ML17059A818

Rochester Gas & Electric Corp Annual Rept for 1994

ML17059A818
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1994
From:	ROCHESTER GAS & ELECTRIC CORP.
To:
Shared Package
ML17059A817	List: ML17059A816 ML17059A818 ML17059A819 ML17059A820 ML17059A821 ML20083P752
References
NUDOCS 9505240379
Download: ML17059A818 (66)

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.v<.l ANNUAL REP 0 RT 1994 9505240379 9505i5 PDR ADOCK 05000220 I

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he Company supplies electric and gas service wholly within the State ofNew York, and is engaged in the production, transmission, distribution and sale ofthese services in a nine-county area centering around the CityofRochester.

The Company's territory, which has a population ofapproximately one million, is well diversified among residential, commercial and indus-trial customers. In addition to the CityofRochester, which is the third largest city and a major I~

industrial center in the State, it includes a substantial

@hew'uburban area with commercial growth and a large and prosperous farming area.

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~.K'~V p Tll~e Key Ye A ISff>gllnlLItf'ml~ffe RGtkE is positioned to succeed in this rapidly developing competitive environment.

Corporate strategies arc refocused to take advantage of new opportunities, and the organization structure is aligned to deliver results in three key areas.

Corporate Services is responsible for corporate vision and strategic planning - analyzing the risks and charting the course for the future. Customer Operations is charged with improving service and value to our customers and shareholders alike through the outstanding commitment and teamwork of our people. Customer Development willfocus on customer satisfaction, research, marketing and building customer alliances through understanding and collabora-tion negotiating a profitable future for RGM.

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Use of1994 Revenue Dollar Taxes 194 Other 0 erations Purchased Gas 194 194 Wages and Benefits 134 Depreciation &Amortization 94 Dividends &Reinvested Earnings 7c Electric Fuel &Purchased Electricity 8e i

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,y,)E,r Interest Source of1994 Revenue Dollar Residential (24>s Electric, 234. Gas) 47'ommercial (21e Electric,5e Gas) 264 N

x,"Eg Industrial (15e Electric, Irt Gas) 16qt Other (Sc Electric,4e Gas) q~l Eq',,

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HIGHLIGHTS LETTER TO SHAREHOLDERS MANAGEMENTS DISCUSSION ANDANALYSIS 10 FINANCIALREPORTS INVESTOR INFORMATION DIRECTORS AND OFFICERS NEW APPOINTMENT 27 58 INSIDE BACKCOVER INSIDE BACKCOVER 0

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LETTER TO SHAREHOLDERS ';

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=-':;-. -,DISCUSSION ANDANALYSiS;;"..':--'.;:-.-.'='-:..--.= --.

10 44<<s FINANCIAL PORTS I

, INVESTOR INFORMATION

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Rochester Oes etttt ttectrle Oortsorettott FinanCia/Data(Dollars in Thousands)

Operating revenues: Electric Gas Operating expenses Operating income Net income Earnings applicable to common stock Rate ofreturn on average common equity Common Stock Data Weighted average number ofshares outstanding (thousands)

Per common share:

Earnings as Reported Earnings before non-recu'rring items Dividends Book Value (year end)

Year-end market price Number ofCommon Stock Shareholders at December 31 Operating Data Sales (thousands)

Kilowatt-hours to customers Kilowatt-hours to other utilities Therms ofgas sold and transported Customers (year end)

Electric Gas Construction expenditures, less allowance for funds used during construction (thousands)

Employees (year end) 1994 1993 Change

$674,753

$655,316

$326,061

$293,708

$845,802

$801,791

$155,012

$147,233

$ 74,375

$ 78,563

$ 67,006

$ 71,263 11.73%

10.25%

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(6) 14 37,327 35,599 5

$1.79

$2.00 (11)

$2.39

$2.19 9

$1.76

$1.72 2

$19.78

$19.70

$20.88

$26.25 (20) 37,212 38,102 (2) 6,520,287 6,507,064 1,021,733 743,588 520,006 529,505 338,509 274,342 335,874 271,353 37 (2) p 1

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$117,219

$139,407 (16) 2,075 2,535 (18)

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A Very Good Year) ineteen ninety-four was another good year. The reasons for continued success go well beyond an improved financial performance where revenues, earnings from continu-ing operations and dividends were again up over the previous year with operating and capital expenses falling under forecast. I like to believe the big reason for success is that in 1994 we brought your company well along in the new direction we charted in our business plans. Our key initiatives to improve financial performance and position RG&E for the new competitive utilityenvironment are working well.

Rochc5tcf Gas ud Beark COfpOfItlOll The Rate Settlement Agreement Is Working(

The rate settlement agreement we negotiated in 1993 with the New York State Public Service Commission (PSC) and a dozen other interested parties is paying offfor every-one. We accepted a reasonable amount ofrisk in the agreement that sets caps on rates and penalties for poor performance. But, in taking on the risks, the agreement we negotiated also offers incentives where superior performance on our part brings increases in earnings for our shareholders and savings for our customers.

Just one year into the three-year rate settlement agreement we not only achieved all the goals, but exceeded many indicators. In fact, the agreement is working so well, we chose not to press our rate increase allowances to the maximum under the terms. The strategy was to forego greater short-term profits with the intent ofminimizing increases for customers and boosting longer-term value for our shareholders. I believe we will continue to perform well for the balance ofthe agreement that expires in mid-1996.

Rochester G4$ phd Bcctdc Corporation The Next Step!

No successful competitor ever achieves success without taking some risks. When our rate settlement agreement expires we expect to replace itwith a competitive initiative plan that willtake us to the next step. We are working right now with the PSC Staff and other interested parties to win support for our proposal that will be officiallyfiled for consideration this Summer.

The PSC is soliciting competitive postur-ing proposals from New York State investor-owned utilities. In deliberations

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o erN Kob on two plans already under review, the PSC Staff suggests that the companies could be more generous with regard to assuming risks and in bringing benefits to ratepayers sooner rather than later. Our plan willbe different, and one we think may be the best option for all parties involved.

We are venturing to assume risks that are in line with a competitive marketplace. By the terms of our competitive initiative we willvoluntarily compel o'urselves to be a competitive energy supplier and service company. Such a competitive position should allow us to retain our customer base and to expand our markets. And, of course, for assuming the greater risks associated with competition, our plan calls for greater oppor-tunities to increase value to our shareholders.

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Here's what we'e saying to the PSC and the other parties in the process. "You want us to be competitive for the benefit ofour customers. We agree and we willoffer a plan that can make that happen. And in return we want you to shape regulation that not only allows competitive operation, but actually promotes itwith rewards for success, penalties for failure, and willallow us to have more say in how our business is regulated." I view our competitive initiative proposal as being the single most important element in secur-ing our future success.

Rochester Gas and Bectrie Corporal Control ofOperating Expenses Exceeds Goals!

Once again our employees have done an outstanding job in managing our operating and capital expenses. Most of the saving was achieved through the extraordinary perfor-mance ofour employees.

They continue to find better ways to get the jobs done as they take on more responsibility in our dramatically reduced work force.

A Twenty Percent Work Force Reduction With No Layoffs!

No matter what part of the country you'e in when you read this letter it's very likely that work force reductions are common in your locale. That's the mandate of this era of fierce competition, rapid technological advances and accelerated shifts in career and skill paths. Utilities are not immune from these influences. Last year I reported to you that 173 out of 217 eligible employees decided to take advantage ofone oftwo Temporary Retirement Enhancement Programs (TREP). That helped financial performance. But, we knew itwas not enough.

In the Summer of 1994 we offered a third TREP where all employees were eligible and 399 people took advantage ofthe offer. That meant we reduced our 1993 work force by 572 employees and arrived at today's complement ofjust over 2,000 people. We fully intend to prepare for competition by permanently reducing operating costs, continuing to review the company's organizational structure and bringing long-term financial improvement to the company.

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0 The after-tax cost oF the last TREP was written-offin 1994 against shareholders'etained earnings, and amounted to $21.9 million.This brings the total cost ofall three TREP programs to $27.2 million.However, we project the associated after-tax savings from the programs to be about $61 millionthrough 1998, Rochester Cos ond Uectrte Corporetlon Our Reorganization Is No Small Matter~

Ofcourse, with the work force reductions we knew we'd have to reorganize the com-pany internally. Our reorganization, though, was not mainly prompted by the 20 percent work force reduction. For the last few years we have been developing plans to best reor-ganize RG8~E to not only survive but prosper in the new competitive utilitymarketplace.

We'e done that.

While formation ofcompetitive business units within utilities has been a popular approach with some companies, we decided to reject that strategy. We intend to remain one company with one-stop shopping offering both electric and gas energy and services.

We intend to continue marketing energy to customers based on their best interests with regard to costs and efficiencies. We intend to be more competitive and more profitable.

In pursuing these goals, we flattened the organization by substantially reducing middle management positions and the number ofdepartments.

RG&E is being redesigned around three major areas. Customer Operations consists of energy production, supply and distribution. Customer Development focuses on customer satisfaction, marketing and research functions. Corporate Services renders internal support functions such as human resources, public affairs, strategic development and financial services.

The reorganization is intended to offer high quality service to our customers at a lower operating cost. In this rapidly developing competitive marketplace customers focus strongly on value. We are determined to remain their supplier of choice by offering the best combination ofprice and service.

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Holding On To Customerst Competition is already here in the form ofvery real electric energy alternative op-tions for some of our larger commercial and industrial accounts. Electric cogeneration potential for some customers and proliferation ofindependent power producers can be attractive options for qualifying businesses.

We have been negotiating energy contracts with some major customers who have been considering alternative opportunities. In each case we have been able to so far retain the business through negotiated pricing and energy efficiency incentive agreements. While the lower energy costs help local com-merce and industry to remain competitive themselves, we also are able to retain their business and avoid any erosion ofour own competitive posture, Rochester Gos octet Oectrte Cortsorot loss Things Are Looking Up!

While I certainly can't claim to predict our future with accuracy, I can look back to the recent past quite precisely. Over the last few years we have kept pace with the goals ofour ambitious corporate business plan. We said we were getting hold ofour future, and we'e been doing that. Last year I wrote here that this is "a new beginning for us."

Well, we'e now beyond the beginning. We are in the midst of the transition. In fact, I believe we are one of the leaders. What we are able to influence and achieve in the next year or two willtell the story. And then, using the same precision ofhindsight, I believe we, you, our customers, and employees willjudge our efforts to have been most successful and profitable.

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Roger W. Kober Chairman ofthe Board, President and Chief Executive Officer

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OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Rochester I

Gas oattt Bectrte Corporotloat T he followingis Management's assessment ofsignificant factors which affect the Company's financial condition and operating results.

Earnings Sunnnary Operating earnings have improved due to modest rate reliefand lower interest expense, coupled with cost control efforts by the Company and savings resulting from work force reduction programs in 1993 and 1994.

Presented below is a table which summarizes the Company's Common Stock earnings on a per-share basis. Non-recurring items and their effect on earnings per share have been identified. Earnings per share as reported in 1994 fell t

below 1993 levels, reflecting one-time charges for work force reduction programs completed during the past year. A total of572 persons, or about lAB]L 22 percent ofthe work force elected to participate in one ofthree programs offered in 1993 and 1994. Ofthat total, 399 were participants in the most recent program completed on October 1, 1994. The overall after-tax savings ofthe program are estimated to be about $61 millionthrough 1998. The latest program resulted in a one-time charge in September 1994 of$33.7 million,or $.59 per share, net oftax. The 1993 writeoffs totaled

$8.2 millionor $.15 per share for the earlier programs.

In addition to the cost ofthe work force reduction programs, earnings as reported include a charge of $.01 per share in 1994 and $.04 per share in 1993 for unrecoverable gas costs.

Excluding the impact ofnon-recurring items, earnings per share for 1994 and 1993 were up despite the effect ofthe issuance ofadditional Common Stock in each year. Future earnings willbe affected, in part, by the Company's success in controlling operating and capital costs within the levels targeted under the terms ofthe 1993 Rate Agreement (see Regulatory Matters), as well as achieving certain incentive goals established in that Agreement. Furthermore, a decision in early 1995 by the Company to discontinue operation ofa weather normalization clause under certain circumstances through May 1995 is expected to have an impact on 1995 earnings as discussed under Operating Revenues and Sales. The impact ofdeveloping competition in the energy marketplace may also affect future earnings.

Earnings per Share Summary (Dollars per Share)

Earnings per Share Before Non-recurring Items Non-recurring Items Gas Under-recovery Writeoff Retirement Enhancement Programs Nine Mile'DvoLitigation Proceeds

'ce Storm Disallowance Total Non-recurring Items Repoited Earnings per Share 1994

$2.39

(.01)

( 59)

$ (.60)

$1.79 1993

$2.19

(.04)

(.15)

$ (.19)

$2.00 1992

$1.91

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$1.86 Dividend Policy In December 1993 the Company announced a quarterly dividend increase from $.43 to $.44 per share ofCommon Stock payable in January 1994. Subsequently, in December 1994 the Company announced a new quarterly dividend rate of $.45 per share payable in January 1995. The Company's Certificate ofIncorporation (Charter) provides for the payment ofdividends on

Rocheaer Gas ad Beark Corporation Common Stock out of the surplus net profits (retained earnings) ofthe Company. The Company believes that future dividend payments willneed to be evaluated in the context ofmaintaining the financial strength necessary to operate in a more competitive and uncertain business environment.

This willrequire consideration, among other things, ofa dividend payout ratio that is lower over time, reevaluating assets and managing greater fluctuation in revenues. While the Company does not presently expect the impact of these factors to affect the Company's abilityto pay the current dividend, future dividends may be affected.

Competition Overview. The Company is operating in a rapidly developing competitive marketplace for electric and gas service. In its electric business, this competitive environment includes a Federal trend toward deregulation and a state trend toward incentive regulation. The passage ofthe National Energy Policy Act of 1992 (Energy Act) has accelerated these competitive challenges by promoting competition in the electric power industry at the wholesale level, and ensuring that a new class ofindependent power producers established under the Energy Act, as well as qualified facilities and other electric utilities, can achieve access to utility-owned transmission facilities upon payment ofappropriate prices. Competition in the Company's gas business was accelerated with the passage ofthe Federal Energy Regulatory Commission's (FERC) Order No. 636. In essence, FERC Order 636 requires interstate natural gas pipeline companies to offer customers "unbundled", or separately-priced, sale and transportation services.

Electric UtilityCompetiflan. Cost pressures on major customers, excess electric capacity in the region, and new technology have created incentives for major customers to investigate different electric supply options. Initially,those options willinclude various forms ofself generation, but may eventually include customer access to the transmission system in order to purchase electricity from suppliers other than the Company.

In New York State, the Public Service Commission (PSC) has encouraged competition by requiring utilities to purchase power from non-utilitygenerating companies at prices in excess of the utilities'nternal cost ofproduction, has established various incentive mechanisms in rate proceedings to provide lower cost energy, and has authorized flexible pricing for certain large customers who have "realistic competitive alternatives".

Phase I ofa PSC proceeding to address various issues related to increasing competition in the New YorkState electric energy markets was completed in the summer of 1994. The PSC approved flexible rate discounts for non-residential electric customers who have competitive alternatives and adopted specific guidelines for such rates. The PSC noted that flexible rates being offered by the Company should serve as one ofthe models for other utilities within the State. Phase IIofthis proceeding is currently underway with an objective to identify regulatory and ratemaking practices that willassist in a transition to a more competitive electric energy market, including investigating the establishment ofan efficient wholesale competitive market, and various issues relating to retail competition. In a Notice issued in December 1994 invitingcomments on proposed principles to guide the transition to competition, the PSC set forth nine general principles as follows. First, competition is endorsed, especially at the wholesale level. Second, service affordabilitymust be maintained. Third, research programs, environmental protection, energy efficiency and fuel diversity must be preserved. Fourth, safety and reliabilitymust not be jeopardized. Fifth, new industry structures should provide increased choice for customers, consumer protection, efficiency incentives and flexibilityto accommodate individual utilities.

