in paragraphs 35 through 38, ~su ra.

Lar c Customer Credit Pro ram

42. RG8'cE shall continue its Large Customer Credit Program in accordance with Schedule E to this Settlement, which shall supersede Schedule F to the 1996 Settlement.

Low-Income Pro ram

43. RGB'E shall continue to implement the Low-Income Program contained in Schedule F to this Settlement and to recover in Residential Rates '" the amounts specified in Schedule K. Prior to June 30, 1999, the Parties shall meet to discuss whether the Program should continue beyond its scheduled expiration date (June 30, 1999) and, if so, in what form.

SC-3, SC-7 and SC-9.

For purposes of this paragraph, "Residential" shall mean SC-1 and SC-4 customers.

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88'4. RG&E shall continue its Service Quality Performance Program in accordance with Schedule G to this Settlement, which shall supersede Schedule H to the 1996 Settlement. 'he new Program shall continue through June 30, 1999. The Electric Reliability component "'f the Program shall apply only to RG&E's distribution operations and the Customer Service component "'hall apply only to the Company's Regulated Load

'"

Serving Entity ("RLSE") operations. Prior to June 30, 1999, the Parties shall meet to discuss whether the Program should continue beyond its scheduled expiration date and, if so, in what form. Notwithstanding the foregoing, if RG&E determines that the implementation of competition results in deterioration of performance under the Service Quality Performance Program;"'G&E shall be permitted, independent of any other provision of this Settlement, to petition the Commission for relief from the effects of any component of the Program that is affected by implementation of competition.

90/

The only substantive difference between the 1996 Program and the current one is in the amounts of the maximum penalties.

9l/

The maximum penalty for the Electric Reliability Component shall be $ 750,000, allocated equally between the two items in this component.

92/

The maximum penalty for the Customer Service component-shall be $ 500,000, allocated equally among the six items in this component.

93/

"RLSE" is defined in Section VIII (p. VIII-23) of RG&E's October 1 Submission and described in paragraph 65, infra.

94/

~E, complaints due to customer confusion.

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Retail Access Generallv

45. RGEcE shall offer its customers the opportunity to purchase their own electric energy and capacity and the Company shall deliver such electric energy and capacity in accordance with the following description of the Company's Retail Access Program. The Parties acknowledge that RGkE's ability to undertake the Retail Access Program is

'"

contingent upon numerous conditions and circumstances, a number of which are not within the direct control of the Parties. Accordingly, the Parties agree that it may become necessary to modify the Program to account for such factors, and they agree further to address such matters in good faith and to cooperate in an effort to propose joint resolutions of any such matters.

46. The Retail Access Program shall be a "Single Retailer" program, as 0

described in RGB.E's October 1 Submission,'" and as such "Single Retailer" program has been modified pursuant to the terms of this Settlement." For a period of three years, beginning with the implementation date of the Program, as described in paragraph 48, infra, RGEcE shall offer the option of unbundled billing services under a tariff to participating Load 9S/

Including the existence of an adequate market, as described in paragraph 52, infra.

See Section VIII (pp. VIII-16,- VIII-18).

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A list of the retailing functions, the provision of which will be the responsibility of LSEs participating in the Program, is included in Schedule H.

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Serving Entities ("LSEs"). 'he Program will be phased in, as described in paragraphs 48 through 52, infra. It shall commence on July 1, 1998 by allowing customers to choose their own supplier of electric energy (the "Energy Only" stage of the Program). During this stage of the Program, the Company shall continue to provide and be compensated for the generating capacity required to serve all customers reliably. On July 1, 1999, subject to the provisions of paragraphs 52 and 68, infra, customers will be permitted to choose their own supplier of energy and capacity (the "Energy and Capacity" stage of the Program). '"

47. RGEcE agreed to cooperate with the Parties to commence work on the Retail Access Program as soon as the Parties executed the Initial Settlement and the Company agrees to continue to do so upon execution of this Settlement; provided, however, that any i ncremental costs or commitments incurred by the Company in connection with such work performed since April 8, 1997 shall be deemed to be included in the Competition Implementation Costs that are subject to recovery pursuant to paragraph 17, ~su ra.

LSEs are described in Section VIII of RGkE's October 1 Submission (pp. VIII VIII-11). An individual customer can qualify as an LSE and procure its combined needs for some or all of its separate accounts. "Unbundled billing services" include preparation and mailing of a single bill on the LSE's behalf. The purpose of having RGEcE offer such service is to permit LSEs to commence operations without having to wait for development of their own billing systems. The three-year limit is intended to recognize that this service will ultimately be available on a competitive basis and, therefore, to give RGEcE the option of terminating this regulated offering after allowing LSEs a reasonable period to make alternative billing arrangements.

As the designation indicates, the LSE will be responsible for purchasing capacity upon commencement of this stage of the Program.

48. Subject to the provisions of paragraphs 45, ~su ra, and 52, infra, the schedule for implementation of the Retail Access Program is as follows and is contingent upon the events listed in Items a through c:

a. Execution of an agreement regarding the functional requirements

of the Program by May 30, 1997;

b. Development of the form of Operating Agreement "" and filing of proposed tariffs by December 1, 1997; Commission approval of tariffs by February 1, 1998;

""

d. The Energy Only stage of the Program begins by July 1, 1998, at which time customers using up to 670 GWH of energy per year, in the aggregate, '"'illbe eligible to participate; il001 "Functional requirements" will describe the business and/or system processes needed to implement retail access and unbundled billing. Subsequent critical components of the system development process, such as the operating agreement, business procedures, communications, system specifications and training, will eventually evolve from these requirements.

I 0 II Operating Agreements are described in Section VIII (pp. VIII VIII-26) of RGB:E's October 1 Submission. The Operating Agreement is currently being drafted in consultation with an Advisory Council made up of the Parties. The Operating Agreement will be referenced in the Distribution Access Tariff and will be on file with the Commission. It is expected that there may be differences between an Agreement for a single customer acting as an LSE and an Agreement. for an LSE serving multiple customers.

10>D Except as provided in paragraph 61, infra, these tariffs shall be effective as of July 1, 1998.

All references to customer consumption are to aggregated use.

The Energy and Capacity stage of the Program begins by July 1, 1999, at which time customers using up to 1,300 GWH of energy per year will be eligible to participate;

f. As of July 1, 2000, customers using up to 2,000 GWH of energy will be eligible to participate;

g. As of July 1, 2001, customers using up to 3,000 GWH of energy will be eligible to participate;

h. As of July 1, 2002, all retail customers will be eligible to participate.

49. To permit implementation without unnecessary disruption, the Parties agree that the Retail Access Program scope and functional requirements will not be changed 0

in a way that substantially alters the administrative and other changes necessary for timely implementation of the Program. No such change in scope or functional requirements shall be made without RGB.E's consent.

50. To the extent that energy consumption by end-use customers in the Company's service territory grows beyond a level of 6,714 GWH during the term of this agreement, the GWH caps on eligibility described in paragraph 48, ~su ra will be increased by the amount of additional energy consumption.

51. Eligibility for the Retail Access Program will nest be restricted by customer class.

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52. The Parties agree that the existence of a functioning Statewide Energy and Capacity Market

in which RGEcE is able to practicably participate is a crucial factor in the Company's ability to implement the Energy and Capacity stage of the Program. If such a Statewide Energy and Capacity Market is not implemented by July 1, 1998, the Company may petition the Commission for a delay in the implementation of the Energy and Capacity stage of the Program and show cause why relief from this schedule is required. If the Program is delayed in this fashion, the provisions of paragraph 56, infra, will apply and the caps on participation in the Energy and Capacity stage of the Program described in paragraph 48, ~su ra, will apply. The Parties further agree that, prior to July 1, 2000, they shall meet to review the progress of retail access under the Program and shall consider and recommend to the Commission, as appropriate, any changes to the implementation schedule 0

that are determined to be necessary; provided, however, that no such changes shall be recommended unless they are revenue neutral and do not materially increase the level of risk borne by the Company.

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The "Statewide Energy and Capacity Market" is defined to be a set of circumstances and conditions such as that identified by the Member Systems of the NYPP in their January 31, 1997 filing with the FERC to create new wholesale market institutions in New York. This Market, as thus defined, would include mechanisms for the wholesale purchase and sale of the electric energy commodity by any qualified entity, as well as the same or different mechanisms for the purchase and sale of generating capacity commitments by such entities.

Distribution Access Char es

53. LSEs will be required to take transmission service under the Company's FERC Open Access Transmission Tariff ("OATT"), "" until such time as that tariff is superseded by a FERC-approved Statewide open access transmission tariff. At that time, LSEs will be required to take service under the Statewide tariff. To the extent that modifications to the OATT are necessary during the term of this Settlement to implement the Retail Access Program, the Company will consult with interested Parties in the development of such modifications, and the Company will file such modifications with the Commission with a request that the Commission approve such modifications. In the filing the Company will justify requested modifications to non-rate terms and conditions and will indicate how I

rates should be designed for the Retail Access Program. Following Commission approval, the Company will file the amendments to the OATT together with the Commission's order approving the amendments with the FERC with a request that the FERC defer to the Commission on such modifications. Where requested by the Company to do so, Staff shall employ all reasonable means to expedite the Commission's approval process. The foregoing process shall not be construed as requiring RG&E to take any action that is inconsistent with lawful FERC jurisdiction and requirements. LSEs will also be required to take distribution service under a PSC-regulated distribution tariff. Any costs not recovered through the FERC-regulated transmission tariff will be recovered, to the extent permitted hereunder, Filed July 9, 1996 in Docket No. OA96-141-000.

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through the PSC-regulated tariffs and any costs recovered through FERC-regulated tariffs shall not be recovered through PSC-regulated tariffs. The distribution access tariff charges will be based upon the loads of the LSE's retail customers aggregated by voltage class..

54. For the Energy Only stage of the Retail Access Program, the rates charged to LSEs under the Company's tariff for distribution access shall be set by deducting from the rates that would apply to bundled retail service $ 0.02305 per KWH . LSEs shall be entitled to purchase energy from the Company at a rate of $ 0.01905 per KWH to serve the, requirements of the retail customers they serve within the Company's service area, provided that such LSEs contract to serve the full requirements of such customers and purchase all of the energy required to do so from the Company through June 30, 1999 or until the Energy Only stage of the Program terminates, if such stage extends beyond June 30, 1999."" In the event that the Energy Only stage of the Program extends beyond June 30, 1999, the distribution access rates may, if necessary, be changed in accordance with paragraph 56, infra.

55. For the Energy and Capacity stage of the Retail Access Program, the rates charged to LSEs under the Company's tariff for distribution access shall be approximately equal, on average, to the rates that would apply to bundled retail service less retailing costs and the per-unit fixed and variable To-Go Costs of non-nuclear energy sources, exclusive of property taxes. The property tax component of the per-unit non-nuclear To-Go 106'f this amount, $ 0.004 per KWH represents average "retailing costs." The types of retailing functions to which "retailing costs" pertain are shown in Schedule H.

07!

1 LSEs shall make this election on a customer-by-customer basis, thus permitting LSEs to diversify their sources of electricity supply.

Costs shall be deducted from bundled rates as follows: twenty (20) percent upon commencement of the Energy and Capacity stage of the Retail Access Program, and an additional twenty (20) percent commencing every twelve (12) months thereafter."

56. Ifthe Statewide Energy and Capacity Market is not fully in place as of July 1, 1998, the Company shall, after consultation with interested Parties, be authorized to charge rates for distribution access that will be approximately equal, on average, to the rates that would apply to bundled retail service less retailing costs and the per-unit market price of energy and capacity, as defined at the points at which the Company's transmission system

""

interconnects with the Statewide transmission system. These rates will apply to distribution access service for a period no longer than twelve (12) months after the full implementation of the Statewide Energy and Capacity Market. The Company will not interfere with or in any way seek to delay the implementation of the Statewide Energy and Capacity Market., The appropriate rates for LSEs purchasing energy from the Company shall be determined consistent with this paragraph.

108!

The total per-unit reduction from bundled rates will average 3.2 cents per KWH. This figure includes both retailing costs and To-Go Costs of non-nuclear energy sources.

Schedule A shows, for illustrative purposes, the average distribution access revenues per KWH by voltage level, without accounting for rate design, for each year of the Energy and Capacity stage of the Program. The actual distribution access rates shall be filed with the Commission as tariff changes.

109!

The Company shall file appropriate tariff leaves to effect such change and the approval process therefor shall be limited to verification of the changes reflected therein. The same procedure shall apply to changes pursuant to paragraph 57, infra.

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57. Upon extension of eligibility for the Retail Access Program to all retail customers on July 1, 2002, the Company shall be authorized to modify its distribution access rates so as to hold constant the degree to which its To-Go Costs are at risk for recovery through the market. "" The Parties agree to meet before July 1, 2001 to discuss future ratemaking plans. If, during the operation of the Energy and Capacity Stage of the Retail Access Program, the market price of energy and capacity measured at the Company's interconnections with the Statewide transmission system, exceeds an average of 3.2 cents per KWH on a persistent and sustained basis, the Parties will meet to discuss the potential acceleration of the Retail Access Program implementation schedule, the associated conditions and limitations on customer participation and continued recovery of nuclear costs in the event of a subsequent decrease in market prices, subject to the provisions of paragraph 23, ~su ra.

0

~Reci rocitv

58. In the event that RG&E is requested to permit access by an electric utility or affiliate"" of such utility where an affiliate of RG&E would be denied comparable access to the service territory of such other utility or utility affiliate, RG&E shall have the 1101 Recovery of non-nuclear To-Go Costs shall continue to be through the market, except that property taxes are to be phased out of regulated rates -as described in paragraph 55, ~su ra.

For purposes of this Settlement, "utility affiliate" shall mean any entity having any ownership, partnership, joint venture or other common enterprise interest with a utility in which either entity has more than five (5) percent ownership in the other or in any of the foregoing entities.

right to petition the Commission for an order requiring that such other utility provide the Company's affiliate comparable access or precluding the other utility or its affiliate from participating in RG&E's Retail Access Program until such time as access is provided to RG&E's affiliate. "" The filing of such petition shall operate automatically to stay participation in RG&E's Program until the matter is decided by an order of the Commission on the petition.

Return to RLSE

59. Customers who have participated in the Retail Access Program shall be permitted to return to service under the Regulated Load Serving Entity ("RSLE") "" tariff;

provided, however, that RG&E shall be permitted to establish reasonable measures, including but not limited to time and frequency limits on switching, to prevent customers from "gaming" the Program. During the Energy Only stage, RG&E will allow such returning customers to take service at regulated retail rates. During the Energy and Capacity stage, if the Company's incremental costs of supplying energy and capacity are different from the costs of energy and capacity embedded in regulated retail rates, the Company shall be permitted to charge such customers the equivalent of regulated retail rates adjusted for the incremental l l2/

The Parties agree that the Commission may be limited by law in the actions it may take with respect to non-New York State entities and their programs. To the extent that any such entity may be the object of a petition, as provided for herein, the Commission shall, to the extent it is legally able to do so, take action consistent with this paragraph.

l l3/

The RLSE is described in paragraph 65, infra.

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costs (whether positive or negative) of procuring energy and capacity on behalf of such customers. Otherwise, such customers will pay regulated retail rates. During the Energy and Capacity stage, RGAE shall have no obligation to maintain capacity for such customers. New customers will pay the same rates and be allowed to take the same services as such returning customers.

Environmental Information

60. RG&E and Staff shall work with LSEs to develop and implement, where feasible, meaningful, and cost-effective, a means of providing customers with information on the fuel mix and emission characteristics of the generation relied upon by their I respective LSEs.

1 Dairvlea Pro~ram

61. The parties agree that the Company's introduction of the Retail Access Program to-eligible farm and food processor customers on February 1, 1998 (five months prior to its starting date for other customers), the introduction of the Program to those customers outside of the caps which otherwise limit participation, and the provision of a rate equal to the market price of energy and capacity plus retailing costs (plus $ 0.006 for

- 50-residential customers), satisfies the rate and timing aspects of the Commission's Order Establishing Retail Access Pilot Programs issued June 23, 1997 in Cases 96-E-0948 et al.

""'or orate Structure

62. RGkE shall separate its existing operations, either functionally or structurally, as indicated, and shall provide for new operations by establishing the following activity-based units:

a functionally separate distribution unit ("DISCO");

b. a functionally separate generating unit ("GENCO");

c. a functionally separate Regulated Load Serving Entity ("RLSE");

o d. a structurally separate Unregulated Load Serving

("ULSE"); and Entity

e. a Holding Company ("HOLDCO"). ""

RG&E will develop and provide, by January 1, 1998, the accounting treatment to be applied to the foregoing units. The Company will meet periodically with Staff during such development period to keep Staff apprised of progress and to receive input.

Petition of Dair lea Coo erative Inc. to Establish an 0 en-Access Pilot Pro ram for Farm aod Food Processor Etectricit Customers (the "~Dair lea case").

The HOLDCO may, at the Company's option, be a functionally separate unit serving essentially the same purposes of a holding company or it may be a legally distinct entity as contemplated in paragraph 67, infra.

~ e DISCO

63. The DISCO shall continue to carry on RG&E's transmission and distribution service which shall be provided to LSEs (Regulated and Unregulated) pursuant to regulated tariffs. Except as otherwise described in this Settlement, DISCO rates shall include the costs of RG&E generating facilities" and all costs identified in Section VII of RG&E's October 1

"" Except to the extent that any of RG&E's generating facilities" are Submission.

sold to unaffiliated entities, ownership of such facilities shall remain with the DISCO either directly or through ownership by the DISCO of the GENCO.

GENCO i 64. Except as otherwise provided in this Settlement, the GENCO shall be responsible for operating RG&E's generating facilities and for their associated To-Go Costs.

RLSE

65. The RLSE shall provide bundled service under tariffs to customers who elect to continue receiving bundled service or who do not have a practicable alternative. The RLSE shall continue to serve as a "Provider of Last Resort" ("POLR") until the Commission approves an alternative means of providing such service. All costs of POLR service that are 1 16/

See paragraphs 19 through 24, 46, 48 and 52, ~su ra.

See paragraph 15, ~su ra.

Including RG&E's interest in any jointly owned generating facilities.

currently included in bundled rates and are not collected directly from customers of the RLSE shall be collected in DISCO rates consistent with paragraph 15, ~su ra. The Company'will work with Staff after the initial implementation of the Retail Access Program to devise. an experimental alternative which will entail providing POLR service on a competitive basis.

This experiment will be conducted during the term of this Settlement.

ULSE

66. The ULSE shall be permitted to function as an energy marketer and provider of other energy services both within and outside RGEcE's utility service territory.

The ULSE shall be permitted to use RGEcE in its name and make known that it is an affiliate of RGEcE. The nature of the relationships among affiliated units or corporations is addressed in the "Standards Pertaining to Affiliates and the Provision of Information" contained in Schedule I attached hereto.

HOLDCO and Ca italization of Unre ulated 0 erations

67. The Parties support RGkE's Petition in substantially the form of Schedule J "" to establish a holding company structure in which RG&E would be permitted to operate through one or more regulated companies and one or more unregulated companies, including energy service companies ("ESCOs") and LSEs. Whether RGAE conducts its Or a similar petition proposing the formation of a HOLDCO with the same result, but e' through a different structure.

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- 53-0 unregulated activities through a HOLDCO or a separate subsidiary of a utility parent, it shall be permitted initially to fund, through cash, loan guarantees or advances, such activities in the amount of $ 50 million. The principles relating to the inter-company relationships, code of conduct, cost allocations, protections and restrictions applicable to a holding company or competitive subsidiary are contained in Schedule I. Authorization to fund such unregulated operations is granted with the approval of this Settlement. Except for the $ 50 million of initial investment, or as otherwise '"" authorized by the Commission, RG&E's regulated Business Segments will neither make loans to, nor guarantee or provide credit support for the obligations of unregulated affiliates, and RG&E's regulated Business Segments will not pledge any utility assets as security for loans or financing arrangements for unregulated activities.

1 Petition for Relief

68. In the event that any of the following conditions occurs or is likely to occur, RG&E or any other Party to this Settlement shall have the right to petition the Commission for review of the operation of this Settlement and appropriate remedial action:

a. Return on equity, determined on a Rate Year regulatory basis for all remaining regulated operations, falls below 8.5 percent or increases above 14.5 percent; I.e., subsequent to initial investment.

b. Pre-tax interest coverage falls below 2.5 times; Governmental action occurs that cannot adequately be addressed through the provisions of this Settlement pertaining to Mandates, including but not limited to:

Actions taken by FERC with respect to: jurisdiction over functions traditionally understood as "local distribution" of electricity; ISO and PE functions and transactions; and Qualifying Facility and Independent Power Producer matters.

ii. Actions taken by the NRC with respect to: nuclear

' decommissioning; nuclear waste disposal; nuclear power plant operating and safety requirements; and financial standards for nuclear power plant operators.

iii. New York State or federal legislation pertaining to:

energy industry restructuring; changes to the Public Utility Regulatory Policies Act; and changes to the Public Utility Holding Company Act of 1935.

69. Any Party seeking review pursuant to the preceding paragraph shall have the burden of showing to the Commission's satisfaction that continued operation of this Settlement as to the specific basis for that Party's petition is unjust or unreasonable. In such i of this event, the Commission may suspend or modify any portions Settlement or take or 0"

o e.

i refuse to take any other action permitted by law under the circumstances as they then exist, 4

the terms and provisions of this Settlement notwithstanding.

70. The Parties acknowledge that the Commission, pursuant to its statutory responsibility, on its own motion or on request of any party, reserves the authority to act on the level of the Company's rates if the Commission determines that unforeseen circumstances have rendered the Company's rates or return on investment unreasonable, inadequate or excessive for the provision of safe and adequate service.

Filin Re uirements

71. RG&E shall file with the Commission, not later than September 30 following each Rate Year subject to this Settlement, (a) a calculation of regulatory earnings e

on common equity for such Rate Year, which filing shall be used for purposes of determining whether the Company's earnings exceed or fall below the 11.80 percent return described in paragraph 10, ~su ra, and (b) a calculation of any penalties incurred pursuant to the Service Quality Performance Program described in paragraph 44, ~su ra.

72. RG&E shall not, as of the effective date of this Settlement, be required to make any of the filings or computations required by the 1996 Settlement.

73. Within 90 days of approval of this Settlement, the Company will file with Staff a plan outlining the manner in which the Company will carry out Retail Access Program phase-in. Such a plan should include, but not be limited to, a customer education

plan and a customer application procedure for each stage of the Retail Access Program. The Company will consult with Staff and the Parties prior to filing such a plan.

Dis utc Resolution

74. In the event of any disagreement over the interpretation of this Settlement or the implementation of any of the provisions of this Settlement, which cannot be resolved informally among the Parties, such disagreement shall be resolved in the following manner unless otherwise provided herein: The Parties shall promptly convene a conference and in good faith shall attempt to resolve such disagreement. If any such disagreement cannot be resolved by the Parties, any Party may petition the Commission for relief on a disputed matter.

e Bindin Effect of Settlement

75. This Settlement represents a negotiated agreement and, except as otherwise expressly stated herein, none of the Parties shall be deemed to have approved, agreed to, or consented to any principle, methodology or interpretation of law, underlying or supposed to underlie any provision hereof, and this Settlement shall not be cited or relied upon with respect to.any matters other than those specifically addressed herein.

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Su ersedin Prior Settlements

76. Except as expressly provided otherwise herein, this Settlement shall, upon approval by the Commission, supersede the DSM Settlement and the 1996 Settlement.

Modification of Settlement

77. Approval by the Commission of this Settlement shall constitute approval of all of its terms. If the Commission approves this Settlement in its entirety or modifies it in a manner acceptable to the Parties, this Settlement shall be implemented in accordance with its terms. Because this Settlement is an integrated whole, with each provision in consideration for, in support of, and dependent on the others, any attempt to modify its terms may frustrate its purpose. Thus, if the Commission does not approve this Settlement in its entirety, without o I modification, each of the Parties reserves the right to withdraw its acceptance by serving written notice on the Commission and the other Parties and to renegotiate and, if necessary, to litigate, without prejudice, any or all issues as to which such Party agreed in this Settlement; such Party shall not be bound by the provisions of this Settlement, as executed or as modified, and this Settlement shall not take effect.

Effect of A reement

.I2, 78. This Settlement calls for RGAE to make major, and in some cases irreversible, commitments for the purpose of furthering the goal of the Commission to restructure the electric industry and to reduce electric rates in the State of New York. RG8cE,

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by executing this Settlement, is making such commitments with the expectation th'at the Parties and the Commission shall continue to honor the assurances embodied in this Settlement. Specifically:

a. As part of this Settlement, RG8cE has agreed to make commitments, as described herein, including but not limited to the following: (i) agreement to withdraw from the three Article 78 proceedings described in paragraph 79, infra; (ii) significant rate reductions; (iii) the restructuring of the Company's business; (iv) opening of the Company's service territory to competitors; (v) providing retail access to customers; and (vi) resolving the Kamine matter while controlling its impact on rates.

b. RGAE has made each such commitment in return for rate and other assurances by the Commission, including but not limited to the following: (i) except to the extent the Company has expressly agreed herein to place generation at market ""

risk, RGEcE shall have a reasonable opportunity to recover all prudently incurred investment and expenses and to earn a reasonable return on investments; (ii) the Company shall have a See paragraph 48, ~su ra.

0 ry

~i

reasonable opportunity to recover transition costs; (iii) rate treatment for the Company's investment in nuclear facilities shall be as described herein; (iv) RG&E shall be afforded a reasonable opportunity to fund and to undertake competitive business activities; and (v) the Company is entitled to recover Kamine costs.

c. The Parties recognize that RGEcE's participation in this Settlement is based on the premise that, in adopting this Settlement, the Commission will find, in substance, that: (i) the foregoing commitments and assurances are inextricably interrelated; (ii) the rates established pursuant to this Settlement are just and reasonable to both customers and shareholders through June 30, 2002; (iii) the reasonable opportunity for RGB.E to continue to recover the prudently incurred costs referred to in subparagraph b, ~su '"-'eyond ra, the term of this Settlement is justified; (iv) except as noted herein, this Settlement constitutes full compliance with the Commission's Other than the future costs of competitive businesses referenced in subparagraph b(iv),

~su ra.

policies identified in Opinion No. 96-12; "" (v) this Settlement is

in the public interest; and (vi) there is a clear need to reduce the burdens imposed by Mandates.

Withdrawal from Liti ation

79. In consideration for the foregoing, RG&E, upon final approval of this Settlement by the Commission, '"'grees to petition the Appellate Division of the Supreme Court for permission to withdraw as a party to the appeal in the Article 78 proceeding brought to challenge Opinion No. 96-12, Ener v Association v. Public Service Commission (Sup. Ct. Albany Co. Index No. 5830-96), and to withdraw the Company's pending Article 78 e I proceedings brought to challenge the Commission's action with respect to: (a) the 1996 Settlement, Rochester Gas and Electric Cor oration v. Public Service Commission (Sup. Ct.

Albany Co. Index No. 6616-96); and (b) the Commission's June 23, 1997 Order Establishing Retail Access Pilot Programs in Cases 96-E-0948 et al., Rochester Gas and Electric Cor oration v. Public Service Commission (Sup. Ct. Albany Co. Index No. 6531-97).

123!

Full compliance pertaining to the following tasks outlined in Opinion No. 96-12 has not been effected by this Settlement: (a) a filing to distinguish and classify transmission and distribution facilities; (b) the proposed resolution of market power problems as related to Load Pockets, as discussed in paragraph 25, ~su ra; (c) compliance with future ESCO requirements (~e, oversight, metering and billing);

(d) compliance with future ISO requirements; and (e) continuation of public forums to provide education and consumer input related to competition and the needs within RG&E's service territory.

24/

1 I.e., after any appeals from such approval are exhausted or the time to appeal has

'

expired, whichever is later.

0

'0 ry

Withdrawal of the two Rochester Gas and Electric cases and RGkE's withdrawal as a party to the Ener Association case shall be effected through Stipulations of Withdrawal, mutually agreed to by RGAE and the Commission. Until the aforementioned petition with respect to the Ener v Association case is granted, the Company will discontinue its litigation activities to the extent that it is able to do so without prejudicing its rights in any of the three Article 78 proceedings.

WO:ROCI I: I I3098

Rochester Gas and Electric Corporation Cases 94-E-09S2 and 96-K%898 Amended and Restated Settlement Agreement October 23, 1997 The party whose signature follows subscribes to the foregoing Amended and Restated Settlcmcnt Ay'ccmcnL Staff of the State of New York Department of Public Service By: l Robert L. Whitaker, Director Office of Regulatory Economics

Rochester Gas and Electric Corporation Cases 94-E-0952 and 96-E-OS98 Amended and Restated Settlement Agreement October 23, 1997 The party whose signature follows subscribes to the foregoing Amended and Restated Settlement Agreement.

Rochester Gas and Electric Corporation By:

William J. ddy Controller

.0 ROC I I: I 02096

'0

'4 0'

Rochester Gas and Electric Corporation Cases 94-E-0952 aud 96-~898 Amended and Restated Settlement Agreement October 23, 1997 The party whose signature follows subscribes to the foregoing Amended and Restated Settleinent Agreement.

The Joint Supporters By:

Ruben S. Brown The E Cubed Company

Rochester Gas and Electric Corporation Cases 94-E-09'Q 9&K%898 Amended and Restated Settlement Agreement October 23, '1997 The party whose signature follows subscribes to the foregoing Amcndcd and Restated Settlement Agreement.

National Association of Energy Service Companies By:

Ru n S. Brown

SCHEDULE A RATE< S (INCLUDING ILLUSTRATIVERATES)

FOR E<LECTRIC SERVICE ROC I l: l 00274

SCHEDULE A RATES (INCLUDING ILLUSTRATIVERATES)

FOR ELECTRIC SE<RVICE ALLOCATIONOF REDUCTIONS ROCI I;I00214

,)

Rochester Gas and Electri oration Allocation of Rate Reductions 7/1/97 Net Present Present Rate Percent Kamine Net Percent New New Forecast Voltage Class Revenue Price Reduction Reduction Recovery Reduction Reduction Revenues Price Sales (000's) (000's) (000's) (000's) (000's) (MWH)

Industrial subtotal $ 76,321 $ 0.0623 $ 441 0.58% 441 0.58% 75,880 $ 0.0619 1,224,884 subtra-comm 39,288 0.0744 224 0.57% 224 0 57% 39,063 0.0740 528,206 subtra-sec 13,342 0.0883 73 054 73 0 54% 13,270 0.0879 151,039 Pfl-Prl 49,322 0.0843 261 0.53% 261 0.53% 49,061 0.0838 585,263 pri-sec 112,697 0.1008 579 P.51% 579 0 51ogo 112,117 0.1003 1,117,538 sec-sec 379.658 0.1233 1,916 0 50% 1,916 p 50% 377,742 0.1227 3,079,691 subtotal $ 594,307 $ 0.1088 $ 3,053 0.51% $ 3,053 0.51% $ 591,254 $ 0.1083 5,461,736 Total $ 670,628 $ 0.1003 $ 3,494 0.52% $ 3,494 0.52% $ 667,134 $ 0.0998 6,686,620 printed: 10/22/97 Page 1

'e

'e 4

0 Rochester Gas and E(ectri oration Allocation of Rate Reductions 7/1/98 Net Present Present Rate Percent Ka mine Net Percent New New Forecast Voltage Class Revenue Price Reduction Reduction Recovery Reduction Reduction Revenues Price Sales (000's) (000's) (000's) (000's) (000's) (MWH) industrial subtotal $ 76,321 $ 0.0623 $ 2,752 3.61% 640 2,112 2.77% 74,209 $ 0.0606 1,224;884 subtra-comm 39,288 0.0744 1 232 3.14% 276 956 2.43% 38,331 0.0726 528,206 subtra-sec 13,342 0.0883 449 3.37% 79 370 2.77% 12,972 0.0859 1 51,039 prl pfl 49,322 0.0843 1,021 2.07% 305 716 1.45% 48,607 0.0831 585,263 pri-sec 112,697 0.1008 1,795 1.59% 584 1,211 1 07% 111,486 0.0998 1,117,538 sec-sec 379,658 0.1233 5,608 48% 1,610 3.998 1.05% 375,660 0.1220 3,079,691 subtotal $ 594,307 $ 0.1088 $ 10,105 1.70 2,854 $ 7,251 1.22% $ 587,056 $ 0.1075 5,461,736 Total $ 670,628 $ 0.1003 $ 12 856 1.92% 3.494 $ 9,363 1.40% $ 661,265 $ 0.0989 6,686,620 printed: 10/22/97 Page 2

0 0

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'0 e

iQ)

Rochester Gas and Electri oration Allocation of Rate Reductions 7/1/99 Net Present Present Rate Percent Ka mine Net Percent New New Forecast Voltage Class Revenue Price Reduction Reduction Recovery Reduction Reduction Revenues Price Sales (000's) (000's) (000's) (000's) (000's) (MWH) industrial subtotal $ 76,321 $ 0.0623 $ 6 968 9.13% 1,548 5,420 7.10% 70,901 $ 0.0579 1,224,884 subtra-comm 39,288 0.0744 3,151 8.02% 667 2,484 6.32% 36,804 0.0697 528,206 subtra-sec 13,342 0.0883 1,084 8.13% 191 893 6.70% 12,449 0.0824 151,039 pri-pri 49,322 0.0843 2,206 4.47% 740 1,466 2.97% 47,856 0.0818 585,263 pri-sec 112,697 0.1008 3,657 3.24% 1,412 2,244 1 99% 110,452 0.0988 1,117,538 sec-sec 379,658 "

0.1233 10,548 2.78% 3,892 6,656 1.75% 373,002 0.1 21 1 3,079,691 subtotal $ 594,307 $ 0.1088 $ 20,645 3.47% 6,901 $ 13,744 2.31% $ 580,563 $ 0.1063 5,461,736 Total $ 670,628 $ 0.1003 $ 27.613 41 8,449 $ 19,1 64 2.86% $ 651,464 $ 0.0974 6,686,620 printed: 10/22/97 Page 3

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<+)

Rochester Gas and Electric oration Allocation of Rate Reductions 7/1/00 Net Present Present Rate Percent Ka mine Net Percent New New Forecast Voltage Class Revenue Price Reduction Reduction Recovery Reduction Reduction Revenues Price Sales (000's) (000's) (000's) (000's) (000's) (MWH)

Industrial subtotal S 76,321 S 0.0623 -S 10,475 13.73% 1,924 8,552 1 1.20% 67,769 S 0.0553 1,224,884 subtra-comm 39,288 0.0744 S 4,434 11.29% 829 3,605 9.17% 35,683 0.0676 528,206 subtra-sec 13,342 0.0883 1,585 1 1.88% 237 1,348 10.10% 11,994 0.0794 151,039 pri-pri 49,322 0.0843 3,094 6.27% 919 2,175 4.41% 47,148 0.0806 585,263 pri-sec 112,697 0.1008 5,160 4.58% 1,755 3,405 3.02% 109,292 0.0978 1,117,538 sec-sec 379,658 0.1233 14,775 3.89% 4,836 9,939 2.62% 369,719 0.1201 3,079,691 subtotal S 594,307 S 0.1088 29,047 4.89% 8,576 $ 20,471 3.44% S 573,836 S 0.1051 5,461,736 Total S 670,628 S 0.1003 S 39,522 5.89% 10,499 S 29,023 4.33% S 641,605 S 0.0960 6,686,620 printed: 10/22/97 Page 4

1 o

Rochester Gas and Electric oration Allocation of Rate Reductions 7/1/01 Net Present Present Rate Percent Ka mine Net Percent New New Forecast Voltage Class Revenue Price Reduction Reduction Recovery Reduction Reduction Revenues Price Sales (000's) (000's) (000's) (000's) (000's) (MWH) industrial subtotal $ 76,321 $ 0.0623 $ 10 491 13.75% 1,924 8,568 1 1.23% 67,753 $ 0.0553 1,224,884 subtra-comm 39,288 0.0744 $ 4 435 11.29% 829 3,606 9.18% 35,682 0.0676 528,206 subtra-sec 13,342 0.0883 1,585 11.88% 237 1,348 10.10% 11,994 0.0794 151,039 pfl pfl 49,322 0.0843 3,387 6.87% 919 2,468 5 QQ% 46,854 0.0801 585,263 pri-sec 112,697 0.1008 7,386 6.55% 1,755 5,631 5 PQ% 107,066 0.0958 1,117 538 sec-sec 379,658 0.1233 23,818 6.27% 4,836 18,982 5 PQ% 360,676 0.1171 3.079,691 subtotal $ 594,307 $ 0.1088 $ 40,61 1 6.83% 8,576 $ 32,035 5.39% $ 562,272 $ 0.1029 5,461,736 Total $ 670,628 $ 0.1003 $ 51,102 7.62% 10,499 $ 40,602 6.05% $ 630,025 $ 0.0942 6,686,620 printed: 10/22/97 Page 5

SCHEDULE A RATES (INCLUDING ILLUSTRATIVERATES)

FOR ELE<CTRIC SE<RVICE<

RATE DE<SIGN ROC l I: l 00274

ILLUSTRATIVERATE DESIGN TO BE PROVIDED ROC I I: I 00274

SCHEDULE A RATES (INCLUDING ILLUSTRATIVE< RATES)

FOR ELECTRIC SERVICE DISTRIBUTION ACCE<SS RE<VE<NUE<S ROC 1 1:100274

ILLUSTRATIVEAVERAGE DISTRIBUTION ACCESS REVE<NUES TO BE PROVIDED ROC l l: l 00274

o APPENDIX A TO SCHEDULE A FLEXIBLE DISTRIBUTION ACCESS TARIFF OPTION

1. The Company shall have the option to negotiate special contracts for distribution access service with Load Serving Entities ("LSEs") that serve customers that have a viable competitive alternative. The purpose of this option is to allow the Company to participate, with LSEs, in efforts to retain or to attract distribution customers in the Company's service territory and thereby to benefit all distribution customers. A "competitive alternative" for this purpose is defined as a means of meeting electric power needs without making use of the Company's distribution system, including relocation outside the Company's service territory.

2. As a transitional arrangement for existing SC-10 customers, the Company shall have the discretion to offer the following two options:

Extend the term of an existing SC-10 contract to June 30, 2002, or

b. Offer a prorated distribution tariff discount to an LSE that serves the customer, for the load taken by that customer, through June 30, 2002.

3. The prorated discount would be calculated in the following manner:

~ calculate the average price per KWH for a particular contract at rates in effect at the end of its term - call this the average contract rate

~ calculate the average price per KWH for that same contract assuming the applicable bundled tariff rates - call this the average full tariff rate

~ Calculate the full discount per KWH - this is equal to the average full tariff rate minus the average contract rate pro-rate the full discount to distribution rates according to this formula: distribution discount = full discount x (average contract rate - 3.2 cents/KWH)/average contract rate-"

For example, if the average full tariff rate was 8 cents, the average contract rate was 7 cents, the discount attributed to distribution rates would be 0.54 cents. The remainder would be attributed in. essence to the contestable cost of 3.2 cents.

ROC I I: I 00274

SCHEDULE 8 E4LECTRIC DEPARTMENT AMORTIZATIONS (Including Decommissioning Accruals)

(000's) 12 MOS. 12 MOS. 12 MOS. 12 MOS. 12 MOS.

JUNE 1998 JUNE 1999 JUNE 2000 JUNE 2001 JUNE 2002 NUC. FUEL STORAGE $ 4,575 $ 4,832 $ 5,103 $ 5,390 $ 5,692 R&D (2,149) 0 0 0 0 SITE REM I DATION 0 0 0 0 0 DSM/HIECA 9,500 9,500 6,606 7,000 7,000 PEN TREP I, II 0 0 0 0 0 PEN TREF III 0 0 0 0 0 PENSION DEF'D ADJ. (38) 0 0 0 0 OTHER DEF'D PROJ 2,294 2,294 2,294 2,295 2,295 ICE STORM 2,546 2,546 2,546 2,546 2,546 SALES USE TAX AUDIT 1,642 1,642 1,642 1,642 1,642 NMII LITIGATION/GE 0 0 0 0 0 REVENUE TAX AUDIT 0 0 0 0 0 FASB 112 1,684 1,684 1,684 1,684 0 CIS PLUS 0 0 0 0 0 LASER LIGHT SHOW 1,675 0 0 0 0 ERAM 0 0 0 0 0 EXCESS EARNINGS 0 0 0 0 0 NMP2 SHARING JOB 010 0 0 0 0 0 NMPS REFUEL OUT II4 0 0 0 0 0 TOTAL $ 21,729 $ 22,498 $ 19,875 $ 20,557 $ 19,175 DECOMMISSIONING ACCRUALS'inna

$ 18,512 $ 18,570 $ 18,631 $ 18,696 $ 18,765 Nine Mile 2 3,646 3,674 3,705 3,739 3,775 TOTAL DECOM.

ACCRUALS $ 22 158 $ 22 244 $ 22 336 . - $ 22 435 $22 540

'he derivation of decommissioning accruals is described in Schedule D.

ROCI nn3025

SCHEDULE C MANUFACTURING CLASSIFICATIONS (Standard Industrial Classifications - Division D. Manufacturing)

Major Group 20 Food and Kindred Products Industry Group No. 201 Meat Products 202 Dairy Products 203 Canned, Frozen, and Preserved Fruits, Vegetables, and Food Specialities 204 Grain Mill Products 205 Bakery Products 206 Sugar and Confectionery Products 207 Fats and Oils 208 Beverages 209 Miscellaneous Food Preparation and Kindred Products Major Group 21 Tobacco Products Industry Group No. 211 Cigarettes 212 Cigars 213 Chewing and Smoking Tobacco and Snuff 214 Tobacco Stemming and Redrying Major Group 22 Textile Mill Products Industry Group No 221 Broad Woven and Fabric Mills, Cotton 222 Broad Woven Fabric Mills, Manmade Fiber and Silk 223 Broad Woven Fabric Mills, Wool (Including Dyeing and Finishing) 224 Narrow Fabric and Other Small wares Mills: Cotton, Wool, Silk, and Manmade Fiber 225 Knitting Mills 226 Dyeing and Finishing Textiles, Except Wood, Fabrics and Knit Goods 227 Carpets and Rugs 228 Yarn and Thread Mills 229 Miscellaneous Textile Goods

Major Group 23 A arel and Other Finished Products Made from Fabrics and Similar Materials Industry Group No 231 Men's and Boys'uits, Coats, and Overcoats 232 Men's and Boys'urnishings, Work Clothing, and Allied Garments 233 Women', Misses', and Juniors'uterwear 234 Women', Misses', Children', and Infants'ndergarments 235 Hats, Caps, and Millinery 236 Girls', Children', and Infants'uterwear 237 Fur Goods 238 Miscellaneous Apparel and Accessories 239 Miscellaneous Fabricated Textile Products Major Group 24 Lumber and Wood Products exce t Furniture Industry Group No. 241 Logging 242 Sawmills and Planing Mills 243 Millwork, Veneer, Plywood, and Structural Wood Members 244 Wood Containers 245 Wood Buildings and Mobile Homes 249 Miscellaneous Wood Products Major Group 25 Furniture and Fixtures Industry Group No 251 Household Furniture 252 Office Furniture 253 Public Building and Related Furniture 254 Partitions, Shelving, Lockers, and Office and Store Fixtures 259 Miscellaneous Furniture and Fixtures Major Group 26 Pa er and Allied Products Industry Group No 261 Pulp Mills 262 Paper Mills 263 Paperboard Mills 265 Paperboard Containers and Boxes 267 Converted Paper and Pegboard Products, Except Containers and Boxes Major Group 27 Printin Publishin and Allied Industries Industry Group No 271 Newspapers: Publishing, or Publishing and Printing 272 Periodicals: Publishing, or Publishing and Printing 273 Books 274 Miscellaneous Publishing 275 Commercial Printing

0 0

~

(Cont'd)

Major Group 27 Printin Publishin and Allied Industries Industry Group No 276 Manifold Business Forms 277 Greeting Cards 278 Blank books, Looseleaf Binders, and Bookbinding and Related Work 279 Service Industries for the Printing Trade Major Group 2S Chemicals and Allied Products Industry Group No 281 Industrial Inorganic Chemicals 282 Plastics Materials and Synthetic Resins, Synthetic Rubber, Cellulosic and Other Manmade Fibers, Except Glass 283 Drugs 284 Soap, Detergents, and Clearing Preparations; Perfumes, Cosmetics, and Other Toilet Preparations 285 Paints, Varnishes, Lacquers, Enamels, and Allied Products 286 Industrial Organic Chemicals 287 Agricultural Chemicals 289 Miscellaneous Chemical Products Major Group 29 Petroleum Refinin and Related Industries 0 Industry Group No. 291 Petroleum Refining 295 Asphalt Paving and Roofing Materials 299 Miscellaneous Products of Petroleum and Coal Major Group 30 Rubber and Miscellaneous Plastics Products Industry Group No 301 Tires and Inner Tubes 302 Rubber and Plastics Footwear 305 Gaskets, Packing, and Sealing Devices and Rubber and Plastics Hose and Belting 306 Fabricated Rubber Products, not Elsewhere Classified 308 Miscellaneous Plastics Products Major Group 31 Leather and Leather Products Industry Group No. 311 Leather Tanning and Finishing 313 Boot and Shoe Cut Stock and Findings 314 Footwear, Except Rubber 315 Leather Gloves and Mittens 316 Luggage 317 Handbags and Other Personal Leather Goods 319 Leather Goods, Not Elsewhere Classified

0 0 0

o

4 Major Group 32 Stone Clay Glass and Concrete Products Industry Group No. 321 Flat Glass 322 Glass and Glassware, Pressed or Blown 323 Glass Products, Made of Purchased Glass 324 Cement, Hydraulic 325 Structural Clay Products 326 Pottery and Related Products 327 Concrete, Gypsum, and Plaster Products 328 Cut Stone and Stone Products 329 Abrasive, Asbestos, and Miscellaneous Nonmetallic Mineral Products Major Group 33 Prima Metal Industries 331 Steel Works, Blast Furnaces, and rolling and Finishing Mills 332 Iron and Steel Foundries 333 Primary Smelting and Refining of Nonferrous Metals 334 Secondary Smelting and Refining of Nonferrous Metals 335 Rolling, Drawing, and Extruding of Nonferrous Metals 336 Nonferrous Foundries (Castings) 339 Miscellaneous Primary Metal Products Major Group 34 Fabricated Metal Products cxcc t Machine;ind Trans ortation

~Eui ment Industry Group No. 341 Metal Cans and Shipping Containers 342 Cutlery, Hand tools, and General Hardware 343 Heating Equipment, Except Electric and Warm Air; and Plumbing Fixtures 344 Fabricated Structural Metal Products 345 Screw Machine Products, and Bolts, Nuts, Screws, Rivets, and Washers 346 Metal Forgings and Stampings 347 Coating, Engraving, and Allied Services 348 Ordnance and Accessories, except Vehicles and Guided Missiles 349 Miscellaneous Fabricated Metal Products Major Group 35 Industrial and Commercial Machine and Com uter K ui ment Industry Group No ":Sl Engines and Turbines

')52 Farm aiid Garden Machinery and Equipment

0 0

(Cont'd)

Major Group 35 Industrial and Commercial Machine and Com uter E ui ment Industry Group No. 353 Construction, Mining, and Materials Handling Machinery and Equipment 354 Metal Working Machinery and Equipment 355 Special Industry Machinery, except Metalworking Machinery 356 General Industrial Machinery and Equipment 357 Computer and Office Equipment 358 Refrigeration and Service Industry Machinery 359 Miscellaneous Industrial and Commercial Machinery and Equipment Major Group 36 Electronic and Other Electrical E ui ment and Com onents E<xce t Com uter E ui ment Industry Group No. 361 Electric Transmission and Distribution Equipment 362 Electrical Industrial Apparatus 363 Household Appliances 364 Electric Lighting and Wiring Equipment 365 Household Audio and video Equipment, and Audio Recordings 366 Communications Equipment 367 Electronic Components and Accessories 369 Miscellaneous Electrical Machinery, Equipment, and Supplies Major Group 37 Trans ortation E< ui ment Industry Group No 371 Motor Vehicles and Motor Vehicle Equipment 372 Aircraft and Parts 373 Ship and Boat Building and Repairing 374 Railroad Equipment 375 Motorcycles, Bicycles, and Parts 376 Guided Missiles and Space Vehicles and Parts 379 Miscellaneous Transportation Equipment Major Group 38 Measurin Anal zin and Controllin Instruments Photo ra hic Medical and 0 tical Goods Watches and Clocks Industry Group No 381 Search, Detection, Navigation, Guidance, Aeronautical, and Nautical Systems, Instruments, and Equipment 382 Laboratory Apparatus and Analytical,.Optical, Measuring, and Controlling Instruments 384 Surgical, Medical, and Dental Instruments and Supplies 385 Ophthalmic Goods 386 Photographic Equipment and Supplies 387 Watches, Clocks, Clockwork Operated Devices, and Parts

Major Group 39 Miscellaneous Manu facturin Industries 391 Jewelry, Silverware, and Plated Ware 393 Musical Instruments 394 Dolls, Toys, Games and Sporting and Athletic Goods 395 Pens, Pencils, and Other Artists'aterials 396 Costume Jewelry, Costume Novelties, Buttons, and Miscellaneous Notions, Except Precious Metal 399 Miscellaneous Manufacturing Industries ROC11:101302

SCHEDULE D NUCLEAR DECOiVIMISSIONING

1. It is-agreed that the projected cost of decommissioning RG&E's 100%

owned Ginna Nuclear Power Plant and its share of the cost of decommissioning Nine Mile Point 2, shall be based on site-specific studies and methods submitted by the Company.

2. The study for Ginna estimates that the decommissioning of Ginna will cost $ 296,303,000 in 1995 dollars. If this amount is inflated by 4.0% annually, the projected cost of decommissioning the facility in 2009 is $ 513,100,000.

3. The study for Nine Mile Point 2 estimates that decommissioning RG&E's 14% share of Nine Mile Point 2 will be $ 112,840,000 in 1995 dollars. If this amount is inflated by 4.0% annually, the projected cost of RG&E's share in 2026 is

$ 380,624,000.

4.. The after-tax interest rates projected to be earned by the amounts collected for decommissioning these plants are 6.40% for each plant's external fund established to qualify for a current tax deduction under Internal Revenue Service ("IRS") rules and 4.77% for each plant's non-IRS qualified external fund. The rates established pursuant to the Settlement to which this Schedule is attached are based on funding the contaminated portions of the units, as required by the Nuclear Regulatory Commission ($ 470,119,000 for

. Ginna and $ 343,318,000 for Nine Mile Point 2), using external funding methods.

5. The annual expense allowance incorporated in rates for Ginna, based on external funding, is $ 17,362,000 for the rate years ending June 1998 through June 2002. The

annual expense allowance incorporated in rates for Nine Mile Point 2, based on external funding, is $ 3,374,000 for rate years ending June 1997 through June 2002. These amounts are to be deposited in separate external funds set up solely for the purpose of accumulating decommissioning funds for each plant.

~ ~

6. Additional annual expense allowances incorporated in rates for Ginna, based on internal funding, are $ 1,150,000, $ 1,208,000, $ 1,269,000, $ 1,334,000, and

$ 1,493,000 for rate years ending June 1998, 1999, 2000, 2001 and 2002, respectively. The additional annual expense allowances incorporated in rates for Nine Mile Point 2 based on internal funding, are $ 272,000, $ 300,000, $ 331,000, $ 365,000, and $ 401,000 for rate years ending June 1998, 1999, 2000, 2001 and 2002, respectively. These additional amounts are for the decommissioning and removal of non-contaminated facilities at Ginna and Nine Mile Point 2.

ROC I I: I 0055 I

o SCHEDULE E LARGE CUSTOMER CREDIT PROGRAM Except as otherwise provided in this Settlement, this Schedule E supersedes the "Demand Side Management Plans" contained in the 1996 Settlement as Schedule F. This Schedule E is intended to continue the Large Customer Credit Program ("LCCP") to the extent that DSM costs continue to be recovered in rates, whether through an SBC or otherwise.

All SC No. 8 customers who, under the 1996 Settlement (Schedule F),

were eligible to exercise the option not to participate in RG&E's DSM programs and who, in fact, exercised such option, shall continue to be covered by the LCCP pursuant to the terms of this Schedule. To the extent that RG&E may be required to file a DSM Plan for any period

~ within the term of this Settlement and the Company is not prohibited from continuing the LCCP, RG&E shall provide notice of this option to eligible customers at least once prior to the commencement of each such DSM Plan. Such notice shall be given not earlier than sixty (60) nor later than thirty (30) days prior to the commencement of each Such DSM Plan.

Eligible customers shall have thirty (30) days after such notice to elect whether to exercise such option. Such customers shall cease to be eligible for direct participation in any aspect of RG&E's DSM programs. The elections of such customers shall be effective for the remaining term of this Settlement.

2. Throughout the term of this Settlement, any SC No. 8 customer who elects not to participate in RG&E's DSM programs and who complies with the criteria for the LCCP shall receive a billing credit of $ 0.0003 per KWH of consumption from the latter of

the date of compliance or the date of commencement of the DSM Plan to which the customer's election not to participate relates; provided that such customer shall not receive any billing credit applicable to the calendar year during which such customer receives payments from RG&E under that year's DSM programs.-" The foregoing credit shall be subject to recalculation in the event that RG&E's spending on DSM program changes materially.

In other words, if a customer receives a payment in 1997, offered pursuant to RG&E's initial (January 1997 through June 199S) Flan, the customer cannot receive a billing credit during the period covered by that Plan. On the other hand, a customer who receives a payment in 1997 pursuant to a plan in effect for a prior year will be permitted to receive a billing credit in 1997 if that customer otherwise qualifies for the election.

ROC I I: l02N3

SCHEDULE F LOW-INCOME PROGRAM This Schedule F supersedes the Low-Income Program contained in the 1996 Settlement as Schedule G.

Customer ualifieations

1. The Low-Income Program (the "Program" ) shall be available to RG&E customers who meet all of the following criteria:

a. The customer must be a gas heating or electric heating customer of the Company.

b. The customer must be payment-troubled or in arrears.

c. The customer must be HEAP eligible.-"

d. The customer must agree to receive a home energy audit at the appropriate residence.

e. The customer must agree to participate in household budget management training.

In the event that the HEAP program is discontinued, RGEcE shall apply comparable criteria.

e-T~G

2. In addition to identifying customers who meet the Program criteria stated in paragraph 1, ~su ra, RG&E shall make a particular effort to identify qualified elderly customers who could benefit from the Program.

3. RG&E shall work with appropriate social agencies and not-for-profit organizations to identify appropriate customers for participation in the Program.~

Pro~ram Size

4. During the first rate year under the 1996 Settlement (July 1, 1996 through June 30, 1997), RG&E shall have enrolled 350 participants in the Program; during the first rate year under the instant Settlement (July 1, 1997 through June 30, 1998), RG&E shall have enrolled 700 participants; and during the second rate year of this Settlement (July 1, 1998 through June 30, 1999), RG&E shall have enrolled 1,000 participants.-"

Such agencies and organizations include the Office for the Aging, Rural Opportunities Inc., the Child Assistance Program of the Department of Social Services ("DSS") and local DSS offices.

RG&E shall make a reasonable effort to replace customers who drop out of the Program.

Pro ram Cpm oncnts

5. Each participant who complies with the Program criteria'shall be eligible to participate, and shall be encouraged to participate, in the Program for three years.

6. During the first year of participation in the Program, each participant shall be expected to make monthly payments on current bills of at least 75 percent of the budget billing amount. The actual amount to be paid shall be greater than 75 percent if the customer is found to be capable of making such greater payments. The remainder of such monthly payments shall be forgiven during the customer's participation in the Program.

During tl>e second and third years of participation, each customer shall be expected to make full payment of the budget billing amount.

7. A participant who has complied with all Program criteria for at least one full year shall receive forgiveness of 25 percent of the customer's arrears balance. A participant who has complied with all Program criteria for at least two full years shall'receive forgiveness of another 25 percent of the customer's arrears balance. A participant who has complied with all Program criteria for at least three full years, and thus has completed the Program, shall receive forgiveness of the remaining 50 percent of the customer's arrears balance.

8. Each Program participant shall receive energy conservation and utilization education through receipt of a SavingPower energy audit and EndServe analysis or similar services.

~-

e 0,

4

9. Each Program participant shall receive training in household financial management, budgeting and wise purchasing practices.

.10. Collection activity shall be suspended during the period that the participant remains in compliance with Program criteria.

~ ~

11. Program participants shall be directed to appropriate DSM programs and weatherization programs, if any.

Cost Recove

12. The cost of the Program shall be recovered entirely tlirough residential electric rates.

13. For purposes of cost recovery, arrears forgiveness shall be assumed not to exceed $ 850 per customer.

14. Recoverable administrative costs shall not exceed 20 percent of total Program costs which shall be calculated by recognizing arrears forgiveness in the year in which a participant enters the Program.

Evaluation

15. RG&E shall evaluate the cost-effectiveness of the Program and report the results to the Commission before the end of the Settlement period. Such evaluation shall include analysis of the benefits of the Program.

ROC I I: I 0 I 036

SCHEDULE G SERVICE QUALITYPERFORMANCE PROGRAM This Schedule 6 supersedes the Service Quality Performance ("SQP") Program contained in the 1996 Settlement as Schedule H.

Overview

1. RG&E shall continue the SQP Program providing for penalties of up to a total of $ 1,250,000 for failure to achieve the minimum acceptable criteria for the service quality measures described below. The specific operation of the penalty system is described below.

2. The SQP Program shall consist of two principal components, an Electric Reliability component and a Customer Service component, as described below.

Electric Reliabili

3. Electric Reliability shall be measured in terms of the System Average Interruption Frequency Index ("SAIFI") and the Customer Average Interruption Duration Index ("CAIDI"), calculated in accordance with Commission requirements.-" Measurement shall be on a weighted average"- Company-wide basis. For SAIFI, the minimum acceptable level shall be 1.27. For CAIDI, the minimum acceptable level shall be 1.73.

See Cases 90-E-1119 and 95-E-0165.

Individual district data included shall be weighted by the number of customers represented.

4. The maximum penalty for SAIFI and CAIDI shall be $ 375,000 each.

5. For SAIFI, penalties shall be graduated, applying as follows: 25 percent of the maximum penalty when performance exceeds the minimum acceptable level; 50 percent of the maximum penalty when performance exceeds 105 percent of the minimum acceptable level; and the full penalty when performance exceeds 110 percent of the minimum acceptable level. For CAIDI, the full penalty shall apply when performance exceeds 110 percent of the minimum acceptable level.

Customer Service

6. Customer Service shall be measured in terms of the six criteria listed in the following table, along with the respective performance levels below which the indicated percentages of the maximum allowable penalty would be imposed:

'

Measure 25% Penalty,50% Penalty 100%

Penalty'ppointments Kept 99.0%

Calls Answered w/in 30 Seconds 73% 71.5% 700/

Bills Adjusted 2.70% 2.85% 3.00%

Estimated Bills - Unscheduled-" 13.7%

Closed-Loop Customer Satisfaction Survey-"

PSC Complaints (per 100,000 9.0 customers)

7. The maximum penalty for each of the measures listed in paragraph 6,

~su ra, shall be $ 83,000.

Under the 1996 Settlement, the Target level was set at the rate year average target per the Meter Reading Implementation Plan. This level shall be updated for the first and second rate years of the instant Settlement period per the Meter Reading Implementation Plan.

Target levels for the first and second rate y'ears of the instant Settlement period shall be set as described in paragraph 11, infra.

e.

Im lementation of Penalties

8. Penalties assessed pursuant to this Schedule shall be treated in accordance with paragraph 30 of the Settlement.

9. The Company shall have the right to seek a waiver of any penalties resulting from below-target performance for calls answered within 30 seconds, bills adjusted and PSC complaints on any of the grounds listed below:

a. performance below the target level resulted from circumstances beyond the Company's control;

b. performance below the target resulted from actions taken to improve long-term performance in that measure of customer service;

c. performance below the target level resulted from actions taken to improve short- or long-term performance in another aspect of customer service; and

'.

performance below the target level resulted from the implementation of competition.

Any of the foregoing conditions, if shown to exist, shall be grounds for a waiver. The Company shall have the burden of demonstrating that one or more of the conditions occurred.

Closed-Lop Customer Satisfaction Surve

10. The Closed-Loop Customer Satisfaction Survey shall be designed to measure and track customer satisfaction with RGAE's customer service processes. The Survey shall focus on customer service processes that have the greatest potential to improve customer satisfaction. The Parties acknowledge, however, that the areas on which the Survey focuses will likely change over the Settlement period.

11. For the first and second rate years of the Settlement period, the Parties shall have an opportunity to review the Survey process, to gain confidence that the Survey process will result in reliable data regarding customer satisfaction with the Company's customer service processes. The Parties shall have an opportunity to review and reach agreement regarding proposed target levels. If the Parties are not confident that the Survey process will produce reliable data as described above, or are unable to agree on acceptable target levels, the Parties shall employ the dispute resolution mechanism provided in the Settlement to resolve the issue. The Company shall meet with the Parties in May preceding the beginning of each rate year to discuss these issues and such review process shall be completed 30 days after the Company provides Staff with the information necessary to complete its review.

Other Matters

12. Performance for all measures subject to the SQP Program shall be calculated on a rate year average basis.

ROC I I: I 12639

a.

SCHEDULE H RETAILING FUNCTIONS

¹tes:

(1) P -

Primary responsibility for function. S Secondary responsibility for function.

Relationship to be governed and further clarified by Operating Agreement under distribution tariff.

(2) The relationship between the ISO/PE (Independent System Operator/Power Exchange) and the disco is not yet clear. For purposes of developing a complete list of LSE/disco activities, the disco is assumed to act as a local extension of the ISO/PE for activities required to maintain system reliability and security.

(3) Functions that are the sole responsibility of the disco have been eliminated from this list.

Load-Serving Entity Disco Functions Responsibilities Responsibilities

1. System requirements forecasting, S P planning, and budgeting (Forecast future Provide energy sales All activities energy delivery system capability/ infrastructure forecasts for disco requirements. Prepare detailed plans and budgets aggregation to modify system to meet requirements.)

2. Energy system work management, S P including prioritization, scheduling, and Work with disco to set All activities coordination (Prioritize, schedule, and emergency and non-coordinate the efficient use of labor and materials emergency work priority to meet customer requests, as well as the and response time construction and maintenance of the energy guidelines system.)

3. Design and documentation of system S P operating rules, operating agreements, Work with disco to All activities and operating procedures (Manage real-time design operating rules, construction and maintenance of the delivery agreements, and system, agreements with energy suppliers and the procedures ISO with respect to delivery and receipt of energy, protection of the system during extreme operating conditions such as load shedding, voltage and pressure reductions, and requests for fuel switching and curtailment of gas or electric usage.)

4. Negotiation and administration of S p contracts for balancing and ancillary May contract with a All activities services (Ancillary services required for secure non-disco provider for and reliable delivery of energy; balancing services some ancillary services, to cover variances between real-time deliveries as provided by FERC and real-time energy consumption. Includes rules accounting and invoice processing support.)

ROC11:101531

Load-Serving Entity Disco Functions Responsibilities Responsibilities

5. Short term forecasting and scheduling of S P system energy requirements (Daily, Produce daily, monthly, All other activities, monthly, and seasonal energy forecasts, short- and seasonal energy including developing term scheduling of energy receipt and delivery, forecasts for customers standard load shapes short-term scheduling of balancing and ancillary with real-time meters. and load-shape-based services.)

Schedule deliveries to forecasts for use by disco interchange point/ LSEs where real-city gate based on those time meters are forecasts, and based on lacking; forecasting load shapes for total system energy customers without real- requirements; and time meters. aggregating LSE delivery schedules to determine requirements for load balancing and ancillary services.

6. Real-time control and monitoring of the S P energy delivery system (Real-time use of Respond to disco/ISO All other activities energy balancing and ancillary services, real-time operating requirements interaction with ISO and third-party suppliers of real-time energy, real-time application and enforcemcnt of system operating rules, operating agreements, and operating procedures, real-time interpretation of SCADA information)

7. Energy imbalance management and S P coordination for the distribution area Provide data as required All other acttvittes (Identify imbalances, trade imbalances, acquire or by agreement with disco curtail energy supply to resolve imbalances, allocate imbalance costs, set imbalance performance standards and monitor compliance among market participants, acquire and manage/process real-time customer meter data for imbalance diagnosis)

8. Management of system restoration S P (Performance of tasks required to analyze, Provide personnel and All other activities coordinate, schedule, and facilitate restoration of resources to support the energy supply system in a timely, safe restoration activities manner.)

ROC11:101531

o Load-Serving Entity Disco Functions Responsibilities Responsibilities

9. Dispatch of field personnel for S P unscheduled energy system work p'o Depending on terms of All other activities, respond to same-day requests for customer service agreement with disco, possibly including and response to emergency or outage situations.) may receive first tracking of costs for

¹ter This may include repairs of equipment and customer notification of charge-back to facilities on the customer side of the meter if such repairs will facilitate a rapid return to outages or emergencies, customer's LSE service. may dispatch field personnel to make initial diagnosis of problem, may dispatch field personnel for repairs of customer-side-of-the-meter equipment and facilities.

10. Real-time response to customer service S P and field personnel inquiries for energy Depending on terms of All other activities delivery facilities'nformation (Provide agreement with disco, data for stake-outs and to respond to such may provide interface customer requests as when they can expect to between direct retail return to service after an outage. Future customer customer query and requests could address such customer issues as interruptions of customer/generator bilateral dtsco.

contracts for operating reasons.)

11. Coordination and maintenance of S P emergency response plans and training Participate in All other activities (Develop, coordinate, and document emergency development of response plans, and associated training emergency response requirements, including emergency response plans and ensure drills.)

¹te: Emergencies include, for example, wire- personnel are trained as down reports (including phone and cable wire- agreed by LSEs and downs), individual or local service outagcs, large- dtsco scale service outages (e.g., ice storms), pole and cable hits, and pipe dig-ups.

12. Deliver energy from the city S P gate/interchange point to the end-user Schedule energy All other activities deliveries (plus losses) to city gate/interchange point and inform disco accordingly ROC11:101531

Load-Serving Entity Disco Functions Responsibilities Responsibilities.