Sixth, more competition should lead to less regulation. Seventh, the current vertically integrated industry is incompatible with effective competition. Eighth, utilities that cooperate in the

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o furthering ofthese principles should have a reasonable opportunity to recover their costs. Ninth, changes in the industry should result in rising income levels.

While the Company is in agreement with the spirit underlying most ofthe principles described above, their implementation could subsequently alter the nature and magnitude ofthe business risks faced by the Company. This is especially true ofany change resulting from the seventh principle. In general, the Company believes market-based solutions to the challenges facing this industry willultimately result in the greatest shareholder value, and itwillcontinue to work to implement such solutions. The Company cannot predict when Phase IIwillbe completed or the final outcome ofthis proceeding.

Gas UtilityCompetition. Competition in the Company's gas business has existed for some time, as larger customers have had the option ofobtaining their own gas supply and transporting it through the Company's distribution system. FERC Order 636 enables the Company and other gas utilities to negotiate directly with gas producers for supplies ofnatural gas. With the unbundling ofservices, primary responsibility for reliable natural gas has shifted from interstate pipeline companies to local distribution companies, such as the Company.

In October 1993 the PSC initiated a proceeding to address issues involving the restructuring of gas utilityservices to respond to competition. In December 1994, the PSC issued an order which established regulatory policies and guidelines for natural gas distributors. The requirements ofthe order having the greatest impact on the Company are as follows. First, the Company must offer its customers unbundled access to upstream facilities such as storage and transportation capacity on the interstate pipelines with which the Company does business. Second, the Company may offer to package an individual supply ofgas to an individual customer in cases where that would lower the Company's overall cost ofsupplying gas. Third, the Company must offer an aggregation program whereby individual customers could join together in a pool for the purpose ofpurchasing gas from a supplier; in such cases the Company would stillprovide the service ofdistributing the gas on the Company's system. Fourth, the PSC allowed the fullrecovery ofthe transition costs resulting from FERC Order 636, and required that a share of these costs be borne by firm transportation customers. Fifth, the PSC willinstitute a future proceeding to consider incentive-based gas cost recovery mechanisms, a departure from the fullflow-through mechanism in place today. Lastly, the PSC willinstitute a separate proceeding to bring about programs ensuring that all customers have access to a basic, affordable gas service. The Company is reviewing these policies and, at the present time, is unable to predict their impact.

Competition and the Company's Prospective Financial Position. The stock ofNew York utilities, including the Company, has dropped during the past year reflecting, in part, investor concern over the impact ofthe competitive and fgfII[tIl P JI(]'f)fII)JI/Pg regulatory changes which have occurred. Some critics have suggested that certain New York State utilities should write down certain regulatory or generating assets as a result of these changes. The Company has deferred certain costs and is recognizing them as expenses when they are reflected in rates and recovered from customers as permitted by Statement ofFinancial Accounting Standard No. 71 (SFAS-71). These costs are shown as Regulatory Assets on the Company's Balance Sheet and a discussion and summarization ofsuch Regulatory Assets is presented in Note 10 ofthe Notes to Financial Statements. Deferral ofthese costs is appropriate while the Company's rates are regulated under a cost-of-service approach. In a purely competitive pricing approach, such costs might not have been incurred or deferred. Accordingly, ifthe Company's rate setting were changed from a cost-of-service approach and it was no longer allowed to defer these costs under SFAS-71, certain ofthese assets may not be fullyrecoverable. In

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0 comm Ibxhestcc Gas and occcrk Corporation addition, stranded assets (or other costs) arise when investments are made in facilities or costs are incurred to service customers and such costs may not be fullyrecoverable in rates. Examples include purchase power contracts (i.e. the Kamine/Besicorp Allegany L.P. contract, see Projected Capital and Other Requirements) or uneconomic generating assets. Excluding the Kamine/Besicorp Allegany L.P. contract, estimates ofstranded asset costs are

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highlysensitive to the competitive wholesale market price assumed in the estimation for electricity. The amount ofstranded assets at December 31, 1994 cannot be determined at this time, but could be significant. While the Company currently believes that its regulatory and stranded assets are probable ofrecovery in rates, industry trends have moved more toward competition, and in a purely competitive environment, it is not clear to what extent, ifany, writeoffs ofsuch assets may occur.

The Company's Response. The growing pace ofcompetition in the energy industry has been a primary focus ofmanagement over the past three years. The Company accepts the challenges of this new environment and is working to anticipate the impact of increased competition. Its business strategy for one year and in summary for five years, focuses on improving cost-effective service while reducing expenses and maintaining a competitive return for the shareholder. The Company is engaged in a continuous process improvement program to find opportunities for improved service and efficiency. Ithas implemented three workforce reduction programs during 1993 and 1994 which have had, and willcontinue to have, a favorable impact on reducing operating costs, while stillenabling the Company to deliver safe, quality service. Also, the Company in August 1994 streamlined its internal organization by combining 14 division-sized functions into three functional areas as part of an ongoing effort to provide customers with the best possible service at the lowest possible price.

The Company is operating under a three-year rate settlement which includes caps on rate increases that approximate or are less than projected inflation, contains incentive programs that tie performance to earnings and stabilizes revenue through revenue adjustment mechanisms.

By settlement with the PSC and others, the Company has a competitive rate tariffthat allows negotiated rates with larger industrial and commercial customers that have competitive electric supply options. Furthermore, the Company has proposed for PSC approval two new flexible pricing tariffs to encourage economic development and new business growth in our service territory.

The Company has responded to the changes in the gas business by positioning itself to obtain greater access to both U.S. and Canadian natural gas supplies and storage, so that itcan take advantage ofthe unbundling ofservices that results from FERC Order 636. A major element of this strategy went into place in 1993 with the start-up ofthe Empire State Pipeline. The Company is engaged in various aspects ofcapacity release and is investigating other options available to mitigate its costs and increase earnings in the new gas business environment.

The Company is evaluating all the factors which impact the rates it charges its customers and therefore its competitive position, both with respect to industrial and commercial customers as well as residential customers. In that regard, it is reviewing its regulatory assets (costs which have been deferred for collection in future rates) and generating facilities for their impact on the Company's rate structure. The Company's workforce reduction programs, efforts to control fixed and operational costs and decisions to delay any collection ofincentives earned under the 1993 Rate Agreement (see Regulatory Matters) all relate to a focus on trying to maintain a rate structure which has long-term benefits for the competitive presence ofthe Company in the industry.

The Company is reviewing its financing strategies as they relate to debt and equity structures,

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the cost ofthese structures including the dividend program and their impact on the Company's rate structure. Allofthese evaluations are in the context ofthe new competitive environment and the abilityofthe Company to shift from a fullyregulated to a more competitive and growth-oriented organization.

In addition to strategies aimed at creating a competitive rate structure, the Company is reviewing strategies which may enhance its ability to respond to competitive forces and regulatory change. These strategies may include business partnerships or combinations with other companies, internal restructuring involving a separation ofsome or all ofits wholesale and retail businesses, and acquisitions ofrelated businesses. No assurance can be given that any ofthese potential strategies willbe pursued or the corresponding results on the financial condition or competitive position ofthe Company.

Liquidityand Capital Resources During 1994 cash flowfrom operations, together with proceeds from external financing activity (see Consolidated Statement ofCash Flows), provided the funds for construction expenditures, the retirement oflong-term debt and short-term borrowings and the retirement and refinancing ofPreferred Stock. Capital requirements during 1995 are anticipated to be satisfied primarily from the use ofinternally generated funds.

Projected Capital and Other Requirements The Companies capital requirements relate primarilyto expenditures for electric generation, transmission and distribution facilities and gas mains and services as well as the repayment of existing debt. Construction programs ofthe Company focus on the need to serve new customers, to provide for the replacement ofobsolete or inefficient utilityproperty and to modify facilities consistent with the most current environmental and safety regulations. The Company has no current plans to install additional baseload generation.

Under Federal and New York State laws and regulations, the Company is required to purchase the electrical output ofunregulated cogeneration facilities which meet certain criteria (Qualifying Facilities). With the exception ofone contract which the Company was compelled by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts ofcapacity, the Company has no other long-term obligations to purchase energy from Qualifying Facilities.

Under State law and regulatory requirements in effect at the time the contract with Kamine was negotiated, the Company was required to pay Kamine a price for power that is substantially greater than the Company's own cost ofproduction and other purchases. Since that time, the State law mandating a minimum price higher than the Company's own costs has been repealed and PSC estimates offuture prices on which the contract was based have declined dramatically.

In September 1994 the Company filed a lawsuit against Kamine seeking to void its contract for the forced purchase ofunneeded electricity at above-market prices which would result in substantial cost increases for the Company's customers. The Company estimates that Kamine will owe the Company $400 millionby the midpoint ofthe contract term and ifthe contract extends to its full25-year term, the total amount ofsuch overpayments (plus interest) could reach approximately $700 million.Alternatively, the Company sought reliefto ensure that its customers would pay no more for the Kamine power than they would pay for power from the Company's other sources ofelectricity. Kamine answered the Company's complaint, seeking to force the Company to take and pay for power at the above-market rates and claiming damages in an unspecified amount alleged to have been caused by the Company's conduct. The Company is

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unable to predict the ultimate outcome ofthis litigation. The Company began receiving test generation from the Kamine facilityduring the last quarter of 1994. In late December 1994, the Company announced itwould no longer be accepting electric power from this facilitybecause it is the Company's position, in addition to other beliefs, that the Kamine facilityis no longer a "QualifyingFacility"as specified under Federal regulations.

On January 27, 1995, Kamine initiated a lawsuit against the Company in Federal District Court for the Western District ofNew York for alleged anti-trust violations by the Company that are based on the same issues that are raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks injunctive reliefsimilar to that requested in Kamine's answer to the Company's lawsuit in New York State Court and damages of $420 million.The Company intends to vigorously defend against this lawsuit, but is unable to predict the outcome at this time.

The Company's most current Integrated Resource Plan (IRP) explores options for complying with the 1990 Clean AirActAmendments. The IRP is part ofan ongoing planning process to examine options for the future with regard to generating resources and alternative methods of meeting electric capacity requirements. Activities are currently under way to:

~ ModifyUnits 2, 3, and 4 at Russell Station and Unit 12 at Beebee Station, all coal-fired facilities, to meet Federal Environmental Protection Agency standards and Clean AirAct requirements,

~ Explore possible partnerships with certain large customers to use alternative generation or existing generation to mutual benefit,

~ Use demand side management programs to reduce the need for generating capacity, and

~ Replace the two steam generators at the Ginna Nuclear Plant.

Replacement ofthe two steam generators at the Ginna Nuclear Plant is expected to be completed in 1996. Much ofthe preliminary preparation is being done during the normal annual refueling and maintenance outages. The Company anticipates that the 1996 outage for refueling and final replacement willtake about 70 days. Cost ofthe replacement is estimated at

$ 115 million;about $40 millionfor the units, about $50 millionfor installation and the remainder for engineering and other services. As discussed under Regulatory Matters, a three-year ctTT'o Qrtr rate settlement establishes a mechanism to share variances from the estimated

$ 115 million cost between customers and the Company.

The Company's capital expenditures program is under continuous review and Q

willbe revised depending upon the progress ofconstruction projects, customer demand for energy, rate relief, government mandates and other O

0 factors. In addition to its projected construction requirements, the O

Company may consider, as conditions warrant, the redemption or refinancing ofcertain long-term securities.

Capital Requirements and Electric Operations. Electric production plant expenditures in 1994 included $31 millionof expenditures made at the pCst Company's Ginna Nuclear Plant, ofwhich $ 16 millionwas incurred for preparation to replace the steam generators. The Company spent $ 15 million on this project in 1993. In addition, nuclear fuel expenditures of$ 11 millionwere incurred at Ginna during 1994. A refueling outage at Ginna normally occurs annually for a period ofapproximately 40 to 50 days. Refueling is expected to take place on an 18-month cycle once the new steam generators are installed.

Exclusive offuel costs, the Companies 14 percent share ofelectric production plant expenditures at the Nine MileTwo nuclear facilitytotaled $5 millionin 1994. Expenditures of

$5 millionduring 1994 were also made for the Company's share ofnuclear fuel at Nine MileTwo.

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~ ~ ~ ~ 0 ~ ~ 1 Q~QO On October 2, 1993 Nine MileTwo was taken out ofservice for a scheduled refueling outage and resumed fulloperation on December 3, 1993. The next refueling outage forNine MileTwo is scheduled forApril 1995.

Electric transmission and distribution expenditures, as presented in the Capital Requirements table, totaled $26 millionin 1994, ofwhich $24 millionwas for the upgrading ofelectric distribution facilities to meet the energy requirements ofnew and existing customers.

Capital Requirements aftd Gas Operations. The Empire State Pipeline (Empire), an intrastate natural gas pipeline subject to PSC regulation between Grand Island and Syracuse, New York

'ommenced operation in November 1993. Empire provides capacity for up to 50 percent ofthe Company's gas requirements. The Company is participating as an equity owner ofEmpire, along with 'subsidiaries ofCoastal Corporation and Westcoast Energy Inc. The PSC authorized the Company to invest up to $20 millionin Empire. The Company's share ofownership in Empire willdepend upon final project costs and method offinancing selected by Empire. In June 1993 Empire secured a $ 150 millioncredit agreement, the proceeds ofwhich were used to finance approximately 75 percent ofthe total construction cost and initialoperating expenses. At December 31, 1994 the Company had invested a net amount of$ 10.3 millionin Energyline and was committed to provide a guarantee for $9.7 millionofthe borrowings under the credit agreement.

Replacement ofolder cast iron mains with longer-lasting and less expensive plastic and coated steel pipe, the relocation ofgas mains for highway improvement, and the installation ofgas services for new load resulted in gas property construction requirements of$20 millionin 1994.

Environmental Issues General. The production and delivery ofenergy are necessarily accompanied by the release of by-products subject to environmental controls. In recognition ofthe Company's responsibility to preserve the quality ofthe air, water, and land it shares with the community it serves, the Company Capital Rerluirentents Type of Facilities Actual Projected 1992 1993 1994 1995 1996 1997 (Millionsof Dollars)

Electric Property Production Transmission and Distribution Street Lighting and Other Subtotal Nuclear Fuel Total Electric Gas Property Common Property Total Carrying Costs Allowance for Funds Used During Construction (AFUDC)

Deferred Financing Charges Included in Other Income Total Construction Requirements Securities Redemptions, Maturities and Sinking Fund Obligations~

Total Capital Requirements

'Excludes ros ective refinancin s.

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84 85 69 11 16 16 95 101 85 19 20 20 15 21 12 129 142 117 2

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81 101 68 19 21 21 100 122 89 17 19 19 11 17 21 128 158 129 4

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Rochester Gas and Benrie Corpora(Ion has taken a variety of measures (e.g., self-auditing, recycling and waste minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental effects from its energy operations and, specifically, to manage and appropriately dispose ofwastes currently being generated. The Company, nevertheless, has been contacted, along with numerous others, concerning wastes shipped off-site to licensed treatment, storage and disposal sites where authorities have later questioned the handling ofsuch wastes. The Company

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typically seeks to cooperate with those authorities and with other site users to

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develop cleanup programs and to fairlyallocate the associated costs. (See Note 10 ofthe Notes to Financial Statements.)