13. Distributed generation/back-up S P generation/buy-back power management Purchase all power from Set and enforce of interaction with energy system (Identify customer generators (not interface interface requirements, accommodate partial and sold to other LSEs) and requirements, full outages of customer-sited generation, analyze provide back-up power. including imposing and resolve power quality and system operating Depending on agreement non-performance issues due to such generation, set and enforce with rEsco, may interface penalties.

performance standards.)

Nore: It is not clear whether the LSE or disco between disco and would be best positioned to have ultimate customer.

authority and accountability over customer-sited generation.

14. Power quality (Accept customer calls, diagnose P S problems, determine problem accountability All other activities Provide diagnostic (calling customer, other customers, disco support upon LSE facilities), prioritize, schedule, and coordinate request, and resolve problem resolution, implement problem resolution.)

power quality Note: Power quality may require a collaborative problems approach among some or all LSEs, the disco and attributable to disco customers and providers with power quality facilities or concerns to address multi-customer or cross- operations, customer issues. including tracking costs and billing LSEs as appropriate

15. Market research (Collect, analyze, and report P S customer data for the support of planning and All other activities Work with LSEs to development of new and existing products and unbundle wholesale services.) distribution services to allow for product differentiation

16. Quality service management (Serve as an P S internal advocate for the customer; collect and All other activities Work with LSEs to analyze customer data for feedback on service set and maintain performance and product quality.) delivery service quality standards and performance ROC11:101531

r Load-Serving Entity Disco Functions Responsibilities Responsibilities

17. Marketing, including pricing design P S identify value through products and services to All other activities  %'ork with LSEs to customers and customer subgroups based on unbundle wholesale needs and desires identified through market research. Coordinate cross-functional teams for distribution services product design and pricing, positioning, and to allow for product promotion of the product and service.) differentiation.

¹re: Does not include regulated tariffs, addressed separately below.

18. Sales (Prospecting, communicating, and selling P ¹A products and services to customers) All activities

19. Maintenance of third party relationships S (Maintain relationships with third parties who Maintain relationships Maintain also have relationships with retail customers for with discos, other LSEs, relationships with energy or energy-related products and services.)

Note: Includes conducting training for trade allies, and joint emergency- and working with local governments to conduct ventures/alliances/ safety-related municipally-mandated undergrounding and other suppliers. organizations, LSEs, activities, acting on behalf of low-income suppliers, and DSS customers to facilitate Department of Social and other parties Service activities, responding to fire department involved in requests to address possible gas leaks and wire-downs, working with various disaster and providing funding emergency offices and organizations, interfacing for services to retail with local governments and public interest customers who can' groups, participating in IEEE standards groups, pay full price for and, in the future, negotiating services, prices, them.

performance standards, and data exchange arrangements with LSEs.)

20. Responding to customer inquiries and P S requests includes turn-on/shut-off, requests for All other activities Implement turn-outage-related information, application on/shut-off. Provide processing, requests for account information, and requests for information regarding energy information upon technologies and end.uses.) request concerning the status of outages whose restoration is being managed by the disco ROC1n101531

0' 4

~ o

Load-Serving Entity Disco Functions Responsibilities Responsibilities

21. Management of the revenue collection P S process (Obtain consumption information, bill Conduct this task at the Conduct this task at customer consistent with service agreement, retail level, for revenue the wholesale level, accept and process payments, manage delinquent collected directly from for revenue accounts, maintain accuracy and integrity of retail customers collected from LSEs customer records.)

Note: Includes design, operations, and maintenance of'IS and other information systems infrastructure.

22. Facilitation of customer trading of P S imbalances and storage balances (Provide Conduct this task at the Conduct this task at customers with an efficient means of engaging in retail level, for retail the wholesale level, transactions with other customers to mitigate customers with real-time for LSEs only expense associated with energy imbalances.)

meters who have been

¹te: Responsibility and practices may be different for gas and electricity. given the option in their retail product design of avoiding the flow-through of wholesale imbalance charges

23. Development and implementation of- P S public involvement programs All other activities Provide funding (Communicate with thc general public for through public purpose of education, information exchange, and policy charge to address customer complaints which may otherwise elevate to a PSC complaint.)

¹re: To facilitate development of the competitive retail market, all customer-interface activities should eventually be conducted by the LSE rather than the disco.

24. Regulatory coordination and tariff design S P (Serve as the liaison between the Company and Regulated LSE will have Wholesale regulatory bodies, design tariffs, conduct rate retail tariff distribution tariff cases.)

¹te: Disco and regulated LSE will remain under responsibilities that and other regulatory rate-of-return and other State regulation. competitive LSEs will coordination not. All LSEs may need activities.

to comply with licensing and reporting requirements.

ROC11:101531

'0

~ o

Load-Serving Entity Disco Functions Responsibilities Responsibilities

25. Forecasting of customer energy P S requirements (Forecasting of electric system All other activities Aggregate LSE and installed reserve capacity and energy required forecasts and to meet customer demand for electric energy, produce total including forecasts for specific groups and/or individual customers as required by future system load service/tariff designs. Forecasts can be daily, forecasts for monthly, seasonally and/or long-term.) distribution system planning and imbalance service requirements

26. Scheduling of capacity and energy P S purchases and delivery to the service area All other activities Scheduling of spot (Capacity (c.g., installed reserve) and energy market energy procurement and delivery scheduling consistent purchases and stand-with forecasts of customer requirements.)

Note: Responsibility and practices may be by capacity to different for gas and electricity. eliminate local load imbalances

~ 27. Negotiation and administration of P S contracts for procurement of energy and All other activities Capacity and energy associated delivery services (Consistent with contracts associated forecasted capacity and energy requirements, with long-term negotiate contracts for the procurement of imbalance trends.

capacity, energy, and wholesale delivery services.

Administration of the contracts includes accounting and invoice processing support.)

¹ter Assumes that LSEs are responsible for pipeline and installed reserve capacity to meet their customers'eeds. It may be that electric installed reserves are more efficiently purchased by the disco for its service area load and passed through in the wholesale distribution tariff.

ROC1n101531

SCHEDQLE I STANDARDS PERTAINING TO AFFILIATES AND THE PROVISION OF INFORiVIATION This Schedule I addresses the relationships, to the extent relevant to the subject matter of this Settlement, among the DISCO-", any HOLDCO that RGAE may establish pursuant to this Settlement or otherwise, the ULSE or any other affiliate, and competitors of the ULSE or such other affiliate.

Standards of Conduct The following Standards of Conduct shall govern the DISCO's relationship with any energy supply and energy service affiliates, including the ULSE:

(i) There are no restrictions on any affiliate's using the same name, trade names, trademarks, service name, service mark or a derivative of a name, of the HOLDCO or the DISCO or in identifying itself as being affiliated with the HOLDCO or the DISCO. The DISCO will not provide sales leads involving customers in its service territory to any affiliate, including the ULSE, and will refrain from giving any appearance that it represents an affiliate or that an affiliate represents the DISCO. If a customer requests information about securing any service or product offered within the service territory by an affiliate, the DISCO may provide a list of In this document, "DISCO" refers to both the DISCO and the RLSE, unless context requires otherwise.

Rocii:l i264i

companies operating in the service territory who provide the service or product, which may include an affiliate, but the DISCO will not promote its affiliate.

(ii) The DISCO will not provide services on preferential terms, nor represent that such terms are available, exclusively to customers who purchase goods or services from, or sell goods and services to, an affiliate of the DISCO.

The DISCO will not purchase goods or services on preferential terms offered only to suppliers who purchase goods or services from or sell goods or services to an affiliate of the DISCO. This standard does not prohibit two or more of the unregulated affiliates from lawfully packaging their services.

(iii) All similarly situated customers, including energy services companies and customers of energy service companies, whether affiliated or unaffiliated, will pay the same rates for the DISCO's utility services and, in the event that any tariffprovision affords the DISCO discretion in the application of

'such provision, the DISCO shall apply such tariff provision in a consistent manner.

(iv) Transactions subject to FERC's jurisdiction-will be governed by FERC's orders or standards as applicable.

(v) Release of proprietary customer information relating to customers within the DISCO's service territory shall be subject to prior authorization by the customer and subject to the customer's direction regarding the person(s) to ROC I I: i i 2641

0 Qa 0

a

whom the information may be released. If a customer authorizes the release of information to a DISCO affiliate or one or more of the affiliate's competitors, the DISCO shall make that information available to the affiliate and/or other competitors designated by the customer on a simultaneous and comparable basis.

(vi) The DISCO will not disclose to its affiliate any customer or market information relative to its service territory that it receives from a marketer, customer or potential customer, which is not available from sources other than the DISCO unless it makes such information available to its affiliate's competitors on a simultaneous and comparable basis.

(vii) Ifany competitor or customer of the DISCO believes that the DISCO has violated the standards of conduct established in this section of the agreement, such competitor or customer may file a complaint in writing with the DISCO. The DISCO will respond to the complaint in writing within twenty (20) business days after receipt of the complaint. After the filing of such response, the DISCO and the complaining party will meet, ifnecessary, in an attempt to resolve the matter informally. Ifthe DISCO and the complaining party are not able to resolve the matter informally within 15 business days after the filing of such response, the matter will be referred promptly to the Commission for disposition. This provision shall not preclude the Commission from addressing any such matter more expeditiously in the event that exigent circumstances so require.

ROC I I:112641

0 e

0:.

4

4 (viii) The Commission may impose on the DISCO remedial action, consistent with the Commission's statutory authority, for violations of the Standards of Conduct. Ifthe Commission, after affording the DISCO a full and fair opportunity to present its position as to any alleged violations of these Standards of Conduct, finds that the DISCO has violated the Standards during the term of this Settlement, it shall provide the DISCO notice of its findings and shall afford the DISCO a reasonable opportunity to remedy such conduct. If the DISCO fails to remedy such conduct within a reasonable period after receiving such notice, the Commission may take remedial action with respect to the DISCO to prevent it from further violating the Standard(s) at issue.

(ix) The Standards of Conduct set forth in this Settlement will apply in lieu of any existing generic standards of conduct (e.g., the interim gas standards established in Case 93-G-0932) and may be proposed as substitutes for any future generic standards of conduct established by the Commission throughout the term of this Settlement. Thereafter, Staff and the Company shall meet to discuss whether any changes in these Standards are appropriate, giving due consideration . to the Company's specific circumstances, including its performance under the existing Standards.-"

The Parties contemplate that, as the unregulated market develops, there will be a need for fewer, rather than more, restrictions.

ROC I I: I i 264 i

'

Access to Books and Records and Reports The following provisions govern the access by Staff to certain books and records in the event that RGEcE establishes a HOLDCO pursuant to this Settlement or, if it does not, to any subsidiaries established by RGEcE itself:

(i) Staff will have access, on reasonable notice and subject to appropriate resolution of confidentiality and privilege issues, to the books and records of the HOLDCO and the HOLDCO majority-owned subsidiaries. Staff will have access, on reasonable notice and subject to appropriate resolution of confidentiality and privilege issues, to the books and records of all other HOLDCO subsidiaries to the extent necessary to audit and monitor any transactions which have occurred between the DISCO and such subsidiaries, to the extent the HOLDCO has'ccess to such books and records.

(ii) The DISCO will supplement the information that the Commission's regulations require it to report annually with the following information:

Transfers of assets to and from an affiliate, cost allocations relative to affiliate transactions, identification of DISCO employees transferred to an affiliate, and a listing of affiliate employees participating in common benefit plans.

(iii) The HOLDCO will provide a list on a quarterly basis to the Commission of all filings made with the Securities and Exchange Commission by the HOLDCO and any subsidiary of the HOLDCO including the DISCO.

ROC I I: I I 2641

~

.(iv) A senior officer of the HOLDCO and the DISCO will each designate an employee, as well as an alternate to act in the absence of such designee, to act as liaison among the HOLDCO, the DISCO and Staff ("Company Liaisons" ). The Company Liaisons will be responsible for ensuring adherence to the established procedures and production of information for Staff, and will be authorized to provide Staff access to any requested information to be provided in accordance with this Agreement.

(v) Access to books and records shall be subject to claims of privilege and confidentiality concerns as set forth infra.

v Affiliate Relations General a) Within 180 days of the formation of any new subsidiary:

(i) The HOLDCO and such subsidiary will maintain books of account and other business records that are separate and distinct from those of the DISCO.

(ii) Any unregulated affiliate, competing in the energy-related business within the Company's service territory, shall establish and maintain offices and work spaces separate and distinct from those of the DISCO in a separate building or leasehold.

b) Cost allocation guidelines are attached as Appendix A to this Schedule.

These guidelines will be amended and/or supplemented, if necessary, to ROC I i: ( 1264 I

reflect affiliate transactions not contemplated by the initial guidelines set forth in Appendix A. The Company will file with the Director of the Office of Accounting and Finance of the Department of Public Service all amendments and supplements to the guidelines, thirty (30) days prior to making such change(s).

"Royalties" The rate plan in this Settlement shall be in lieu of any and all "royalty" payments that could or might be asserted to be payable by any affiliate of the DISCO or imputed to the DISCO or credited to DISCO customers at any time, including after the expiration of this Settlement; provided, however, that applicability of this section 2 to the post-Settlement period shall be conditioned upon RG&E's compliance with the standards contained in this Schedule I as such standards may be modified pursuant to item (ix) of "Standards of Conduct," ~su ra.

3. Transfer of Assets a) Transfers of assets from the DISCO to an affiliate or from an affiliate to the DISCO will not require prior Commission approval except for the transfer of generating stations and other assets from. the DISCO whose transfer requires Commission approval under Public Service Law $ 70.

b) For all assets other than generating stations, transfers of assets from the DISCO to an affiliate shall be at the higher of net book value or fair ROC I I:I I 264 I

market value-" and transfers of assets from an affiliate to the DISCO shall be on a basis not to exceed fair market value except that the DISCO may, as part of its reorganization, transfer to the HOLDCO or affiliate title to office furniture, equipment and other assets having an aggregate net book value not to exceed $ 5.0 million.

4. Personnel a) The DISCO and the unregulated affiliates will have separate operating employees.

b) Non-administrative operating officers of the DISCO will not be operating officers of any of the unregulated affiliates.

c) Officers of the HOLDCO may be officers of the DISCO. Officers of the.

DISCO may not be directors of any of the unregulated affiliates.

d) Employees may be transferred between the DISCO and an unregulated affiliate upon mutual agreement. Transferred employees may not be reemployed by the DISCO for a minimum of one year from the transfer date. Employees returning to the DISCO may not be transferred to an unregulated affiliate for a minimum of one year from the date of return.

The DISCO will file annual reports to the Commission, beginning with the Rate Year ending June 30, 1998, showing transfers between the DISCO Fair market value shall be determined in accordance with the cost allocation guidelines.

See Appendix A.

Roci i:i I264i

and unregulated affiliates by employee name, former company, former position, new company and new position.

e) The foregoing provisions do not restrict any affiliate from loaning employees, on a fully loaded cost basis, to the DISCO to respond to an emergency that threatens the safety or reliability of service to consumers or to assist the DISCO during Ginna Station outages.

f) The compensation of DISCO employees may not be tied to the performance of any of the unregulated subsidiaries; provided, however, that stock of the HOLDCO may be used as an element of compensation; and provided further that the compensation of the officers of the HOLDCO who are also officers of the DISCO may be based upon the performance of the DISCO and the aggregate performance of the HOLDCO.

g) The employees of HOLDCO, DISCO and the unregulated subsidiaries may participate in common pension and benefit plans, and the cost shall be allocated as set forth in Appendix A.

5. Provision of Services and Goods a) Corporate services (such as corporate governance, administrative, legal, purchasing, and accounting) may be provided by HOLDCO for the DISCO and unregulated subsidiaries on a fully-loaded cost basis.

b) The DISCO may provide other services to an unregulated affiliate, except that the DISCO may not use any of its marketing or sales employees to ROC I I: i ) 264 i

'0 0

'0

- 10-provide services to an unregulated affiliate for business within the DISCO's territory. The unregulated affiliate shall compensate the DISCO for the services of employees performing such services at the higher of the employees'ully-loaded cost or the price that the DISCO would charge a third party for such employees'ervices.

c) The unregulated affiliates may provide services to the HOLDCO and the DISCO. Any management, construction, engineering or similar contract between the DISCO and an affiliate and any contract for the purchase by the DISCO from an affiliate of electric energy or gas shall be governed by Public Service Law $ 110, and will be subject to any applicable FERC requirements. All other goods and services will be provided to the DISCO at a price that shall not be greater than fair market value.

d) The DISCO, the HOLDCO, and the unregulated affiliates may be covered by common property/casualty and other business insurance policies. The costs of such policies shall be allocated among the DISCO, the HOLDCO and the unregulated affiliates in an equitable manner.

Privileged Information Nothing is this Settlement requires or will be construed to require the DISCO, the HOLDCO or an unregulated affiliate to provide Staff or any other party access to, or to make disclosure of any information as to which the entity in possession of such information would be j entitled to assert a legal privilege, such as the attorney-client privilege, if, either (i) the privilege ROC I I: I I 264 I

0 ll

could be asserted pursuant to CPLH. f 4503, CPLR $ 3101 (or any other applicable statute or constitution) in a judicial proceeding, action, trial or hearing, or (ii) providing access to or making disclosure of such information would impair in any manner the right of the entity in possession of such information to assert such privilege against third parties.

If Staff or any other party seeks access to or disclosure of any information that either the DISCO, the HOLDCO or an unregulated affiliate believes is exempt from access or disclosure under the terms of this Settlement, counsel for the entity asserting such privilege will detail, to the extent practical without destroying the privilege, the reasons why the privilege is being claimed in sufficient detail to permit a determination of whether or not to dispute the claim of privilege. If Staff decides to dispute such claim, it may request that an assigned Administrative Law Judge conduct an in camera review of such information to determine whether it is in fact exempt from access or disclosure under the terms of this section, which disclosure shall not be deemed waiver of the privilege. Such determination will be subject to review by the Commission and, ifnecessary, to judicial review.

Confidentiality of Records The HOLDCO and the DISCO shall designate as confidential any non-public information to or of which Staff requests access or disclosure, and which the HOLDCO, the DISCO or an unregulated subsidiary believes is entitled to be treated as a trade secret. Any party will have the right to contest the trade secret nature of such designated confidential information.

Anyone who is afforded access to, or to whom disclosure is made of, designated confidential portions of books and records, financial information, contracts, minutes, memoranda, ROC I I: I I 2641

'0

~.

business plans, and the like, will agree to maintain such information as confidential, other than information that previously has been made public. For the purposes of this Agreement, "information that previously has been made public" will mean information that either (i) has been disclosed by either the HOLDCO, the DISCO or any unregulated affiliate in financial or other literature to the financial community or to the public at large, (ii) appears in documents contained in the public files of a local, State or federal agency, body or court and which has not been accorded trade secret protection, or (iii) information that otherwise is in the public domain.

In the event that Staff or any other party receives any information designated as confidential pursuant to the procedures described in this Settlement and desires to use such information in a litigated proceeding before the Commission, Staff or the party will first notify counsel for the DISCO and the HOLDCO and the unregulated affiliate, if applicable, of the nature of such information as well as its intention to use such information in such proceeding and afford the DISCO, the HOLDCO and/or the unregulated affiliate, ifapplicable, the opportunity to apply to the Administrative Law Judge presiding over such proceeding within ten (10) business days for a ruling designed to maintain the confidentiality of such information under Part 6-1 of the Commission's Rules of Procedure (16 NYCRR). Staff and any other party may object to any such application on the grounds that such information is not entitled to be treated as a trade secret under Part 6-1. The matter shall be resolved pursuant to the procedures of Part 6-1.

In the event that a member of Staff receives any information designated as confidential pursuant to the procedures described in this Settlement and desires to use or refer to such information in a memorandum or other document which may become an "agency record" as the term is defined in the New York Freedom of Information Law (Public Officers Law f 86),

ROCI I:I I264I

'r Staff first shall notify the Company Liaisons of the nature of such information as well as its intended use, and afford the DISCO, the HOLDCO and/or the unregulated affiliate, ifapplicable, the opportunity to apply to the Commission under Part 6-1 of the Commission's Rules of Procedure within ten (10) business days for a protective order designed to maintain the confidentiality of such information. Staff and any other party may object to any such application on the grounds that such information is not entitled to be treated as a trade secret under Part 6-1.

The matter shall be resolved pursuant to the procedures of Part 6-1.

+i ROCI I:I l264I

a 1

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APPENDIX A TO SCHEDULE I COST ALLOCATIONGUIDELINES I<'OR AFFILIATE< TRANSACTIONS Costs associated with goods and services provided by and among a HOLDCO/parent company and a DISCO and/or other affiliates will follow allocation procedures designed to ensure that those costs incurred on an affiliate's behalf are appropriately identified and assigned to the affiliate on a systematic, rational, and fully loaded basis.

Direct Costs: These are costs incurred by the HOLDCO or DISCO in direct support of an i, affiliate. They will be charged directly to the affiliate without undergoing any allocation process.

These costs would include goods and services provided that are readily ascribable to an affiliate entity and are for the specific benefit of the affiliate and not mutually beneficial to all affiliates.

The amount so charged will be the original cost incurred within the affiliated group without any adjustments for intercompany profit or other purpose except the recognition of Indirect Costs described below.

Indirect Costs: These are consequential costs incurred in connection with Direct Costs. For example, the costs of employee benefits, sales and other such costs are indirect costs. These costs, will be charged directly to affiliates, concurrently with the related Birect Costs.

Joint and Common Costs: These are other costs that encompass broad general and k

administrative corporate activity and thus in theory benefit all affiliates. As such, it is necessary that each affiliate bear a representative share of these costs. Examples includes: Corporate

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Governance (Board of Directors and Officers), General Accounting (including Accounts Payable and Payroll), Finance and Treasury, Purchasing, Internal Audit, Human Resources, and Real Estate. The assignment of Joint and Common Costs will be made by allocation and charged to the appropriate books of account of each affiliate monthly based on a factor. The general methodology is as follows:

Calculate the allocation factor based on criteria such as: (a) number of employees; (b) total assets; (c) gross revenue; and (d) shareholders'quity.

(Note: zero shall be substituted when an allocation factor is negative)

The simple mathematical average of the allocation bases described above will be computed quarterly and will be used prospectively as the default factor for cost allocation to affiliates. (For certain types of allocable costs, a subset of the allocation bases might be appropriately used instead of the default factor.) The percentage thus derived will be applied each month to costs associated with those areas identified as corporate administrative and general within the HOLDCO.

V Such amount will be deemed to be the allocable Joint and Common Costs and charged via intercompany accounts to the appropriate affiliate(s). The amounts charged will be regarded as pre-tax amounts.

Roc! I: i I 264 i

SCHEDULE J FORM OF PETITION TO FORM HOLDING COMPANY STATE OF NEW YORK BEFORE THE PUBLIC SERVICE COMMISSION CASE 97-M- In the Matter of the Application of Rochester Gas and Electric Corporation under the Public Service Law, Including Sections 70, 107, 10S and 110 Thereof, to Form a Holding Company and for Certain Related Transactions PETITION

, 1997

STATE OF NEW YORK BEFORE THE PUBLIC SERVICE COMMISSION CASE 97-M- In the Matter of the Application of Rochester Gas and Electric Corporation under the Public Service Law, Including Sections 70, 107, 108 and 110 Thereof, to Form a Holding Company and for Certain Related Transactions

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PETITION Petitioner, ROCHESTER GAS AND ELECTRIC CORPORATION

("Company" ), hereby applies to the Commission for authority under Sections 70, 107, 108 and 110 of the Public Service Law to form a holding company and for certain related transactions.

The Commission may rely on information included in Company's submissions, including the t, documents relating to the settlement agreement ("Settlement Agreement" ) in the Competitive Opportunities Case as support for the action requested in this filing.

In support of this application the Company states:

1. The Company supplies electric and gas service in nine counties centering about the City of Rochester, New York. The Company is a corporation organized pursuant to the laws of the State of New York in 1904. Certified copies of its organizational documents have been duly filed with the Commission.

2. There is appended hereto, as Schedule A, a statement of financial condition of the Company at December 31, 1996, pursuant to the Commission's Rules of Procedure, 16 NYCRR $ 18.1.

3. The Settlement Agreement permits the establishment of a holding company structure under which one or more regulated companies and one or more unregulated companies may operate. These operating companies would be direct or indirect subsidiaries of a holding company ("HoldCo"). This structure will benefit the Company's 0

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customers, shareholders and employees by providing the flexibility needed to compete effectively in the changing utility industry, while at the same time protecting the Company's customers from the risks inherent in the unregulated businesses.

To compete effectively, the Company must have no less flexibility in doing business than that available to its competitors. A holding company structure would allow the Company to implement a decision to enter or deploy capital in a competitive business without the delay of a regulatory approval process. The delays necessarily associated with obtaining regulatory approvals for such investments on a specific, case-by-case basis while reasonable, necessary and largely unavoidable in a regulated context, are simply inconsistent with competitive success. The new corporate structure also would permit the issuance of securities by the HoldCo, or a separate finance subsidiary, to finance competitive businesses (including "CompCo"). Under the Company's current corporate structure, Section 69 of the Public Service Law would not permit the issuance of securities for this purpose.

. 5. The customers of the regulated utility subsidiary protected from the risks inherent in competitive businesses.

("RegCo") would be The RegCo, as a separate legal entity, would not bear any losses or be responsible for any obligations that may arise from the HoldCo or its competitive businesses. In addition, the RegCo, which would not count as an asset any investment in a competitive business, should not have its access to capital markets or credit ratings adversely affected by the HoldCo or its competitive businesses.

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6. U Upon Commission approval and receipt of the necessary shareholder and other regulatory approvals (described in paragraph 13 below), the Company intends to establish the HoldCo pursuant to a tax-free reorganization (the "Reorganization" ). The Reorganization would be effected as a "binding share exchange" as follows:

First, the Company would create the HoldCo as a first-tier, wholly-owned subsidiary.

Then, in accordance with a plan of exchange adopted pursuant to Section 9l3 of the Business Corporation Law,

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the Company's common shareholders would receive one HoldCo common share in exchange for each Company common share held by the shareholders immediately prior to the Reorganization.

7. Upon consummation of the Reorganization, all of the Company's common shares would be held by the HoldCo, and all of the HoldCo's common shares would be publicly held. The Company does not expect that any change in the preferred stock or debt of the Company would be effected by the Reorganization, except that the Company may need to amend the voting rights of the preferred stock in order to qualify for a tax free reorganization under the Internal Revenue Code.-" In connection with the HoldCo's commencement of operations, the RegCo may lease office space to the HoldCo and transfer to the HoldCo office furniture, equipment and other assets having an aggregate net book cost of not to exceed $ 5 million.

8. The Company would be the RegCo,'and HoldCo would have

<< subsidiaries in addition to the RegCo.-" The Company's strategic plans as to the competitive businesses in which it will compete will necessarily evolve as the utility industry continues to evolve. Regardless of the businesses involved, it is essential that the competitive businesses not be disadvantaged by regulatory or operating constraints imposed by the Commission. The competitive businesses should be able to transact business with each other and with the RegCo on the same basis as their competitors.

9. The Company believes that the Commission can, without imposing operating constraints on HoldCo or its competitive businesses, protect the RegCo's customers and prevent any unfair competitive advantage. The provisions set forth in the Settlement A change in the voting rights of the preferred stock would require an amendmcnt of the Company's Certificate of Incorporation.

It is expected that the Company, simultaneously with the Reorganization or shortly before, will drop its stock in Energyline Inc. at.d CompCo into HoldCo and that Energyline Inc. and CompCo will become wholly-owned subsidia;lcs of HoldCo.

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Agreement, and the corporate structure, will protect the RegCo's customers from the risks of competitive businesses.

10. Because the Settlement Agreement provides for a fundamental change in the Company and the opening of its electric business to competition, the Company believes that only limited operating constraints, tailored closely to the activity to be monitored, are appropriate. These constraints, along with the existing statutory tools of the Commission and the Federal Energy Regulatory Commission and the federal and state antitrust laws, will be adequate to protect customers and ensure that robust competition develops while at the same time allowing the HoldCo and its subsidiaries to compete in the market. As competition, develops, the Company believes that the specific restrictions should be reviewed to determine whether they are still appropriate or necessary.

11. The Settlement Agreement sets forth the conditions to the making of capital contributions to HoldCo and its unregulated affiliates. Those provisions are incorporated in this Petition by reference.

12. The Company also agrees to abide by certain operating principles relating to intercompany relationships, its code of conduct, cost allocations and other provisions, all as set forth in Schedule I to the Settlement Agreement.

13. Implementation of the HoldCo structure will require certain approvals in addition to that of the Commission and other actions by federal and state authorities.

Consummation of the Reorganization will require the adoption of a plan of exchange at a meeting of the Company's shareholders. In connection with its solicitation of proxies to vote at the meeting, HoldCo must file a Registration Statement on Form S-4 with the Securities and Exchange Commission to register the HoldCo common shares to be exchanged for the outstanding Company common shares and such Registration Statement must become effective.

The Registration Statement will also contain a proxy statement of the Company describing the Reorganization in detail, which proxy statement will be mailed to Company shareholders prior to the meeting referred to above. The Company must deliver to the New York State Secretary of State a certificate of exchange under Section 913 of the New York Business

Corporation Law, the certificate of exchange must be endorsed on behalf of the Commission (pursuant to Section 108 of the Public Service Law), and the Secretary of State must file the certificate of exchange. In addition, prior to the reorganization it is expected that HoldCo would file with the Securities and Exchange Commission for the intrastate exemption from the registration requirements of the Public Utilities Holding Company Act provided by Section 3(a)(1) thereof or Rule 2 thereunder. The Company will need to file for the approval of the Federal Energy Regulatory Commission and the Nuclear Regulatory Commission.

14. The Company respectfully reserves the right to withdraw this Petition at any time prior to its acceptance of an order of the Commission with respect to the Petition.

The Company further requests that any such order by its terms permit the Company (even after unconditionally accepting the order) to decide not to consummate the transactions

, described herein.

AVHEREFORE, the Company requests that the Commission issue an order authorizing (i) the formation 'of a holding company for the Company, as described and subject to the conditions contained herein, (ii) the related transactions described herein and in the Settlement Agreement, (iii) the Secretary of the Commission to endorse the Commission's consent and approval upon the certificate of exchange executed by the Company, and (iv) such other and further relief to which Petitioner may be entitled by reason of the premises.

Respectfully submitted, ROCHESTER GAS AND ELECTRIC CORPORATION By:

Title:

Dated: , 1997 Rochester, New York

STATE OF NEW YORK COUNTY OF MONROE

, being duly sworn, deposes and says: I am the of ROCHESTER GAS AND ELECTRIC CORPORATION, the Petitioner herein; I have read the foregoing Petition and know the contents thereof; the same is true to the best of my knowledge.

Sworn to before me this day of , 1997 I

Notary Public, State of New York ROC I I: I I 2640

SCHEDULE>> K SBC PROGRAM COSTS (SMM)

Settlement Energy Environmental Year ~Efficienc Low-Income RAD P~ro rams Total 4.0 0.5 0.2 0.0 4.7 44 0.6 0.2 0.0 5.2 44 0.2 0.2 0.0 4.8

~y l 47 44 4.3 0.1 0.0 0.2 0.2 0.0 0.0 4.5 ROC I I: I I 3027

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EXHIBITB Copy to- 1 F. Colon.

G. Lang STATE OF NEW YORK J. Reynolds PUBLIC SERVICE COMMISSION D. Schraver J. Smith At a session of the Public Service D. Tennant W. Thomas Commission. held in the City of Albany on November 25, 1997 COMMISSIONERS PRESENT:

John F. O'Mara, Chairman Maureen O. Helmer Thomas J. Dunleavy CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/

Restructuring Pursuant to Opinion No. 96-12.

ORDER ADOPTING TERMS OF SETTLEMENT SUBJECT TO CONDITIONS AND CHANGES (Issued and Effective November 26, 1997)

BY THE COMMISSION:

INTRODUCTION This proceeding concerns issues related to competitive opportunities for electric service for Rochester Gas and Electric Corporation (RG&E or the company). Interested parties were encouraged to reach a negotiated resolution of the complex issues raised by the transition to a competitive market for the supply of electricity.'fter filing a Settlement Agreement dated April 8, 1997 (April 8 Settlement), the parties proposed further revisions to resolve concerns identified by us. These further revisions were reflected in an Amended and" Restated Settlement Agreement (Settlement) dated October 23, 1997'eached by RG&E, Department of Public Service staff (staff), Multiple Intervenors, Joint Supporters, and the National Association of Energy. Service Companies. After careful review of the Settlement, the comments Cases 94-E-0952 et al., In the Matter of Com etitive 0 ortunities Re ardin Electric Service, Order Establishing Procedures and Schedule (issued October 9, 1996)", p. 3.

A copy of the Settlement is Appendix A to this order.

CASE 96-E-0898 received, and the evidence and arguments in this proceeding, the Settlement is adopted subject to the conditions and changes set forth infra.

This abbreviated order sets forth our decision. A more

, comprehensive opinion will follow, describing the bases for our decision. The statute of limitations for fili'ng petitions for rehearing or clarification of our decision will be deemed to run from the date of issuance of our opinion.

THE SETTLEMENT The Settlement would change the regulatory framework for RGEE to prepare it for the .dynamic changes taking place in the electric industry and the emergence of competition. The terms of the Settlement are largely based on those of the April 8 Settlement, which was the subject of supporting and opposing II statements and testimony, rebuttal statements and testimony, evidentiary hearings, post-hearing briefs, a recommended decision, and briefs on exceptions and opposing exceptions.

In a recommended decision issued July 16, 1997, Administrative Law Judge Walter T. Moynihan found that the terms of April 8 Settlement were reasonable. Among other th'ings, he concluded that the phase-in of competition would proceed at a reasonable pace, the average back-out rate would reflect RGEE's cost of energy and capacity for its non-nuclear generating units, and the proposed corporate restructuring would expose the company's, electric generation operations to market forces.'fter reviewing the recommended decision and the parties exceptions, we identified several major'reas of concern regarding the terms of the April 8 Settlement,'ncluding the following: achieving greater rate reductions for residential and small commercial customers; ameliorating the impacts of the proposed increase in the monthly customer charge; increasing the R.D., pp. 71, 72 .

These issues were discussed at our session on October 8, 1997.

h CASE 96-E-0898 ratepayers share of possible excessive earnings and gains on the sale of generating units, while still encouraging divestiture; accelerating the pace of retail access if warranted; increasing the backout rate during the Energy Only phase of retail access; and establishing minimum spending limits on system benefits charges.

As a result of further negotiations, the Settlement was fi3.ed and parti'es were invited to submit further written comments.

The terms of the Settlement will offer a sound regulatory framework for RG&E, its competitors, and its customers in the transition to fully competitive generation and energy service markets. Having reviewed these terms, however, there are several important issues that are not resolved to our satisfaction. For this reason, we adopt the terms of the Settlement subject to the following:

1. The Settlement ($ 6) provides that, beginning July 1, 1999 and continuing through June 30, 2002, Incremental Manufacturing Load shall be served at an average rate of $ 0.059 per kWh. We adopt this term on the condition that the average rate instead is $ 0.045 per kWh..

2. The Settlement ($ 10(b)) provides that the first

$ 800,000 of the customers'hare of any excess earnings will be used to reduce rates for certain large customer classes. We conclude, that large customers already receive substantial benefits under other provisions of the Settlement; thus, there is no need for this unique additional benefit. Accordingly, we adopt this term on the condition that the first sentence of 10(b) is removed, and the words "...of this amount..." 'aragraph are deleted from the second sentence.

3. Certain provisions of the Settlement (i.e., )$ 8, 11-17, 24 (with respect to shut-down costs), and $ 30) provide for deferral and recovery without requiring further petition to or approval by the Commission. Without altering the intent of these

~, terms, we adopt them on the condition that a formal petition will

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CASE '96-E-0898 be filed with the Commission prior to establishing deferrals or any recovery during the term of the Settlement.

4. The Settlement ($ 23) makes reference to possible Statewide resolution of the future ratemaking and ownership of nuclear facilities. Paragraph 23(d) states that "no.change in the treatment of RGRE's nuclear facilities shall be implemented until at least January 1, 2000." The January 1, 2000 date might be construed as precluding a sale or transfer, through an auction or otherwise, of the company s interest in nuclear facilities until at least the year 2000 and, thus, could conflict with subsequent action on the August 1997 Staff Report on Nuclear Generation. We adopt this paragraph on the condition that $ 23(d) is modifi'ed to read as follows: "no change in the treatment of RGEE's nuclear facilities shall be implemented prior to the Commission's resolution of the August 1997 Staff Report on Nuclear Generation."

5. The Settlement ($ 48(h) ) provides that, "[a] s of July 1, 2002, all retail customers will be eligible to participate" in RGSE's Retail Access Program. Our approval of the Settlement is conditioned on the company moving to full retail access one year earlier. Accordingly, $ 48(f) is modified by adding the word "and" at the end; $ 48(g) is modified to read:

"As of July 1, 2001, all retail customers will be eligible to participate."; and $ 48(h) is deleted.

6. The last sentence of .$ 52 of the Settlement provides for a possible increase in the pace of retail access implementation if certain conditions are met. Xn light of the modifications described in the preceding'paragraph, this last sentence is unnecessary, and therefore, we adopt $ 52 on the condition that this sentence is deleted.

7. The'Settlement (Sch. A) provides that, by the final year of the term, rates for the smaller customer classes will be 5.0% below the rates in effect as of June 30, 1997. The Settlement is approved on condition that the rate reduction for

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the "pri-pri," "pri-sec," and "sec-sec" voltage classes will be increased from 5.0~ to 7.5% in the final year of the Settlement.

CASE 96-E-0898 This change requires a corresponding adjustment to the cumulative reduction shown in $ 2, which would increase the amount for July 1, 2001, from "$ 51.1 million" to "$ 64.6 million."

8. The Settlement ($ 55, n. 108, and )57) identifies a contestable rate of $ 0.032 per kWh, but does not indicate whether the Gross Receipts Tax (GRT) is considered in the derivation of that amount. We adopt this rate subject to the'clarification that the $ 0.032 rate includes the impact of the GRT.

9. The Settlement ($ 67) authorizes RGEE to provide initial funding for unregulated business activities in the amount of $ 50 million. We authorize RGEE to fund unregulated operations in the amount of $ 100 million. Therefore, we adopt $ 67 except

$ 50 million is increased to $ 100 million.

STATE ENVIRONMENTAL UALITY REVIEW ACT EVALUATION In conformance with the State Environmental Quality Review Act (SEQRA), we issued on May 20, 1996 a Final Generic Environmental Impact Statement (FGEIS), which evaluated the action adopted in Case 94-E-0952. We also required individual utilities to file an environmental assessment of their restructuring proposals. In a June 19, 1997 ruling, Chief Administrative Law Judge Lynch narrowed the issues needing further consideration in the environmental assessment. RGB filed an Environmental Assessment Form (EAF) concerning the April 8 Settlement on June 24, 1997.

Subsequent to filing of the EAF, Public Interest Intervenors (PII) filed a.petition asking that a Supplemental Environmental Impact Statement be filed. In its arguments supporting the petition, PII raised several substantive issues for SEQRA consideration.

The information provided by RGEE in its EAF, the parties'omments and responses, the Settlement, and-other information were evaluated in order to determine whether the potential impacts resulting from adopting the Settlement's, terms would be within the bounds and thresholds of the FGEIS adopted in 1996. The analysis examined several areas of potential impacts

CASE 96-E-0898 including the potential for increased air emissions, which could increase as a result of greater load growth due to reduced rates, and reduced demand side management programs.

Arguably, all of the potential impacts need not be considered given that some result from Type II exempt rate actions. Nonetheless, considering all factors, the potential environmental impacts of the Settlement are found to be within the bounds and thresholds evaluated in the FGEIS. Therefore, no further SEQRA action is necessary. However, as a matter of U

discretion, monitoring of RGEE s restructuring will be implemented.

The final EAF will be appended to the opinion to be issued later.

DISCUSSION Taking into account our overall responsibility to set just and reasonable rates, the company's statutory burden of proof, and our settlement guidelines, and having considered the evidence, comments, arguments, and EAF information, the terms of the Settlement, subject to the above described conditions, and changes, are found to be reasonable and in the public interest.

Among other things, these terms, conditions, and changes will help consumers in and around Rochester save over

$ 115 million in cumulative rate reductions over the next few years and this will help retain and, attract businesses and stimul'ate economic activity. In addition, customers will no longer be liable for $ 73 million in credits owned the company arising from flex-rate discounts and past incentives. The Settlement's terms also include an incentive for divestiture of the utility's generation and establishes an environment for a robust, competitive electric generation market. With this framework and expected competition in the energy services sector, many customers can anticipate receiving electricity bills lower than otherwise and all customers should enjoy greater choices of energy providers and services. At the sane time, the

CASE 96-E-0898 Settlement's terms fairly address environmental concerns during the transition to a fully competitive market.

Accordingly, the Settlement's terms are adopted in their entirety subject to the conditions and changes listed above and they are incorporated by reference, into this as the terms of the Settlement are interrelated, as are order.'nasmuch our conditions and changes listed above, if any term, condition, or change is modified, vacated, or otherwise materially affected by judicial review, we may re-examine our entire decision.

The Commission orders:

1. The terms of the Amended and Restated Settlement Agreement (Settlement) dated October 23, 1997 and filed in this proceeding, as modified by the conditions and changes described above, are adopted in their entirety and are incorporated as part of this order.

2. The potential environmental impacts of these terms are within the bounds and thresholds evaluated in the 1996 FGEIS, and, therefore, no further SEQRA action is necessary.

3. RG&E is directed to file by December 1, 1997, to become effective no later than July 1, 1998, such tariff amendments as are necessary to effectuate the retail access program contemplated by the Settlement as adopted and to implement Opinion No. 97-'5. RGB is also directed to file by June 1, 1998, to become effective July 1, 1998, such tariff amendments as are necessary to effectuate the rate reductions and other rate related matters contemplated by the Settlement as adopted. The company shall serve copies of its filings upon all parties to this proceeding. Any comments on the filing to effectuate the retail access program must be received at the Commission's offices within 45 days of publication in the State Register pursuant to the State Administrative Procedure Act. Any To the extent the last seven words of $ 77 suggests any signatory could prevent us from making this decision, such language is contrary to the public interest and is not adopted.

CASE 96-E-0898 comments on the filing to effectuate the rate reductions must be received at the Commission's offices within ten days of service of the company's proposed amendments. The amendments shall not become effective on a permanent basis until approved by the Commission.

4. To the extent exceptions to the recommended decision issued in this proceeding on July 16, 1997 are not moot, or are otherwise granted, they are denied.

S. RG&E, in cooperation wi'th staff, shall monitor the environmental impacts of electric restructuring resulting from this order.

6. RG&E must submit a written statement of unconditional acceptance of the conditions and changes contained in this order, signed and acknowledged by a duly authorized officer of RGEE, by December 1, 1997. Xf such acceptance of this order is not so filed, the adoption of the terms of the Settlement may be revoked. This statement should be filed with the Secretary of the Commission and served on all parties in this proceeding.

7. This proceeding is continued.

By the Commission, (SIGNED) JOHN C. CRARY Secretary

EXHIBITC Copy to:

STATE OF NEW YORK RNG PUBLIC SERVICE COMMISSION RJB SWW OPINION NO. 98-1 CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/

Restructuring Pursuant to Opinion No. 96-12.

OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT SUBJECT TO CONDITIONS AND CHANGES Issued and Effective: January 14, 1998

CASE 96-E-0898 TABLE OF CONTENTS Pacae APPEARANCES INTRODUCTION PROCEDURAL HISTORY Procedural Concerns THE REVISED SETTLEMENT REVENUE REQUIREMENT 10 Strandable Costs 10 Kamine Cost Recovery 15 Return on Equity 17 Gain on Sale of Generating Plants 21 SBC Funding 22 Other Proposals 23 REVENUE ALLOCATION AND RATE DESIGN 25 THE PROGRAM 30 Single Retailer Model 30 Implementation Schedule 31 Delivery Rates Other Retail Access Issues 38 CORPORATE STRUCTURE 39 ENVIRONMENTAL MATTERS MARKET POWER MITIGATION 42 FINDINGS UNDER SEQRA 43 CONCLUSION ORDER 47 APPENDIX A APPENDIX B APPENDIX C

CASE 96-E-0898 APPEARANCES FOR ROCHESTER GAS AND ELECTRIC CORPORATION:

Nixon, Hargrave, Devans & Doyle (by Robert J. Bird, Richard N. George, and Stanley W. Widger, Jr., Esqs.),

Clinton Square P.O. Box 1051, Rochester, New York 14603 FOR DEPARTMENT OF PUBLIC SERVICE STAFF:

Michelle Phillips, Esq., Three Empire State Plaza, Albany, New York 12223-1350 FOR ATTORNEY GENERAL OF THE STATE OF NEW YORK:

Glen C. King, Esq., The Capitol, Albany, New York 12247 FOR NEW YORK STATE CONSUMER PROTECTION BOARD:

Anne Curtin and James Warden, Esqs.,

99 Washington Avenue, Suite 1020, Albany, New York 12210 FOR NEW YORK POWER AUTHORITY:

~ Eric J. Schmaler, Esq., 1633 Broadway, New York, New York 10019 FOR AMERICAN ASSOCIATION OF RETIRED PERSONS:

Ward, Sommer &: Moore, LLC (by Douglas H. Ward, Esq.),

122 South Swan Street, Albany, New York 12210 FOR PUBLIC INTEREST INTERVENORS AND FOR PACE ENERGY PROJECT:

David Resnick, Esq., 78 North Broadway, White Plains, New York 10606 FOR 1PPNY:

Aaron Breidenbaugh, 291 Hudson Avenue, Albany, New York 12210 FOR ENRON TRADE Ec CAPITAL RESOURCES:

Read R Laniado (by Kevin Brocks, Esq.),

23 Eagle Street, Albany, New York 12207

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CASE 96-E-0898 APPEARANCES FOR MULTIPLE INTERVENORS:

Couch, White, Brenner, Howard & Feigenbaum (by Robert M. Loughney, Esq.), 540 Broadway, P.O. Box 2222, Albany, New York 12201 FOR RETAIL COUNCIL OF NEW YORK:

Cohen, Dax 8 Koenig (by Paul Rapp, Esq.),

90 State Street, Albany, New York 12211 FOR WHEELED ELECTRIC POWER COMPANY:

Joel Blau, Esq., 32 Windsor Court, Delmar, New York 12054 I

FOR CONSOL DATED EDISON COMPANY OF NEW YORK' NC John F. Gallagher, Esq., 4 Irving Place, New York, New York 10003 FOR CONSOLIDATED NATURAL GAS COMPANIES:

Whiteman, Osterman 8 Hanna (by Michael Whiteman, Esq.),

One Commerce Plaza, Albany, New York 12260 FOR NEW YORK STATE ELECTRIC Sc GAS CORPORATION:

Huber Lawrence E Abell (by Andrew Fisher, Esq.),

605 Third Avenue, New York, New York 10158 PRO SE:

Jerome Bowe, 104 Brentwood Drive, Penfield, New York 14526 Charles A. Straka, 6 Oakwood Lane, Fairport, New York 14405

STATE OF NEW YORK PUBLIC SERVICE COMMISSION COMMISSIONERS:

John F. O'Mara, Chairman Maureen O. Helmer Thomas J. Dunleavy CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/

Restructuring Pursuant to Opinion No. 96-12 NO. 98-1 'PINION OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT SUBJECT TO CONDITIONS AND CHANGES (Issued and Effective January 14, 1998)

BY THE COMMISSION:

INTRODUCTION This proceeding concerns issues related to rates and the restructuring of the electric utility industry for Rochester Gas and Electric Corporation (RG&E or the company). Interested parties were encouraged to reach a negotiated resolution of the complex issues raised by the transition to a competitive market for the supply of electricity.'fter filing a Settlement Agreement dated April 8, 1997 (April 8 Settlement), the parties proposed further revisions to resolve concerns identified by us at our October 8, 1997 session.

These further revisions were reflected in an Amended and Restated Settlement Agreement (Revised Settlement) dated October 23, 1997 reached by RG8E, Department of Public Service Staff (Staff),

Multiple Intervenors, Joint Supporters, and the National Association of Energy Service Companies. After careful review of the April 8 Settlement, the Revised Settlement, the comments received, the evidence, and arguments in this proceeding, we

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Cases 94-E-0952 et al., In the Matter of Com etitive 0 ortunities Re ardin Electric Service, Order Establishing Procedures and Schedule (issued October 9, 1996), p. 3, (October 9 Order). i

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CASE 96-E-0898 issued an order adopting the Revised Settlement subject to certain conditions and changes.'he findings and decision made in that order are hereby incorporated, and this opinion describes the bases for our decision.

PROCEDURAL HISTORY Opinion No,. 96-12'equired five of the State' electric utilities to file plans to bring to New York State consumers the benefits of a competitive electricity market. In compliance with that opinion and order, RGSE submitted its plan on, October 1, 1996.

Considerable public comment on the April 8 Settlement was received through educational forums, public statement hearings,'nd consumer correspondence. While the comments generally supported our goals for a competitive marketplace, four areas of concern were identified by the public: system and service reliability; the impact of competition on low- and fixed-income consumers; the effect of strandable costs on rates; and the need for consumer education.

Concerns were also expressed about the relatively smaller revenue decreases for residential and small commercial customers; the increase in the residential and small commercial customers'n monthly customer charge, which would have resulted in overall bill increase for roughly 43. of the residential customers; the failure to quantify and require sharing of strandable costs, which it was alleged would have justified Case 96-E-0898, Order Adopting Terms of Settlement Subject to Conditions and Changes (issued November 26, 1997) (November 26 Order) .

Cases 94-E-0952 et al., In the Matter of Com etitive 0 ortunities Re ardin Electric Service, Opinion No. 96-12 (issued May 20, 1996).

Educational forums and public statement hearings were held on May 28 and 29, 1997 in Canandaigua and Rochester, respectively.

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CASE 96-E-0898 further rate reductions; the slow pace of conversion to retail access--about five years; and the lack of a system to decide who would be afforded retail access first.

Evidentiary hearings on the April 8 Settlement were held from June 3 through June 5, 1997; the record contains 2,029 transcript pages (Tr.) and 82 exhibits. In addition, statements and briefs in support of or in opposition to the April 8 Settlement were submitted by numerous parties.

On July 16, 1997, a recommended decision by Administrative Law Judge Walter T. Moynihan was issued, which generally supported adoption of the April 8 Settlement. Briefs and/or reply briefs on exceptions were received from RGEE; Staff; Joint Supporters; the Department of Law (Attorney General)

Multiple Intervenors; State Consumer Protection Board (CPB); New York Power Authority (NYPA); American Association of Retired Persons (AARP); Public Interest Intervenors (PII), a broad-based umbrella coalition comprising 18 consumer and environmental organizations; Public Utility Law Project of New York, Inc.

(PULP), a not-for-profit public interest firm representing the interests of low-income residential consumers; Retail Council of New York (Retail Council), an association of nearly 5,000 retail enterprises in New York State; Independent Power Producers of New York, Inc. and Enron Capital & Trade Resources (IPPNY/Enron),

Wheeled Electric Power Company (WEPCO), independent power marketers; and Mr. Jerome P. Bowe, a pro se intervenor.

After reviewing the recommended decision and the parties'xceptions, we requested the parties to renegotiate the terms of the April 8 Settlement to: achieve greater rate reductions for residential and other small customers; consider ameliorating the impacts of the proposed increase in the monthly customer charge; increase the ratepayers'hare of possible excessive earnings and gains on the sale of generating units,

~ 'ppendix A is a list of abbreviations used in this document.

These issues were discussed at our session on October 8, 1997.

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CASE 96-E-0898 while still encouraging divestiture; accelerate the pace of retail access if warranted; increase the back-out rate during the Energy Only stage of retail access; and establish minimum spending limits for the system benefits charge (SBC).

As a result of further negotiations, the Revised Settlement was filed and parties were invited to submit further written comments.'hirteen parties submitted the five signatories to the Revised Settlement and comments'ncluding eight others that oppose its adoption.

In our November 26 Order, we found that with certain modifications the terms of the Revised Settlement offer a sound regulatory framework for RG&E, its competitors, and its customers in the transition to fully competitive generation and energy service markets.

Procedural Concerns The recommended decision rejected an argument that most of the active parties were unfairly or improperly excluded from discussions among Staff, the company, CPB, and Multiple Intervenors. The recommended decision observed that we waived in part our settlement guidelines'n the instant case to enhance the parties'bility to be creative and communicate freely.4 Thus, the recommended decision concluded the caucusing among some parties was not proscribed, and the April 8 Settlement should not be rejected or modified based on this procedural argument.

AARP and Mr. Bowe except, arguing the April 8 Settlement was reached as a result of procedures that denied parties a meaningful opportunity to participate. AARP also Case 96-E-0898, Notice Inviting Comments on Proposed Settlement (issued October 24, 1997).

Appendix B is a list of the parties who filed comments.

Cases 90-M-0255 et al., Settlement Procedures and Guidelines Opinion No. 92-2 (issued March 24, 1992), Appendix B, p. 4 (guideline B.(3)).

October 9 Order.

CASE 96-E-0898 asserts that, because we truncated important procedures, the April 8 Settlement should be rejected. RG&E replies that earlier negotiations were unproductive when all parties were present.

The procedures followed in this case have afforded all parties ample opportunities to shape the decisions reached in this case. As the recommended decision notes, we waived our settlement guidelines to permit caucusing to enhance the to be creative, communicate freely, and reach an parties'bility expeditiously negotiated resolution. The waiver of the guidelines permitted not only the caucusing mentioned above, but also discussions among Staff and other parties. As a result of the caucusing, a draft agreement was prepared and circulated among all the parties. After further negotiations, at which all parties had an opportunity to attend, modifications were incorporated in the agreement based on the various This modified agreement is the April 8 Settlement. In parties'omments.

addition, all parties were afforded an opportunity to conduct discovery, present testimony and pre-hearing position papers, cross-examine witnesses, submit post-hearing briefs, and file briefs on and opposing exceptions to Judge Moynihan's recommended decision. Moreover, all parties were given a further opportunity to comment on the Revised Settlement. These procedural steps gave each party a reasonable opportunity to participate.

Consequently, AARP's and Mr. Bowe's procedural exceptions are denied.

THE REVISED SETTLEMENT Generally, the Revised Settlement is intended to resolve all issues in this proceeding. In addition to a number of miscellaneous provisions, the Revised Settlement addresses three main topics: rate reductions, retail access, and corporate restructuring. The Revised Settlement would establish electric rates for a five-year period (July 1, 1997 through June 30, 2002) at levels that are, overall, below their current levels. While rates for all customer classes would be reduced, large industrial and commercial customers would receive the biggest decreases.

CASE 96-E-0898 The Revised Settlement calls for rate reductions in each of five years culminating in a net $ 40.6 million (6.1%)

decrease in RGEE's electric revenues in the fifth year as compared with rates in effect on July 1, 1996. The cumulative revenue decrease, subject to certain contingencies discussed infra, would be $ 101.6 million. In addition, RGEE would forgo

$ 73 million of incentive payments and lost net revenues otherwise due it arising from discounts contained in its flex-rate contracts.

The rates to be established to produce the foregoing revenue reductions would not be modified to reflect changes in revenues or expense, state and local taxes (other than gross receipts taxes and property taxes) and asset sales during the term of the Revised Settlement except for the following items, some of which are the subject of exceptions as more fully discussed infra:

a. Kamine/Besicorp - Allegany L.P.

(Kamine) recovery;

b. Variations in the levels of mandated relief; C. Securitization benefits;

d. Deferrals; and

e. Adjustments Except for changes arising from a mandated SBC and securitization, which would be reflected in rates without any limitations, rates will only be changed if the pre-tax net effect of all other such items, on a projected cumulative basis during the term of the Revised Settlement, would be greater than

$ 30 million. However, no such rate adjustment would be made in rate years'ne or two, and adjustments in the final three rate 0 A rate year is a one-year period commencing on July 1 of one calendar year and terminating on June 30 of the following calendar year.

CASE 96-E-0898 years would be subject to monetary limitations, which ensure that there would be rate decreases during the five years. Any amounts that are not recovered as a consequence of the monetary limitations may be deferred.

Generally, the Revised Settlement provides that the revenue decreases would be allocated to RG&E's service classes based on their responsibility for generation costs'he proposed revenue reductions are in addition to the base rate reductions and the elimination of fuel adjustment charges effective July 1, 1996, in accordance with a settlement agreement (1996 Settlement) that we approved with modifications.'ursuant to'he 1996 Settlement, the total reductions for the 12 months ended June 30, 1997 approximated 2.5% for residential customers and 4.5% for non-residential customers.'everal specific rate design changes are also set forth in the Revised Settlement, including a proposed yearly $ 1.50 increase in the monthly customer charge for the residential and small business customers, elimination of the difference between the peak and shoulder-peak energy charges as of July 1, 1997 for large industrial customers, and modification of the energy audit requirement in the flex-rate tariffs. In addition, beginning July 1, 1999 and continuing through June 30, 2002, certain incremental manufacturing load of at least 50 kW would be served at an average rate of $ 0.059 per kWh. All other changes in revenues would be allocated uniformly within each service classification.

With respect to the Retail Access Program (Program),

the Revised Settlement requires RGEE to open its electric system Cases 95-E-0673 et al., Rochester Gas and EIectric Cor oration, Order Approving Terms of Settlement Agreement With Changes (issued June 27, 1996), which was restated in Cases 95-E-0673 et al., Opinion No. 96-27 (issued September 26, 1996). Our modification of the 1996 Settlement is the subject of an Article 78 proceeding that will be terminated upon approval of the pending Revised Settlement.

0 These decreases reduced the company's revenues by million

$ 23 annually.

0

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CASE 96-E-0898 to competition at a pace such that all retail customers would be allowed to choose their own supplier of energy and capacity by July 1, 2002. The signatories recognize that RG&E's ability to undertake the Program is contingent upon factors such as a functioning statewide energy and capacity market, which are not in the direct control of the company. They agree to modify the Program, if necessary, to account for such factors, and to address such matters in good faith.

The Revised Settlement would adopt a single-retailer model, which would allow a Load Serving Entity (LSE)'o purchase power on the open market and distribution access from RGGE. The LSE would market the power to customers'nd be responsible for scheduling deliveries.

The Program would be deployed in stages. In the Energy Only stage, which would commence on July 1, 1998,,customers (up to 10-'f the systemwide energy sales of 6,714 gWh) would be able to choose their own supplier of electric energy. The back-out rate during this stage is estimated to be approximately $ .019 per kNh.'n July 1, 1999, the Energy and Capacity stage would be introduced, which would permit customers using up to 20'. of the total energy to choose their own supplier of energy and capacity.

The back-out rate for this stage, $ .032 per kWh, is generally equal to the variable costs and specified fixed costs that RG&E incurs to produce power from its fossil and hydro generating units and from power purchased (other than from Kamine). On July 1 of the following two years, the Program would be expanded An LSE is analogous to the energy services company (ESCO) in a two-retailer model.

An individual customer could qualify as an LSE and procure energy to meet'its own needs.

The Revised Settlement calls for a back-out rate of $ .004 per kWh for retailing costs plus an allowance of $ .01905 per kNh as the value of energy (equivalent to the company's buy-back rate). Thus, RG&E would deduct a total of approximately

$ .02305 per kWh from bundled rates during the Energy Only stage.

CASE 96-E-0898 to include 30'. and 46'. of the energy, and on July 1, 2002 all of the company's energy. The schedule may be accelerated if the market price for power exceeds $ .032 per kWh on a persistent and sustained basis during the Energy and Capacity stage. Also, to the extent that energy consumption by end-use customers grows beyond a level of 6,714 gWh, the energy caps on eligibility will be increased by the amount of additional consumption.

As for corporate restructuring, RG&E would functionally divide existing operations into the following activity-based units: distribution unit (DISCO), generating unit (GENCO),

regulated load service entity (RLSE), and, at its option, a functionally separate holding company (HOLDCO). The company would also create a structurally separate unregulated load serving entity (ULSE). The ULSE would be an energy marketer and provider of other energy services both within and outside RG&E's DISCO service territory.

The DISCO would continue RG&E's transmission and service, which would be provided to the ULSE and the

'istribution RLSE pursuant to regulated tariffs. The GENCO would be responsible for operating RG&E's generating facilities. RG&E's GENCO would consist of a portfolio of nuclear and non-nuclear sources. The output from nuclear sources would be "dedicated" to regulated load, which is subject to change to conform with the outcome of any separate statewide proceeding on nuclear issues.

Output from non-nuclear sources (which would initially serve regulated load) would serve load on a competitively priced basis as customers migrate away from the RLSE. The RLSE would continue to serve as a provider of last resort (POLR) and provide bundled service under tariffs to customers who elect to continue receiving bundled service or who do not have a practicable alternative. In addition, RG&E would commit to working with Staff to develop an experimental alternative to provide POLR service on a competitive basis.

The Revised Settlement also provides for continuation of a program to assist low-income customers and a service quality program to maintain safe and reliable service. Further, the

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CASE 96-E-0898 Revised Settlement responds to our directive'o introduce retail access to farm and food processor customers on an expedited basis and affects three pending appeals of our prior decisions concerning RGKE.'inally, except as expressly provided otherwise, the Revised Settlement would supersede the 1996 Settlement.

Parties took a number of exceptions to the recommended decision and submitted comments on the Revised Settlement. In addition, we imposed conditions and changes in our November 26 Order before adopting the Revised Settlement. Inasmuch as issues were raised at various stages, this opinion will address the parties'xceptions as stated in their briefs on exceptions and briefs opposing exceptions (where relevant), any corresponding revisions made in the Revised Settlement, the parties'omments on these revisions, and the conditions as stated in our, November 26 Order.

/

REVENUE RE UIREMENT Strandable Costs For the five-year term of the April 8 Settlement (and the Revised Settlement), RGEE's tariff rates are presumed to include all prudently incurred investment in electric plant and electric regulatory assets (sunk costs) as of March 1, 1997.

Cases 96-E-0948 et al., Petition of Dair lea Coo erative Inc.,

Order Concerning Retail Access Proposals (issued February 25, 1997) .

RG&E will petition the court for permission to withdraw (1) as a party to the appeal in the Article 78 proceeding brought to challenge Opinion No. 96-12, Ener Association v. Public Service Commission (Sup. Ct. Albany Co. Index No. 5830-96);

(2) the company's pending Article 78 proceeding Rochester Gas and Electric Cor oration v. Public Service Commission (Sup.

Ct. Albany Co. Index No. 6616-96). (In the latter case, we rejected the 1996 Settlement's Kamine provisions); and (3) the company's pending Article 78 proceeding Rochester Gas and Electric Cor oration v. Public Service Commission (Sup. Ct.

Albany Co. Index No. 6531-97) brought to challenge our June 23, 1997 Order Establishing Retail Access Pilot Programs in Cases 96-E-0948 et al.

CASE 96-E-0898 Rates would be reduced without identifying cost savings. Thus, neither RG&E's rates for full service nor its rates for unbundled service would reflect any savings specifically identified as arising from the exclusion of strandable costs, but the company must manage its business to reduce costs in line with the revenue reductions in order to maintain its rate of return.

In addition, for those customers who choose to purchase power in the competitive market, there may be additional cost savings. These customers can avoid paying RG&E's back-out energy, capacity, and retailing rate of $ .032 per kWh and pay the market price for such power. They would reap the savings from lower priced market power and RG&E's stockholders would bear the loss if the company were unable to reduce its generating cost to the market price.

In the Revised Settlement, the signatories agreed to meet prior to July 1, 2000 (one year earlier than agreed to in the April 8 Settlement) to discuss future ratemaking treatment for sunk costs. In addition, at the end of the five-year term, there may be funds available to offset some of the sunk costs.

These funds could come from earnings in excess of the allowed rate of return on equity, unused funds set aside to match a potential liability for Kamine (both discussed more fully infra),

and, if we approve, the customers'hare of any gains on the sale of generating plants.

In the meantime, both the April 8 Settlement and the Revised Settlement provide that the costs of RG&E's nuclear generating facilities, Ginna Station and the company's 14'. share of Nine Mile Point 2, would be recovered in retail rates at least through 1999. RG&E further commits to participate in good-faith negotiations with Staff and with the other cotenants of Nine Mile Point 2 regarding future rate treatment of this facility. The signatories anticipate that similar treatment will be applied to Ginna Station.

For the non-nuclear generating facilities, both agreements address the "fixed" and "variable" portions of RG&E's fossil generating units, hydroelectric generating units, gas

~ e CASE 96-E-0898 turbines, and power purchase contracts (other than Kamine),

collectively known as the "To-Go Costs." In the Energy Only stage, the company would allow $ .01905 per kWh as the estimated market value for energy provided and would agree to sell to retailers at this rate. With an allowance of $ .004 per kWh for retailing costs, the allowance would be $ .02305 per kWh, which is greater than the estimated $ .013 per kWh in the April 8 Settlement. The variable portion of the To-Go Costs would be subject to the. market for electricity commencing July 1, 1998, the start of the Energy Only stage.

The fixed portion of such costs is the remainder of all To-Go Costs not defined as variable. The fixed portion comprises all capital costs incurred after February 28, 1997, 06M expenses, and property, payroll and other taxes. The fixed portion of the To-Go Costs are assumed to be recovered in full through the company's distribution access tariff until July 1, 1999, the start of the Energy and Capacity stage, after which recovery of the combined fixed and variable To-Go Costs and retailing costs, a total of $ .032 per kWh, would be subject to competition.

The recommended decision did not include specific estimates of strandable costs in the computation of RG&E's revenue requirement. According to the recommended decision, studies of RGSE's strandable costs are speculative at present because of the lack of a competitive market for electricity. The recommended decision also noted that the April 8 Settlement calls for rate reductions without specifying an estimate of strandable costs and allows for future consideration of such costs when some of the variables, such as the actual market price for electricity, will be known.

The recommended decision also pointed out that, except for nuclear power and Kamine purchases, the recovery of the remaining half of RGEE's To-Go Costs for generation would depend upon the company's ability to compete with outside sources of power. If the competitive prices are lower than RGSE's back-out rates, customers who purchase that power will automatically enjoy

0

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CASE 96-E-0898 the benefits and stockholders will bear the effects of the revenue loss.

Several parties except, insisting that strandable costs should be calculated now and that further rate reductions should be authorized by disallowing a portion of the strandable costs.

AARP renews its claim that strandable costs amount to

$ 800 million to $ 940 million, and AARP calls for an equal sharing of strandable costs between ratepayers and stockholders unless the financial integrity of RG&E is in jeopardy or legislation is passed prohibiting sharing.