Federal Clean AirAct Amendments. The Company is developing strategies responsive to the Federal Clean AirActAmendments of 1990 (Amendments).

The Amendments willprimarilyaffect air emissions from the Company's fossil-fueled electric generating facilities. The Company is in the process of identifying the optimum mix ofcontrol measures that willallow the fossil fuel based portion ofthe generation system to fullycomply with applicable regulatory requirements. Although work is continuing, not all compliance control measures have been determined. A range ofcapital costs between $20 millionand $30 millionhas been estimated for the implementation ofseveral potential scenarios which would enable the Company to meet the foreseeable NOx and sulphur dioxide requirements ofthe Amendments. These capital costs would be incurred between 1996 and 2000. The Company estimates that it could also incur up to

$2.1 millionofadditional annual operating expenses, excluding fuel, to comply with the Amendments. The Company anticipates that the costs incurred to comply with the Amendments willbe recoverable through rates based on previous rate recovery ofenvironmental costs required by governmental authorities.

Redemption ofSecurities Discretionary redemption ofsecurities totaled $24.5 millionduring 1994. A $ 16 millionfirst mortgage bond maturity and $ 11.3 millionofsinking fund obligations were also a part ofthe Company's capital requirements in 1994.

Capital requirements in 1993 included a $75 millionfirst mortgage bond inaturity, $ 17 million ofsinking fund obligations, and discretionary first mortgage bond redemptions of $ 120 million.

Capital Requirements Summary The Company's capital program is designed to maintain reliable and safe electric and natural gas service, to improve the Company's competitive position, and to meet future customer service requirements. Capital requirements for the three-year period 1992 to 1994 and the current estimate ofcapital requirements through 1997 are summarized in the Capital Requirements table.

Financing and Capital Structure Capital requirements in 1994 were satisfied primarilyby a combination ofinternally generated funds and short-term borrowings and the Company foresees modest near-term financing requirements. With an increasingly competitive environment, the Company believes maintaining a high degree offinancial flexibilityis critical. In this regard, the Company's long-term objective is to control capital expenditures, to move to a less leveraged capital structure and to increase the common equity percentage ofcapitalization toward the 50 percent range.

The Company is utilizingits credit agreements to meet any interim external financing needs prior to issuing any long-term securities. As financial market conditions warrant, the Company may, from time to time, issue securities to permit the early redemption ofhigher-cost senior

securities. The Company's financing program is under continuous review and may be revised depending upon the level ofconstruction, financial market conditions, and other factors.

Financing. Under provisions ofthe Company's Charter, the Company may not issue unsecured debt ifimmediately after such issuance the total amount ofunsecured debt outstanding would exceed 15 percent ofthe Company's total secured indebtedness, capital, and surplus without the approval ofat least a majority ofthe holders ofoutstanding Preferred Stock. At December 31, 1994, including the $32.0 millionofunsecured indebtedness already outstanding as discussed in the followingparagraph, the Company was able to issue $37.5 millionofadditional unsecured debt under this provision.

Short-term credit is available from certain banks pursuant to a $90 millionrevolving credit agreement which continues until December 31, 1997 and may be extended annually. Borrowings under this agreement are secured by a subordinate mortgage on substantially all ofthe Company's property except cash and accounts receivable. In addition, the Company entered into a Loan and Security Agreement to provide for borrowing up to $30 millionfor the exclusive purpose of financing FERC Order 636 transition costs (see Energy Supply and Costs Gas) and up to

$20 millionas needed from time to time for other working capital needs. Borrowings under this agreement, which can be renewed annually, are secured by a lien on the Companies accounts receivable. The Company also has unsecured lines ofcredit totaling $72 millionwith several other banks. Funds available pursuant to these lines ofcredit are at the discretion ofthe respective banks. At December 31, 1994 the Company had short-term borrowings outstanding of

$51.6 million,consisting of$32.0 millionofunsecured short-term debt and $ 19.6 millionof secured short-term debt. In addition, borrowings of$ 18.7 millionassociated with FERC Order 636 transition costs (recorded on the Balance Sheet as a deferred credit) were outstanding at December 31, 1994.

In March 1994 the Company redeemed 180,000 shares ofits 8.25% Preferred Stock, Series R, representing all ofthe outstanding shares ofthis series. Atthe Company's option, 120,000 of these shares were redeemed prior to their normal sinking fund redemption date. Later that month, the Company issued 250,000 shares of6.60% Preferred Stock, Series V.

During 1994 approximately 644,000 new shares ofCommon Stock were sold through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan (ADRPlan), providing

$ 14.8 millionto help finance its capital expenditures program. New shares issued in 1994 and 1993 Rate Increases Granted Class of Service Effective Oate of Increase Amount of Increase (Annual Basis)

(000's)

Percent Increase Authorized Rate of Return on Rate Base Equity Electric July 1, 1991 July 1, 1992 July 1, 1993>>

July 1, 1994>>

'July 1, 1995>>

$33,133 32,220 18,500 20,900 21,800 5 5%

9.66%

11.70%

5.2 9.31 11.00 2.8 9.46 11.50 3.0 9.23 11.50 3.0

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9.41 11.50 Gas July 1, 1991 1,148 0.4 9.66 11.70 July 1, 1992 12,316 4.1 9.31 11.00 July 1, 1993>>

2,600 1.1 9.46 11.50 8.90 11.50 July 1, 1995>>

'See under heading Regulatory Matters foradditional details. Amounts for 1995 are subject to certain adjustments to be filed with the FSC b theCompanyinMar<<h 1995.

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through the ADRPlan were purchased from the Company at a market price above the book value per share at the time ofpurchase.

Capital Structure. The Company's retained earnings at December 31, 1994 were $74.6 million,a decrease ofapproximately $0.5 millioncompared with a year earlier. Retained earnings were reduced by approximately $21.9 millionin September 1994 resulting from the charge for a work force reduction program, as discussed under the heading Earnings Summary. Common equity (including retained earnings) comprised 44.5 percent ofthe Company's capitalization at December 31, 1994, with the balance being comprised of 7.3 percent preferred equity and 48.2 percent long-term debt. As presented, these percentages are based on the Company's capitalization inclusive ofits long-term liabilityto the United States Department ofEnergy (DOE) for nuclear waste disposal as explained in Note 10 ofthe Notes to Financial Statements. To improve its capital structure, the Company currently anticipates the issuance of new shares of Common Stock, primarilythrough the Company's ADR Plan. The Company is reviewing its financing strategies as they relate to debt and equity structures in the context ofthe new competitive environment and the abilityofthe Company to shift from a fullyregulated to a more competitive organization.

Rochester Gas <<d Dccttic Corpor<<Ion Regulatory Matters New York State Public Service Commission (PSC). The Company is subject to PSC regulation of rates, service, and sale ofsecurities, among other matters. On August 24, 1993 the PSC issued an order approving a settlement agreement (1993 Rate Agreement) among the Company, PSC Staff and other interested parties. The 1993 Rate Agreement willdetermine the Company's rates through June 30, 1996 and includes certain incentive arrangements providing for both rewards and penalties. The 1993 Rate Agreement amounts are based on an allowed return on common equity of 11.50% through June 30, 1996. Earnings between 8.50% and 14.50% willbe absorbed/

retained by the Company. Earnings above 14.50% willbe refunded to the customers. If,but not unless, earnings fall below 8.50%, or cash interest coverage falls below 2.2 times, the Company can petition the PSC for relief.

In the first quarter of 1994 the Company filed with the PSC certain adjustments required under various clauses ofthe 1993 Rate Agreement and new rates were subsequently approved and became effective for the rate year beginning July 1, 1994 (Year 2 under the Agreement). These new rates primarilyreflect adjustments for higher property taxes, a Federal tax rate increase, and variations in electric sales between actual and projected levels offset, in part, by operating and maintenance expense savings achieved in Year 1 under the 1993 Rate Agreement.

Asummary ofrecent PSC rate decisions is presented in the table titled Rate Increases. The amounts presented in this table do not include any variations from the estimated cost of fuel included in base rates which are or may be collected/refunded through the Company's fuel clause provisions (see Operating Revenues and Sales).

P fg QPPPQ]'gpss f$fg The1993RateAgreementincludes:

~ Incentive mechanisms that have the potential to either increase or reduce earnings from 5 to 110 basis points each, depending on the Company's ability to meet a variety ofprescribed targets in the areas ofelectric fuel costs, demand side management, service quality, and integrated resource management (relative electric production efficiency). During the rate year ending June 30, 1995,

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these incentives have the potential to affect earnings by approximately $ 12 million.

~ Mechanisms for sharing costs between customers and shareholders for operation and maintenance expense variations. In general, these variances are shared 50% by customers and

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I Gas and Gectnc CofpochlioA 50/o by the Company, unless those costs are directly manageable by the Company, in which case there is no sharing and such costs are to be absorbed/retained by the Company.

~ Mechanisms for sharing variances between forecasted and actual electric capital expenditures related to production and transmission facilities. The Company willretain the savings for cost of money and depreciation on underspending variances. Ifthere is an overspending variance, the Company willwrite off50~/o ofthe net cumulative amount ofthe variance.

~ Sharing mechanism regarding the replacement ofthe Ginna Nuclear Plant steam generators.

Agraduated sharing percentage is applied for up to $ 15 millionofvariances, plus or minus, from the forecasted cost oF $ 115 million.Variances above $ 130 millionor below $ 100 millionare absorbed by the Company. Replacement ofthe steam generators was made subject to a final prudency review by the PSC.

~ An Electric Revenue Adjustment Mechanism (ERAM) designed to stabilize electric revenues by eliminating the impact ofvariations in electric sales. A gas weather normalization clause previously in place was retained.

To the extent incentive and sharing mechanisms apply, the negotiated base revenue increase shown in the table titled Rate Increases may be adjusted up or down in Year 3. Negotiated electric base rate increases could be reduced to zero or increased up to an additional 1.6/o in Year 3 and 1.8/o in the followingyear. Negotiated gas base rate increases could also be reduced to zero or increased up to an additional 1.6~/o in Year 3, and 1.8/o in the followingyear, exclusive ofthe impact ofEmpire going into service.

Contained in the rate order forYear 2 is recognition of$9.6 millionrelated to the Company's performance in Year 1, recovery ofwhich the Company has delayed for future consideration. The

$9.6 millionis comprised of the following:

~ $ 1.9 millionfor ERAM,

~ $6.7 millionfor an Integrated Resource Management Incentive or relative electric production efficiency, and

~ $ 1.0 millionfor a Service Quality Incentive.

In electing to delay for possible future recovery those incentive amounts forwhich it was entitled, the Company gave consideration to the current and future competitive environment and its objective for minimizing price impacts on the customer while protecting earnings for shareholders.

The Company obtained PSC approval for a new flexible pricing tarifffor major industrial and commercial electric customers in a settlement approved by the PSC in March 1994. This tariff allows the Company to negotiate competitive electric rates at discount prices to compete with alternative power sources, such as customer-owned generation facilities. Under the terms ofthe settlement, the Company willabsorb 30 percent ofany net revenues lost as a result ofsuch discounts through June 1996, while the remainder may be recovered from other customers. The portion recoverable after June 1996 is expected to be determined in a future Company rate proceeding. Under these tariffprovisions, the Company has negotiated long-term electric supply contracts with three ofits large industrial and commercial electric customers at discounted rates.

It intends to pursue negotiations with other large customers as the need and opportunity arise.

The Company has not experienced any customer loss due to competitive alternative arrangements.

The PSC Staff is currently reviewing the Company's application for the recovery ofcertain deferred gas costs as discussed under the heading Energy Supply and CostGas.

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Rochester Oaa estd oeetrte Cotpofatton The PSC has been conducting proceedings to investigate various issues regarding the emerging competitive environment in the electric and gas business in New York State, as noted under the heading Competition.

The Company became aware during 1993 that it did not account properly for certain gas purchases for the period August 1990-August 1992 resulting in undercharges to gas

. --185-tfoif-;/gi customers ofapproximately $7.5 million.Ofthe total undercharges,

$2.3 million had previously been expensed and $5.2 millionhad been deferred on the

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Company's Balance Sheet. In March 1994, the PSC approved a December 1993 settlement among the Company, PSC Staff and another party providing for the recovery in rates of $2.6 millionover three years. The Company wrote off$2.0 millionofthe undercharges as ofDecember 31, 1993, reducing 1993 earnings by four cents per share, net of tax. In April 1994 the 88<<

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3 Company wrote offan additional $0.6 millionreducing 1994 earnings by 8088

'pproximately one cent per share, net of tax. Due to rate increase limitations

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established forYear 2 ofthe rate settlement, the Company is precluded from

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~p'."4~I recovering the undercharges until Year 3, which begins July I, i995.

In June 1992, the PSC allowed the Company to defer and recover through rates over a period often years approximately $21.3 millionofnon-capital incremental storm-damage repair costs incurred as a result ofa March 1991 ice storm. The PSC has permitted the unamortized balance of these allowed costs to be included in rate base. Rate recovery ofan additional $8.2 millionofnon-capital storm-damage costs incurred by the Company was denied by the PSC and the Company accordingly recorded in the second quarter of 1992 a charge to earnings in the amount of$8.2 million,equivalent to approximately $.15 per share, net of tax.

Results ofOperations The followingfinancial review identifies the causes ofsignificant changes in the amounts of revenues and expenses, comparing 1994 to 1993 and 1993 to 1992. The Notes to Financial Statements contain additional information.

Operating Revenrres and Sales Compared with a year earlier, operating revenues rose five percent in 1994 following a six percent increase in 1993. Operating revenues in 1994 were pushed higher by gains in retail customer electric and gas revenues, while revenues from the sale ofelectric energy to other utilities were basically unchanged from a year earlier. Customer revenue increases in 1994 resulted Operating Revenrres Increase or (Decreasej from Prior Year (Thousands of Dollars)

Electric Department 1993 1994 1994 Gas Department 1993 Customer Revenues (Estimated) from:

Rate Increases Fuel Costs Weather Effects (Heating &Cooling)

Customer Consumption Other Total Change in Customer Revenues Electric Sales to Other Utilities Total Change in Operating Revenues

$18,647 3,171 (1,166) 1,726 (3,185) 19,193 244

$19,437

$21,827 9,093 200 4,374 (4,806) 30,688 (9,180)

$21,508

$ 4,155 29,989 (3,362)

(2,406) 3,977 32,353

$32,353

$ 8,087 25,593 700 1,381 (3,777) 31,984

$31,984

primarilyfrom rate reliefand recovery ofhigher fuel costs. Details ofthe revenue changes are presented in the Operating Revenues table. As presented in this table, the base cost offuel has been excluded from customer consumption and is included under fuel costs, revenue taxes are included as a part ofother revenues, and unbilled revenues are included in each caption as appropriate.

Changes in fuel and purchased power cost revenues normally have been earnings neutral in the past. The Company, however, does have fuel clause provisions which currently provide that customers and shareholders willshare, generally on a 50/o/50/o basis subject to certain incentive limits, the benefits and detriments realized from actual electric fuel costs, generation mix, sales of gas to dual-fuel customers and sales ofelectricity to other utilities compared with PSC-approved forecast, or base rate, amounts. As a result ofthese sharing arrangements, discussed further in Note 1 ofthe Notes to Financial Statements, pretax earnings were increased by $4.4 million in 1993 and $3.9 millionin 1994, primarilyreflecting actual experience in both electric fuel costs and generation mix compared with rate assumptions. Deferred costs associated with the DOE's assessment for future uranium enrichment decontamination and certain transition costs incurred by the Company's gas supply pipeline companies and billed to the Company are being recovered through the Company's fuel adjustment clauses.