AARP maintains the recommended decision is inconsistent with Opinion No. 96-12, which stated that strandable costs should be allocated through a "careful balancing of interests and expectations"; that "innovative means must be used to reduce the amount of strandable costs before they are considered for recovery"; and that these costs should be "recovered with an eye to lowering rates, [and] fostering economic development.

According to AARP, the recommended decision admits that the April 8 Settlement is not supported by substantial evidence of the amount of strandable costs because the signatories did not estimate them and they did not set forth how such costs will be estimated in the future.

CPB reiterates its estimated range of $ 1,200 million to

$ 1,500 million for strandable costs, but notes that a precise estimate of strandable costs is not needed to require immediate rate reductions of up to ten percent. CPB also claims that the recommended decision fails to recognize that the disparities between competitive electric prices and current rates will be at their zenith over the next several years, which should be taken advantage of to reduce rates. Finally, CPB responds to various criticisms of its strandable cost proposal by noting that (1) with respect to bond ratings, CPB would limit its strandable cost disallowance to maintain an equity ratio of at least 40%,

0 1 Cases 94-E-0952 er al., ~su ra Opini,on No. 96-12, mimeo pp. 89-90.

CASE 96-E-0898 and (2) with respect to sharing, CPB's proposals would allocate 30% of the total strandable costs to RG&E's shareholders.

RG&E and Staff support the recommended decision's conclusions with respect to strandable costs. They point out that the April 8 Settlement does not guarantee recovery of strandable costs; and note that approximately $ 155 million in cumulative rate reductions and forgone credits are called for in the April 8 Settlement without specifying how the company is to reduce its costs. The comparable figure for the Revised Settlement is $ 174.6 million.

Staff explains that the strandable cost studies submitted by CPB and AARP contain data and computational errors that render them unreliable as a basis for modifying the April 8 Settlement. An example of the errors contained in the studies that staff observed is AARP's reliance upon 1995 data, which does not provide an accurate representation of the costs of the Kamine purchased power contract. The omission of the Kamine contract costs alone, staff suggests, could increase strandable costs by over $ 101 million, and a double count of regulatory assets would decrease strandable costs by $ 210 million. On the other hand, Staff notes that the April 8 Settlement provides meaningful rate reductions, strong incentives to mitigate costs, including strandable costs, and powerful incentives for RG&E to manage its operations efficiently and aggressively.

RG&E argues that CPB's position is consistent with its advocacy of confiscating investors'unds in order to provide a short-term benefit today for customers, regardless of the long-term consequences. For example, RG&E maintains that it would suffer a bond downgrading were CPB's proposals to be implemented, and that its stock value would decline significantly. RG&E points to the stocks of utilities in Texas, which suffered a significant and immediate drop in prices when the Texas commission announced that those utilities would have to write off a portion of strandable costs. Likewise, the company cites a 50%

decline in the stock price and a bond downgrading of the parent company of Public Service Company of New Hampshire when that

CASE 96-E-0898 state's commission announced the utility would have to absorb some strandable costs.

In comments on the Revised Settlement, the Retail Council repeats the calls for a current estimation of stranded costs, in order to justify further rate relief.

We find reasonable the Revised Settlement's treatment of strandable costs. First, by including in the back-out rate a component for the fixed portion of the To-Go Costs, RG&E's customers have a meaningful opportunity to avoid the equivalent of some of RG&E' strandable costs if they can purchase electric power on the market at a price below the back-out rate. In addition, the Revised Settlement calls for rate reductions and the relinquishment of other benefits without specifying how RG&E is to achieve the complementary savings needed so that it can maintain its overall rate of return. The Revised Settlement also requires the parties to meet prior to July 1, 2000 to discuss the future ratemaking treatment of RG&E's sunk costs. Finally, the exceptions calling for an immediate estimate of strandable costs

~ are denied because the estimates proffered on the record contain data and computational errors.

Kamine Cost Recover RG&E is involved in litigation pertaining to its power purchase from facilities 'owned by Kamine. The April 8 Settlement's Kamine recovery provisions permit RG&E to set aside

$ 33.2 million ($ 32.9 million in the Revised Settlement) over the five-year term to cover costs related to resolution of the litigation. Assuming a settlement of the Kamine litigation, RG&E would be allowed to continue after July 1, 2002 to reflect in rates $ 10.6 million per year ($ 10.5 million in the Revised Settlement) until the cost of that settlement is recovered.

However, if no settlement were reached and RG&E were obligated to pay, RG&E would be permitted to recover from ratepayers up to seven-eights of the cost of the maximum output of Kamine during the five-year term, less amounts already accrued and any securitization benefits forthcoming. Also the

CASE 96-E-0898

$ 10.6 million ($ 10.5 million under the Revised. Settlement) automatic recovery would end at the termination of the five-year term. The unrecovered balance, if any, would be deferred for future recovery, and we would determine the timing of future recovery.

The recommended decision supports the April 8 Settlement's treatment of the Kamine dispute. The recommended decision also pointed out that, in the absence of a settlement of that dispute, there are limits on the immediate rate impacts of Kamine cost recovery, and recovery of Kamine costs on a long term basis may be subject to the forces of a competitive market for electricity. For these reasons, the Judge recommended approval of the Kamine cost recovery provisions.

CPB excepts, contending footnote 31 of the April 8 Settlement limits the company to recovery of prudent and verifiable costs, and that any court ordered damage payments could be, but should not be, recovered in rates. In addition, CPB notes that, if the Kamine dispute is settled, RG&E would be entitled to 100% recovery of strandable Kamine costs. CPB requests that this provision be clarified to assure recovery only if the total cost of the settlement is less than the Kamine contract price.

The Attorney General argues that there should be no automatic recovery of Kamine costs, and that we should insist on a prudence review of all payments to Kamine.

RG&E responds that it has steadfastly pursued all available avenues to relieve its customers of the burden they would bear if the Kamine contract were enforced. In the process, it states, the company has saved its customers tens of millions of dollars. It criticizes CPB's suggestion that it should continue to devote its resources to avoiding excessive Kamine power costs, while bearing the entire risk of damages, as "the ultimate form of cynical, one-way-street regulation." With respect to CPB's second point, RG&E does not anticipate settling the contractual claim for an amount greater than that payable under the contract ~

CASE 96-E-0898 At our October 8, 1997 session, we noted our discretion to reduce rates during the five-year term if it becomes clear that the Kamine cost recovery clause would recover more funds than needed to resolve the contract dispute. The Revised Settlement expressly acknowledges that discretion. In comments on the Revised Settlement, RGEE, Staff, CPB, and Multiple Intervenors maintain this flow-through provision is reasonable.

Further, as alluded to above, footnote 31 states specifically

" [n] o cost referenced in this [Revised] Settlement may be considered for recovery, true-up or deferral unless it is prudent and verifiable."

Return on E uit Under the April 8 Settlement, if RGEE achieves a return on common equity for its regulated operations in excess of 11.80'.

for the entire five-year term, the company would be entitled to retain 50'f the amount in excess of 11.80'. and to use the remaining 50% to write down accumulated deferrals or sunk costs.

The recommended decision found these provisions reasonable. It noted that CPB's proposed 10.2% return on equity did not include a stayout premium, which at the time was computed to be 1.44%

based on the spread between the June 1997 treasury bills and May 2002 treasury bonds. The recommended decision noted that adding a stayout premium to CPB's return would increase it to 11.64'.,

close to the April 8 Settlement's sharing threshold.

CPB, the Attorney General, and the Retail Council take exceptions. CPB claims that its proposed 10.2% return on equity should be used as the sharing threshold. CPB's 10.2; equity return was based on discounted cash flow, capital asset pricing model, comparable earnings, and risk premium methods. CPB also contends the recommended decision miscalculated the stayout premium. Citing the recommended decision in the Generic Finance Proceeding (Case 91-G-0509), CPB claims the premium should be based on one-half of the spread, which it says would reduce the

~ recommended decision's figure from 11.64. to 10.92%

o CASE 96-E-0898 CPB also renews its call for different sharing of earnings over the threshold, with 50'. to write down strandable costs, 25% for the stockholders and 25% for the ratepayers for earnings in excess of 10.2'. It proposes this computation be performed annually instead of for five years.

The Attorney General supports continuation of the 11.2%

sharing threshold in the 1996 Settlement, contending RG&E will assume little additional risk as a result of the introduction of competition.

The Retail Council calls for the flow through of all excess earnings to ratepayers. According to it, the April 8 Settlement gives 100% of excess earnings to stockholders because the portion that would be used for write downs is simply a return of capital to shareholders. The Retail Council argues we should reject the concept of a "regulatory compact," which it sees as guaranteeing shareholder recovery of all past investments.

RG&E responds that CPB's proposed 10.2-. return on equity is about 130 basis points below the average allowed returns for electric utilities in the fourth'quarter of 1996 and first quarter of 1997. Also RG&E observes that CPB's implied spread over bond yields is about 160 basis points, which is less than that employed in the Generic Finance Proceeding, where a 350 basis point risk premium above the utilities'ond yields was generally employed and 250 basis points was considered the low-end of the range. RG&E conducted its own studies and concludes that its current cost of equity is between 11.95% and 12.20-..

Moreover, RG&E points out that CPB's strandable cost proposal would weaken the company's financial position by lowering its equity ratio and increasing its risk, which could lead to a decline in its bond ratings. RG&E suggests its equity ratio would be reduced from the existing 49'-. to 36.3 . if CPB's total rate base disallowances were adopted.

Finally, RG&E observes that CPB's proposed allocation of excess earnings on an annual basis would be unfairly asymmetrical because excess earnings in good years would be shared with the ratepayers but earnings shortfalls in bad years

CASE 96-E-0898 would be completely absorbed by the stockholders. RGGE suggests it would never earn the target return if this change is adopted.

At our October 8, 1997 session, we suggested that the 11.8. return on equity sharing threshold was too high, especially given that the company had recently earned excess profits, which it would retain fully under the April 8 Settlement, and that the provisions related to deferrals could result in the need for rate increases at the end of the five-year term.

RGEE, Staff, and Multiple Intervenors maintain that the Revised Settlement addresses our concerns. They cite the Revised Settlement's provision that imputes 150 basis points of the 1997 rate year overearnings to the 11.8'. return on equity measurements over the five-year term. This would effectively reduce the sharing cap to 11.5%

The excess earnings allocation would also be reallocated such that (1) half of the excess would be used to write down deferred costs accumulated during the term, and any portion of this half remaining after deferrals are written down would be retained by the company as earnings; and (2) with regard to the other half of any excess earnings, the first $ 800,000 would be used to reduce rates for certain large industrial and commercial customer classes. The remainder would be used to write down accumulated deferrals or sunk costs, and to the extent that any part of this latter half remains after writing down such deferrals and sunk costs, we would determine its disposition.

Multiple Intervenors states that the $ 800,000 allocation for large customers is intended to correct for the fact that a disproportionate share of the SBC reallocation was directed to small customers. Staff asserts that the Revised Settlement reduces the likelihood of rate increases at the end of the five-year term.

CPB reiterates its claim that the earnings sharing trigger should be 10.2% and notes that, since the time its direct testimony was submitted, interest rates on 30-year treasury bonds have declined by about 60 basis points, which it claims would justify a lower equity return.

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CASE 96-E-0898 The Retail Council reiterates that the treatment of excess earnings is unacceptable because the reallocation of excess earnings benefits only shareholders or large customers.

The 11.5'-. sharing threshold falls within the range of equity returns presented in this case: from 10'; by CPB to 12.2%

by RGEE. Although a cursory view would lead to the conclusion that the 11.5% is on the high side, a closer examination will show the 11.5% effective threshold is reasonable. First, it must be remembered that we recently established an 11.2% sharing threshold in the company's last case'hat covers the three-year period ending June 30, 1999. If earnings exceed that, over the entire three-year period, they were to be shared equally between shareholders and customers, with the customers'hare being used to write down assets.

Second, the Revised Settlement would extend the stayout period by two years, and would increase the company's business risk by removing its monopoly status and subjecting it to competition. In addition, the Revised Settlement's revenue reductions place more risk on the shareholders. The combination of the two-year extension, increased business risk, and reduced revenues more than justify the increase in the threshold for sharing.

Third, the Revised Settlement allocates more of any excess earnings to write down deferred costs or sunk costs.

We do have one reservation about the provision that

$ 800,000 of excess earnings will be used to reduce rates for certain large customer classes. We conclude that large customers will already receive substantial benefits under other provisions of the Revised Settlement; thus, there is no need for this unique additional benefit. Accordingly, we adopt this term of the Revised Settlement on the condition that the first sentence of Paragraph 10(b) is removed, and the words "...of this amount..."

are deleted from the second sentence.

0 1 Cases 95-5-0673 et al., ~su za, Opinion No. 96-27, mimeo pp. 7, 21, and 27.

CASE 96-E-0898 Gain on Sale of Generatin Plants The April 8 Settlement contains no separate provisions for the disposition of gains, if any, on the sale of electric generating plants. Rather, any gains would be included in the return on equity and shared if that return exceeds certain thresholds.

At our October 8, 1997 session, we stated our belief that the April 8 Settlement was unbalanced with respect- to its treatment of any gain on the sale of generating assets. We also sought a provision that would encourage RG&E to sell generating plants. The Revised Settlement contains provisions that increase the customers'hare of gains realized on such sales, and provide an incentive to encourage prompt divestiture of generation.

Staff and RGSE observe that the Revised Settlement generally provides for a 20%/80% split between shareholders and ratepayers of any net gains over the five-year term and that customers will benefit from any such gain on the sale of generating assets regardless of the company's level of equity return. The split may change to 40: shareholder and 60:

ratepayer on the first $ 20 million of net gain in the first three years of the Revised Settlement. These parties maintain this additional allocation to the shareholder is a sufficient incentive to encourage prompt divestiture.

CPB replies that a divestiture incentive is unwarranted because RGEE's rates are among the highest in the nation and any rate reduction resulting from the flow through of a net gain to ratepayers would make the company's rates more competitive, produce additional sales, and increase shareholders'arnings.

We find that the Revised Settlement's treatment of gains on the sale of. generating assets is reasonable because it ensures ratepayers will receive a substantial portion of any net gains on the sale of plants that were acquired on behalf of and financially supported by the ratepayers. In addition, we adopt the incentive for RG&E to divest generating assets promptly because divestiture will hasten the development of a competitive power market, the benefits of which will redound to ratepayers,

0 O.

CASE 96-E-0898 consistent with Opinion No. 96-12, and, ensure

~ ~

~ a fair quantification of strandable costs.' ~

SBC Fundin The recommended decision supported the April 8 Settlement provisions related to the SBC charge, i.e., to flow through to ratepayers all mandated increases and decreases in spending for SBC programs, which include research and development, energy efficiency, low income, and environmental protection. The level of spending already reflected in rates had been established in the 1996 Settlement, which set rates for the three-year period ending June 30, 1999.

AARP, CPB, and PII except to the recommended decision's conclusion not to modify the April 8 Settlement provisions related to the SBC charge. They seek specific spending levels.

For example, CPB requests that the 1995 spending levels be maintained throughout the five-year term, while PII supports expenditures derived from a $ .0015 per kWh rate charged to all energy sales.

Staff points out that the Revised Settlement would build specific SBC expenditures into the rates, the cost of which would be greater than the total that would be spent if the SBC were set at $ .001 per kWh for three years. However, Staff further explains that the expenditures would be spread over five years because most of the expenditures relate to ongoing energy savings and incentive payments that the company is obligated to pay for under its DSM bidding program.

PII opposes the SBC modifications contained in the Revised Settlement because it would reduce expenditures for these programs by nearly half from $ 7.8 million in 1995 to an average of $ 4.78 million beginning in 1998. PII sets forth several examples of specific spending reductions that would result and states that the cuts are inconsistent with the clearly expressed

~

Cases 94-E-0952 et al., ~sn ra, Opinion No. 96-12, mimeo p. 60.

o CASE 96-E-0898 intention to preserve these programs at least during the transition period.'urthermore, PII calls for the elimination of the Large Customer Credit Program, which allows industrial customers to elect not to participate in the DSM program and thereby receive a

$ .0003 per kWh credit. Arguing that RG&E will no longer offer DSM programs, PII believes the credit should be terminated.

Since the SBC funding allowance contained in the Revised Settlement meets our stated goal, we find these provisions acceptable. With respect to PII's position that the Large Customer Credit Program be eliminated, we note that the credit is subject to recalculation in the event that RG&E's spending on DSM programs changes materially.'ther Pro osals Several parties support other changes to parts of the Revised Settlement that are unchanged from the April 8 Settlement .

PII proposes a "price cap plus" mechanism for RG&E's revenue requirement, which is a combined revenue cap and price cap. Under price cap plus, the initial year's revenue cap would be set using traditional cost of service regulation and in subsequent years, the revenue cap would be adjusted for three factors: inflation, productivity, and growth. In addition, PII's price cap plus includes a revenue cap true-up.

PII's price cap plus proposal is not acceptable because it could lead to increased rates if productivity is not sufficient to offset inflation and, in any event, would require annual regulatory oversight of the true-up mechanism. In effect, this proposal runs counter to our objective, which is to rely more on competition and less on regulation.

Cases 94-E-0952 et al., ~sn ra Opini,on No. 96-12, mimeo p. 61.

Cases 95-E-0673 and 95-G-0674, Rochester Gas and Electric Cor oration - DSM, Opinion No. 95-20 (issued December 27, 1995), mimeo Appendix p. 9.

CASE 96-E-0898 CPB proposes to reduce the revenue requirement by

$ 235,000 to reflect reforms in Workers'ompensation Law. CPB's adjustment is subsumed in the overall revenue reductions required by this order and is rejected because this change is but one of many changes expected in the future that will affect earnings subject to the sharing threshold.

CPB also proposes we modify the provision that would permit RG&E to defer the costs of operation and maintenance related to inflation in excess of 4.0'%PB states we should simultaneously require the return on equity to drop below 9.

before deferral is permitted. The CPB's modification is asymmetrical, i. e., RG&E would have to bear 100% of the excess inflation risk as the return on equity drops from 11.5. to 9.0%,

but the company would only retain a small portion of th'e upside benefit above the 11.5'. equity return because of other equity return sharing mechanism we adopted ~su ra. Consequently, this proposal is not adopted.

AARP excepts to the property tax incentive, which would

~ allow RG&E to defer for future recovery or pass back to ratepayers 50. of any property tax expense increase or decrease in comparison to the base level, i.e., the actual tax expenditures during the 12 months ended February 28, 1997 less taxes related to any assets sold after June 30, 1997. The other 50; would be reflected in the rate of return computations. AARP characterizes the provision as a bribe to get the company to lobby for tax reductions.

AARP's exception is rejected because the provision will encourage RG&E to pursue reductions in the cost of property taxes, or failing that, because the provision will spare customers half of any 'increase in such costs.

We note that certain provisions of the Revised Settlement (i.e., ($ 8, 11-17, 24 (with respect to shut-down costs), and $ 30) provide for deferral and recovery without requiring further petition to or approval by us. Without altering the intent of these terms, we adopt them on the condition that a formal petition will be filed with us prior to

CASE 96-E-0898 establishing deferrals or commencing any recovery during the five-year term.

Finally, we also observe that the Revised Settlement refers to possible Statewide resolution of the future ratemaking and ownership of nuclear facilities. Paragraph 23(d) states that "no change in the trea'tment of RG&E's nuclear facilities shall be implemented until at least January 1, 2000." The January 1, 2000 date might be construed as precluding a sale or transfer, through an auction or otherwise, of the company's interest in nuclear facilities until at least the year 2000 and, thus, could conflict with subsequent action on the August 1997 Staff Report on Nuclear Generation. We adopt this paragraph on the condition that $ 23(d) is modified to read as follows: "no change in the treatment of RG&E's nuclear facilities shall be implemented prior to the Commission's resolution of the August 1997 Staff Report on Nuclear Generation." l REVENUE ALLOCATION AND RATE DESIGN Pursuant to the April 8 Settlement, revenue decreases would generally be allocated to RG&E's service classes based on their responsibility for generation costs. As a result, the large industrial customers would receive rate reductions of 10-:

to achieve an average rate of $ .056 per kWh; large commercial customers would receive rate reductions of 8% to achieve an average rate of $ .068 per kWh; other industrial and commercial customers would receive rate reductions of 3.7'. to achieve an average rate of $ .08 per kWh; and residential and small business customers would receive rate reductions averaging 2.5%, with rates varying depending on usage and classification. Several I

specific rate design changes were also set foith, including among others a proposed annual $ 1.50 increase in the monthly customer charge for residential and small business customers.

The Judge recommended the allocation favoring the large industrial customers because (1) as Multiple Intervenors had observed, RG&E's residential, commercial, and industrial rates were in 1995, respectively, 34.6'-., 32.1'., and 61.5'. above

e CASE 96-E-0898 corresponding national average rates, which justifies proportionately greater reductions for the industrial class, and (2) the allocation of revenues and individual rate changes would move RG&E's rates closer to the marginal costs, which is economically efficient and makes sense in an increasingly competitive electricity market.

With respect to the increases in the monthly charge, the recommended decision concluded that the ultimate customer charge of $ 17.50 is justified by the fact that the comparable marginal cost is about $ 20.'PB excepts, arguing greater attention can and should be paid to rates charged for electricity around the country. It provides extensive legal arguments in support of this proposition. Assuming we were to adopt this approach, CPB concludes we should adopt equal across-the-board percentage decreases for all classes.

AARP objects to residential customers receiving smaller decreases and argues substantial joint and common costs should not be allocated to customer costs so more of them can be covered in rates paid by non-residential users.

PULP contends that we have no statutory authority to favor larger industrial customers over other customers. PULP also asserts it is irrational and illegal to favor this one customer class over others as there assertedly has been no showing the industrial customers need such a decrease.

PII claims that the customer charge should not be increased from the current $ 10 monthly charge to $ 17.50 over the five years because the marginal cost study was calculated three years ago and was not submitted in this case, and because the effect of such a charge would increase bills for 43; of the residential class even with an overall revenue decrease. In addition, PII is concerned that the decrease to energy rates would carry negative environmental consequences. According to

~

Exhibits 50 and 51, Tr. 1,450-1,459.

0 e

CASE 96-E-0898 PII, the increase in sales would be accompanied by an increase in pollution.

0 Staff, RG&E, and Multiple Intervenors support the recommended decision's findings with respect to revenue allocation and rate design. They note that rates must be realigned to promote economic development and industrial competitiveness. For example, Staff reasons that industrial customers who may be considering whether to expand in Rochester or to relocate and expand elsewhere might be induced by lower rates to remain in the RG&E service territory. The resulting expansion of facilities and creation of new jobs, Staff states, would have positive economic impacts for the ratepayers and for the local community.

These parties further assert that marginal costs are a rational basis upon which to set rates, and large customers are contributing revenues disproportionately in excess of their marginal costs of service relative to residential and other small customers.

0 With respect to the annual $ 1.50 increase in the monthly customer charges over the term of the April 8 Settlement, Staff and RG&E readily concede that about 43. of the residential class would experience bill increases, but they note that the current customer charge is well below the $ 20 marginal costs, and energy prices overall are well above marginal costs, resulting in improper price signals upon which customers base their decisions.

RG&E also notes that its low-income customers are just as likely to consume more than the average level of energy as they are to consume less than average. Therefore, RG&E believes that the increase in the customer charge will not fall disproportionately on low-income customers.

At our October 8, 1997 session, we did not question the rate reductions for large industrial customers but expressed interest in providing larger rate decreases to residential and other small customers. In addition, we asked the parties to reconsider the customer impact of five annual increases of $ 1.50

CASE 96-E-0898 in the monthly customer charge, but acknowledged that larger rate reductions for small customer classes might allay this concern.

RG&E, Staff, and Multiple Intervenors note that the Revised Settlement would give all service classifications at least a five percent reduction. They explain that through reallocation of the SBC funding and the use of Gross Receipts Tax (GRT) reductions the overall revenue decrease will change from

$ 27.1 million (4.1%) to $ 40.6 million (6.1%). Multiple Intervenors points out that a disproportionate share of the SBC reallocation (approximately $ 800,000) was directed to the residential and small commercial customers. Staf f states that every class will receive the benefits of the GRT reductions.

The Attorney General, CPB, Retail Council, PII, PULP, and Mr. Straka claim that even further reductions are warranted for the residential and small commercial classes. PULP maintains the allocation of the revenue decrease is not balanced and there is no support for the proposition that the industrial customers are paying a subsidy under current rates. PII, CPB, and Mr. Straka also observe that the planned rate reductions for residential and small commercial customers are back-end loaded, i.e., by year four these customers will receive a 2.62: reduction and then in year five jump to the full decrease of about 5%. On the other hand, PII states that the largest industrial customers will receive 11.2% decreases, or most of their reductions, by year four. The Attorney General adds that the flow through of the GRT reductions would cost RG&E nothing and the rates contained in the Revised Settlement would still be uncompetitive.

Mr. Owens, Mr. Straka, and CPB claim that 36% of residential customers would still receive a bill increase under the Revised Settlement, which they state is unacceptable.

Mr. Owens recommends that the monthly charge increase be halved to $ .75 per year, while CPB would eliminate any increase in this rate.

As CPB argues, we can consider a number of factors in determining a proper level of rates. An important consideration is the competitiveness of RG&E's rates with those of other areas

CASE 96-E-0898 in the nation. As large industrial customers have the widest array of competitive alternatives, and are very sensitive to the level of rates, their rates should be aligned as closely as possible to comparative alternatives. Under the April 8 Settlement, the large industrial rates would have been ultimately reduced to $ .056 per kWh on average, which approaches the industrial national average price for electricity of approximately $ . 046 per kWh. Under the Revised Settlement, the industrial rates would be $ .055 per kWh.

However, we find that the residential and small commercial customers'ould not receive sufficient revenue, reductions under the Revised Agreement. We will increase the revenue reductions for those customers from approximately 5.0% to 7.5. in the final year of the term. This change requires a corresponding adjustment to the Revised Settlement's cumulative reduction from $ 51.1 million to $ 64.6 million for July 1, 2001.

The Revised Settlement provides that, beginning July 1, 1999 and continuing through June 30, 2002, Incremental Manufacturing Load shall be served at an average rate of $ .059 per kWh. We adopt this term on the condition that the average rate instead is $ .045 per kWh so that it approximates the national average rate.

With respect to the increase in the residential and small commercial customer charges, we observe that the increases are based on comparisons of rates and marginal costs, which suggest energy rates should be reduced and that customer charges may be increased without exceeding cost. This realignment is consistent with the coming competitive market for electricity and retailing services. We note that the further rate reductions approved for the residential customers will reduce to 27% the percentage of customers who will receive bill increases on average. It should also be noted that the yearly $ 1.50 increase Residential and other small users are identified in the Revised Settlement schedules by their lower voltage class as "pri-pri," "sec-sec," and "pri-sec."

CASE 96-E-0898 in the monthly customer charge had already been approved for the three years ending June 30, 1999 in the company's last rate proceeding. The Revised Settlement reasonably extends the increase for three more years.

Lastly, PII's opposition to a decrease in energy charges, because of potential negative environmental impacts, is rejected. Even with the change, energy rates will remain above marginal costs and PII has offered no evidence that environmental impacts are so substantial as to exceed the environmental thresholds discussed infra.

PROGRAM Sin le Retailer Model'HE The single retailer model is the foundation upon which the entire Program is built. According to the April 8 Settlement, a single retailer, or LSE, would purchase power on the open market and distribution access from RG&E. The LSE would market the power to customers and would be responsible for scheduling deliveries based on load shapes or real-time meter data. Also, for the first three years of the Program, RG&E would offer billing services to the LSEs so that they may commence operations without having to wait for development of their own billing systems. RG&E would retain ownership of the meters.

Numerous objections were raised. The recommended decision considered many of these but did not address WEPCO's security deposit concerns because the issue would be the subject of an operating agreement.

On exception, WEPCO asserts that the single retailer model would preclude all but the largest LSEs from entering the market because it fears RGEE will require LSEs to post security deposits, and to participate in service restoration efforts and The issue of the applicability of the Home Energy Fair Practices Act to single retailers has been considered in another Commission order. Cases 94-E-0952 and 96-E-0898,

~su za, Order Regarding Regulatory Regime for Single Retailer Model (issued December 24, 1997).

CASE 96-E-0898 power quality matters. In lieu of a security deposit, WEPCO proposes a "lock box" approach, i.e., a shared bank account between the LSE and RGEE.

RG&E responds that these issues should be part of the discussion leading up to an operating agreement because there are less costly approaches than the "lock box" approach such as individual guarantees, letters of credit, and escrow arrangements. With respect to participatio'n in service restoration and power quality issues of WEPCO, RG&E argues that these customer contacts are an ongoing element of being a retailer.

We agree with the Judge that these issues should be considered in connection with an operating agreement especially in view of our recent opinion to require utilities to file tariffs covering various operating procedures.'ntil the parties have an opportunity to address both the proposed tariffs and operating agreements, these issues are not ripe for decision.

~ Im lementation Schedule As noted above, retail competition would be introduced in stages over five years, beginning with a one-year Energy Only stage and then a multi-year Energy and Capacity stage. The recommended decision supported this approach to give RGRE sufficient time to overcome problems relating to its nuclear plants and load pockets.

A number of parties except. CPB urges full retail access no later than one year after the implementation of the independent system operator (ISO). The Attorney General believes that an accelerated schedule is needed because the five-year term would be too restrictive, precluding chances to take advantage of arising opportunities. In the meantime, the Attorney General urges that the 1996 Settlement be left in effect, the company be

~ ~ 'ase 94-E-0952, In the Matter Re ardin Electric Service, 1997), mimeo p. 34.

of Com etitive 0 ortunities Opinion No. 97-5 (issued May 19,

CASE 96-E-0898 required to solve its nuclear and load pocket problems, and retail access be implemented shortly after competition becomes technically feasible.

IPPNY/Enron and WEPCO assert that RGEE's problems are not technical but rather financial. They believe that the problems can be addressed now and the Program can be accelerated.

According to IPPNY/Enron, the April 8 and Revised Settlements themselves support its statement that there are no technical impediments because they provide for an accelerated retail access schedule if the market price for power is above RG&E's back-out rate of $ .032 per kWh. Several parties point to the more rapid introduction of retail access required in other states as justification for a quicker timetable for RG&E.

At our October 8, 1997 session, we urged the parties to consider and explore ways to speed up the introduction of retail access. We noted that the April 8 Settlement calls for an accelerated schedule only if a statewide resolution of nuclear generation issues permitted an earlier placement of such power on the market, or if market prices for power exceeded $ .032 per kWh on a persistent and sustained basis. The Revised Settlement contains a new provision, which establishes a process whereby the parties will meet prior to July 1, 2000 to assess the feasibility of accelerating retail access.'taff believes that this new process is preferable to renegotiating a number of important provisions related to the retail access schedule.

CPB, the Attorney General, WEPCO, the Retail Council, and Mr. Straka disagree. They assert that the retail access schedule is protracted and will cause RGEE to fall behind other upstate utilities such as NYSEG and Niagara Mohawk, which have proposals under which all customers would be eligible for retail access by the end of 1999. WEPCO contends that RG&E's nuclear generation is not a reason to delay implementation of retail access because we indicated that the State should move toward

~ retail competition with due speed even without a statewide

CASE 96-E-0898 solution to nuclear issues.'PB wants full retail access for RGRE by 1999 or within 12 months of the implementation of the ISO.

The Attorney General seeks clarification of the modified language. It notes that the provision to consider accelerating retail access could be read as providing RG8E with veto power concerning any change in the schedule for implementation of competition, and the Attorney General would rather have us grant other parties the right to submit a recommendation without RGaE's concurrence. In addition, the Attorney General understands that the "risk" that must be addressed relates to RGEE's profits, which it claims should be explicitly stated.'e recognize that RGSE is unique among the state utilities in that more than half its generation is nuclear fueled, and therefore believe that a phase-in of retail access should be long enough to give RGEE sufficient time to address this fact. However, we find the five-year phase-in period for retail access to be excessive, and conclude that four years should suffice. Consequently, we will require full implementation for the Program by July 1, 2001, which is one year earlier than provided for in the Revised Settlement.

The last sentence of $ 52 of the Revised Settlement (which is set forth in the preceding footnote) provides for a Cases 94-E-0982 et al., ~su ta, Opinion No. 96-12, mimeo p. 88.

The relevant portion of f52 of the Revised Settlement is as follows:

The parties further agree that, prior to July 1, 2000, they shall meet to review the progress of retail access under the Program and shall consider and recommend to the Commission, as appropriate, any changes to the implementation schedule that are determined to be necessary; provided, however, that no such changes shall be

~ recommended unless they are revenue neutral and do not materially increase the level of risk borne by the Company.

CASE 96-E-0898 possible increase in the pace of retail access implementation if certain conditions are met. Xn light of our modification of the retail access schedule, the last sentence is unnecessary, and therefore, is not adopted.

Not only will full retail access be achieved one year earlier, but also the effective percentage of retail access available for the non-contract customers should be greater than identified in the Revised Settlement. This is because a large part of RG&E's load is under contract and these contract customers cannot participate in the Program until their contracts expire. Consequently, a greater proportion of the non-contract customers will be able to switch to the Program in the early years.