The effect ofweather variations on operating revenues is most measurable in the Gas Department, where revenues from spaceheating customers comprise about 85 to 90 percent of.

total gas operating revenues. Variation in weather conditions can also have a meaningful impact on the volume ofgas delivered and the revenues derived from the transportation ofcustomer-owned gas since a substantial portion of these gas deliveries is ultimately used for spaceheating.

Weather in the Company's service area during 1993 was colder than normal, in contrast to 1994 which was warmer than normal, despite record-setting cold weather in January 1994. Overall, weather during 1994 was 4.9 percent warmer than 1993 on a calendar-month heating degree day basis. Warmer than normal summer weather during 1994 and 1993 boosted electric energy sales to meet the demand for air conditioning usage. The decoupling, or separation, ofsales level fluctuations from revenue through the ERAM provisions, discussed under Regulatory Matters, and a gas normalization weather clause (see followingparagraph) may mitigate the effect ofabnormal weather conditions on earnings.

Retail customers who use gas for spaceheating are subject to a weather normalization adjustment to reflect the impact ofvariations from normal weather on a billingcycle month basis for the months ofOctober through May, inclusive. The weather normalization adjustment for a billingcycle applies only ifthe actual heating degree days are lower than 97.5 percent or higher than 102.5 percent ofthe normal heating degree days. Weather normalization adjustments lowered gas revenues in 1994 and 1993 by approximately $ 1.25 million,and $ 1.2 million,respectively.

Adjustments willcontinue through June 1996 in accordance with the 1993 Rate Agreement for weather which is colder than normal. However, beginning in January 1995 and continuing until May 1995, the Company elected to discontinue the operation ofthis clause in circumstances where the weather is warmer than normal bec'ause ofthe unusually mild weather that has been experienced in its service territory and the adverse effects on customer bills. The earnings impact of this decision in 1995 willrange between $3.5 and $8.7 milliondepending on the duration of mild weather for the heating season.

Compared with a year earlier, kilowatt-hour sales ofenergy to retail customers were nearly flat in 1994, after climbing about one percent in 1993. Electric demand for air conditioning usage had a significant impact on such sales in each of these years. During 1993 and 1994, an increase in combined sales to residential and commercial customers more than offset a decline in sales to industrial customers, which occurred as a result, in part, ofa decline in local manufacturing

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employment. The Company had a net gain ofover 2,600 new electric customers during 1994, including nearly 350 new commercial customers.

Fluctuations in revenues from electric sales to other utilities are generally related to the Company's customer energy requirements, New York Power Pool energy market ERVICIN

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~ ~ ~

~ e QNgEI and transmission conditions and the availability ofelectric generation from Company facilities. Such revenues in 1993 and 1994 reflect the sale ofenergy at a lower average rate per megawatt hour, a result, in part, ofcompetition and greater availability ofenergy. With the possibility ofmore open access to transmission services as provided for under the Energy Act, the Company is examining alternative markets and procedures to meet what it believes willbe increased competition for the sale ofelectric energy to other utilities.

The transportation ofgas forlarge-volume customers who are able to purchase natural gas from sources other than the Company remains an important component ofthe Company's marketing mix. Company facilities are used to distribute this gas, which amounted to 13.6 milliondekatherms in 1994 and Recherrer Gee and Becrnc Corporenon 12.4 milliondekatherms in 1993. These purchases have caused decreases in customer revenues, with offsetting decreases in purchased gas expenses, but in general do not adversely affect earnings because transportation customers are billed at rates which, except for the cost ofbuying and transporting gas to our city gate, approximate the rates charged the Company's other gas service customers. Gas supplies transported in this manner are not included in Company therm sales, depressing reported gas sales to non-residential customers.

Therms ofgas sold and transported combined, including unbilled sales, were down about two percent in 1994, after being nearly flat in 1993. These changes reflect, primarily, the effect of weather variations on therm sales to customers with spaceheating. Ifadjusted for normal weather conditions, residential gas sales would have increased about 0.6 percent in 1994 over 1993, while nonresidential sales, including gas transported, would have increased approximately 1.9 percent in 1994. The average use per residential gas customer, when adjusted for normal weather conditions, was slightly down in 1994, followinga modest decrease in 1993.

Fluctuations in "Other" customer revenues shown in the Operating Revenues table for both comparison periods are largely the result ofrevenue taxes, deferred fuel costs, and miscellaneous revenues.

Operating Expenses Increase or (Decrease) from Prior Year (Thousands of Dollars)

Fuel for Electric Generation Purchased Electricity Gas Purchased for Resale Other Operation Maintenance Depreciation Amortization ofOther Plant Taxes Charged to Operating Expenses Local, State and Other Taxes Federal Income Tax Total Change in Operating Expenses 1994 5

(910) 5,439 27,506 515 (6,624) 3,284 2,886 11,915

$44,ln1 1993 8 (2,505) 1,857 25,593 8,757 (1,027)

(176)

(675) 2,640 5,739

$40,203

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ s QQ

~

~ ~ ~ ~ ~ ~ ~

FIRST ttochester Gas arid Gectrlc Cortsoratlon Operating Expenses Compared with the prior year, operating expenses were up $44.0 millionin 1994 after increasing $40.2 millionin 1993. These increases were driven by higher gas purchased for resale costs in each comparison period. The increases in operating expenses were mitigated by the Company's continuing efforts to curtail increases in maintenance and other operation expenses. Operating expenses are summarized in the table titled Operating Expenses.

Energy Costs Electric. For both comparison periods, an electric generation mix favoring less expensive nuclear fuel, compared with the cost of coal or oil, resulted in fuel expenses not increasing at the same rate as RRlRR electric generation. The average cost of coal and nuclear fuel decreased in 1994 over 1993.

The Company purchases electric power to supplement its own generation when needed to meet load or reserve requirements, and when such power is available at a cost lower than the Company's production cost. For both comparison periods, the increase in purchased electricity expense was primarily caused by an increase in kilowatt-hours purchased. Average rates for purchased electricity declined in 1994 and in 1993.

Energy Supply and CostsGas. As a result ofthe implementation of FERC Order 636, and the commencement ofoperation ofEmpire, the Company now purchases all ofits required gas supply directly from numerous producers and marketers under contracts containing varying terms and conditions. The Company holds firmtransportation capacity on ten major pipelines, giving the Company access to the major gas-producing regions ofNorth America. In addition to firm pipeline capacity, the Company also has obtained contracts for firmstorage capacity on the CNG Transmission Corporation (CNG) system (10.4 billioncubic feet) and on the ANRPipeline system (6.4 billioncubic feet) which are used to help satisfy its customers'inter demand requirements.

The Company acquires gas supply and transportation capacity based on its requirements to meet peak loads which generally occur in the winter months. With Empire going on-line, the Company's gas supply and transportation capacity have also been enhanced and increased. The Company expects to have excess gas and transportation capacity at various times throughout the year which itwillattempt to sell separately or bundled as a package to customers outside the Company's franchise area. The Company is also able to mitigate transportation costs via the capacity release market. To what extent the Company can successfully achieve the assignment or sale of any excess gas and/or transportation capacity, or at what price, cannot be determined at the present time.

As a result ofthe restructuring ofthe gas transportation industry by FERC and related decisions, there willbe a number ofchanges in this aspect ofthe Company's business over the next several years. These changes willrequire the Company to pay a share ofcertain transition costs incurred by the pipelines as a result ofthe FERC-ordered industry restructuring. Although the final amounts of such transition costs are subject to continuing negotiations with several pipelines and ongoing pipeline filings requiring FERC approval, the Company expects such costs to range between

$44 and $52 million.Asubstantial portion ofsuch costs willbe on the CNG system ofwhich approximately $27 millionwas billed to the Company in December 1993 and subsequently paid by the Company. The Company has entered into a $30 millioncredit agreement with a domestic bank to provide funds for the Company's transition cost liabilityto CNG. At December 31, 1994 the Company had $ 18.7 millionofborrowings outstanding under the credit agreement. The Company has begun collecting those costs through the Gas Clause Adjustment in its rates.

It was primarily an increase in average purchased gas rates that pushed up the cost of gas purchased for resale for both comparison periods. These higher rates reflect, in part, increased QQ v

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o q<4o Rochester Gas ural Bectrk Corporation demand charges and newly assessable gas service restructuring charges as a result of FERC Order 636. In contrast to 1993, a decrease in the volume ofgas purchased for resale helped to mitigate the overall increase in purchased gas expense in 1994.

A reconciliation ofgas costs incurred and gas costs billed to customers is done annually, as of August 31, and the excess or deficiency is refunded to or recovered from customers during a subsequent period. In October 1994, the Company submitted to the PSC its annual reconciliation providing for recovery of$24 millionofdeferred gas costs, which was substantially higher than in previous years due to the factors mentioned above.

The staff ofthe PSC has reviewed the Company's application for recovery ofthese deferred costs and various other parties requested that the PSC conduct hearings to determine whether and on what terms the deferral should be recovered. On December 19, 1994, the PSC instituted a proceeding to review the Company's practices regarding acquisition ofpipeline capacity, the deferred costs ofthe capacity and the Company's recovery ofthose costs. The costs included in the deferral have ordinarily been recovered in the past and the Company believes that they should be recovered in this instance; however, it is possible that with respect to these costs, the PSC may not recognize all ofthem in rates. Ifthat were to occur, the Company would be compelled to discontinue deferring and recovering costs above the allowed amount, and would recognize the disallowed costs as they were incurred as a charge against earnings. In addition, in a more adverse decision, the PSC could order the Company to refund a portion ofsuch costs previously collected from ratepayers. Pending the conclusion ofthe proceeding, the PSC directed the Company to recover FERC Order 636 transition costs over a five-year period and all other unrecovered gas costs over 18 months.

As an interim measure, on February 1, 1995 the PSC directed the Company to remove from existing rates $ 16 millionofgas revenues representing a portion ofthe costs attributable to excess capacity over the remaining term ofthe contracts. Prospective capacity release credits obtained by the Company are to be used to offset such amounts. These deferred costs are subject to recovery by the Company from customers, with interest, to the extent the Company's actions are found prudent.

The Company cannot predict to what extent the deferred costs described above would be recoverable in rates.

The Company's purchased gas expense charged to customers willbe higher during the 1994-95 heating season for the reasons described above.

Operating Expenses, Excluding Fuel. After rising approximately $8.8 millionin 1993, the growth in other operation expenses remained flat in 1994, a direct result ofthe Company's cost control efforts and workforce reduction programs. For 1994, higher costs for the Company's demand side management program, claims, and uncollectibles were offset by lower payroll and employee welfare costs due to employee reductions and reduced expenses for contractors and consultants.

The change in other operation expenses for the 1993 comparison period reflects primarily increased payroll costs and demand side management expenses partially offset by lower fire and liabilityinsurance costs, transportation, materials and supplies, and legal expense.

Statement ofFinancial Accounting Standards 112 (SFAS-112), "Employees'Accounting for Postemployment Benefits", was adopted by the Company during the first quarter of 1994.

SFAS-112 requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employment but before retirement. The additional postemployment obligation at the time ofthe accounting change was approximately $ 11 million and is being deferred on the Balance Sheet. The Company anticipates filingwith the PSC for recovery ofthe incremental expenses as the result ofthe adoption ofSFAS-112.

Statement ofFinancial Accounting Standards 115 (SFAS-115), "Accounting for Certain Investments in Debt and Equity Securities" was also adopted by the Company in the first quarter of 1994 and requires that debt and equity securities not held to maturity or held for trading purposes be recorded at fair value with unrealized gains and losses excluded from earnings and

~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~

~

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~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ 0 ~ ~ ~ ~ ~ ~ 00 ~ Ot 4 \\

recorded as a separate component ofshareholders'quity. The Company's accounting policy, as prescribed by the PSC, with respect to its nuclear decommissioning trusts is to reflect the trusts'ssets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability.

Lower maintenance expense in both comparison periods reflects reduced payroll and contractor costs.

Despite an increase in depreciable plant in both comparison periods, depreciation declined moderately in 1993 due mainly to a decrease in the depreciation and accrued decommissioning expenses related to the Ginna Nuclear Plant because of a three-year extension ofits operating license. For the 1994 comparison period, the higher depreciation expense reflects the increase in depreciable plant.

Taxes Charged to Operating Expenses. The increase in local, state and other taxes in both comparison periods resulted primarilyfrom an increase in revenues combined with increased property tax rates and generally higher property assessments.

The 1994 comparison period also reflects certain assessments for prior years'axes.

During the first quarter of 1993, the Company adopted SFAS-109 entitled "Accounting for Income Taxes" issued by the FASH in February 1992. The Company's adoption ofSFAS-109 did not have a material effect on the Company's results ofoperations although since then, reflection of a deferred tax liability,together with a corresponding regulatory asset, caused total assets and liabilities to increase significantly. See Note 2 ofthe Notes to Financial Statements for further discussion ofSFAS-109 and an analysis of Federal income taxes.

In August 1993, the Revenue Reconciliation Actof 1993 (1993 Tax Act) was signed into law.

Among other provisions, the 1993 Tax Act provides for a Federal corporate income tax rate of35%

(previously 34%) retroactive to January 1, 1993. In 1993, the Company adjusted its tax reserve balances to reflect this new rate. Such adjustment had no material effect on the Company's financial condition or results ofoperations.

Other Statement ofIncome Items Variations in non-operating Federal income tax reflect mainly accounting adjustments related to retirement enhancement programs (see Earnings Summary), regulatory disallowances, and employee performance incentive programs (discussed below in this section).

Recorded under the caption Other Income and Deductions is the recognition ofretirement enhancement programs designed to reduce overall labor costs which were implemented by the Company during the third and fourth quarters of 1993 and the third quarter of 1994. These programs are discussed under Earnings Summary.

Recorded under the caption Regulatory Disallowances is the recognition ofthe 1992 PSC order related to a March 1991 ice storm, and a 1993 settlement with the PSC, as supplemented in 1994, regarding certain gas purchase undercharges, each discussed under the heading New York State Public Service Commission.

Other Income in 1992 includes $3.5 millionofproceeds received in settlement oflawsuits filed against certain contractors involved in the construction ofthe Nine MileTwo nuclear plant.

Other Net Income and Deductions for 1993 and 1994 results mainly from the recognition of employee performance incentive programs in each of those years. These programs recognize employees'chievements in meeting corporate goals and reducing expenses. For the 1994 comparison period, Other Net Income and Deductions also reflects higher miscellaneous interest revenues.

Both mandatory and optional redemptions ofcertain higher-cost first mortgage bonds have helped to reduce long-term debt interest expense over the three-year period 1992-1994. The average short-term debt outstanding decreased in 1993 and 1994.

~ ~ ~ I Rochester Gkr Jtrj Brotflc Coqeration STATEMENT OF INCOME STATEMENT OF RETAINED EARNINGS BALANCESHEET STATEMENTOF CASH FLOWS NOTES TO FINANCIALSTATEMENTS REPORT OF INDEPENDENT ACCOUNTANTS REPORT OF MANAGEMENT INTERIMFINANCIALDATA COMMONSTOCK AND DIVIDENDS SELECTED FINANCIALDATA ELECTRIC DEPARTMENT STATISTICS GAS DEPARTMENT STATISTICS 29 29 30 31 32 51 52 52 53 54 56 57

~ ~ ~ ~ ~0@

~

~

~

Electric Market Profile (thousands ofmwh sold) 8 000 7,519 7,251 79542 Other UtiTities Qg gg gild Other Industrial ': ~

Gas Market Profile (millionsofthmns sold and transported) 550 520 Transported g@ M I Other Industrial Commercial Degree Day Variations From Normal b Heating Degree Days b Cooling Degree Days 268 297 199 166 Commercial i

~ i Normal

-38 Residential Residential

-204 I

aoch98889 G88 888t Boctno COIOOOOOOII I 100 896 1,001 949 Operating Revenues (millions ofdollars)

Earnings And Dividends Per Share OfCommon Stock (dollars) 2.50 Capitalization AtDecember 31 (millionsofdollars)

I 700 1,652 1,673 1,504

~

$6".:.

Electric

~

9 9

0 Eaminy-Continuing Operations b Eaminy-As Reported b Dividends Ch (h

OO Common PAIuity SEC Preferred Stock i'9 Long-Term Debt

~

~

9 Embedded (Annual) Cost OfLong-Term Debt At Year End (percent) 8 7.91 7.36 7.40 3.51x 2.70x 3.00x Pretax Interest Coverage AtYear End (exduding AFUDC) 4 325 301 222 242 Customers per Employee AtYear End

e CO0N!500IL((D>ktiID> !5Mtill)RNti 09(r ((NCO0(IR e (Thousands of Dollars)

Year Ended December 31 1994 1993 1992

'perating Revenues Electric Gas Electric sales to other utilities Total Operating Revenues Operating Expenses Fuel Expenses Fuel forelectric generation Purchased electricity Gas purchased for resale Total Fuel Expenses Operating Revenues Less Fuel Expenses Other Operating Expenses Operations excluding fuel expenses Maintenance Depreciation and amortization Taxes local, state and other Federal income tax Total Other Operating Expenses Ope'rating Income Other Income and Deductions Allowance for other funds used during construction Federal income tax Pension Plan Curtailment Regulatory disallowances Other, net Total Other. Income and (Deductions)

Income Before Interest Charges Interest Charges

,Long term debt Other, net Allowance for borrowed funds used during construction Total Interest'harges Net Income Dividends on Preferred Stock Earnings Applicable to Common Stock Weighted Average¹mber ofShares forPeriod (000's)

Earnings per Common Share S

658,148 326,061 984,209 16,605 1,000,81 4 44,961 37,002 194,390 276,353 724,461 235,896 55,069 87,461 129,778 61,245 569,449 155,012 396 161259 (33,679)

(600)

(4,853)

(22,477) 132,535 53,606 6,566 (2,012) 58,160 74,375 7,369 5

67,006 37 327 1.79

$638,955 293,708 932,663 16,361 949,024

'5,871 31,563 166,884 244,31 8 704,706 235,381 61,693 84,177 126,892 49,330 557.473

'1 47,233 153 9,827 (8/179)

(1,953)

(7,074)

(7.226) 140,007 56,451 6,707 (1,714) 61,444 78,563 7,300

$ 71.263 35,599 2.00

$608,267 261,724 869,991 25,541 895,532 48,376 29,706 141,291 219,373 676,159 226,624 62,720 85,028 124,252 43,591 542,21 5 133,944 164 4,195 (8,215) 6,155 2,299 136,243 60,810 7,178 (2,184) 65,804 70,439

= 8,290

$ 62,149 33,258 1.86 H CO9N09LODbk'll'IDb ÃI'Qadi'III¹'9@ mi'iJ'SONIDb M,QNON@

0-(Thousands of Doilars)

Year Ended December 31, 1994 1993 1992" Balance at Beginning ofPeriod Add Net Income Adjustment Associated with Stock Redemption Total Deduct Dividends declared on capital stock Cumulative preferred stock Common stock Total Balance at End ofPeriod The accompanying notes are an integral part ofthe financial statements.

$ 75>126 74,375 (1,398) 148,103 7,369 66,168 73,537 6 74,566 3 66,968 78,563 (933) 144,598 7,300 62.1 72 69.472 8 75,'(26

$ 61,515 70,439 131,954 8,290 56,696 64,086

$ 66,968 H

~

~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

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~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ) ~ ~ ~ ~ 0

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~ 0 00IBOB BIN!2IBO IIIB IIIIBI01I0III BIBIT.,B:,:,:,:...:::,:,:,,'00 0>BBt tt05273e C0q>020224748

{Thousands ot Dollars)

Assets UtilityPlant Electric Gas Common Nuclear fuel,,

Less: Accumulated depreciation Nuclear fuelamortization Construction work in progress Net UtilityPlant Current Assets Cash and cash equivalents Accounts receivable, net ofallowance For doubtful accounts:

1994

$950,'993

$600 Unbil!ed revenue receivable Materials and supplies, at average cost Fossil fuel Construction and other supplies Gas stored underground Prepayments Total Current Assets Investrncnt in Enipire Dcfern'd Debits Unamortized debt expense Nuclear generating plant decommissiomng fund Nine MileTsSvo deferred costs Deferred finance charges Nine MileTSvo Other Deferred Debits Regulatory assets-lricome taxes Uranium enrichment decommissioning deferral Deferred ice storm charges FERC 636 transition costs Demand side management costs Deferred fuel costs gas Other regulatory assets Total Deferred Debits Total Assets t:apltatlzatlon and liabilities Capitalization Long term debtmortgage bonds promissory notes Preferred stock redeemablc at option ofCompany Prcfcrred stock subject to mandatory redemption Common shareho! ders'quity Common stock Retained earnings Total Common Shareholders'quity Total Capitalization Long Term Liabilities (Department ofEnergy)

Nuclear waste disposal Uranium enrichment decommissioning Total Long Term Liabilities Current Liabilities tung term.debt due within one year Preferred stock redeemable within one year Note Payable Empire Short term debt Accounts payable Dividends payable Taxes accrued Interest accrued Other Total Current Liabilities Deferred Credits and Other Liabilities Accumulated deferred income taxes Deferred finance charges Nine MileTwo Pension costs accrued Other Total Deferred Credits and Other Liabilities

'onnnitinents and Other Matters(Note 10)

Total Ca italization and Liabilities "Reclsssified for comparailvepnrposes.

'Ihe accompanying notes are an integral part ofthe financial statements, At December 31 1994

$2,284,634 370,205 135,975 190,337 2,901,15'I 1,263,637 159,46'I 1,550,053 120,060 1,686,913 2,810 110>417 54,270

',908 13,264 24,315 23,535 236,519 38,560 18,343 49>011 33,462 19,242 19,214 205,794 20,169 19,111 32,479 19,807 33,845 33.727 504,204 32,466,106 643,278 91,900 67,000 55,000 670,569 74,566 745.135

'l,602,313 70,895 16,931 07,026 29,600 51,600 42,934 18,818 3,471 11,967 22,937 101,327 402,894 19,242 75,912 96,682 594,730 S2,400,196 1993*

$2,234,530 356 484 125,428 174,357 2,890,799 1,190,801 144.282 1,555,716 112,750 1,668,466 2,327

'04,753 61,330 5,983 13,644 38,989 21.563 240,589 38,560 19,326

38,930 34,513 19,242 27,073 241,741 23,421 21,621 41,265 20,573

• 5,754 14.310 507,769 32.463.384 655,731 91,900 67,000 42,000 652,172 75,126 727,298 1,583,929 68,055 21,749 09.804 21,250 6,000 29,600 68,100 52,596 18,066 6,472 12,955 19.491 234,530 425,648 19,242 31,919 78,312 555.121 S2.463,384

~ CODIIODILIIDBkWIDBatrtt'ir(tMIIWODIt CLH(n WILODW@ e (Thousands of Dollars)

Year Ended December 31 1994 1993 1992 Cash Floe from Operations Net incotne Adjustments to reconcile net income to net cash provided from operatingactivities:

Depreciation and amortization Amortization of nuclear fuel Deferred fuelelectric Deferred fuel gas Deferred income taxes Allowance forfunds used during construction Unbilled revenue, net Deferred ice storm costs Nuclear generating plant decommissioning fund Changes in certain current assets and Iiabilities:

Accounts receivable Materials and suppliesfossil fuel construction and other supplies

gas stored underground Taxes accrued Accounts payable Interest accrued Other current assets and liabilities, net Other, net Total 0 eratin 74,375 S

78,563 70,439 85,028 87)461 18,048 (1,967)

(28,091) 13,193 (2,408) 7,060 2,510 (10,081) 84,177 18,861 (2,072)

(11,500) 15,232 (1,867)

(5,107) 2,576 (9,381) 18,803 2,543 4,896 10,466 (2,348)

(6,631) 12,234 (10,328)

(12,461) 6,290

.(514)

(28,991)

(7,271) 12,018 (2,506) 6,113 10,966 (8,239)

(1,507)

(591)

(2,942) 1,693 (13,404)

(852)

(2,528)

(5,832)

(5,664)

(1,925) 380 14,674 (3,001)

(9,662)

(988) 317 61,881

$ 216,112

$ 153,126

$ 150,900 Cash Flow from Investing Activities UtilityPlant Plant additions Nuclear fuel additions Lesg Allowance forfunds used during construction

'dditions to UtilityPlant Investment in Empire net Other, net Total Investin

$(103,737)

(15,890)"

2,408 (117,219)

(150)

$(117,369)

S(125,744)

(15,530)

'1,867 (139,407) 884 (1,907)

$ (14D,43D)

S(115,792)

(11,763) 2,348 (1 25,207)

(9,846) 490

$(134,563)

Cash Floe from Financing Activities Proceeds fronu Sale/Issue ofcommon stock Sale ofpreferred stock Sale oflong term debt, mortgage bonds Short term borrowings Retirement oflong ternr debt Retirement ofpreferred stock Capital stock expense Discount and expense ofissuing long term debt

'ividends paid on preferred stock Dividends paid on common stock Other, net Total Financing Increase in cash and cash equivalents Cash and cash equivalents at beginning ofyear Cash and cash e uivalents at end of ear S

61,254 (12,000)

(615)

(7,909)

(7,548)

(60,893)

(1,468)

S (12,128) 568 1,759 17,369 (18,000) 1,028 (531)

(7,328)

(65,457)

(91)

S 63,928 25,000 200,000 160,500 (16,500) 17,300

'8,700)

(33,750)

(200,249)

(160,000)

(1,735)

(6,368)

(8,290)

(55,216)

(185)

$ (16.066)

$ (98,260) 271 3 ~

1,488 483 2,327 2,810 2,327 1,759 W IBXI?I?BXNIBXBIBIX~OB NBNXBBXXIN?XIXXIXXIXII-Thousands of Dollars)

Cash paid During the Year Interest paid (net ofcapitalized amount)

Income taxes aid Year Ended December 31 1994 571186 28,411 1993 S

60,852 S

32,779 1992 S

64,431 22,911 The accompanying notes are an integral part ofthe financial statements.

N ~ ~ ~ ~

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Summary ofAccounting Principles General.

The Company is subject,to regulation by the Public Service Commission ofthe State ofNew York (PSC) under New Yorkstatutes and by the Federal Energy Regulatory Commission (FERC) as a licensee and public utilityunder the Federal Power Act. The Company's accounting policies conform to

'enerally accepted accounting principles as applied to New York State public utilities giving effect to the ratemaking and accounting practices and policies ofthe PSC.

Energyline Corporation, which is a wholly-owned subsidiary, was incorporated in July 1992.

Energyline was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. On November 1, 1993 Empire commenced service. The Company has authority to invest up to $20 millionin Empire. In June 1993 Empire secured a $ 150 millioncredit agreement, the proceeds ofwhich are to finance approximately 75% of the total construction cost and initialoper-ating expenses. Energyline is obligated to pay its 20% share ofthe balance outstanding subject to a maximum commitment. of $9.7 millionunde'r the credit agreement. Excluding the loan commitment, at December 31, 1994 the Company had invested a net amount of$ 10.3 millionin Energyline.

Principles ofConsolidation.

The consolidated financial statements include the accounts ofthe Company and its wholly-owned subsidiaries Roxdel and Energyline. Allintercompany balances and transactions have been eliminated.

Adescription ofthe Company's principal accounting policies follows.

Rates and Revenue.

Revenue is recorded on the basis ofmeters read. In addition, the Company records an estimate of unbilled revenue for service rendered subsequent to the meter-read date through the end ofthe accounting period.

Tariffs for electric and gas service include fuel cost adjustment clauses which adjust the rates monthly to reflect changes in the actual average cost offuels. The electric fuel adjustment provides that ratepayers and the Company willshare the effects ofany variation from forecast monthly unit fuel costs on a 50%/50% basis up to a $5.6 millioncumulative annual gain or loss to the Company.

Thereafter, 100% ofadditional fuel clause adjustment, amounts are assigned to customers. The electric fuel cost adjustment also provides that any variation from forecast margins below $7.1 millionor above $8.5 millionon sales to electric utilities be shared with retail customers on a 50%/50% basis.,

In'addition, there is a similar 50%/50% sharing process. ofvariances from forecasted margins derived from sales and the transportation ofprivately owned gas to large customers that can use alternate fuels.

Under the Company's Electric Revenue Assurance Mechanism (ERAM),which was established in the 1993 multi-year rate settlement, any variations between actual margins and the established targets may be recovered from or returned to customers. Beginning July 1994 through December 31, 1994,

$7.3 millionwas recoverable from customers. The Company is not currently recognizing ERAM amounts as part ofincome. The ultimate recognition, ifany, willbe determined based on a filingwith the PSC during 1995.

Retail customers who use gas for spaceheating are subject to a weather normalization adjustment to reflect the impact ofvariations from normal weather on a billingmonth basis for the months of October through May, inclusive. The weather normalization adjustment for a billingcycle applies

. onlyifthe actual heating degree days are lower than 97.5% or higher than 102.5% ofthe normal heating degree days. Weather normalization adjustments lowered gas revenues in 1994 and 1993 by approximately $ 1.25 millionand $ 1.2 millionrespectively. Adjustments willcontinue through, June 1996 in accordance with the 1993 multi-year rate settlement agreement for weather which is colder than normal (also see Note 10).

~ ~ ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ ~ ~ 1 ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ 0 ~ ~I ~ ~ 0 ~ ~ ~ ~ ~

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~ ~ ~ ~ ~ ~ ~ ~ ~ 1 ~ ~ ~ ~\\ ~ ~ ~ ~

The Company practices fuel cost deferral accounting as described above. A reconciliation ofrecover-able gas costs with gas revenues is done annually as ofAugust 31, and the excess or deficiency is refunded fo or recovered from the customers during a subsequent period.

UtilityPlant, Depreciation and Amortization.

The cost ofadditions to utilityplantand replacement ofretirement units ofproperty is capitalized.,

Cost includes labor, material, and similar items, as well as indirect charges such as engineering and supervision, and is recorded at original cost. The Company capitalizes an Allowance for Funds Used During Construction approximately equivalent to the cost ofcapital devoted to plant under construction that is not included in its rate base. Replacement ofminor items ofproperty is included in maintenance

expenses. posts of depreciable units of'plant retired are eliminated &om utilityplant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve.

Depreciation in the financial statements is provided on a straight-line basis at rates based on the estimated useful lives ofproperty, which have resulted in provisions of2.9% per annum ofaverage depreciable property in 1994, 1993, and 1992.

FSRC Order 636, Under this order, gas supply and pipeline companies are allowed to pass restructuring and transition costs associated with the implementation ofthe order on to their customers. The Company, as a customer, has estimated total cost to ratige between'$44 and $52 millionwhich willbe paid to its sup-pliers. A regulatory asset and related deferred credit have been established on the balance sheet to account for these estimated costs. Approximately $33.7 millionofthese costs were paid to var'ious suppliers, ofwhich $ 15 millionhas been included in purchased gas costs (see Note 10).

Allowance for Funds Used During Construction.

The Company capitalizes an Allowance for Funds Used During Construction (AFUDC) based upon the cost ofborrowed funds for construction purposes, and a reasonable rate upon the Company's other funds when so used. AFUDC is segregated into two components and classified in the Consolidated Statement ofIncome as Allowarice for Borrowed Funds Used During Construction, an offset to Interest Charges, and Allowance for Other Funds used During Construction, a part ofOther Income.