Deliver Rates The April 8 Settlement includes rates for delivery during both stages of the Program. During the Energy Only stage, the distribution access rate would equal the average rate for bundled retail service less the per-unit retailing cost and the per-unit energy-related cost of all non-nuclear energy sources, estimated to be at least $ .013 per kWh.

ln the Energy and Capacity stage, the rates charged to LSEs would equal, on average, the rates for bundled retail service less $ .032 per kWh, which includes retailing cost of

$ .004 per kWh and the per-unit fixed and variable To-Go Costs of non-nuclear energy sources, exclusive of a portion of property taxes. Twenty percent of the property tax component of the per-unit non-nuclear To-Go Costs would be deducted from bundled rates upon commencement of the Energy and Capacity stage and an additional 20% commencing every 12 months thereafter during the term of the April 8 Settlement. The actual distribution access rates would be filed as tariff changes.

Pursuant to the April 8 Settlement, when the Program is opened to all retail customers on July 1, 2002, the company would be authorized to modify its distribution access rates, so as to hold constant the degree to which its To-Go Costs are at

CASE 96-E-0898 risk for recovery through the market. The signatories to the April 8 Settlement agree to meet before July 1, 2001 to discuss the future of these ratemaking plans'he recommended decision found the average rate, reasonable and rejected calls for a higher back-out rate and periodic updating. However, the recommended decision found the retailing costs for residential customers is greater than the average of $ .004 per kWh. Thus, it would require RGEE to estimate and reflect the actual retailing costs in each class's back-out rate when it is filed.

AARP and WEPCO except, arguing the back-out rate is too low and will inhibit competition. These parties ask us to order ROTE to reflect the proper retailing costs in each class's back-out rate. In addition, WEPCO questions the justification for an Energy Only stage because the $ .013 per kWh is so low that it is unlikely that LSEs or customers would participate in this stage.

WEPCO supports its argument by pointing to the experience in Orange and Rockland Utilities'ilot program, which contained an energy-only format. According to WEPCO, that program did not produce sufficient savings to warrant participation by small customers. WEPCO requests that the initial back-out rate be set at $ .032 per kWh with appropriate updating each year.

WEPCO also argues that a fixed back-out rate for a period of two to five years in a highly uncertain environment would entail considerable risks. If the fixed back-out rate understates the market price of energy and capacity, WEPCO'laims that a robust competitive retail market will not develop. When entering into a highly uncertain situation, WEPCO advises, the best course of action is to build in checkpoints such as an annual reset of the back-out rate.

RG&E agrees with WEPCO that the Energy Only stage has limited value, but observes that until the necessary supporting mechanisms and structures for a capacity market are in place, capacity charges will be incurred by RG&E, which it must recover.

RG&E opposes an annual update of the $ .032 per kWh back-out rate because (1) a fixed rate will provide competitors with a stable

CASE 96-E-0898 target against which to compete and (2) a fixed rate will limit the risk faced by the company from customer migration to retail access. Periodic updating, RGEE notes, would subject it to a variable level of risk and therefore upset the balance struck by the signatories to the April 8 Settlement.

Staff maintains that the April 8 Settlement does not preclude update of the back-out rate if circumstances warrant such action, but agrees that at this time the overriding concern is to create a stable and certain rate for LSEs.

With respect to the appropriate level of retailing costs to include in the back-out rate, Staff and RGEE oppose the recommended decision's proposal to compute each class's retailing costs. Staff observes that such a proposal would add an unwarranted level of complexity in the tariffs. RGEE maintains that even if the $ .004 per kWh retailing cost is less than actual for the residential customer class, it does not follow that the overall back-out rate is understated given that residential customers receive substantial allocations of NYPA hydropower at low rates. The net effect, according to the company, is that the combined cost of energy, capacity, and retailing is approximately equal over all classes.

At our October 8, 1997 session, we expressed our desire to have the back-out rate during the Energy Only stage approximate market energy prices and to require the company to sell energy at that price.

According to RGEE, Staff, and Joint Supporters, the Revised Settlement's back-out rate of $ .02305 per kWh (inclusive of $ .004 per kWh retailing costs) is designed to address our concern that the earlier estimated $ .013 per kWh back-out rate was too low to encourage competition. Staff observes that the significant increase in the back-out rate also automatically reduces the delivery rate charged to LSEs. The proponents further note that RGSE is now committed to giving LSEs the option of purchasing energy from RG&E at $ .01905 per kWh, the energy portion of the back-out rate. CPB agrees that this rate appears reasonable.

CASE 96-E-0898 WEPCO acknowledges that the new rate is an improvement, but maintains it still falls short of WEPCO's estimate of approximately $ .028 per kWh for the wholesale cost of purchasing power. Consequently, it believes that LSEs will be forced to purchase power from RG&E. WEPCO objects to the use of the

$ .004 per kWh company-wide average cost of retailing, reiterating its claim that the actual retailing costs for small customers is higher. It cites our recent decision in the Dairylea Case'n which a $ .01 per kWh adder was adopted for small customers.

We conclude that the Revised Settlement's back-out rate during the Energy Only stage is acceptable. The Energy Only stage is expected to be implemented before the development of a mature statewide energy and capacity market. In addition, RGEE should gain valuable experience during the Energy Only stage because it will provide a controllable and workable environment in which to prepare for the remaining phase of retail access. In sum, we are unpersuaded by WEPCO's objections to the Energy Only stage.

0 With respect to the Energy and Capacity stage, the use of the $ .032 per kWh fixed back-out rate should contribute to a stable competitive market because the rate is based on RGEE's costs and the lack of periodic updating will provide potential competitors with predictable competitive target back-out and distribution rates--significant inputs to their price.

One item still concerns us, however. The Revised Settlement identifies a contestable rate of $ .032 per kWh, but does not indicate whether GRT is considered in the derivation of that amount. We adopt this rate subject to the clarification that .the $ .032 rate includes the impact of GRT.

Finally, the recommended decision's suggestion to reflect actual retailing costs in each service classification is rejected because it would add a layer of unnecessary complexity.

This complexity would arise not only from the allocation of 0 Case 96-E-0948, ~su ra Order,Establishing Retail Access Pilot Program, pp. 13-16.

CASE 96-E-0898 retailing costs themselves, 'but also from consideration of other class specific changes that parties would no doubt raise as 0 further refinements.

Other Retail Access issues PULP's claims that we lack the authority (1) to approve general retail wheeling for all customer classes, and (2) to deregulate new generation providers. PULP is essentially repeating the arguments it raised in an Article 78 proceeding challenging Opinion No. 96-12. The Supreme Court'as rejected PULP's claims, and they are rejected here based on the rationale set forth in the Con Edison rate/restructuring decision.'YPA's and RGEE's exceptions to the recommended decision's refusal to consider a separate Economic Development Power (EDP) tariff rate are denied. Since NYPA has no EDP customers in RGEE's service territory and the Revised Settlement does not address EDP rates, we see no need to address this issue in this decision. However, if a customer requests an EDP rate in the future, we will address the issue at that time.

CPB's request to require LSEs to provide price information to applicants in a common format is rejected. This requirement is unnecessary in a competitive market where participating marketers have the incentive to show prospective customers how their prices, however packaged, compare to those offered by others.

AARP's call for a fund to establish a POLR that would provide consumers with electricity at affordable prices is denied. Recognizing that innovative POLR pilot programs could be Ener Association et al. v. Public Service Comm'n, 169 Misc. 2d 924, 933 (1996).

Case 96-E-0897, Consolidated Edison Com an of New York Inc.,

Opinion and Order Adopting Terms of Settlement Subject to Conditions and Understandings, Opinion No. 97-16 (issued November 3, 1997), mimeo p. 30.

CASE 96-E-0898 explored, we have decided that, "[f]or now, the utilities will function as POLRs."'ARP, CPB, and PULP also raise a number of concerns about consumer protections and marketing guidelines. As these concerns were either already considered or are the subject of a separate proceeding,'ll of these exceptions are denied.

Finall'y, CPB calls for the development of a customer education program because it believes the April 8 Settlement (and for that matter the Revised Settlement) does not address this item. CPB's exception is denied; the Revised Settlement ($ 73) sets forth the requirement that RGEE file a consumer education plan. This Department will also be continuing broad outreach and education efforts, as well as monitoring and overseeing the utilities'wn outreach and education efforts, which should be considerable.

CORPORATE STRUCTURE The Revised Settlement incorporates the April 8

~ Settlement's provisions that would require RGEE to functionally separate its existing operations and structurally separate its ULSE. In addition, RG&E would be permitted to form a holding company. The recommended decision agreed with these proposals because the high cost of divestiture effectively precludes structural separation, especially with respect to the company's sizable nuclear assets. In addition, the recommended decision found reasonable the principles set forth in the April 8 Settlement relating to affiliate relationships, code of conduct, cost allocations, protections, and restrictions because they were based on standards approved in other cases and would permit our review in the event of abuse. Finally, the recommended decision concluded that no proscriptions, prohibitions against competition, or royalty payments should be imposed on RGEE Cases 94-E-0952 et al., ~su ra, Opinion No. 97-5, mimeo p. 43

~ and Opinion No. 97-17, mimeo p. 21.

Ibid I p 26.

CASE 96-E-0898 because the rate reductions, among other things, are a quid pro duo for the benefits the company expects to receive through the operation of its unregulated businesses.

The Attorney General and CPB prefer divestiture of generation to prevent self-dealing and other abuses arising from affiliate relationships. The Attorney General fears that Staff may not have the resources to audit effectively the various transactions among the affiliates. CPB would extend the standards for the relationship between distribution entity, i.e.,

the DISCO and its ULSE, to the DISCO's relationship with the RSLE. CPB also supports physical separation.

WEPCO seeks to prohibit RG&E's unregulated marketing affiliate from using RG&E's name, relying on the expertise and experience of utility personnel, and relying on RG&E's financial resources. Furthermore, WEPCO asks that RG&E's affiliates be excluded from competing in the service territory for two years or until 20; of the company's customers are served by LSEs.

The Attorney General and CPB seek a royalty payment from the unregulated subsidiaries to compensate the regulated utility for good will that RG&E's name and affiliation will bring them.

RG&E has stated that it will transition out of its wholly-owned fossil and hydro generation over the next several years. The company plans to retire or otherwise remove Ginna Station from rate base when its license expires in 2009, and prior to that Ginna Station and Nine Mile 2 are subject to a statewide resolution of nuclear plant ownership and ratemaking.

In view of the relatively short remaining lives on much of the company's generation, the pending resolution of nuclear plant issues, and the incentive to divest plants, functional separation of RG&E's existing operations is accepted. The structural separation of its ULSE are subject to the various rules, codes, and restrictions set forth in the Revised Settlement. Inasmuch as most of these provisions are based on standards we established

~ in other proceedings, and are expected to anticipate likely

CASE 96-E-0898 potential abuses, they are adopted without the modifications proposed by CPB.

RGRE's affiliates will not be prohibited from using the name of RGEE or competing in the company's service territory, or be required to pay a royalty for the use of the RG&E name and its affiliation. These concessions were part of the give and take in the negotiations and will not be disturbed.

Finally, whether RGEE conducts its unregulated activities through a holding company or a separate subsidiary of a utility parent, the company would be permitted initially to fund its activities in the amount of $ 50 million under the terms of the Revised Settlement. Except for the $ 50 million, RGEE's regulated business segments would not be permitted to fund such unregulated operations, and would neither be allowed to make loans to, nor guarantee or provide credit support for, the obligations of unregulated affiliates.

In view of our changes and modifications to the Revised Settlement, especially the acceleration of the introduction of retail access, and our desire to bring the benefits of a competitive electric generation industry to New York consumers, we will increase the maximum for funding for unregulated activities to $ 100 million.

ENVIRONMENTAL MATTERS The recommended decision did not support calls for a mandatory disclosure of generation sources and the imposition of more stringent environmental requirements on older generation facilities. We previously considered and rejected similar requests in a separate proceeding.'II and CPB except, pointing out that we did not expressly reject these proposals and arguing they should be considered here.

PII and CPB are correct in part. In fact, at our October 8, 1997 session, we directed the parties to consider desi g nin g a method of p roviding customers with environmental Case 94-E-0952, ~su ra Opinio,n No. 97-5.

CASE 96-E-0898 information. The Revised Settlement contains language requiring the company to work with LSEs on developing such environmental information.

However, we will not impose more stringent emission standards on older generation facilities. We view this request by PII as a thinly disguised attempt to impose new environmental standards on older plants, which will not likely create a level playing field for competing generation sources. The fact that these plants have an advantage in costs attributed to lower emission standards is but one cost consideration. PII did not address the total cost, which includes other factors that may more than offset this advantage.

MARKET POWER MITIGATION During the five-year term, RG&E would be required to maintain its system in the most cost effective manner, file a market power mitigation plan with the Federal Energy Regulatory Commission (FERC),'nd take appropriate action in accordance with the outcome of that filing. The Revised Settlement also reserves our right to implement market power mitigation measures for retail service after the five-year term. The recommended decision found these provisions reasonable.

A number of parties raise concerns that anticipate problems related to market power and load pockets. In comments on the Revised Settlement, PII suggests RG&E is only bound to "consider" a range of options to maintain the reliability of its system. Accordingly, PII repeats its demand that the company be "obligated" to undertake various forecasts, load monitoring programs, evaluations, and implement alternates to major transmission and distribution additions.

RGEcE filed its request to engage in wholesale sales of capacity and energy at market based rates with FERC on July 1, 1997 and amended it on July 25, 1997. RGEE addressed issue of market power in its request to FERC. By order issued the September 12, 1997, FERC accepted RGSE's filing.

CASE 96-E-0898 These exceptions are denied without prejudice. As noted in its FERC fil'ing, RG&E has committed to implement transmission system upgrades, which by June 1999 will eliminate load pockets for all but 3% of summer hours. Moreover, because RG&E must maintain system reliability within load pockets by operating its units, the cost of which are already in rates, market power concerns are mitigated. Any auction of RG&E generation will be subject to our approval to ensure, among other things, that any market power concerns are addressed. If a specific problem should arise in the meantime, we will address it on an ad hoc basis.

FINDINGS UNDER SE RA In conformance with the State Environmental Quality Review Act (SEQRA), we previously issued a Final Generic Environmental Impact Statement (FGEIS) on May 3, 1996.'e also required individual utilities to file an environmental assessment of their October 1996 restructuring proposals. RG&E filed an

~ Environmental Assessment Form (EAF) concerning the April 8 Settlement on June 24, to

'1997.'ubsequent filing of the EAF, PII filed a petition asking that a Supplemental Environmental Impact Statement be filed. In its arguments supporting the petition, PII raised several substantive issues for SEQRA consideration. In a June 19, 1997 ruling, Chief Administrative Law Judge Lynch narrowed the issues needing further consideration in the environmental assessment..

The information provided by RG&E in its EAF, the parties'omments, the Revised'ettlement, and other information were evaluated in order to determine whether the potential impacts resulting from adopting the Revised Settlement's terms would be within the bounds and thresholds of the FGEIS adopted in Cases 94-E-0952 et al., ~su ta, Opinion No. 96-12, mimeo

~ pp. 76-81.

The final Environmental Assessment Form is Appendix C.

CASE 96-E-0898 1996. The evaluation also considered the conditions and changes to the Revised Settlement that we adopted at our session on November 25, 1997.

Arguably, all of the potential impacts need not be considered, given that some result from Type II exempt rate actions. Nonetheless, the analysis examined all areas in which impacts could reasonably be expected.

No impacts were found to 'be associated with price cap regulation. RGEE currently operates under a form of price cap regulation; the continuation of this rate setting approach for the regulated transmission and distribution company, consequently, does not constitute a change induced by competition or by the Revised Settlement. Moreover, the possibility of prudence review is seen as an important deterrent to excessive infrastructure investments as well as an incentive for promoting the use of targeted DSM as appropriate to avoid excessive transmission and distribution upgrades.

No significant impacts were determined to result from either retirement or new construction of generation as a result of the Revised Settlement. Also, the company asserts it has no plans to either retire any of its existing electric generating facilities or construct new generating facilities as a consequence of the Revised Settlement.

The Revised Settlement will not result in significant new transmission line construction impacts. The company's 1996 load pocket study indicates that under high summer usage and equipment failures, load pockets may occur. An application filed by the company with FERC (dated July 1, 1997 and amended July 25, 1997) contains RG&E's plan to reinforce its transmission and distribution system in order to alleviate the two load pockets within its service territory. The plan notes that with the exception of one new 115 kV transmission line (under ten miles in length), the construction required will be limited to capacitor and transformer work within existing substations.

0'o CASE 96-E-0898 I

Minor localized community economic impacts may occur (e.cC, due to reduced tax receipts), but these would be balanced by positive effects in other localities.

A greater source of concern is the possible increase in air pollution that could accompany increased demand for electric energy. It is likely that increases in energy demand will result from the Revised Settlement's decrease in rates (0.56: average annual increase in demand over the 1998-2012 period) and in DSM expenditures (0.3% increase in demand). Each of these incremental growth rates is an upper bound. For example, it is not clear that all of the rate reductions from the Revised Settlement should be attributed to restructuring; also, the lower 1

DSM expenditures do not consider LSEs'SM spending. Staff's opinion is that the actual growth rates will be substantially less than the corresponding rates in the FGEIS (1'. annual incremental growth from the "high sales" scenario, and 0.29% from the "no incremental utility DSM" scenario) ~

Because of the inherent uncertainty in forecasting future impacts, as a matter of discretion, monitoring of RGEE's restructuring and environmental impacts is being implemented,'nd an SBC is being established. While limiting the rate decreases in the Revised Settlement, which were adopted after extensive negotiations, could mitigate environmental impacts, this would reduce the economic benefits of the rate reductions to consumers and businesses. The mitigation methods we are adopting are reasonable in these circumstances.

Based on these analyses, the potential environmental impacts of the Revised Settlement are found to be within the range of thresholds and conditions set forth in the FGEIS.

Therefore, no future SEQRA action is necessary.

November 26 Order, p. 8.

CASE 96-E-0898 CONCLUSION Our Settlement Guidelines establish the following standards for assessing a proposed settlement in light of our obligation to set just and reasonable rates and a utility's burden, under the Public Service Law, of showing the reasonableness of a rate change it is proposing:

a. A desirable settlement should strive for a balance among (1) protection of the ratepayers, (2) fairness to investors, and (3) the long term viability of the utility; should be consistent with sound environmental, social, and economic policies of the Agency and the State; and should produce results that were within the range of reasonable results that would have arisen from a Commission decision in a litigated proceeding.

b. In judging a settlement, the Commission shall give weight to the fact that a settlement reflects the agreement by normally adversarial parties.'enerally, we find that the Revised Settlement as modified'rovides for reductions that are reasonable and provide ratepayers significant benefits over the five-year term. In addition, ratepayers will no longer be liable for credits arising from flex-rate discounts and past incentives. Furthermore, the rates will be redesigned to more closely reflect marginal costs, which should not only remove some of the inter- and intra-class return discrepancies, but also bring the rates close to those expected when the electricity market is competitive.

The Program in the Revised Settlement, as modified, is reasonable because it phases in competition at a pace that will allow RG&E to overcome problems related to its- reliance on Cases 90-M-0225 et al., ~su ra, Opinion No. 92-2, Appendix B,

p. 8.

The November 26 Order required RG&E to submit a written statement unconditionally accepting the conditions and modification contained therein. On December 1, 1997, such a statement was duly filed with the Secretary.

CASE 96-E-0898 nuclear power, gives customers prompt access to a retail electricity market, and provides for back-out rates at a level that should stimulate competition.

The proposed restructuring of RG&E in conjunction with the incentives to operate its generating facilities efficiently, and the safeguards governing the transactions of the various affiliates, are reasonable as discussed above. While RG&E's ULSE will benefit by being permitted to use the corporate name and up to $ 100 million of funding from the company, the ULSE will be an added source of competition, the benefits of which should redound to electric consumers.

Although all of the signatories did not submit their litigation positions, RG&E did. It is clear from reviewing the company's October 1, 1996 submission that RG&E made substantial concession especially with respect to rate reductions. Multiple Intervenors notes that it would have argued for larger rate decreases, a faster phase-in of retail access, and a greater sharing of stranded costs during the transition period.

~ i It should also be kept in mind that a number of parties opposed the April 8 Settlement and the Revised Settlement and they litigated their positions. After considering the facts and reasons behind their positions, we adopted a number of modifications to the Revised Settlement.

In light of all of the above, we adopt the terms of the Revised Settlement subject to the conditions and changes described above, which were previously included in the November 26 Order.

The Commission orders:

1. Clauses one through five contained in the Order Adopting Terms of Settlement Subject to Conditions and Changes (issued November 26, 1997) are adopted in their entirety and are incorporated as part of this opinion and order.

CASE 96-E-0898

2. Case 96-E-0898 is continued.

By the Commission, (Signed) JOHN C. CRARY Secretary

CASE 96-E-0898 DRAFT APPENDIX A Page 1 of 2 CASE 96-E-0898 ROCHESTER GAS AND ELECTRIC CORPORATION LIST OF ABBREVIATIONS AARP American Association of Capital & Trade Resources Retired Persons ISO - Independent System ATTORNEY GENERAL - New York Operator State Department of Law KAMINE - Kamine/Beisco CASH 06M - Cash Operation and Allegany L.P.

Maintenance CPB - New York State Consumer KCAM - Kamine Cost Adjustment Protection Board Mechanism DAIRYLEA Dairylea kW Kilowatt Cooperative Inc.

kWh Kilowatt-hour DISCO - Distribution Unit LSE - Load Serving Entity DSM - Demand Side Management

- Economic Development MBIS - Metering, billing, and EDP information services Power NEV New Energy Ventures,

~ ENTEK - Entek Power Services, Inc.

Inc.

NRC - Nuclear Regulatory ESCO - Energy Service Company Commission FERC - Federal Energy NYPA - New York Power Regulatory Commission Authority of the State of New York FGEIS - Final Generic Environmental Impact PII Public Interest Statement Intervenors GDP - Gross Domestic Product POLR -,Provider of Last Resort GENCO - Generating Unit PSL Public Service Law GRT - Gross Receipt Tax PULP - Public Utility Law Project of- New York, Inc.

gWh Gigawatt-hour RETAIL COUNCIL Retail HEFPA - Home Energy Fair Council of New York Practices Act RGsE Rochester Gas and HOLDCO - Holding Company Electric Corporation IPPNY~Enron - Independent RSLE - Regulated Load Serving Power Producers of New Entity York, Inc. and Enron

CASE 96-E-0898 - DRAFT APPENDIX A Page 2 of 2 SAPA - State Administrative Procedure Act SBC - System Benefits Charge SC - Service Classification Staff New York State Department of Public Service Staff ULSE - Unregulated Load Serving Entity WEPCO -- Wheeled Electric Power Company

CASE 96-E-0898 DRAFT APPENDIX B List of Parties Which Filed Comments on October 31 1997 Rochester Gas and Electric Corporation (RG&E)

New York State Department of Public Service Staff (Staff)

Multiple Intervenors Joint Supporters National Association of Energy Service Companies 0 onents New York State Department of Law (Attorney General)

New York State Consumer Protection Board (CPB)

Public Interest Intervenors (PII)

Public Utility Law Project of New York, Inc. (PULP)

~ Retail Council of New York (Retail Council)

Wheeled Electric Power Company (WEPCO)

Larry Owens Charles Straka

EXHIBITD

~W A"

SECURITIES 20K) EXCEGQIGE COMMISSION WXSHINmoN, D.C. 20549 CFORM 10-K (Nark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15((R) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended: December 31, 1997 OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 1-672-2 Rochester Gas and Electric Corporation (Exact name of registrant as specified in its charter)

New York 16-0612110 (State or other jurisdiction of (i.R.S. Employer incorporation or organization) identification No.}

89 East Avenue, Rochester, NY 14649 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (716) 546-2700 Securities registered pursuant to Section 12(b} of the Act:

Name of each exchange Title of each class on which re istered Common Stock, $5 par value=- New York Stock Exchange

ROCHESTER GAS AND ELECTRIC CORPORATION Information Required on Form 10-K ltern Number Descriotion Paae Par: I Item 1 Business Item 2 Properties 12 Item 3 Legal Proceedings 14 Item 4 Submission of Matters to a Vote of Security Holders 14 Item 4A Executive Officers of the Registrant 14 Part ZZ Item 5 Market for the Registrant's Common Equity anK.

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 Ztem 8 Financial Statements and Supplementary Data 34 Item 9 Changes in and Disagreements with Accountants on Accounting and F'nancial Disclosure 68 Item 10 Directors and Executive Officers of the Registrant 69 Item 11 Executive Compensat'on 69 12 Secur'ty Ownership oz Certain Beneficial Owners and Management 69 em '3 Certain Relationships and Related Transactions 69 Pav ~ TV Ztem 14 Exhibits, Financia'tatement Schedules and Reports on Form 8-K 70 Signatuzes 75

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't 67. 1't 71.1%

Gas 32. 4% 32.9% 28. 9't 100,0+o 100 0+o 100.0+o The Company is operating in a rapidly changing competi'tive marketplace for elect ic 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 compet'ion in the electric energy marketplace in New York State over the next five years.

Regarding the Company's electric business, in early 1996 the Federal Energy Regulatory Commission (FERC) issued new rules to facilitate the development of competitive wholesale markets. In 1997 the Company together with other New York utilities filed with FERC a "Comprehensive Propaphl to Restructure the New York Wholesale Market" and requested approval of their'-restructuring plan in ea.ly 1998. At the State level, the PSC endorsed a fundamental'estructuring of the electric utility industry in the State in its "Competitive Opportunities Proceed'ng". 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 wh'le lower'ng custome" prices and establishing an opportun'ty fo" compe 've returns on shareholder investments.

A'hough tne Company is jus" beginn'ng to rece'e app cations from potential compe"'tors under its distr'bu 'on tar'==. '= expec"s more to be filed,I par='c 'arly from companies w'th s"rong retailing and customer service capab'3es anc wholesale powe trading exper='se.

<i" th the unbundling of services as c'rected by FERC Order 636, primary responsibility for reliable natural gas has shif=ec from 'n=erstate pipeline companies to local distr'bution compan'es, such as =he Company. All gas cus omers have a choice o. supp'ers s'nce November 1996. subjec" to certain p'.".ase-in limita ions through '998 fo" 'oss o cas co-..=..oci=y sales. Some of these

companies a"e large, nationa'ly known, p b'ic', he c marke=ers or suppliers.

1997 tne Company commencec nego=ia=ions wi"h ='.".e staf.he PSC and othe" parties with the objective of develop"ng a m perta'n'ng to the Company's gas business.

year settlement of issues In See Item 7 - Management' D'c ss'n anc Ana's' of Financial Cond'ion anc Results of Operations under the heac'ng "Compe:ition" 'or further information on the Competitive Opportunities Set emen= and the competi"ive challenges the Company faces in its electric and gas business and how i is responding to those cha1l enges.

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

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 w'th the surrounding development, lack of a rail/coal delivery system and more stringent clean air regulations made the plant uneconomical in the develop'ng competitive generation business. The retirement of Beebee Station is not expected to have a material effect on the Company's financia'1 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 eX'ectric capabil'ity and energy currently provided by the plant is expected to be replaced by purchased power as nee'ded.

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.

Unde arrangements dating from September 1975, ownership, output and cost of the project are shared by the Company (14%), Niagara (41%) Long 'Island L'ghting Company (18%), New York State Electric & Gas Corporation (18%%.a'nd Central Hudson Gas 6 Electric Corporation (9%). Under the operating Agreement, niagara serves as operator of Nine Mile Two, but all five cotenant owners share certain policy, budget and managerial oversight unct'ons. The base term of the Ope ating Agreement is 24 months from i s effective da e, with automatic extension, unless term'..ated by w itten notice of one or more of he cotenant owners to the othe" cotenant owners; such term'nation becomes e=fective six months from the receipt of any such notice of terminat.'on by a'1 =he co"enant owners receiving such ro"'ce. he gross and ne" book cos= o= =he Company's share o Nine Mile Two

'nc'uc'ng $ 374 million of disa'owec cos=s previously wr'tten off as of December 3 , '997 are $ 879 million and $ 399 mi 'ion, respect'vely.

.he Company's Ginna Plant, nas been '".. commercial operation since o'he chCompany's w'.".

ly 1, 1970, p ovides 480 Mw electric generat'ng capacity. In A gust 1991 t?.e NRC approved the Co."..pany's app 'ca='on 'o" amendment to e te. d the Girna Plant operating license exp'ra='on Ca=e '"om Apr 25, 2006 to Septembe" 18, 2009.

.he g.oss and net book cos" o=. the G ."..-.a P'.an: as of December 31, 1997 are

$ 560 million and $ 309 m'lion, espec=ive ;. From t'me to time he NRC issues d'ectives requiring all o" a cer"a'.". g=o p o reac=or 1'ensees to perform a..alyses as to their abil'ty to mee= specifiec cr'ter'a, g 'de'nes or operating objectives and where necessa y "o mod =y =ac .'='es, sys=ems o" procedures to con=orm thereto. Typically, these c;rec= ves a"e prem'sed on the NRC's obligation to protect the public health and sa=e=y. .he Company reviews such d'rectives and implements a variety o'odifications based on these directives and resulting analyses. Expenditures a= =he G'nna P'ant, including the cost of tnese modifications, are estima ec =o be $ 0.;on. $ 10.4 m llion and $ 6.4 m'1'ion for the years 1998, 1999 and 2000. respectively, and are included in the capital expenditure amounts presented under 'tern 7 - Management's Discussion and Analysis of Financial Condition and Re'suits o'pera=ions.

The Company has four licensed hydroelec ric generating sta ions with an

~,. aggregate capability of 47 megawatts.

licenses were timely made in 1991, the FERC was Although applications .'or renewal of those unable to complete processing of many such applications by the December 31, 1993 license exp'ration. The FERC, therefore, issued annual licenses t?.at essent'ally ex end the terms of the old licenses year-to year until processing of the new ones can be completed. The

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 d'scussion of that top'c.

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 concentrate to uranium hexafluoride, (3) the enrichment of the uranium hexafluo ide, (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 se vices for the Ginna Plant and Nine Mile Two.have been made to pe mit operation of the units through the years indicated:

Ginna Plant Nine'Mile Two'"

Uranium Concentrate 2000 2002'"

Conversion (')

o'000 2002 ~~~

~ Enrichment (5) (6)

Fabrication 2001 2003 (1) Information was supplied by Niagara Mohawk Power Corporation.

(2) Arrangements have been made fo" 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 unde" which 't may procure up to 80 percent of the annual Ginna Plant uranium requi ements. A second contrac" is in place to supply about 30't of the annual requ'rements for 1998 through 1999, and 100'4 of requirements in 2000. The remaining requirements are uncommitted.

(4) Seventy percent of the conversion requirements have been procured through 1997 under one contract. A second contract is in place cover'ng 70% of requ'ements in 1998 and 1999, and 100%, 'n 2000. Twenty pe cent of requirements for 1998 are covered by a contract for delive y of UF6 (uranium plus conversion). Ten percent of requiremen s for 1998 will be filled from inventory.

(5) The Company has a contract with United States Enrichment Corporation (USEC) for nuclear fuel enrichment services which assures provision of 70% of the Ginna Plant's requirements through 1999. A second enrichment contract is in place which assures 30% of the Ginna Plant's requirements through 1999 and 100% of requirements in 2000 and 2001.

(6) Nine Mile Two is covered for 100't of requirements through 1998 and for 75't (with an option to increase to 100%) from 1999 through 2003.

(a) The First Mortgage prohibits the issuance of additional First Mortgage Bonds unless earnings (as defined) for a period of twelve months ending not earlier than sixty days prior to the issue date of the additional bonds are at least 2.00 times the annual interest charges on First Mortgage Bonds, both those outstanding and those proposed to be outstanding. The ratio under this test for the twelve months ended December 31, 1997 was 6.99.

(b) The First Mortgage also provides that, if additional First Mortgage Bonds are being issued on the basis of property additions (as defined), the pr'ncipal 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, Firs" Mortgage Bonds may be issued on the basis of 100( of the principal amount of other F'st 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 prefe red stockholders, the Company may not issue additional preferred stock unless in a 12-month period within the preceding 15 months: (a) net earnings applicable to payment of dividends on preferred stock, after'a~e's, have been at least 2.00 times the annual dividend requirements on preferred=.stock, including the shares both outstanding and proposed to be issued, and (b) net;'earnings available for interest on indebtedness, after taxes, have been at least 1.50 times the annual interest requirements on indebtedness and annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued. For the twelve months ended December 31, 1997, the coverage atio under (b) above (the more res"rictive provision) was 2.83.

For information with respec" to sho" -term borrowing arrangements and

mita ions see Item 8, Note 9 - Shor=-.erm Debt.

The Company's Charter does no" contain any financial tests fo the issuance of pre erence or common stock.

The Company's securities ratings a>> December 31, 1997 were:

Mortgage Pre'erred Bonds Stock Standard a Poor's Corporation BBB~ BBB Moody's Investors Service Baal baa2 Duff a Phelps BBB~ BBB The securi ies ratings set forth in the ".able are subject to revision andjor withdrawal at any time by the respec ive rating organizations and should not be considered a recommendation to buy, sell o hold securities of the Company.

ENVIRONMENTAL QUALITY CONTROL Operations at the Company's facilities are subject to various federal, ~

state and local environmental standards. To assure the Company's compliance with these requirements, the Company expended approximately $ 0.6 million on a variety of projects and facility additions during 1997.

s 0

0',

o

10 ectric Department Statistics Electric Year Ended December 31 Revenue (000's) 1997 1996 '995'994 '993'992 Residen ial $ 252,464 $ 254,885 $ 256; 294 $ 243,961 $ 234,866 222 ,210 Co.".mercia 210,643 215,763 215,696 206,545 196,100 187 ,262 144,305 153,337 157,464 150.372 148>084 XC! ,507 Yu">c'pa'"d 0-"e- 66,898 67,128 57,270 59,905 57 ,288 72,06'79,C73 Electric revenue from our customers 690,883 696.582 658,148 638,955 608 ,267 Other electric utilities 20,856 16.885 25,883 16, 605 16, 361 25 ,541 Total electric revenue 700.329 707.768 722,465 674,753 655,316 633 , 808 Flectric Expense (000's)

Fue used '.". electric generation 47.665 40.938 44,190 4C,961 45,871 48,376 P "chased electricity 28,347 46,48C SC,167 37,002 31,563 29,706 0 he" operation 205,058 204,746 199,524 192,360 192,7C9 183,118 Ha'ntenance 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, sta e and o he" 91.111 95<010 102,3&0 97,919 96,0C3 94,8C1

.otal electric expense 516,793 521,222 523<10S 494>74& 491,016 482,968 Operating Xncome befo e Fede a! Xrcome Tax 183,536 186,546 199,360 180, 005 164,300 150,840 Federa! income tax 61,837 61,901 59,500 52,842 43,845 38,046 Operating Xncome from Electric Operations (000's) S 121,699 S 124,645 & 139.860 $ 127,1.63 Pl

'~ ~

S 120,455 112,794 Electric Operating Ratio 8, 46.0 47.1 47.3 47.7 49.2 49.7 Electric Sales - KWH (000's)

Residential 2,139,064 2,132,902 2,144,718 2, 117, 168 2 ~ 123,277 2,084,705 Commercial 2, 118,991 2,061,625 2,064.813 2, 028, 611 986,100 1, 938. 173 v ldus 2,010,613 2,010,963 1,96C,975 1,860,833 4 892,700 1,929,720

~

~cipa and Other 537,051 520,885 531,311 513,675 504,987 503,388 r Other

.ota e.ectr c .stones sales c =. fries 6.&OS, 1,218,794 I!9 6,726,375 99C. 842 6,705,817

l. 4&C, 196 6,520,287 1.02'.733

6. 507,064 743.588 6.455,986 1,062,738

.ota e ectric sales 8.024.5'3 7.72-.2-7 8.190.0 3 7.542,020 250,652 7.518,724 Electri" C stcmers at December 3'es'dent'a 308.909 307, 81 306.601 30C. 494 302. 219 300,344 30,940 30.620 30.426 29,984 29,635 29,339 1,300 ~ 325 ',347 1,36! .,382 1.386 2,824 2,688 2.7!1 2,670 2.638 2,605

.ota e ectr'c cus omers 3C3,973 34 >84 34:,085 338,509 335.87C 333,674 ectr city Generatec and P .rchased ~

!O>H (000's)

Foss K.c'ar 4.094,272

.63:.933 l. 478.120 '.520.936 2.197,757 0 ~ < 19 544 C. 64 5,646 C>wc> ~ >8 C. 191,035

..yc 0 227,867 248,990 :7'.. 886 218.:29 '99,239 278,318 P"mped storage 238.900 246,726 23".904 247. 550 233,477 226,39!

.

ess energy fo. pumping (358,350) (370,097) (36:,'44) (37:.383) (355,725) (3CC,2C5)

Othe 890 936  :.2C5 2.559 811 Tora. generated - ne 6.893,765 5,733.340 6,32>,790 6,'00,839 6.095.943 6.550,067 P rchased 1,30 ,636 2.437,433 2.343.4&C  :.998,882 1.646.244 1.389,875 To a. electric energy 8. 195. 401 8.:70,773 8,671.274 8,099,721 7,742,187 7.939.942 Sys em ):et Capabi!ity-KN at December 31 Fossil 526.000 529,000 529.000 532,000 541,000 541,000 Huclear 638,000 638.000 6C0,000 617,000 620,000 617,000 Hydro 47,000 47,000 47,000 47,000 C7,000 C7,000 O hew 28,000 ~,000 28,000 29,000 29.000 29,000 Purchased 375, 000 375, 000 375.000 375,000 347,000 348,000 Total system t net capability 1,614,000 1,617.000 1.619.000 1 600 000 1,584,000 1,582,000 eak Load . KW 1,421,000 1,305,000 1,C25,000 1.374.000 1,333,000 1,252,000 1 LLoad Factor . Het  %, 56.1 61.9 57.6 58.8 59.1 62.5

~ Reclassified for compara ive purposes.

12 Item 2. PROPERTIES ELECTRIC PROPERTIES The net capability of the Company's electric generating plants in ope ation as of December 31, 1997 the net generation of each plant for the year ended December 31, 1997, and the year each plant was placed in service are as set forth be'w:

Electric Generating Plants Net Year Unit Net Generation Placed in Capability thousands Service (Hw) (kwh)

Beebee Station (Steam) Coal 1959 80 418,139 Beebee Station (Gas Turbine) Oil 1969 14 Russell Station (Steam) Coal 1949-1957 257 -',237,958 Ginna Station (Steam) Nuclear 1970 480 3,894,652 Oswego Unit 6" (Steam) Oil 1980 189 8,817 Nine Mile Point Ugq ~

No 2 (2l (Steam) Nuclea 1988 158 1,224,892 Station No. 9 (Gas . 'rbine) Gas 1969 465 Sta=ion 5 (Hydro) Water 19'7 39 173,487 5 0"he" Stations (Hydro) Water '. 906. 1960 54.380 P mped Sto age '" 238,900 Less: energy for pumping 239 ~3 (358,350)

TE5 (1) Represents 24% share of jointly-owned facility.

(2) Represents 14% share of jointly-owned facility.

(3) Owned and operated by the Power Authority.'

C Item 3. LEGAL PROCEEDINGS 0 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 o security holders curing the fourth quarter of the fiscal year ended December 31, 1997.

Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT Age Positions, Offices and Business Experience Name 1/1/98 1993 to date Thomas S. Richards 54 Chairman of the Board, Presiden" and Chief Executive Officer - January 1998 to date.

President and Chief Operatic 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.

Sen'or Vice President, Finance and General Counse' Oc obe" 1993 to August, 1994.

General Counse' January, 1993 to October, 993.

M'chae ~

J. Bovalino Pres'cent, Energet x. Znc (a wholly owned subsiciary of tne Company) January 1998 to cate.

Senior V'ce Presicen", Energy Services January '997 to December 1997.

V'ce Pres'cen , Reta'1 Services for Plum S rect Enterpr'ses (a wholly owned subsidiary o N'agara Mohawk Powe" Corporation, 300 Erie Bou'evarc Nest, Syracuse, NY 13202) prior to jo'n ng the Company.

Robert E. Smith 60 Senio" Vice Presiden", Energy Operations Angus 1995 o date.

Sen'or Vice President,- Customer Operations August, 1994 to August, 1995.

Senior Vice President, Production and Engineering - 1993 to August, 1994.

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16 PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS COMMON STOCK AND DIVIDENDS Earni ngs /Di vi d ends 1997 1996 1995 Shares/Shareholders 1997 1996 1995 am rgs pe" snare u.-uer or snares 00's)

~ basic $ 2.30 $ 2.32 $ 1.69 weighted average - basic 38,853 38,762 38,113

~ dilu ed $ 2.30 $ 2.32 $ 1.69 diluted 38,909 38,762 38. 113 Dividends paid Actual nu.-.ker at pe" share $ 1.80 $ 1.80 $ 1.80 .DeceWe 31 38,862 38,851 38,453 Nurser of shazeholde s a Dace..bar 31 31 337 33 675 35 356 TAX STATUS OP CASH DIVIDENDS Cash dividends paid in 1997, 1996 and 1995 were 100 percent taxable for federal income tax purposes.

DIVIDEND POLICY

~ I The Company has paid cash dividends quarterly on its CommOn'. Stock without interruption since it became publicly held in 1949.

dividend payments will be dependent upon the Company's future earnings, its The level o :future cash f'nancial requirements and other factors. The Company's Certificate of Incorporation provides fo" the payment of d'vidends on Common Stock out of the surplus net profits (retained earnings) of the Company.

Quarterly d'idends on Common S"ock are generally paid on the twenty-fifth day of Januarv, Ap" i', July and October. an January '998, the Company paid a cash c'iaend of $ .45 per share on its Com..on Stock. The January 1998 dividend payment is equ'valent to $ 1.80 on an annual basis.

COMMON STOCK TRADING Sha es of the Company's Co...-..on S=ock are tracec on the Ne~ York Stock Exchange

'eer the sy-,~ol "RGS".

Common Stock - Price Range 1997 1996 1995 High 1st qua"ter 20 3/8 23 3/4 23 2nd cuarter 7/ 6 7/8 5/8 3rd 4th quarter quarrer 34 15/:6

/2

~

2'/8 21 9 5/8 22 24 24 1/8 1/8 Low 1st quarter 18 7/8 21 1/4 20 3/8 2nd quarter '8 19 7/8 20 1/8 3rd quarter 20 5/8 18 20 4tn quarter 23 3/4 17 7/8 22 3/8 At December 31 34 19 1/8 22 5/8

18 ONDENSED CONSOLIDATED BALANCE SHEET tThousands 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 amonSzation 1.569,078 1.518.878 1.423.098 1.3353083 1.253,117

',714,368 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 808.344 786,559 757.848 745.135. 4 727.298 658.500 Total Capitalization 1.477,678 1,545.513 1.596,080 1.602.&t3'1.583.929 1.438.380 Long Term Liabitities (Department

, of Energy) 96.726 93,752 90,887 87.826 89.804 94,602 Current Uabilities 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 otal Capitalization and Liabilities 32268.289 32361.476 32456.151 62.446.954 32.444 442 32030.199 ectassified for comparative purposes.

i o

.o

20 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 4

The following is Management's assessment of certain significant factors affecting the financial condition and operating results of the Company. This assessment contains forward-looking statements which are subject to various risks and uncertainties. The Company's actual results could differ from those anticipated in such forward-looking statements as a result of numerous factors wnicn 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 Operat'ng Revenues and Sales Fossil Unit Rat ngs anc Status Operating Expenses Dividend Policy Page 33 EARNINGS

SUMMARY

Desp'te rate reductions '".. Du y '996 and 1997, earn'ngs applicable to Common Stock were nearly unchanged in 1997 due, ir. part, to "he increased ava'ability of the Company's Ginna nuclear generating facility following the 1996 refueling and steam generator replacemen: outage. Increased Company generation allowed the Company to reduce purchased electric expense, while increasing available power for customer consumption and resale. A decrease in financing costs as a result of discretionary edemptions and ref'nancing ac"ivities during the year also helped to increase earnings. In addition to rate reductions, offsetting a gain in 1997 earn'ngs were a wa"mer heating season during the first quarter of the yea" coupled with a cooler summer which affected a' cond'ioning 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 Ae'counting Standards No. 128 ("SFAS-128"),

"Earnings per Share," which changes the methodology of calculating earnings per share. The Company adopted SFAS No. 128 during the fourth quarter of 1997. The impact on earnings per share for prior periods is not material. A discussion of the calculation of earnings per share is presented in Note 1 to the Notes to Financial Statements.

Basic and dilutive earnings per share of $ 1.69 reported in 1995 reflect a pretax reduction of $ 44.2 million, or $ .75 per share net-of -tax, in connection

'0

~.

'e 0'

22 The Company believes that the Settlement will not adversely affect its eligibility to continue to apply Statement of the exception of certain Financial Accounting Standards No.

"to-go costs" associated with non-71 ("SFAS-71"), with 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 recuctions will be as follows: Rate Yea" 1: $ 3.5 million; Rate Yea" 2: $ '2.8 million; Rate Year 3: $ 27.6 million; Rate Year 4: $ 39.5 million; anc Rate Yea" 5: $ 64.6 m'llion.

The Rate P)an 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 w'h 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'lion; Rate Year 4 and continuing until Settlement payments are complete or July 1, 2002, whichever is later, $ 10.5 million.

In the event that the Company earns a return on common. equity in excess of an effective rate of 11.50 percent over the entire five-year .term of the Settlement, 50 percent of such -excess will be used to write dowh 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 extraordinary events occur, including a rate of return on common equity below 8.5 percent or above 14.5 percent, or a pretax interest coverage below 2.5 t'mes, then e'ther the Company or any other party to the Settlement would have the right to petition the PSC for review of

=he Se"tlemen and appropriate remedia'ction.

Retail Access. RGaE's Energy Cnoice Program will be ava'lable to all of its c s"ome s, without regard to customer class, on an equal basis up to certa'n sage caps. On July 1, 1998, custome s wnose electric loads represent app oximately 10 percent of the Company's total annual retail sales will be e'ig'ble to purchase electricity (bu" no" capac'ty commitments) from alternative suppers. On July 1, 1999, customers with 20 percent of total sales will be e 'gible and as of July 1, 2000, 30 percent of tota'ales will be eligible.

o= Ju'y 1, 2001, all reta'1 customers capac'ty from alternative suppliers.

we elig'ble -o purchase energy and As During the initial, energy onlv s=age o'he Reta'l Access Program, the Company's d'str'bution rate will be se= by deducting 2.3 ce.. s per kilowatt hour

("KWH") from its full service ("buncled") ra es and Load Serving Entities acting as retailers in the Company's serv'ce area will be en itl'ed to purchase electricity from the Company at a rate of 1.9 cents per KWH. During the energy and capac'<<y stage, the rate will ge..era'ly eq al "he bundled rate less the cost of the electric commodity and the Company's no..-nuclear generating capacity.

Tnese commodity and capacity costs, generay referred to as "contestable costs,"

are estimated to be 3.2 cents per KWii, inclusive of gross receipts taxes.

Generating Assets. The Company w'l no be required to divest any of its generation facilities. To the extent that the Company sells any generating assets during the term of the Settlement, gains on such sales will be shared between the Company and customers. With regard to losses on such sales, the Settlement acknowledges an intent that the Company will be permitted to recover such losses through distribution rates during the term of the Settlement. Future rate treatment is to be consistent with the principle that the Company is to have a reasonable opportunity to recover such costs.

"To-go costs" of the Company's non-nuclear resources (i.e., capital costs incurred after February 28, 1997, operation and maintenance expenses, and property, payroll and other taxes) are to be recovered through the distribution

0 e-

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 from the regulated utility to will be no suitable mechanism for the reallocation,installed the LSE, of responsibility for ensuring adequate reserve capacity.

Accordingly, during the initial "Energy On)y" stage of the Energy Choice Program (July 1, 1998 to July 1, 1999), LSEs will be able to choose tne'r 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 a's energy, to serve the loads of their retail customers, and distribution charges will be accordingly reduced as nereinafter described. If by July 1, 1998 there is not a functioning Statewide energy and capacity market (see discussion under FERC Open Transmission Orders),

the Company may petition the PSC for deferral of the scheduled commencement of the Energy and Capacity stage.

Summary. The availability of LSEs to serve eligible customers and how quickly they decide to become involved cannot be determined. Likewise, the Company is not able to predict the number of customers that may chose to no longer be served under the Company's regulated tariffs.

The proposed tarif s for Energy Choice as filed by the .Qotppany are expected to become effective February 1, 1998 for the pilot program. The PpC has not set a decision-making date for the full-scale program. The Company is'nable to pred'ct what final rules or regulations wil) ultimately be adopted by the PSC 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 formation and operation of Energetix effective January ', 1998. Energetix is an unregulated subsidiary of the Company that will br'ng energy products and services to the marketplace both within and outside the Company's franchise area.

.he Settlement approved by the PSC in Novembe allows for the investment of up to $ 100 million i,n unregulated businesses during the next five yea s. During 998. the Company expects to determine the actual level of the initial

nvestments to be made in unregulated bus'ness opportunities.

On July 1, 1997 the Company and Energetix filed with the Federal Energy Regulatory Commission (FERC) seek'ng autnor'zat'on to engage in the wholesale sale o electric energy and capac'ty a" market-based rates. Tnese applications were accepted by FERC on Septembe" 12, 1997. The Comoany mus" seek separate authorization in order to sell electric energy to Ene"getix at market-based rates.

Stock Repurchase Plan.. In Decembe" 1997 the Company's Board of Directors approved a Stock Repurchase Plan. Th's plan, which is subject to approval by the PSC, provides for the repurchase ove" the next three years of up to 4.5 million shares of Common Stock, representing approximately 11.5 percent of the Company's outstanding shares of Common Stock at December 31, 1997. The Company expects a PSC decision in early 1998.

Nuclear Operating Company. In October 1996, the Company and Niagara Mohawk Power Corporation (Niagara) announced plans to establish a nuclear operating company to be known as the New York Nuclear Operating Company (NYNOC). Since that time NYNOC has been organized as a New York Limited Liability Company and the Consolidated Edi'son 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 eventua'ly assume responsibility for operation of all the nuclear plants in New York State, including the Company's totally owned Ginna Nuclear plant and join ly owned Nine Mile Two. The Company believes that NYNOC could contribute to ma'ntaining a high level of operational performance, contribute to continued satisfactory Nuclear

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 utilitiesassociated would be permitted to require customers converting from sales service to take pipeline capacity for which the utilities had originally contracted. The PSC has indicated that it will address the issue of how the costs of such capacity would be recovered after the three-year period during the th'd year of the phase-in period. The PSC Staff has recently issued a posi"'n paper on The Future of the Natural Gas Industry in which the Staff proposes that local distribution companies (such as the Company) exit the mercnant function in five years. Treatment of existing pipeline capacity contracts and Provicer of Last Resort responsibilities are substantial issues to be worked out between the PSC, the local gas distribution comoanies 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 posi:tion paper.

Gas customers have had a choice of suppliers since November 1, 1996. Under separate transportation tariffs, the Company distributes the gas and charges fo" the distribution as well as associated services. The Company believes its position in the market is such that it wil) maintain its distribution system margins. Under a phase-in limitation, loss of gas commodity sales may be lim'ted to five percent of .the Company's annual gas volume the first year, and then f've add'tional 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,

'0 customers were being served under this service.

In July 1997, the Company commenced negotiations with the PSC Staff and othe 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 e o= the en 're business by structur'ng a settlement that will be as consistent as possible with the provisions of the Set" lemen in the Compet'ive Opportun'ie Proceec'ng, as discussed earlier. Nego=ia=io..s are at an early stage; accorc'ngly, he Company can make no precic='on as to thei" outcome.

COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POS1TION. With PSC approva , the Company has de erred cer"a'n costs rather tnan recognize them o

's books when incurred. Such deferred costs are hen recognized as expenses when "hey a e included in rates and recovered from c stomers. Such deferral acco nting is permitted by SEAS-71. These de errec costs a"e shown as Regul a t ory se s o.. the Company s Ba ance Shee". anc a c sc ssion anc summarization of such

. egu atory Assets is presented in No=e 0 o'he No"es "o ."- nanc'al Statements.

a competitive electr'c marke, s=rancab'e asse=s wou d arise when investments are made in facil'ties, o" cos" s a"e incurred to service custome s, and such costs are not fully ecoverab e in market. based ra=es. Estimates of such strandable assets are high'y sens'=ive "o =he compet've wholesale market price assumed in the estimation, .-. a compe 'ive natural gas market strandable asse"s would a ise where customers -...'gra=e away =rom dependence on the Company fo" fu' service, leaving the Company w th s "p'us pipel'qe 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 :o Financial Statements.

At December 31, 1997 the Company believes that its regulatory and strandable assets, if any, are not impaired and are probable of recovery. The Settlement in the Competitive Opportun'ties 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.

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. Unde" federal and New York State laws and egulations, the Company is requ'ed 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 it will incur approximately $ 15 million of costs through January 1, 2000, associated with making the necessary modifications identified to date. Total costs incurred in 1997 were approximately $ 1.4 million.

ENVIRONMENTAL ISSUES. The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. The Company has taken a variety of measures (e.g., self-audit'g, recycling and waste minimization, tra'ning of employees in hazardous waste management) to reduce the potential fo" adverse environmental effects from its energy operations. A more deta'ed cise'sion concerning the Company's e..v'ronmental matters, including a d'scuss'on of the federal Clean Ai" Act Amencments, can be found in Note 10 of the No=es to Financial Statements.

a.".d REDEMPTION OF SECURITIES. In acc : on =o 's = mortgage bond matur'ies mandatory s'nking func obga='ons ove" "he pas= three vears, d'iscretionary redemption of securities totalec $ m''on '.". '99", $ 49 .-.. 'on in 1996, and approx'mately $ 152 mill'on 'n 1997. :nc cec '.". c's cre"'ona"y redempt'ons for

'997 were nearly $ 102 millio.. o'x-exemp" sec "'= es wh'c.. were re 'nanced with

..ew mult'.mode tax-exempt bonds as cise ssec unce" a'Hf C g

'0 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-tean 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 issu'g 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 f'nancial market conditions warrant, the Company may also, from time to time, redeem higher cost senior securities.

RESULTS OF OPEBATIONS The following financial review identifies the causes of significant changes in the amounts of revenues and expenses, comparing 1997 to 1996 and '996 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'pyzating revenues, operating revenues less fuel expenses were nearly unchanged ref5ecting primarily a decline in purchased electricity expense as a result of incrdased availability of the Company's generating facilities.

The effect of weather variations on operating revenues is most measurable in the Gas Department, where revenues from spaceheating customers comprise about 90 to 95 percent of total gas operating revenues. Compared to a year earlier, weather 'n the Company's service area was 9.0 percent warmer during the first three months of 1997 and 1. 1 percent warme. for the entire year on a calendar mon n heating degree day basis. In contrast, weather during 1996 was 7. 1 percent colder than 1995 on a calendar month heating degree day basis. With elimination of a weather normalization clause in the Company's gas tariff effective November

'995, abnormal weather va iations may have a more pronounced effect on gas revenues. Cooler than normal summer weather during 1997 and 1996 hampered the demand for air conditioning usage, with a more pronounced effect in 1997 with the 1997 weathe" being approximately 27 percent cooler than 1996.

Compared with a yea" earlier, kilowatt-hour sales of energy to retail customers were up 1.2 percent in 1997, follow'ng a 0.3 percent increase in 1996.

Sa1es to commercial customers achieved the largest gain in 1997. Sales to

'ndustrial customers led the 'ncrease in 1996 compared to a year earlier and we e driven by one large industrial customer who purchased more electric powe" as an a'ternative to power produced at its own plan". Decreased electric demand fo" air conditioning usage c'aused by cooler summe" weather had an impact on k'lowatt-hour sales in 1996 and 1997.

Fluctuations in revenues from electric sales to other utilities a e 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 othe utilities rose in 1997 due to increased sales resulting from greater availability of our combined nuclear and fossil generation, a favorable wholesale market in the second half of the year, and increased marketing of available capacity. In contrast to 1997, revenues from sales cw 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

32 shareholders will assume the full benefits and detriments realized from actual electric fuel costs and generation mix compared with PSC-approved forecast amounts.

The Company normally purchases electric power to supplement its own generation when needed to meet load or reserve requirements, and when such po~er is available at a cost lower than the Company's production cost. new Increased availability and efficiencies following the 1996 installation of steam generators at the Ginna nuclear plant resulted in lower kilowatt-hour purchases of electricity in 1997 which led to a decline in purchased electric power expense. Despite an increase in k'owatt-hours purchased in 1996, electric pu"chased 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 F'nancial Statements). The Company purchased 337 thousand megawatt-hours of energy from Kamine at a total price of $ 16. 6 million in 1995. The Kamine facility has been out of service since the middle of February 1996 which helped to lower the unit cost for purchased electricity in 1996 compared to 1995.

Energy Management and Costs - Gas. The Company acquires gas supply and transportation capacity based on its requirements to meet peak loads which occur in the winter months. The Company is committed to transportation capacity on the Empire State Pipeline (Empire) and the CNG Transmission Corporation (CNG) pipeline systems, as well as to upstream pipeline transportationand storage services. The combined CNG and Empire transportation capacity'-i's adequate to meet the Company's current requirements. '

or 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

'..crease in operations excluding fuel expenses reflects mainly higher outside serv'ces expenses, recognition of obsolete and unproductive materials inventory, s"orm costs, and regulatory compliance costs partially offset by lower payroll cos"s anc decreased expense associa"ed with uncollectible accounts. For the 1996 compar'son period, the increase i.. operat'ons excluding fuel expenses reflects

...a'.".ly h'gher payroll costs and an increase 'n amortizat'on expense beginnin "ly 1, 1996 for customer information system enhancements. Higher payroll costs for this period reflects amortizatio.. of additional ear'y retirement costs for programs concluded in October 1994 and greater employee redeploymen /outplacement cos"s. An additional expense accrual for doubtful accoun"s increased operating expenses bv $ 15.0 million in 1995.

The Company is continuing to take aggressive steps to improve i"s co. ection e.aborts.

o, Uncollectible expense in '997 was $ 18 mil'ion, compared with

$ 20 mi 1'on in 1996. In 1995, uncollec"ible 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 gene ators (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-serv'ce date of Nine Mile Two as a result of an agreement reached with the Internal Revenue Service.

34 Item 8. FINANCIAL, STATEMENTS AND SUPPLEMENTARY DATA

'0 A. FINANCZAI 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

'0 Interim Financial Data.

'0

CONSOUDATED STATEMENT OF INCOME (Thousands of Doaars) Year Ended December 31 1997 1996 1995 radng Revenues lectric $ 679.473 $ 690.883 $ 696.582 Gas 336.309 346.279 293.863 1,015.782 1,037.1 62 990.445 Ekrctric sales to other utrTIties 20.856 16.885 25.883 Total Operating Revenues 1.036.638 1.054,047 1,01 6328 Operating Expenses Fuel Expenses Foci tor electric generation 47.665 40.938 44,190 Purchased etectricny 28.347 46.484 54.167 Gas purchased for resale 196,579 292.297 767762 Total Fuel Expenses 272.59i 289779 266,ii9 Operat(ng Revenues Less Fuel Expenses 764.047 750,209 764328.'66.094 Other Operating Expenses Operatens excluding fuel expenses 268,474 259.207 Maintenance 46.635 47.063 49,226 Depreciation and ambit(sation 116.522 105.614 91.593 Taxes - local. state and orner 121.796 126.868 133,895 Federal income tax 65.279 69.501 66.215 Tbtal Other Operating ExpenSeS 618,706 615,140 600,136 Operabng Income 145341 149.188 150.073 Other (Income) and Deduct(ons Allowance lor other funds used during consuuction (351) (684) (585)

Federal income tax (3.704) (3,450) (16,948)

Regulatory disallowances 26.866 Other. net 3,308 (712) 9,631 Total Other (Income) and Deductions (747) (4.846) 18,964 Interest Charges term debt 44,615 48,618 53.026

r. net 6,676 9.328 9.056

( ance lor borrowed funds used dunng consuucten (563) (1.423) (2.901)

Total Interest Charges 50.728 59.181 Net Income 95360 97 57 i 77.928 DividendS On Preterred Stoct( 5.805 7.465 7.465 Earn(ngs Appacable tO Common Stock $ 89.555 $ 90.046 Eamegs per Common Share ~ Base $ 2.30 $ 2.32 $ 1.69 Earnv(gs per Common Share - Dauted $ 2.30 $ 2.32 $ 1.69 CONSOLIDATED STATEMENT OF RETAINED EARNINGS (Thousands of Dotlars) Year Ended December 31 1997 1996 1995 Balance at Beginning ol Pered $ 90.540 $ 70.330 $ 74.566 Add Net Income 95.360 97,511 71,928 Adlustmenl Assooated wnh Stock Redempten f846)

Total \ 85.054 I 67,841 146.494 Deduct Diveends declared on captat stock CumutatNe preferred stock. al required rates 5.805 7.465 7.465 Common Stock 69.936 69.836 687699 Total 75 741 77.301 76 164 BalanCe al End ol Period $ 109,313. $ 90,540 $ 70,330 Dividends Declared per Common Share $ 1.80 $ 1.80 $ 1.80 mpanying notes are an integral perl Ol 'the financial statements.

CHESTER GAS AND ELECTRIC CORPORATION NSOLIDATED STATEMENT OF CASH FLOWS (Thousands of Doliars) Year Ended Decembe'r 31 1997 1996 1995 CASH FLOW FROM OPERATIONS Net income 95,360 97,511 S 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 Deterred income taxes (10,064) 6,391 (8,047)

Allowance for funds used during construction (914) (2,107) (3.486)

Unbilied 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 disa! Iowance 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) ~

.i '1,238) 6,837 Taxes accrued 347 '=.'13,944) 15,167 Accounts payable 3,733 P,116) 9,644 Other current assets and liabilities, net 7,344 (5,186) 9,639 Other, net 6,847 28,762 Total Operating 234.852 201.226 251.791 H FLOW FROM INVESTING ACTIVITIES et additions to utility plant (84.068) (114,274) (109,547)

Other, net (1) 9,204 11,124 Total Investing f84.069)

CASH FLOW FROM FINANCING ACTIVITIES Proceeds from:

Sale.'Issuance of common stock 272 8.612 17,074 Issuance of long term debt 101,900 Short term borrowings, net 6.000 14,000 (51,600)

Retirement of long term debt (151.568} (67,332) (1,000)

Retirement of preferred stock (30.000)

Dividends paid on preferred stock (6.366) (7,465) (7,465)

Dividends paid on common stock (69.933} (69,657) (68,347)

Other, net 3.016 2.866 Total Financing Increase (Decrease) in cash and cash equivalents (146.679) 4.104 S (118,976) ~1 41,311 12,~057 S (22,820)

Cash and cash equivalents at beginning of year S 21.301 S 44,121 2,810 Cash and cash equivalents at end of year S 25.405 S 21.301 S 44.121 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Thousands of Dollars) 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.

40 Allowance for Other Funds Used During Construction, a part of Other Income. The rate approved by the PSC for purposes of computing AFUDC was 5.0% during the three-year period ended December 31, 1997. Replacement of minor items of property is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve.

CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and sho -term commercial pape". These investments have original matu itv no" exceed'ng three months. Such investments are stated at cost, which approx'mates fair value, and are considered cash equivalents for financial statement purposes.

INVESTMENTS IN DEBT AND EQUITY SECURITIES. The Company's accounting pol'cy, as prescribed by the PSC, with respeqt 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 cor esponding accrued decommissioning liability.

GAS SUPPLY. The Company periodically enters into agreements to minimize price risks for natural gas in storage. Gains or losses resulting from these agreements are deferred until the corresponding gas is withdrawn from storage and delivered to customers.

RESEARCH AND DEVELOPMENT COST. Research and Development costs were charged to expense as incurred. Expend'tures for the years 1997, 1996, pnd 1995 were

$ 4.5 million, $ 4.9 million and $ 5.2 million respectively.

ENVIRONMENTAL REMEDZATZON COSTS. The Company, accrues for lo'sses associated with environmental remediation ob'igations when such losses are probable and reasonably estimable. Accruals fo" est'mated losses from environmental remediation obligations generally are recognized no later than completion of the remed'al feasibility study.

Such acc uals are adjusted as furthe" 'nformat'on develops or c'rcumstances hange. Cos s o future expend'" res for env'ronmental remed'at'on obligations are no discounted to the'rese."." value.

MATERIALS SUPPLIES AND FUELS.

va.ued a" the lower of cos" o" market s ng =he ~

" rs=-i" "

Materia s anc s pp'ies nventories are

'nvenzories are valued at average cost. .he Companv per'od'cal'y enters into

~ rst-out met'~od I Q I I ~ ~uel agreements to m'nimize price 'sks for nat ral gas .". s"orage. Gains or losses esu't'ng 'm these agreements are ce=errec ".".=

w'hcrawn from storage anc de ivered to c 'stomers.

the corresponding gas is TOCK-BASED COMPENSATION. F'na..c.a Acco nt.ng Stancarcs Board Statement 123 (SFAS.1.23), Accounting :o" S"ock Base" Co.-..pe.-.sa:'on, was adopted by the Company in the first quarter o= .996.  := reco."..-..encs he use of a fair valu based method of accounting for co.-..pensa='on cos"s associa"ed w'th stock-based co.-..pensation. The Company c rrent'y '.".as S=ock Ap =ec a=ion R'ghts plans cover'n certain emp oyees and directors. Fo" =hese p'ans, =he Company's accounting po'cy has been to use a fa'- va'ue me=hoc o= comp t'ng per'odic compensation expense. SEAS- 123 was applied to the va a='on o= "he 996 Pe formance Stock Opt'on Plan (PSOP), which became e=fect ve on an a"y 22, 1997. The aggregate amount charged to expense's a result of these plans approximates $ 1.0 million annually in 1996 and 1995, and approx'ma es $ 8.2 m'ion 'n 1997. Additional information on the PSOP is included '".. No e 8.

RECLASSIFICATIONS. Certain amounts in he'rior years'inancial statements were reclassified to confo".z wi"h c rren= year presentation.

I EARNINGS PER SHARE. SFAS-128. Earn'ngs Pe" Share, was adopted by the Company in the fourth quarter of 1997. This statement replaces the presentation fg7 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 sha.eholders by the weighted average number of common shares ou standing fo" the period. Diluted EPS reflects the potential dilution that could occur if securities or othe contracts to issue

42 Note 2. FEDERAL INCOME TAXES 4 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 fo" the three most recent years.

(Thousands o! Do'ars) 1997 1996 1995 Charged (Credited) to operat,ing expense:

Current $ 69,812 $ 65,757 65,368 Deferred (4,533) 3.744 847 boa a1 vr'Y6T ..