The rates approved by the PSC for purposes ofcomputing AFUDC ranged from 3.9% to 7.1%

during the three-year period ended December 31, 1994.

'he Company did not accrue AFUDCon a portion ofits investment in Nine MileTwo for which a cash return was allowed. Amounts were accumulated in deferred debit and credit accounts equal to the amount ofAFUDCwhich was no longer accrued. The balance in the deferred credit account was intended to reduce future cash revenue requirements over a period substantially shorter than the life of Nine MileTwo, and the balance in the deferred debit account would then be collected from customers over a longer period oftime. The current balances of$ 19.2 millionare expected to remain on the Company's books for future application by the PSC as a rate moderator.

I Federal Income Tax.

Statement ofFinancial Accounting Standards (SFAS) 109, Accounting for Income Taxes, was adopted by the Company during the firstquarter of 1993 (see Note 2).

Retirenient Health Care and Life Insurance Benefits.

The Company provides certain health care and life insurance benefits for retired employees and health care coverage for surviving spouses of retirees. Substantially all ofthe Companies employees may become eligible for these benefits ifthey reach retirement age while worhng for the Company.

These and similar benefits for active employees are provided through insurance policies whose premiums are based upon the experience ofbenefits actually paid.

~

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(mntinurdfrom page ss)

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In December 1990, the Financial Accounting Standards Board issued SFAS-106 entitled "A'ccounting for Postretirement Benefits Other Than Pensions" effective for fiscal years beginning after December 15, 1992. Among other things, SFAS-].06 requires accrual accounting by employers for postretirement benefits other than pensions reflecting currently earned benefits. The Company adopted this accounting practice in 1992.

In September 1993, the PSC issued a "Statement of. Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions". The Statement's provisions require, among other things, ten-year amortization ofactuarial gains and losses and deferral ofdifferences between actual costs and rate allowances.

Postemployment Benefits.

SFAS-112,"Employers'Accounting for Postemployment Benefits", was adopted by the Company during the first quarter of 1994. SFAS-112 requires the Company to recognize the obligation to provide postemployment benefits to former or inactive employees after employment but before retirement.

The additional'postemployment obligation at the time ofthe accounting change was approximately

$ 11 millionand is being deferred on the balance sheet; Investme>Its in Debt and Equity Securities.

SFAS-115, "Accounting for Certain Investments in Debt and Equity Securities" was adopted by the Company in the first quarter of 1994 and requires that debt and equity securities not held to maturity or held for trading purposes be recorded at fair value with unrealized gains and losses excluded from earnings and recorded as a separate component ofshareholders'quity. The Company's accounting policy, as prescribed by the PSC, with respect to its nuclear decommissioning trusts is to reflect the trusts'ssets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability.

Ea rnings Per Sh a re.

Earnings applicable to each share ofcommon stock are based on the weighted average number of shares outstanding during the respective years.

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Federal Income Taxes The provision for Federal income taxes is distributed between operating expense and other income based upon the treatment ofthe various components ofthe provision in the ratemaking process. The followingis a summary ofincome tax expense for the three most recent years.

(Thousands of Dollars) 1994 1993 1992

$33,453

]5,877 49,330 1994 Charged to operating expense:

Current,

$35,658

$36,101 Deferred 25,587 7,490 Total 61,245 43,591 Charged (Credited) to other income:

Current (7,419)

(9,182)

(7,171 }

Deferred (6,408) 1,787 5,402 Investment tax credit (2,432)

(2,432)

(2,426)

Total (16,259)

(9,827)

(4,195)

Total Federal income tax expense

$44,986

$39,503

$39,396 The followingis a reconciliation of the difference between the amount ofFederal income tax expense reported in the Consolidated Statement ofIncome and the amount computed by multiplyingthe income by the statutory tax rate.

(Ihousands of Doifars) 1993 1992 RO4)474407 c03 oo(( r)44443o COr(70401(071

%of Pretax Amount Income

%of

%of Pretax Pretax Amount Income Amount Income

$ 74,375

$ 78,563 44,980 39,503

$119,361

$118,066

, $ 41,776 35.0

$ 41,323 Net Income Add: Federal income tax expense

Income before Federal income tax Computed tax expense Increases (decreases) in tax resultinp from:

Difference between tax depreciatron'and amount deferred Investment tax credit Miscellaneous items, net Total Federal income tax expense 6,685, 5.6 6,337 (2,432)

(2.0)

(2 432)

(1,043)

(0.9)

(5,725) 8 44,906 37.7 8 39,503 tax liabilityis as follows:

1994 Asummary ofthe components ofthe net deferred thousands of Oollars)

$ 70,439 39,396 8109,835 35.0

$ 37,344 34.0 1993 1992 5.4 6,775 6.2 (2.1)

'2,426)

(2.2)

~4.0)

~(2,297

~(2.1 33.5 S 39,396 35.9 Nuclear decommissioning

$ (13,390)

S (11,518)

$ (13,087)

Nine Miledisallowance (10,276)

. (15,200)

(19,569)

Alternative minimum tax (9,584)

(27,908)

(27,611)

Accelerated depreciation 184,941 164,821 174,237 Investment tax credit 32,723 34,305 55,206 Deferred ice storm charges 4,930 5,642 6,519 Depreciation previously flowed through 200,956 246,127 Other 72>594 29,379 (4.022)

'Total

$402.094 8425,648,8171,673 The Company adopted SFAS-109 "Accounting for Income Taxes" in 1993. SFAS-109 requires that a deferred tax liabilitymust be recognized on the balance sheet for tax differences previously flowed through to customers. Substantially all of these flow-through adjustments relate to propet ty plant and equipment and related investment tax credits and willbe amortized consistent with the depreciation ofthese accounts. The net amount of the additional liabilityat December 31, 1993 and 1994 was

$241 millionand $206 million,respectively. In conjunction with the recognition of this liability,a corresponding regulatory asset was also recognized.

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SFAS-109 also requires that a deferred tax liabilityor asset be adjusted in the period ofenactment for the effect ofchanges in tax laws or rates. During 1993 the statutory income tax rate was increased one percent to 35o/o. This resulted in increases of$.6 millionand $ 1.3 millionfor current and deferred tax liabilities, respectively. There was no earnings impact since the effects ofthe tax change have been deferred forfuture recovery.

As ofDecember 31, 1994, the regulatory asset recognized by the Company as a result ofadopting SFAS-109 is attributed to $ 184 millionin depreciation, $21 millionto property taxes, $ 18 millionof.

deferred finance charges Nine MileTwo and $3 millionofMiscellaneous items offset by $ 18 million attributed to investment tax credits and $2 millionto revenue taxes.

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o Pension Plan and. Other Retirement Benefits The Company has a defined benefit pension plan covering substantially all ofits employees. The benefits are based on years of.service and the employee's compensation during the last three years of employment. The Company's funding policyis to contribute annually an amount consistent with the requirements ofthe 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) 1994 1993 Rochester Gss ttrtd llectrte eetporethsrt Accumulated benefit obligation, including vested benefits of

$330.5 in 1994 and $286.1 in 1993 Projected benefit'obligation for service rendered to date Less Plan assets at fair value, primarilylisted stocks and bonds Plan assets in excess ofprojected benefits Unrecognized net loss (gain) from past experience different from that assumed and effects ofchanges in assumptions Prior service cost not) et recognized in net periodic pension cost Unrecognized net obhgation at December 31 Pension costs accrued "Actuarialpresent value.

'"Indudes $43.3 millionpension plan curtailment charge.

"'Includes $9.2 millionpension plan curtailment charge.

Net pension cost included the followingcomponents:

(Millions)

$(354,8)'(309.3)"

$(433.5)*

(429.5)'51.7 490.3 18.2 60.8 (110.9)

(110.6) 13.4 13.7 3.4 4.2 S (75.9)"

$ (31.9)*"

(Millions) 1994 1993 1992 Service cost benefits earned during the period Interest cost on projected benefit obligation Actual return on plan assets Net amortization and deferral Net periodic pension cost 8.2 32.2 0.8 (40.0) 1.2 8.7 8.8 30.0 27.9 (60.2)

(35.1) 24.3, 5.5 S

2.8 S

7.1 During 1994, the Company offered to its employees a Temporary Retirement Enhancement Program (TREP 3). Atotal of399 employees elected to participate in TREP 3 resulting in a net curtailment charge of$43.3 millionincluding $71 ~ 1-millioncost ofthe enhanced benefit offset by a curtailment gain of$27.8 million.In connection with the curtailment, the Company revalued the projected benefit obligation as ofSeptember 30, 1994 utilizingthe then current discount rate of8.25/o.

The projected benefit obligation at December 31, 1994, September 30, 1994, and December 31, 1993 assumed discount rates of8.50o/o, 8.25o/o and 7.25o/o, respectively and long-term rate ofincrease in future compensation levels of6.00/o. The assumed long-term rate ofreturn on plan assets was 8.50o/o.

The unrecognized net obligation is being amortized over 15 years beginning January 1986.

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In September 1993, the PSC issued a "Statement ofPolicy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other Than Pensions" (Statement).

The 1994 and 1993 pension cost reflects adoption ofthe Statement's provisions which, among other things, requires ten-year amortization ofactuarial gains and losses and deferral ofdifferences between actual costs and rate allowances.

In addition to providing pension benefits, the Company provides certain health care and life insur-ance benefits to retired employees and health care coverage forsurviving spouses of retirees.'ubstantially all ofthe Company's employees are eligible provided that they retire as employees ofthe Company. In 1994, the health care benefit consisted of a contribution ofup to $ 193 per month towards the cost of a group health policy provided by the Company. The lifeinsurance benefit consists of a Basic Group Lifebenefit, covering substantially all employees, providing a death benefit equal to one-halfofthe retiree's final pay In addition, certain employees and retirees, employed by the Company at December 31, 1982, are entitled to a Special Group Lifebenefit providing a death benefit equal to the employee's December 31, 1982 pay.

The Company adopted SFAS-106, "Accounting for Postretirement Benefits Other Than Pensions" as ofJanuary 1, 1992 for financial accounting purposes. Subsequently, with the issuance ofthe Statement referenced above, the Company's 'application ofSFAS-106 willextend to ratemaking purposes as well.

The Company has elected to amortize the unrecognized, unfundedAccumulated Postretirement Benefit Obligation at January 1, 1992 over twenty years as provided by SFAS-106. The Company intends to continue funding these benefits as the benefit becomes due.

The plans'unded status reconciled with the Company's balance sheet is as follows:

(Millions)

Accumulated.postretirement benefi obligation:

Retired employees Active employees Less Plan assets at fairvalue, Accumulated Jiostretirement benefit-obligation (in excess of) less than fair value ofassets Unrecognized net loss (gain) from past experience different from that assumed and effects ofchanges in assumptions Prior service cost not yet recognized in net periodic pension cost Unrecognized net obhgation at December 31 Accrued postretirement benefi cost Net periodic postretirement benefit cost included the followingcomponents:

1994

$(42.4)

(26.4)

$(68.8) 0.0 (68.8) 0.8 5.6 47.9

$(14.5) 1994 (Millions)

'993 S(39.9) g (24.9)

$(64.8) 0.0 (64.8) 2.9 1.7 50.7

$ (9,5) 1993

$ 0.7 4.6 0.0 22

$ 7.5 Service cost benefits attributed to the period Interest cost on accumulated postretirement benefit obligation Actual return on plan assets Net amortization and deferral Net periodic postretirement benefit cost

$ 0.9 4.9 0.0 3.4

$ 9.2 The Accumulated Postretirement Benefit Obligation at December 31, 1994 and 1993 assumed discount rates of8.50% and 7.25%, respectively and long-term rate ofincrease in future compensation levels of6 percent.

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1993 1992 Electric Operating Information Operating revenues 674,753 655,316 Operatingexpenses,excludingprovision for.income taxes 489,902 486,951 Pretax operating income 184,771 Provision for income taxes 52,842 Net operating income S

124,520 Other lnforrrfation Depreciation and amortization 72,326 Nuclear fuel amortization 18,861 Capital expenditures S

112,022

'nvestment Information Identifiable assets (a)

$1.920,504

$7,978,009 Gas Operati ngInfornration Operating revenues

$293,708 Operating expenses, excluding provision for income taxes 265,510

'retax operating income 28,198 Provision for income taxes 5,485 Net operating income

$ 22,713 Other Information Depreciation and amortization

$ 12,250 S 11,851 Capital expenditures

$ 23,742 S 27,385 Investment Information Identifiable assets (a)

$407,333

$491,563 5

(el 8xcludes cash, unamortized debt expense and other common items.

Jointly-Owned Facilities The followingtable sets forth the jointly-owned electric generating facilities in which the Company is participating. Both Oswego Unit No. 6 and Nine MilePoint Nuclear Plant UnitNo. 2 have been constructed and are operated by Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share ofdirect expenses associated with these two units is included in the appropriate operating expenses in the Statement ofIncome.

Various modifications willbe made throughout the lives ofthese plants to increase operating efficiency or reliability,and to satisfy changing environmental and safety regulations.

S 633,808 482,968 168,365 43,845 150,840 38,046 S

112,794 131,929 75,211 18,048 93,477 73,213 S

18,803 S

100,974

$1,671,492

$326,061 294,575 31,486 8,403 r

$ 23,083

$261,724 235,029 26,695 5.545

$ 21,150 S 11,815 S 24,231

$354,528 4 Departmental Financial Information The Company's records are maintained by operating departments, in accordance with PSC accounting

>> policies, giving effect to the ratemaking process. The followingis the operating data for each ofthe Company's departments, and no interdepartmental adjustments are required to arrive at the operating data included in the Statement ofIncome.

Pfiousands of Dollars) 1994 Net megawatt capacity RG8rE's share megawatts

percent Year ofcompletion Oswego Unit No. 6 850 204 24 1980 Nine Mile Point Nuclear Unit No. 2 1,080 151 14 1988 Millionsof Dollars at December 31, 1994 Plant In Service Balance Accumulated Provision For Depreciation Plant Under Construction

$98.1

$34.5

$ 0.6

$876.6

$452.1 S

8.3 The Plant in Service and Accumulated Provision for Depreciation balances forNine MilePoint Nuclear Unit No. 2 shown above include disallowed costs of$374.3 million.Such costs, net ofincome tax effects, were previously written offin 1987 and 1989.

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~ ~ ~ ~ ~

(Thousands of Dollars)

Principal Amount 0/

Series Due December 31 1994 1993 50Ortr00rrr eno 0rrd rlecrne Corporanon

$ 16,000 18,000 18,000 20,000 20,000 30,000 30,000 30,000 30,000 50,000 50,000 10,000 10,000 2,750 15,000 25,500 25,500 100,000 100,000 100,000 100,000 10,500 10,500 U

V X

Y CC EE (a)

FF JJoo(.)

PP QQ (b)

RR(a)

SS (a)

(b) (c)

(b) (c)

(b) (c)

(c)

(c)

(c)

(b) (c)

(c) 45/s 5.30 6'/<

6.7 8.00 8s/s 61/2 10.95 13'/s 8'/s 9'/s 80/0 6.35 6.50 7.00 7.15 7.13 7.64 7.66 7.67 6.375 7.45 Sept. 15, 1994 May 1, 1996 Sept. 15, 1997 July I, 1998 Aug. 15, 1999 Sept. 15,2007 Aug. 1, 2009 Feb. 15, 2005 June 15, 1999 Dec. I, 2028 Apr. I, 2021 Mar. 15, 2002 May 15, 2032 May 15, 2032 Jan. 14, 2000 Feb. 10,2003 Mar. 3,2003 Mar. 15, 2023 Mar. 15, 2023 Mar. 15, 2023 July 30, 2003 July 30, 2023 50,000 50,000 30,000 30,000 39,000 39,000 1,000 1,000 33,000

'3,000 5,000-5,000 12,000 12,000 40,000 40,000 40,000 40,000 644,000 677,750 (722)

(769)

Net bond discount Less: Due within one year Total 21,250 C

5643,270 3655,737 (a}The Series EE, Series OO, Series RR and Series SS First Mortgage Bonds equal the principal amount ofand provide for all payments ofprincipal, premium and interest corresponding to the Pollution Control Revenue Bonds, Series A,Series C, and Pollution Control Refunding Revenue Bonds, Series 1992 A, Series 1992 B (Rochester Gas and Electric Corporation Projects), respectively, issued by the New York State Energy Research and Development Authoritythrough a participation agreement with the Company. Payment ofthe principal of, and interest on the Series 1992 Aand Series 1992 B Bonds are guaranteed under a Bond Insurance Policy by Municipal Bond Investors Assurance Corporation. The Series EE Bonds are subject to a mandatory sinking fund beginning August 1, 2000 and each August 1 thereafter. Nine annual deposits aggregating $3.2 million willbe made to the sinking fund, with the balance of$6.8 millionprincipal amount oF the bonds becoming due August 1,2009.

(b}The Series QQ First'Mortgage Bonds and the 7%, 7.15%, 7.13% and 6.375% medium-term notes described beloware generally not redeemable prior to maturity.

(c) In 1993 the Company issued $200 millionunder a medium-term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A"with maturities that range from seven years to thirtyyears.

The First Mortgage provides security for the bonds through a first lien on substantially all the property owned. by the Company (except cash and accounts receivable).

Sinking and improvement fund requirements aggregate $333,540 per annum under the First Mortgage, excluding mandatory sinking funds ofindividual series. Such requirements may be met by certification ofadditional property or by depositing cash with the Trustee. The 1993 and 1994 require-ments were met by certification ofadditional property.

On February 15, 1994 the Company redeemed

$2.75 millionprincipal amount ofits First Mortgage 10.95% Bonds, Series FF, pursuant to a sinking fund provision. On June 15, 1994 the Company redeemed all ofits outstanding $ 15 millionprincipal amount ofFirst Mortgage 13'/s% Bonds, Series JJ, due June 15, 1999. Ofthe $15 milliontotal, $2.5 millionwas redeemed through a mandatory sinking fund provision, and the remaining $ 12.5 millionwas redeemed at the Company's option.

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(Thousands of Dollars)

- Series V Ser'ies W Series X

'eries Y 1995 1996

$18,000 31 8,000 1997

$20,000 020.000 1998

$30,000

. 330,000 1999

$30,000

$30,000 Promissory Notes Issued Due (Thousands of Dollars)

December 31 1994 1993 1 I G00 0000 0000200 C0000001fOn November 15, 1984 (d)

$51,700

$51,700 December S, 1985 (e) 40,200 40,200 Tofal 091.900 091,900 (d) The $51.7 millionPromissory Note was issued in connection WithNYSERDA's Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation project), Series 1984.

This obligation is supported by an irrevocable Letter ofCredit expiring October 15, 1997. The interest rate on this note for each monthly interest payment period willbe based on the evaluation ofthe yields ofshort term tax-exempt securities. at par having the same credit rating as said Series 1984 Bonds. The average interest rate was 2.82% for 1994, 2.19% for 1993 and 2.74% for 1992. The interest rate willbe adjusted monthly unless converted to a fixed rate.

. (e) The $40.2 millionPromissory Note was issued in connection with NYSERDA's Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), Series 1985. This obligation is supported by an irrevocable Letter ofCredit expiring November 30, 1997. The annual interest rate was adjusted to 3.10% effective November 15, 1992, to 2.75% effective November 15, 1993 and to 4.40% effective November 15, 1994. The interest rate willbe adjusted annually unless converted to a fixed rate.

The Company is obligated to make payments ofprincipal, premium and interest on each Promissory Note which correspond to the payments ofprincipal, premium, ifany, and interest on certain Pollution Control Revenue Bonds issued by the New York State Energy Research and Development Authority (NYSERDA) as described above. These obligations, are supported by certain Bank Letters ofCredit discussed above. Anyamounts advanced. under such Letters ofCredit must be repaid, with interest, by the Company.

Based on an estimated borrowing rate at year-end 1994 of8.62% for long term debt with similar terms and average maturities (13 years), the fairvalue ofthe Company's long term debt outstanding (including Promissory Notes as described above) is approximately $667 millionat December 31, 1994.

Based on an estimated borrowing rate at year-end 1993 of6.68% for long term debt with similar terms and average maturities (14 years), the fairvalue ofthe Company's long term debt outstanding (including Promissory Notes as described above) is approximately $816 millionat December 31, 1993.

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Type, b'y Order of Seniority Par Value Shares Authorized Shares Outstand!ng Preferred Stock (cumulative)

$100 2,000,000 Preferred Stock (cumulative) 25 4,000,000 Preference Stock 1

5,000,000 "See below for mandatory redemption requirements No shares ofpreferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.

A. Preferred Stock, not subject to mandatory redemption:

Shares (Thousands)

Outsfanding December 31 Series December 31, 1994 1994 1993 1,220,000*

Optional Redemption (per share)

$iy R¹tdhrar K ta¹6 0¹tc$ $$¹rrr40 eor$ ¹ordiMssi

$105 101 101 102,5 102 101 102 4

F 120,000,

$12,000

$12,000 4.10 H

80,000 8,000 8,000 4'/i 60,000 6,000 6,000 410 l

50,000 5I000 5,000 4.95 60,000 6,000 6,000 4.55 M

100,000 10,000 10,000 7.50

- N 200,000 20,000 20,000 Total 670,000

$67,000

$67,000

¹May be redeemed at any time at the option or che Company on 30 days minimum notice, pius ace sued dividends in a0 cases.

8. Preferred Stock, subject to mandatory redemption:

Shares (Thousands)

Outstanding December 31 Series December 31,1994 1994 1993 Optional Redemption (per share) 8.25 7.45 7.55 7.65 6.60 S

T U

V Less: Due within one year Total 100,000 100,000 100,000 250,000 550,000 550,000

$18,000 10,000 10,000 10,000 10,000 10I000 10,000 25,000

$55,000

$40,000 6,000

$55,000

$42,000 Not applicable Not applicable Not applicable Not applicable Not Before 3/1/04+

+Thereafter at $ 100.00 Mandatory Redemption Provisions.

in the event the Company should be in arrears in the sinking fund requirement, the Company may not redeem or pay dividends on any stock subordinate to the Preferred Stock

Series R. The Company redeemed the remaining 180,000 shares on March 1, 1994 at $ 100 per share.

Capital stock expense of$ 1.4 millionwas charged against retained earnings in connection with the redemption ofthe Series R Preferred Stock in 1994.

.Series S, Series T, Series U.Allofthe shares are subject to redemption pursuant.to mandatory sinking funds on September 1, 1997 in the case ofSeries S, September 1, 1998 in the case ofSeries T and

'eptember 1, 1999 in the case ofSeries U; in each case at $ 100 per share.

Series VThe Series V is subject to a mandatory sinking fund suAicient to redeem on each March 1 beginning in 2004 to and including 2008, 12,500 shares at $ 100 per share and on March 1, 2009, the balance ofthe outstanding shares. The Company has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund.

Based on an estimated'dividend rate at year-end 1994 of7.50% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (8.65 years), the fairvalue ofthe Company's Preferred Stock, subject to mandatory redemption, is approximately $54 millionat December 31, 1994.

Based on an estimated dividend rate at year-end 1993 of5.25% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (3.25 years), the fair value ofthe Company's Preferred Stock, subject to mandatory redemption, is approximately $53 millionat December 31, 1993.

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Common Stock At December 31, 1994, there were 50,000,000 shares of$5 par value Common Stock authorized, of which 37,669,963 were outstanding. No shares ofCommon Stock are reserved for options, warrants, conversions, or other rights. There were 549,135 shares ofCommon Stock reserved and unissued for shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan and 138,870 shares reserved and unissued for employees under the RG&E Savings Plus Plan.

Capital stock expense increased in 1992 and 1993 primarilydue to expenses associated with the public sale ofCommon Stock. Redemption ofthe Company's 8.25% Preferred Stock, Series R, decreased capital stock expense by $0.9 millionin 1993 and $ 1.4 millionin 1994.

Common Stock Per Share Shares Outstanding Amount (Thousands)

$529,339 48,000 13,338 2,590 (1,735)

$591,532 44,438

$21.325-$ 24,850

$22.063-$ 25.188

$29.625 14,076 2,741 (615)

$652,172 36,911,265 644,478

]14,220 37.669,963 Balance, Ianuary I, 1992 32,1011139 Sale ofStock

$24.000 2,000,000 Automatic Dividend Reinvestment and Stock Purchase Plan 584,854 Savings Plus Plan 110,666 Decrease (Increase) in Capital Stock Expense Balance, December 31, 1992 34,796,659 Sale ofStock 1,500,000 Automatic Dividend Reinvestment and Stock Purchase Plan

$25.475-$ 29.413 515,036 Savings Plus Plan

$25.81~29.250 99,570 Decrease (Increase) in Capital Stock Expense Balance, December 31, 1993 Automatic Dividend Reinvestment and Stock Purchase Plan

$20.313-$ 25.088 14,797 Savings Plus Plan

$20.313-$ 24.875 2,572 Decrease (Increase) in Capital Stock Expense 7,026 Balance, December 31, 1994 3670,569 Short Term Debt At December 31, 1994 and December 31, 1993, the Company had short term debt outstanding of

$51.6 millionand $68.1 million,respectively. Theweighted average interest rate on short term debt outstanding at year end 1994 was 6.01% and was 4.50% for borrowings during the year. For 1993, the weighted average interest rate on short term debt outstanding at year end was 3,46% and was 3.48%

for borrowings during the year.

The Company has a $90 millionrevolving credit agreement for a term ofthree years. In November of 1994 the Company was granted a one-year extension ofthe commitment termination date to December 31, 1997. Commitment fees related to this facilityamounted to $ 169,000 per year in 1994, 1993 and 1992.

The Company's Charter provides that unsecured debt may not'exceed 15 percent ofthe Company's total capitalization (excluding unsecured debt). As ofDecember 31, 1994, the Company would be able to incur $37.5 millionofadditional unsecured debt under this provision. In order to be able to use its revolving credit agreement, the Company has created a subordinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted by this provision of the Company's Charter.

The Company has entered into a Loan and Security Agreement to provide for borrowings up to

$30 millionfor the exclusive purpose offinancing Federal Energy Regula, tory Commission (FERC)

Order 636 transition costs (636 Notes) and up to $20 millionas needed from time to time forother working capital needs (Secured Notes). Borrowings under this agreement, which can be renewed annually, are secured by a lien on the Company's accounts receivable. Additional unsecured lines of credit totaling $72 million(Unsecured Notes) are also available from several other banks, at their discretion.

, AtDecember 31, 1994, borrowings outstanding were $ 18.7 millionof636 Notes (recorded on the Balance Sheet as a deferred credit), $ 19.6 millionofSecured Notes, and $32.0 millionofUnsecured Notes.

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Capital Expenditure.s.

The Company's 1995 construction expenditures program is currently estimated at $ 132 million, including $30 millionrelated to replacement ofthe steam generators at the Ginna Nuclear Plant.

The Company has entered into certain commitments for purchase ofmaterials and equipment in connection with that program.

Nuclear-Related Matters.

Decommissioning Trust. The Company is collecting in its electric rates amounts for the eventual

'ecommissioning ofits Ginna Plant and for its.14% share ofthe decommissioning ofNine MileTwo.

The operating licenses for these plants expire in 2009 and 2026, respectively.

Under accounting procedures approved by the PSC, the Company has collected approximately

$70.1 millionthrough December 31, 1994. In connection with the Company's rate settlement completed in August 1993, the PSC approved the collection during the rate year ending June 30, 1995 ofan aggregate $8.9 million'fordecommissioning, covering both nuclear units. The amount allowed in rates is based on estimated ultimate decommissioning costs of$ 163.0 millionfor Ginna and

$37.1 millionfor the Company's 14% share ofNine MileTwo (January 1994 dollars). This estimate is based principally on the application of a Nuclear Regulatory Commission (NRC) formula to determine minimum funding with an additional allowance'or removal ofnon-contaminated structures. Site specific studies ofthe anticipated costs'of actual decommissioning are required to be submitted to the NRC at least five years prior to the expiration ofthe license. The Company believes that decommissioning costs are likelyto exceed these estimates but is unable,to predict the costs at

'this time. The Company currently anticipates performing a site specific cost analysis ofdecommissioning at Ginna during 1995.

The NRC requires reactor licensees to submit funding plans that establish minimum NRC external funding levels for reactor decommissioning. The Company's plan, filed in 1990, consists ofan external decommissioning trust fund covering both its Ginna Plaiit and its Nine MileTwo share, The Company is depositing in an external decommissioning trust the amount of the NRC minimum funding require-ment only. Since 1990, the Company has contributed $45.7 millionto this fund and, including invest-ment returns, the fund has a balance of$49.0 millionas ofDecember 31, 1994. The amount attributed to the allowance for removal ofnon-contaminated structures is being jield in an internal reserve. The internal reserve balance as ofDecember 31, 1994 is $24.4 million.

The Company is aware ofrecent NRC activities related to upward revisions to the required minimum funding levels. These activities, primarily focused on disposition oflowlevel radioactive waste, may require the Company to increase funding. The Company continues to monitor these activities but cannot predict what regulatory actions the NRC may ultimately take.

The Staft ofthe Securities and Exchange Commission and the Financial Accounting Standards Board are currently studying the recognition, measurement and classification ofdecommissioning costs for nuclear generating stations in the financial statements ofelectric utilities. Ifcurrent account-ing practices for such costs were changed, the annual provisions for decommissioning costs would increase, the estimated cost fordecommissioning could be reclassified as a liabilityrather than as accumulated depreciation and trust fund income from the external decommissioning trusts could be reported as investment income rather than ns a reduction to decommissioning expense. Ifannual decommissioning costs increased, the Company would defer the effects ofsuch costs pending disposition by the Public Service Commission.

Uranium Enrichment Deconiamination and Decommissioning Fund. As part ofthe National Energy Act (EnergyAct) issued in October 1992, utilitieswith nuclear generating facilities are assessed an annual fee payable over 15 years to pay for the decommissioning ofFederally owned uranium enrichment facilities. The assessments for Ginna and Nine MileTwo are estimated to total $22,1 million,excluding inflation and interest. The firstinstallment of$1.6million was paid in 1993. The Company made the second of 15 payments for this purpose in April 1994, remitting approximately $1.4 million.The Q I ~ ~ ~ ~

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Roehestcr Cas and Beche Corporation

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third of 15 payments (approximately $ 1.5 million)was made in October 1994. Aliabilityhas been recognized on the financial statements along with a corresponding regulatory asset. For the two facilities the Company's liabilityat December 31, 1994 is $ 18,5 million($16.9 nillionas a long-term liabilityand $ 1.6 millionas a current liability).In October 1993, the Company began recovery of this deferral through its fuel adjustment clause. The Company believes that the fullamount of the assessment willbe recoverable in rates as described in the Energy Act.