Charged (Credited) to othe." incone:

C'u ent 1,828 (6,097) (9.996)

Deferred (3, 100) 5. 079 (4. 520)

Defe=red investnent tax credit Total (2. 432) 73, lUT7 ~$

(2.432) 57 (2,432)

(Vi~4 Total federal income ax 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 Income., and the amount computed at the statutory tax rate of 35%.

(Thousands of Dollars) 1997 1996 aet Income $ 95,360 $ 9'7, 511 $ 71.928 dd: federa. income tax expense 61, 575 66 49,267 income before federal income tax Comp ted tax expense a" s atu ory tax ra e "ncreases (decreases) in tax resulting from:

Difference between tax depreciation

$

$

'56,935 54,927 $ Os'995 05'163.562 57,247

$

$

21, 195

42. 418 and amo .".= defe red '0,772 10,796 '7, 197 Deferrec .'nvestment ax c edit (2,432) (2,432) (2,432)

)( sce'aneo s items, net ( .692) 440 2, 084

.ota federal income ax expense $ 61, 575 $ 66 $ 49. 267 A s mmary of the components of the ne" deferred tax liability is as fo'lows:

a

(.ho sands of Dollars) 1997 1996 1995 a)" c'a" deco 's'" 'g Accelerated dep. eciation

$ (20.807) 216,704

$ (17, 880) 213,907

$ (14,797) 197.952 Defe red invest.en tax credit 27,981 29,562 3', 143 Depreciation previously flowed through 157,538 169,562- 183,077 pension (23,166) (24,570) (24,241) other ( 3.281) (553) 4.518 To al $ 344.969 $ 370,028 $ 377,652

44 Note 3. PENSION PLAN AND OTHER POST EMPLOYMENT BENEFITS 0 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

• s 392.6

• Projected benefit obligation for service rendered to date S (499.3)

• S (480.2)

• Less: Plan assets at fair value, primarily listed stocks and bonds 638.4 '-". 567.1 Plan assets in excess of projected benefits Unrecogn'zed net loss (gain) from past 139.1

.

~ '6.9 experience different from that assumed and effects of changes in assumptions ( 219.0) (170.7)

Pr'r p service cost not yet recognized in net periodic pension cost 10.7 11.6 Unrecogn'zed net obligation at Decembe" 31 Pension costs accrued s 67.4 s 69.8 Actuarial present value.

Ne" pension cost included the following componer.ts:

(Mill'ons) 1997 1996 1995 Service cost - benefits earned during the pe 'od , s 6.2 $ 7.4 $ 6.0

nterest'ost on projected benefi ob'iga=ion 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 ~s The projected benefit obligation at Decembe" 31, 1997 and December 31, 1996 assumed discount rates of 6.75% and 7-.Z5%, 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.

1'n 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. Zn

46 Note 4. DEPARTMENTAL FINANCIAL INFORMATION

,0 The Company's records are maintained by operating departments, in accordance with PSC accounting policies'he 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 Zncome.

(Thousands of Dollars) 1997 1996 1995 Electric Operating Znformation 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 operat'ng income $ 121,699 S 124,645 S 139,860 Other Xnformation J I Depreciation and amortization 103,395 $ &~-,615 $ 78, 812 Nuclear fuel amortization 17,419 16;209; 17, 982 Capital expenditures

$

$ 58,522 95, 334'93,

$

634 Xnvestment Znformation, Zdentifiable assets (a) $ 1,783,825 $ 1,877,224 $ 1,913,762 Opera"'ng Xnformat'on Ooera-'ng revenue S 336,309 S 346,279 $ 293,863 Operating expenses, excluding prov's'on for income taxes 309.225 3'4,'36 276,935 Pre"ax operating income 27,084 32, 143 16,928 Provision for income taxes 3,442 7,600 6,715 Ne= operat'ng 'ncome S 23,642 S 24,543 S 10,213 Other nformation Deprec'ation S 13, 127 S '2,999 S 12,781 Capital expenditures S 25, 546 S 18, 940 $ 15, 913 Xnves tment Znf orma tion identifiable assets (a) S 441,849 S 447,865 S 477,758 (a) Excludes cash, unamortized debt expense. and other co~on items.

e=

Note 6. LONG-TERM DEBT

!0 FIRST MORTGAGE BONDS (Thousands of Dollars)

Principal Amount December 31 Series Due 1996 6 1/4 W Sept. 15, 1997 20,000 6.7 X July 1, 1998 30,000 30,000 8.00 Y Aug'5, 20091999 29,668 6 1/2 EE Aug. 1, 1O.OOO 8 3/8 OO)a) Dec. 1, 2028 25,500 25,500 9 3/8 PP Apr. 1, 2021 100,000 100,000 8 1/4 QQ Ib)

Mar. 15, 2002 100,000 100,000 6.35 RR<a) May 15, 2032 10,500 1O,SOO 6.50 SS)a) May 15, 2032 50,000 50,000 7.00 (b) (c) Jan. 14, 2000 30,000 30,000 7.15 (b) (c) Feb. 10, 2003 39,000 39,000 7 '3 7.64 (b)

(c)

(c) Mar. 3, 2003 Mar. 15, 2023 1,000 33,000 1,000 33,000 7.66 (c) Mar. 15, 2023 5,000 5,000 7.67 (c) Mar. 15, 2023 12,000. 12,000 6.375 (b) (c) July 30, 2003 40,000 40,000 7.45 (c) July 30, 2023 40,000 40,000 gilt), ))I SSP.), 6((

Net bond discount (566) (614)

Less: Due within one year 30,000 20,000 Total ~44 4 ~YP (a) The Series 00, Series RR and Series SS First Mortgage Bonds equal the principal amount of and provide for all payments of principal, premium and int,crest corresponding to the Pollution Control Revenue Bonds, Series C, and Pollution Control Refunding Revenue Bonas, Series 1992 A, Series )992 B (Rochester Gas and Electric Co pora ion Projects), respectively, 'ssued by the New York State Energy Research and Development Authority (NYSERDA) through a participation agreement w'th the Company. Payments of the pr'ncipal of, and interest on the Series 1992 A and Series 1992 B Bonds are cuaranteed under a Bond Insurance Policy by MB"A Insurance Corporation.

(b) The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7.13% and 6.375'4 mecium-t,erm not,es aescribed be'ow are genera'y no" redeemab'e prior to maturity.

(c) Zn 1993 the Company issued $ 200 mil'ion under a medium-term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A" with maturities that "ange from seven years to thirty years.

The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by the Company (except cash and accounts receivable).

S inking and improvement fund requirements aggregate $ 333,540 per annum under the First Mortgage, excluding mandatory sinking funds of individual series.

Such, requirements may be met by certification of additional property or by depositing cash with the Trustee. The 1997 and 1996 requirements were met with funds deposited with the Trustee, and these funds were used for redemption of outstanding bonds of Series Y.

On May 1, 1997 the Company redeemed all its outstanding First Mortgage 8%

Bonds, Series Y, due August 15, 1999 and all its outstanding First Mortgage 6'.

Bonds, Series w, due September 15, 1997. On October 15, 1997, the Company redeemed all its outstanding First Mortgage 65% Bonds, Series EE.

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 Septembe 1, 2033. Proceeds are expected to be used to redeem the Ser's OO, tax-exempt, first mortgage bonds which are not redeemable until December "998.

Note 7. PREFERRED AND PREFERENCE STOCK Par Shares Shares T e b Order of Seniorit Value 'uthorized Outstandin Preferred Stock (cumulative) $ 100 2,000,000 920,000*

Preferred Stock (cumulative) 25 4,000,000 Preference Stock 1 5,000,000 See below for mandatory redemption requirements.

No shares of preferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.

A. PREFERRED STOCKi NOT SUBJECT TO MANDATORY REDEMPTION:

Shares (Thousands) Optional e 4

~ Series Outstanding December 31, 1997 120,000 $

December 31, 1997

'2, 000 1996

$ 12,000

(

Redemption er share)

$ 105 4.10 80,000 8,000 8,000 101 3/4 60,000 6,000 6,000 101

4. 0 J 50,000 5,000 5,000 102.5 K 60,000 6,000 6,000 102 4 on 100,000 ,10,000 10.000 101 7.50 N 20,000 102 o"a' 470 000 547 000 $ 67 000 May be redeemed at any time at the op='on o= "'he Company on 30 days min'mum no='ce, plus accrued dividends in al. cases. .he Ser'es N were redeemed on Apr'1 22, 1997.

B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:

se"ies Shares Outstanding December 31, 1997 '997

(.housands)

December '996'ptional

31. Redemption

( er share) 7.45 S $ $ 10,000 Not applicable 7.55 T 100,000 3.0, 000 10,000 Not applicable 7.65 U 100,000 10,000 1Q,QOO Not applicable 6.60 V 250,000 25,000 25,000 Not Before 3/1/04+

Total , (mU $ ~4, VR ,UH Less: Doe within one year 100. 000 10.000 10,000 Total 350 000 ~35 000 ~45 000

+ Thereafter at $ 100.00

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 o 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 Pe formance 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 RGRE 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 (Increase) in Capital Stock Expense ( 125)

Balance, December 31, 1995 38,453,163 $ 687,518 Shares Issued through Stock Plans 398,301 8,612 Dec ease (Increase) in Capital Stock Expense ( 111)

Ba ance, December 31, 1996 38,851,464 $ 696,019 Shares Issued through Stock P ans 0,883 272 Addit'onal Paid in Capital 2,399 Decrease (Increase) 'n, Captock Expense Ba ance, December 31. 1997 38,862,347 699,03" PERFORMANCE STOCK OPTION PLAN Effective January 22, '99'7, he Company acop.ed a Performance Stock Option Plan which provides for the granting of op:fons to p ."chase up to 2,000,000 authorized but unissued shar'es or t"easury shares o: $ 5 pa"- value Common Stock to executive officers and other key employees. Yo par='c'pant shall be granted options for more than 200,000 sha es o= Co.-.=..on S"oci'. c 'ng any calendar year.

The options would be exercisable for a period to be dete mined by the Committee on Management (the Committee). The Committee may in 'ts 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 exe.cise.

In 1997, the Board of Directo s granted 504,700 options at an exercise price of $ 19.0625 per share. These options are vested at 50% when the stock closes at $ 25 per share, 75% at $ 30 per share and 100% at $ 35 per share.

Also in 1997, the Board of Directors granted 50,159 options at an exercise price of $ 24.75 per share. These options are vested at 25% when the stock closes

0 0

e.

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 dur'ng 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.

Commitment fees related to this facility amounted to $ 113,000 in 1997 and 1996, and $ 165,000 in 1995.

The Company's Charter provides that the Company may not issue unsecured debt if immediately after such issuance the total amount of unsecured debt outstanding would exceed 15 percent of the Company's total secured indebtedness, capital, and surplus without the approval of at least a majority of the holders of outstanding Preferred Stock. As of December 31, 1997, the Company would be able to incur approximately $ 103.8 million of additional unsecured debt under this provision. The Company has unsecured lines of credit totaling $ 27 million available from several banks, at their discretion.

In order to be able to use its $ 90 million revolving credit agreement, the 4 Company has created a subordinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted bj- this provision of the Company's Charter. In addition, the Company has a Loan and Security Agreement to provide for borrowings up to $ 10 million for the exclusive purpose financing Federal Energy Regulatory Commission Order 636 transition costs(636

'f Notes) and up to $ 30 million as needed from time to time for other working capital needs. Bo rowings under this agreement, which can be renewed annually, are secured by a lien on the Company's accounts receivable.

A- 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).

0 0>>

56 assets during the term of the Settlement, gains on such sales will be shared between the Company and customers. With regard to losses on such sales, the Settlement acknowledges an intent that the Company will be permitted to recover such losses through distribution rates during the term of the Settlement. Future rate treatment is to be consistent with the principle that the Company is to have a reasonable opportunity to recover such costs.

"To-go costs" of the Company's non-nuclear resources (i.e., capital costs incurred afte" February 28, 1997, operation and maintenance expenses, and prope ty, 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 thereaftervariable in accordance with the phase-in schedule for the Retail Access program. The 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. In July, 1997, the Financial Accounting Standards Boa'rd's Emerging Issues Task Force (EZTF) reached a consensus on accounting rules for utilities'ransition plans for moving to more competitive environments and provided guidance on when utilities with transition plans will need to discontinue the ~lication of SFAS-71, "Accounting for the Effects of Certain Types of Regulation'".'he major EZTF 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 u 'lity to reasonably determine what the transition plan will entail. The EZTF also concluded that a decision to continue to carry some o all of the regulatory assets (including stranded costs) and liab'lities of the sepa able portion of the bus'ess that is discontinuing the appl'ation of SFAS-71 should be determined on the basis of where the regulated cash flows to realize and settle them will be der'ved. Zf a t ansition plan provides fo" a non-bypassable fee fo" the recovery of stranded costs, there may no- be any significant write-off d'cont'nued for a segment.

'f SFAS-71 is The Company's application of the EZTF 97-4 consensus has not affected its

'nancial pos'tion or results of operat'ons because any above. market generation costs, regula ory assets and regulatory liabil'ties associated with the generation po zion of its business will be recovered by the regulated portion of tne Company through its distribution rates, g'ven the Se"tlement provisions. The Set lement provides for recovery of all prudently inc 'rred sunk costs (all investment in electric plant and electric regulatory assets) as of March 1, 1997 by inclusion in rates charged pursuant to " the Company's distribution access ta 'ff. The Settlement a'so states tha" he Parties intend tha" the p ovisions oi this Settlement will allow the Company to continue to recover such costs, during the term of the Settlement, unde= SFAS-71 '. and tha "such treatment shall be consistent with the principle tha= the Company shall have a reasonable opportunity beyond July 1, 2002 to recover all such costs!'s noted previously, the fixed portion of the non-nuclear generation to-go costs af ter July 1, 1999 and the variable portion of the non-nuclear generat'on to-go costs after July 1, 1998 are subject to market forces and would no longer be able to apply SFAS-71.

The Company's net investment at Decembe" 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

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 wh'ch 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.

En a competitive natural gas market, strandable assets would arise whe e customers migrate away from dependence on the Company for full serv'e, leav'ng 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 w'hether and to what extent there may be an impact on the level and recoverability of stiandable assets cannot be determinea at this t'me.

At December 31, 1997 the Company believes that its regulatory and st andable 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. lt the PSC may seek to apply similar principles to other types of gene ating appears that facil'ties. A determination in this proceeding could have an impact on strandable assets.

CAPITAL EXPENDITURES The Company's 1998 construction expenditures program is currently estimated a= $ "24 million. The Company has entered in"o certain commi"ments for purchase o= materia s and equipment in connect'on w'th that program.

NUCLEAR-RELATED MATTERS DECOMMTSSEONZNG TRUST. The Company is col)ect'ng amounts in 'ts electric rates for the eventual decommissioning of o" the decommissioning of Nine M'e Two.

'ts Ginna Plant and for its 14% share The operating licenses for these plants exp're in 2009 and 2026, respectively.

Under accounting procedures approvec by he PSC, the Company has collected decomm'ssioning costs of approximately s116.1 m': lion through Decembe 31, 1997 ana 's authorized to collect approximate'y $ 22 million annually through June 30, 2002 'or decommission'ng, covering both nuclear un'ts. The amount allowed in

=ates is based on est'mated ultimate decommission'ng costs of $ 296.3 million for Ginna and $ '12.8 million fo" the Company's 14+ share of Nine Mile Two (1995 dollars). These estimates are based on s'te spec'fic cost studies for each plant completed in 1995. Site specific studies of the anticipated costs of actual aecommissioning are required to be submitted to the NRC at %east five years prior to the expiration of the license.

The NRC requires reactor licensees to submit funding plans that establish minimum NRC external funding levels for eactor decommissioning. The Company's plan, filed in 1990, consists of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990, the Company has contributed $ 86.4 million to this fund and, including realized and unrealized investment returns, the fund has a balance of $ 132.5 million as of December 31, 1997. The amount attributed to the allowance for removal of non-contaminated structures is being held in an internal reserve. The internal reserve balance as of December 31, 1997 is $ 29.7 million.

The NRC is currently considering proposals which may impact financial funding requirements for decommissioning of nuclear power plants. Under current

0 ~

'o

60 government could assess licensees for the clean-up of these federal facilities.

In January 1998, the U.S. Supreme Court refused to hear the case, effectively upholding the dismissal of the utility claims.

NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear Waste Act) of 1982, as amended, requires the DOE to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high-level nuclear waste repository is not expected to be operational before the yea" 2010. The DOE is proposing to establ'sh an interim storage facility which may al'ow title to and possession of nuclear waste prior to the establishment o a it to take permanent repository. In December 1996 the DOE notified the Company that the DOE will not start acceptance of Ginna spent fuel ina 1998. Infor January 1997 the DOE released a draft request for proposal outlining process 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,foradjusted quarterly. The Nuclear Waste Act also requires the DOE to the disposal of nuclear fuel irradiated after April 6, 1983, for a provide charge of approximately one mill ($ .001) per KWH of nuclear .energy generated and sold. This charge (approximately $ 3.6 million per year) is'c~jently being collected from customers and paid to the DOE pursuant to PSC I'uthorization. The Company expects to utilize on-site storage for all-spent or retireG 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 spen" nuclear fuel from util'ty companies. In the Company's determination of nuclear fuel costs it has taken into account that nuclear fuel would not be reprocessed and has provided fo" disposal costs in accordance with the Nuclear Waste Act. The Company has completed a conceptual stucy 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 sa ety cr'teria,'s to install high-capacity spent fuel racks in the existing area of the spent fuel pool. The additional storage capacity, scheduled to be

'mpiemented prior to September 2000, would allow interim storage of all spent fue'ischarged from the Ginna Plant through the end of its Operat'ng License in "he yea" 2009.

ENVXRONMENTAL MATTERS The following tables list various sites where past waste handling and disposal has o" may have occurred that are discussed below:

TABLE I COMPANY-OWNED SITES Estimated Site Name Location Company Cost West Station* Rochester, NY Ultimate costs have East Station Rochester-, NY not been determined.

Front Street* Rochester, NY The Company has Brewer Street Rochester, NY incurred aggregate Brooks Avenue Rochester, NY costs for these sites

~ Canandaigua Canandaigua, NY through December 31, 1997 of $ 4.3 million.

• Voluntary agreement signed.

k

o 62 sewer system project showed a layer containing a black viscous material. The study of the layer found that some of the soil and ground water on-site had been adversely impacted. The matter was reported to the NYSDEC and, in September 1990, the Company also provided the agency with a risk assessment. The report oz 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 ~here gas manufacturing took place 's located in Canandaigua, New York. Limited investigative work performed tnere du ing the summer of 1995 has shown evidence of both the former gas manufactur'ng operations and leakage from fuel tanks. The NYSDEC was informed; the fuel tanks removed; and additional investigative work continues. The SIR costs associated with these actions are included in Table I. .The NYSDEC has not taken any action against the Company as a result of these findings.

On another portion of the Company's property (Brewer Street}, the County of Monroe has installed and operates sewer lines. ,During sewer installation, tne 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 azea. The County's letter takes the position that it intends to seek reimbursement for its additional costs incurred with respect to the materials once. the,NYSDEC identifies the generator thereof and that any further cleanup action which the NYSDEC may require at the retention pond site is the Company's .responsibility.

In a November 1997 letter, the County has claimed that the Company was the original generator of the materials. -- It asserts that liable for 50't of all County costs presently it will hold the Company estimated at a total of approximately $ 5 million -- associated both with the materials'xcavation, treatment and disposal and with effec 'ng a regulatorily-approved closure of the reten"'on pond area. The Company coulc 'ncur costs as yet undetermined were to be found liable fo" such closure and mate ials handl'ng, although if it prov'sions of an existing easement a=ford the Company rights which mav sezve to o==se" all or a portion of any such Coun"y claim. To date, the Company has agreec "o pay a 20~a share of the Co nty's '995 'nvestigation of this area, which

's es=imated to cost no more than $ 150,000. bu= no commitment has been made "owa"c any subsequent investigat'ons o" remecia measures which may be

,.

reco. .ended by the investigations.

Monitoring wells installed at another Company fac"'ity (Brooks Avenue) in 989 revealed that an undetermined amo "..". of 'eadec gasoline nad reached the gro nc water. The Company has continued "o monitor 'ree prod ct levels in the we ls. and has begun a modes" free proc c. recovery projec=.

tha= urther It is estimated investigative work 'nto "h's prob'e... r,"ay cos= up =o $ 100,000. While

.e cos" o. corrective act'ons canno= be ce:erm'nec o S .".= 'nves igations are compie"ed, preliminary estimates are no" expectec to exceed $ 500,000.

SUPERFUND AND NON-OWNED OTHER SITES. 'he Company has been or may be associatec as a potentially responsible par"y (PRP) a" seve.". s'es no" owned by The Company has signed orders on consen: =or ve o'hese sites and recorded estimated liabilities tota'ing approximately $ .8 mil'ion.

In one sate, known as the Quanta Reso rces 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 aga'n contacted by EPA in late August, 1996. The EPA informed the Company that it believed certain additional work was required, including a study to determ"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

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 cos" between $ 500,000 and $ 2,500,000 annually.

GAS COST RECOVERY GAS RESTRUCTURING PROCEEDING. In the PSC's Proceeding on Restructur'ng 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 th'rd 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 fo the capacity that could be stranded by converting customers; (c) actively encourage competition including collaboration with marketers to expand the number of customers taking transpor'tation service from the LDC and to provide customer education; and (d) to the extent LDCs cannot shed all their capacity as contracts exp're, to continue to seek lower cost options and more flexibility and shorter contract terms, where cost-effective. LDCs are required to,figeplans addressing the foregoing issues by April 1, 1998. Pursuant to the PSC's:~ders, the cost of capacity defined as "excess" may not be fully recoverable in ra'tes,'ccordingly, the Company's ability to avoid absorbing this cost w'll depend on 'the success of remarketing and portfolio structur'g e"orts and, if such efforts do not result in eliminating all "excess" capacity, on a satisfactory explanation as to why all sucn capacity could not be elim'nated. .he Company is engaged in negotiations with tne Staff of the PSC and other par"ies to address these and other issues related to the future provision o= gas serv'ce. At this time, no assessment of he poten ial impac" of these requ'rements on the Company can be made.

On September 4, 1997, the PSC a'o 'suec =or comment a Staff position pape" wh'ch proposes that LDCs exit =ne'r merchant funct'on. '.e., cease to supp'v the natu al gas commodity to =he' ex's='ng c s"o...ers, with'n 'ive years anc t.".at they elim'nate o" restr c= re t"anspo"ta='on anc s"orage capacity con"racts extending beyond five years so as "o elim'nate obgations beyond that po'nt, excep" where capac'ty is recu'rec to ="'='pera='ona'equiremen"s or the LDC's obligations as the "supp 'e" o= 'as" reso."" to c"s"ome s having no competitive alternative. I'coptec by ='."e PSC, =he Staff proposal could require the Company to remarke more capac'", anc to co so more rap'c'y than currently contemplated.

prec'c=ion can be made as to w.".e=her =he S=aff proposa so, the exten of its potent'a'mpa"= on ='.".e Compan;.

w'e The comme.".". per'oc co.-.c'ec on December 20, '997, and no adopted or, 1995 GAS SETTLEMENT. ;he Company '..as en=erec 'nto several agreements to help manage its pipeline capac'", costs anc '..as s "cess'" 'y me" Settlement targets for capacity remarke 'ng =o= =he =we ve mon=hs encir.g October 31, 1997, thereby avoiding negative financia 'mpac=s =o" ="..a per'.od. .he Company beeves that it will also be successfu. 'n mee='ng the Settlement targets in the emaining year of the Settlement pe" od, a'=ho gh no ass rance may be given.

The FERC approved a change '".. rate des gn 'or the Great Lakes Gas Transmission Limited Partnersh'p (Great Lakes) on which the Company holds transportation capacity. This change .resulted 'n 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 Sett}ement, the Company may recover approximately one-half of the surcharge in "ates charged to customers; but the remainder may no" be passed through and has been previously reserved. The Company, which paid the Great Lak'es assessme..t unde" protes , vigorously contested it before the FERC, bu" 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.

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 Compet'tive 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 liabil'ty unde= the State action exemption, that the Company's actions did not injure compet'tion and that the Department of Justice's cia'ims 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~ for electricity from Qualifying Facilities at a rate that equals the cost to fhe ugility of power it would otherwise produce itself or purchase from other sources ('voided Cost).

With the exception of one contract which the Company was compelled by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts of capacity, the Company has no long-term obligations to purchase energy from Qualifying Facilities.

~ Unde." State law and regulatory requirements in effect at the time the co..tract with Kamine was negotiated, the Company was required to ag ee to pay Kam'ne a price for power that is substantially greater than the Company's own cos" of production and other purchases. Since that time the State "six-cent" law mandat'ng a minimum price highe" than the Company's own costs has been repealed and PSC est'mates of future costs on which the contract was based have declined drama 'cally.

In September 1,994, the Company commenced a lawsuit in New York State Supreme Court, Monroe County, seeking to void or, alternatively, to reform a Powe" Purchase Agreement with Kamine for the purchase of the electrical output of a cogenerat'on facility in the Town of Hume, Allegany County, New York, for a term of 25 years. The contract was negot'ated pursuant to the spec'fic pricing requirement o' State statute tha was later repealed, as well as estimates of Avoided Costs by the PSC that subsequently were drast'cally reduced. As a result, the contract requires the Company to pay prices fo" Kamine's elec rical output that dramatically exceed current Avoided Costs and current proj ections of Avoided Costs. The Company's lawsuit seeks to avoid payments to Kamine that exceec 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

~.

68 INTERIM FINANCIAL DATA Xn the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the availability of surplus electricity. The sum of the quarterly earnings per share may not equal the fiscal year earnings per share due to rounding.

(Thousands oi Dollars)

Ea=nirgs pe" Common Share Opera ing Ope"ating Net Ea"nings on (ir. dollars)

Septe..e'er Oua"te= Ended Revenues Income income Common Stock Basic Diluted Dece.".5e= 31, 1997 $ 271,039 $ 24,406 $ 14.031 $ 12,726 $ .32 $ .32 30, 1997 221,335 34,616 21,724 20,419 .52 .52 June 30, 1997 229,419 31,125 18, 172 16,681 .42 .C2 Ya"ch 31, 1997 314,845 55,194 41,433 39,729 1.02 1.02 Dece"..5e 31, $ 274,431 $ 33,048 $ 22,228 $ 20,362 $ 0.52 $ .52 30, 1996 1996'epte.".ke" 234,843 36,159 21,062 19, 196 0.49 .49

~~une 30. 1996 235.577 23,115 11,732 9,866 0.25 .25 Ya"ch 31. 1996 309,195 56,866 42,489 40.623 1.05 1.05 Decerhe" 31, 1995" $ 270,518 $ 32,324 $ (387) $ (2,253) $ (.05) $ (.05)

Septe.-.>e" 30. 1995 245,145 41,738 26.934 25,068 .65 June 30, 1995 219,546 29,454 14,861 12,995 .34 .34 Yiatch 31> 1995 281,119 46,557 30,520 28,653 .75 .75 Reclassified for comparative purposes.

Includes recognition of $ 28.7 million net-of-tax gas settlement adjustment.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Noae

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 th's 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 ZZ - Valuation and Qualifying Accounts.

(a) 3. Exh'bits - See List o'xhibits.

(b) Reports on Form 8-K The Company filed a Form 8-K dated Decembe" 5, 1997, reporting unde" Item 5, Other Events, approval by the PSC of the Company's Competitive Opportunities Case Settlement with the PSC staf'nd othe part'es wi"n respect to the restruc ur'ng of the electric utility indus"ry in New York State.

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. (Piled in Regist ation No. 33-49805 as Exhibit 4-5 in Ju)y 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 Pile 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 Rocheste 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 Regwstration No. 33-49805 as Exhibit 4-5 in July 1993)

Exhibit 4.2* Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of

~ the State of New York on March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarte" ended March 31, 1994, SEC File No. 1-672.)

Ex".ib' 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 Ma ch 31, 1996, SEC File No. 1-672) xLibit 4.4>> General Mortgage to Bankers Trust Company, as Trustee, dated Septembe" 1, 1918, and suppleme..ts thereto, dated March 1, 1921, Octobe" 23, 1928, August 1, 1932 and May 1, 1940. (Filed as xhib't 4-2 'n :ebruary 199 on Form 10-K :or the yea" ended December 31, '990, SEC File No. 1-672-2)

Exhibit 4-5* Supplemental Indenture, dated as of March 1, 1983 between the Company and Bankers Trust Company, as Trustee (Filed as Exhibit 4-1 on Form 8-K dated July 15, 1993, SEC File No. 1-672)

Exhibit 10-1* Basic Agreement dated as of September 22, 1975 among the Company, Niagara Mohawk Power Corporation, Long Island Lighting Company, New York State Electric & Gas Corporation and Central Hudson Gas & Electric Corporation. (Filed in Registration No.

2-54547, as Exhibit .5.-P in October 1975.)

Exhibit 10-2* Letter amendment modifying Basic Agreement dated September 22, 1975 among the Company, Central Hudson Gas & Electric Corporation, Orange and Rockland Utilities, Inc. and Niagara Mohawk Power Corporation. (Filed in Registration No. 2-56351, as Exhibit 5-R in June 1976.)

0 ~ i e

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 yea" ended December 31, 1995, SEC File No. 1-672-2)

Exhibit 10-17* (A) Change of Control Agreement dated January 2, 1997 between the Company and Michael J. Bovalino, Senior Vice President, Energy Services. (Filed as Exhibit 10-18 in February 1997 on Form 10-K for the year ended December 31, 1996, SEC File No. 1-672-2)

Exhibit 10-18 Amended and Restated Settlement Agreement dated October 23, 1997 between the Company the Staff of the New York Public Service Commission (PSC), and certain other parties (Filed as Exhibit 10-4 on Form 10-Q for the quarter ended September 30, 1997, SEC File No. 1-672) as amended pursuant to an order of the PSC issued January 14, 1998 .-N'3ccluding Appendices) filed herewith.

Exhibit 10-19~ (A) Form of Rochester Gas and Electric Corporation 1996 Performance Stock Option Plan Agreement. (Filed as Exhibit 10-1 in November '997 on Form 10-Q for the quarter ended Septembe 30, '997, SEC ": ile No. 1-672) 10-20* (A) Agreement, datec Octobe" ', '997, between the Company and Michael T. Toma'no, Senior Vice Pres'dent and General Counsel. (Filec as Exh'bit 10-2 'n November 1997 on Form 10-Q fo" the q ar=er encec September 30, 1997, SEC File No.

1.672)

Ex'.-'b't 10-21* Agreemen" cated as o= Sep=ember 23,'997 between the Company and Internationa'us'..ess Machines Corporat'on. (Filed as Exhibit 10-3 '.-. November 997 on For;.. 0-Q 'or the quarter nded September 30, 997, SEC .='Ie No. -672)

Exh'bi" 23 Consen" o Pr'ce Nate"ho se P, independent accountants "xh'bit 27 Financial Da" a Schec "e. p rsuant to tern 601 (c) of Regulation S-K. ~

Incorporated by reference.

(A) Denotes executive compensation plans and arrangements.

The Company agrees to furnish to the Commission, upon request, a copy of all agreements or instruments defining the rights of holders of debt which do not exceed 10% of the total assets with respect to each issue, including the Supplemental Indentures under the General Mortgage and credit agreements in connection with promissory notes as set forth in Note 6 of the Notes to Financial Statements.

76 SIGNATURE TITLE DATE ir D'ctors:

/S/ WILLIAM BALDERSTON Wz 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. Grxer

/S/ SUSAN R. HOLLIDAY Director February 11, 1998 Susan R. Ho z ay

/S/ JAY T. HOLMES Director February 11, 1998 Jay T. Ho mes

/S/ SAMUEL T. HUBBARD,JR Director February 11, 1998 Samue T. Hu ar ,Jr.

/S/ ROGER W. KOBER Direc"or February 11, 1998 Roger W. Ko er

/S/ CONSTANCE M. MITCHELL D'rector February 11, 1998 Constance M. Mite e

/S/ CORNELIUS J. MURPHY Director February 11, 1998 Come xus 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

EXHIBITE 0

• ROCHESTER GAS & ELECTRIC CORPORATION Nuclear Opera'tions Group PRESIDENT

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CHAIRMAN,CEO S. RICHARDS SR. VICE PRESIDENT ENERGY OPERATIONS P. C.WILKIBPS VICE PRESIDENT NUCLEAR OPERATIONS R. C. MECREDY DEPARTMENT MANAGER ~ DEPARTMENT MANAGER PLANT MANAGER DIRECTOR .;,

NUCLEAR ENGINEEIUNO SERVICES =

NUCLEAR ASSESSMENT 8: COST 'UDGET T.A. MARLOW R. J. WATTS J.A. WIDAY G.M. VAUGHN DEPARTMENT MANAGER SUPERINTI'.NDENT SUPERINTENDENT NUCLEAR'GUUNINO GINNAPRODUCTION OINNAMAINTENANCE-iLW. POPP '.A. MARCHIONDA J.P. SMITH Girraa Leadership Team

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