Nuclear Fuel Disposal Costs. The Nuclear Waste PolicyAct (Nuclear Waste Act) of 1982, as amended, requires the United States Department ofEnergy (DOE) to establish a nuclear waste disposal site and to take title to nuclear waste. Apermanent DOE high-level nuclear waste repository is not expected to be operational before. the year 2010. The DOE is pursuing efforts to establish a monitored retrievable interim storage facilitywhich may allow itto take title to and possession ofnuclear waste prior to the establishment of a permanen't repository. The Act provides for a determination of the fees collectible by-the DOE for the disposal ofnuclear fuel irradiated prior to April7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery offuel 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 $70.9 millionat December 31, 1994. The Company is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liabilityand interest is accrued at the current three-month Treasury billrate, adjusted quarterly. The Act also requires the DOE to provide for the disposal ofnuclear fuel irradiated after April6, 1983, for a charge ofone mill

($.001) per KWHofnuclear energy generated and sold. This charge is currently being collected from customers and paid to the DOE pursuant to PSC authorization. The Company expects to utilize on-site storage for all spent or retired nuclear fuel assemblies until an interim or permanent nuclear disposal facilityis operational.

Spent Nuclear Fuel Litigation. The Nuclear Waste Act obligates the DOE to accept for disposal spent nuclear fuel ("SNF") starting in 1998. Since the mid-1980s the Company and other nuclear plant owners and operators have paid substantial fees to the DOE for the disposal ofSNF. DOE has indicated that it may not be in a position to accept SNF in 1998. On June 20, 1994, Northern States Power Company and other owners and operators ofnuclear power plants filed suit against DOE and the U.S.

in the U.S. Court ofAppeals for the District ofColumbia Circuit asking for a declaration that DOE is not acting in accordance with law, seeking orders directing DOE to submit to the Court a description ofand progress reports on a program to begin acceptance ofSNF by 1998, and requesting other relief at appropriate times including an order allowing petitioners to pay fees into an escrow fund rather than to DOE. The Company has joined Northern States and the other petitioners in this litigation. On September 9, 1994, the DOE responded to the petition by filinga motion to dismiss stating that (1) the petition was premature, (2) it has taken no "final"action that would be subject to review and (3) any injurysuffered as a result ofits failure to begin spent fuel acceptance in 1998 is too speculative. On September 30, 1994 the petitioners filed their oppositions to the DOE's motion, On October 14, 1994, DOE filed its reply to the petitioners'ppositions.

Nuclear Fuel Enrichment Services. The Company has a contract with the United States Enrichment Corporation (USEC), formerly part ofthe DOE, for nuclear fuel enrichment services which assures provision for 700/0 ofthe Ginna Nuclear Plant's requirements throughout its service lifeor 30 years, whichever is less. No payment obligation accrues unless such enrichment services are needed.

Annually, the Company is permitted to decline USEC-furnished enrichment for a future year upon

'giving ten years'otice. Consistent with that provision, the Company has terminated its commitment to USEC for the years 2000, 2001 and 2002. The USEC waived, for an interim period, the obligation to give ten years'otice for 2003 and 2004. The Company has secured the remaining 300/0 ofits Ginna requirements for the reload years 1994 through 1995 under different arrangements with USEC. The Company plans to meet its enrichment requirements foryears beyond those already committed by making further arrangements with USEC or by contracting with third parties. Negotiations are underway withUrenco, a European enrichment facilityto fillall or part ofthe unfilled enrichment services through 2002. The estimated cost ofenrichment services utilized for the next seven years (priced at the most current rates) is expected to be $6 millionin 1995 and ranges from $ 10 millionto

$ 13 millionevery 18 months thereafter.

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Insurance Program. The Price-Anderson Act establishes a Federal program insuring against public lia-bilityin the event of a nuclear accident at a,licensed U.S. reactor. Under the program, claims would first be met by insurance which licensees are required to carry in the maximum amount available (currently

$200 million).IFclaims exceed that amount, licensees are subject to a retrospective assessment up to

$79.3 millionper licensed facilityfor each nuclear incident, payable at a rate not to exceed $10 million per year. Those assessments are subject to periodic inflation-indexing and a surcharge forNew York State premium taxes. The Company's interests in two nuclear units could thus expose itto a potential liabilityfor each accident of$90.4 millionthrough retrospective assessments of$ 11.4 millionper year in the event of a sufficiently serious nuclear accident at its own or another U.S. commercial nuclear reactor, Claims alleging radiation-induced injuries to workers at nuclear reactor sites are covered under a separate, industry-wide insurance program. That program contains a retrospective premium assessment feature whereby participants in the program can be assessed to pay incurred losses that exceed the program's reserves. Under the plan as currently established, the Company could be assessed a maximum of$3.1 millionover the lifeofthe insurance coverage.

The Company is a member ofNuclear Electric Insurance Limited,which provides insurance coverage for the cost ofreplacement power during certain prolonged accidental outages ofnuclear generating units and coverage for property losses in excess of$500 millionat nuclear generating units.

Ifan insuring program's losses exceeded its other resources available to pay claims, the Company could be subject to maximum assessments in any one policyyear ofapproximately $5.0 millionand

$ 19.5 millionin the event oflosses under the replacement power and property damage coverages, respectively.

Non-UtilityGenerating Contract.

Under Federal and New YorkState laws and regulations, the Company is required to purchase the electrical output'of unregulated cogeneration facilities which meet certain criteria (Qualifying Facilities). With the exception ofone contract which the Company was compelled by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts ofcapacity, the Company has no other long-term obhgations to purchase energy from Qualifying Facilities.

Under State law and regulatory requirements in effect at the time the contract with Kamine was negotiated, the Company was required to pay Kamine a price for power that is substantially greater than the Companies own cost ofproduction and other purchases. Since that time the State law mandating a minimum price higher than the Company's own costs has been repealed and PSC estimates offuture prices on which the contract was based have declined dramatically, In September 1994, the Company filed a lawsuit against Kamine seeking to void its contract for the forced purchase ofunneeded electricity at above-market prices which would result in substantial cost increases for the Company's customers. The Company estimates that Kamine willowe the Company

$400 millionby the midpoint ofthe contract term and ifthe contract extends to its full25-year term, the total amount ofsuch overpayments (plus interest) could reach approximately $700 million.

Alternatively, the Company sought reliefto ensure that its customers would pay no more for the Kamine power than they would pay for power from the Company's other sources oF electricity. Kamine answered the Company's complaint, seeking to force the Company to take and pay for power at the above-market rates and claiming damages in an unspecified amount alleged to have been caused by the Company's conduct. The Company is unable to predict the ultimate outcome ofthis litigation.The Companybegan receiving test generation from the Kamine facilityduring the last quarter of 1994.

In late December 1994, the Company announced itwould bio longer be accepting electric power from this facilitybecause itis the Company's position, in addition to other beliefs, that the Kamine facilityis no longer a "QualifyingFacility"as specified under Federal regulations.

On January 27, 1995, Kamine initiated a lawsuit against the Company in Federal DistrictCourt for the Western DistrictofNew Yorkfor alleged anti-trust violations by the Company that are based on the same issues that are raised by the Company's New YorkState Court lawsuit. The Kamine lawsuit seeks injunctive reliefsimilar to that requested in Kamine's answer to the Company's lawsuit in New York State Court and damages of$420 million.The Company intends to vigorously defend against this lawsuit, but is unable to predict the outcome at this time.

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The followingtable lists various sites where past waste handling and disposal has or may have occurred that are discussed below:

Site Name l.ocation Estimated Company Cost'ochester Gas and Bcark'orpontlon Rochester, NY Rochester, NY Rochester, NY Rochester, NY Rochester, NY Canandaigua, NY Syracuse, NY Pendleton, NY Morehead, KY Mexico, NY Bergen, NY Oswego, NY Oswego, NY

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Compntty-Owned Sites:

West. Station.

Ultimate costs have not been East Station

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determined. The Company has Front Street incurred aggregate costs for these Brewer Street sites through December 31, 1994 BrooksAvenue of$2.5 million.

Can andaigua Sttperfitttd and Other Sites:

Quanta Resources>>

Ultimate costs have not been Frontier Chemical Pendleton>>

determined. The Company has Maxey Flats" incurred aggregate costs for these Mexico Milk sites through December 31, 1994 Byron Barrel and Drum of$0.2 million.

Eulton Terminals'AS ofOswego"

'Orders on consent signed.

Company-Owned Waste Site Activities.As part ofits commitment to environmental excellence, the Company is conducting proactive Site Investigation and/or Remediation (SIR) efforts at six Company-owned sites where past waste handling and disposal may have occurred. Remediation activities at three ofthese sites are in various stages ofplanning or completion and the Company is conducting a program to restore, as necessary to meet environmental standards, the other three sites. The Company anticipates spending $ 10 millionover the next five years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 ($ 1.5 millionannually) for recovery ofSIR costs.

To the extent actual expenditures differfrom this amount, they willbe deferred for future disposition and recovery as authorized by the PSC.

The Company owns, and was the prior owner or operator of, a number oflocations within the vicinityofthe Lower Falls ofthe Genesee River, which had been identified by the NewYorkState Department ofEnvjronmental Conservation (NYSDEC). The preceding paragraph includes references to Company owned property in this vicinity.In mid-1991, NYSDEC advised the Company that ithad delisted the Lower Falls site, i.eremoved it from its Registry ofInactive Hazardous Waste Disposal Sites. The effect ofdelisting is to terminate the Company's status as a potentially responsible party for the Lower Falls site, to discontinue the pending NYSDEC review ofa joint Company/City ofRochester proposal for a limited further investigation ofthe Lower Falls, to defer the prospect ofremedial action and perhaps to end any Company sharing ofthe cost thereof. However, NYSDEC also stated its inten-tion to consider listing individual manufactured gas plant sites within the larger, original site once the State ofNew Yorkadopts new Federal hazardous waste criteria. These manufactured gas plant sites make up three ofthe sixsites referenced in the previous paragraph. There is at least some material at one ofthe individual manufactured gas plant sites that could trigger relisting. The Company is unable to predict what further listing action NYSDEC may take.

As already mentioned, the Company and its predecessors formerly owned and operated three man-ufactured gas facilities within the Lower Falls area. In September 1991, the Company initiated a study ofsubsurface conditions in the vicinityofretired facilities atits West Station manufactured gas property and has since commenced the removal ofsoils containing hazardous substances in order to minimize any potential long-term exposure risks. Cleanup efforts have been temporarily suspended while the Company investigates more cost effective remedial technologies. The Company has obtained a research permit (including an air permit) in order to evaluate the burning ofmaterial from its West Station property in a coal-fired boiler as a possible disposal strategy. At the second ofthe three manu-factured gas plant sites known as East Station, an interim remedial action was undertaken in late 1993.

Groundwater monitoring wells were also installed to assess the quality ofthe groundwater at this location. The Company has informed the NYSDEC ofthe results ofthe samples taken. These results may indicate that some further action maybe required.

Atthe third Lower FaHs area property owned by the Company (Front Street) whe're gas manufactur'-

ing took place, a boring placed in Fall 1988 for a sewer system project showed a layer containing a black

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viscous material. The study ofthe layer found that some ofthe soil and ground water on-site had been adversely impacted by the hazardous substance constituents ofthe black viscous material, but evidence was inadequate to determine whether the material or its constituents had migrated off-site. The matter was reported to the NYSDEC and, in September 1990, the Company also provided the agency with a risk assessment for its review That assessment concluded that the findings warranted no agency action and that site conditions posed no significant threat to the environment. Although NYSDEC could require the Company to undertake further investigation and/or remediation, the agency has taken no action since the report's submittal. The Company is formulating plans forlong-term management of the site.

Another property owned by the Company where gas manufacturing took place is located in Canandaigua, New York. No residues ofthe former gas production operations have been discovered there, although investigative work has been limited to date.

On another portion ofthe Company's property in the Lower Falls (Brewer Street), and elsewhere in the general area, the County ofMonroe has installed and operates sewer lines. During sewer installa-tion, the County constructed over Company property certain retention ponds which reportedly received from the sewer construction area certain fossil-fuel-based materials ("the materials" ) found there. In July 1989, the Company received a letter from the County asserting that activities ofthe Company left the County unable to effect a regulatorily-approved closure ofthe retention pond area.

The County's letter takes the position that it intends to seek reimbursement for its additional costs incurred with respect to the materials once the NYSDEC identifies the generator thereof and that any further cleanup action which the NYSDEC may require at the retention pond site is the Company's responsibility. In the course ofdiscussions over this matter, the County has claimed, without offering any evidence, that the Company was the original generator ofthe materials. It asserts that itwillhold the Company liable for all County costs presently estimated at $ 1.5 million associated both with the materials'xcavation, treatment and disposal and with effecting a regulatorily-approved closure of the retention pond area. The Company could incur costs as yet undetermined ifitwere to be found liable for such closure and materials handling, although provisions ofan existing easement afford the Company rights which may serve to offset all or a portion ofany such County claim. To date, the Company has agreed to pay a 20% share ofthe County's most recent investigation ofthis area, which commenced in September 1993 and which is estimated to cost no more than $ 150,000, but no commit-ment has been made toward any remedial measures which may be recommended by the investigation.

In the letter announcing the delisting ofthe Lower Falls site,'YSDEC indicated an intention to pursue appropriate closure ofthe County's former'etention pond area, suggesting that itwillbe evalu-ated separately to determine whether it meets the criteria ofan inactive hazardous waste disposal site.

The Company is unable to assess what implications the NYSDEC letter may have for the County's claim against it.

Monitoringwells installed at another Company facility(Brooks Avenue) in I989 revealed that an undetermined amount ofleaded gasoline.had reached the groundwater. The Company has continued to monitor free product'levels in the wells, and has begun a modest free product recovery project, reports on both ofwhich are routinely furnished to the NYSDEC. Free product levels in the wells have declined. In December 1994, the NYSDEC granted a permit for the storage ofhazardous wastes at this location. Conditions ofthe permit require additional investigation and corrective action of the hazardous constituents at the site. It is estimated that such investigations may cost approximately

$ 100,000. The cost ofcorrective actions cannot be determined until investigations are completed.

Seperfend ahd Other Sifes, The Company has been or may be associated as a potentially responsible party (PRP) at seven sites not owned by it,but for which the Company has been identified as a PRP.

The Company has signed orders on consent for five ofthese sites and recorded estimated liabilities totaling approximately $0.8 million.

In August 1990, the Company was notified ofthe existence of a Federal Superfund site located in.

Syracuse, NY,known as the Quanta Resources Site. The Federal Environmental Protection Agency (EPA) has included the Company in its listofapproximately 25 PRPs at the site, but no data has been produced showing that any ofits wastes were delivered to the site. In return for its release from liability for that phase, the Company has joined other PRPs in agreeing to divide among them, utilizinga two-tier structure, EPA's cost ofa contractor-performed removal action intended'to stabilize the site and

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has signed a consent order to that effect. jhe Company, in the lower tier ofPRPs, paid its $27,500 share ofsuch cost. Although the NYSDEC has not yet made an assessment for certain response and investi-gation costs ithas incurred at the site, nor is there as yet any information on which to determine the cost to design and conduct at the site any remedial measures which Federal or state authorities may require, the Company does not expect its costs to exceed $250,000.

On May21, 1993, the Company was notified by NYSDEC that it was considered a PRP for the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY.The Company has signed, along with other participating parties, an Administrative Order on Consent with NYSDEC. The Order on Consent obligates the parties to implement a work plan and remediate the site. The PRPs have negoti-ated a workplan for site remediation and have retained a consulting firmto implement the workplan.

Preliminary estimates indicate site remediation willbe between $6 and $8 million.The Company is participating with the group to allocate costs among the PRPs. InApril1994, the Company recorded an estimated liabilityof$0.7 millionfor site remediation based on preliminary aHocation. Subsequent work has indicated that total is likelyto be lower when final.

The Company is involved in the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky'and has signed various consent orders to that effect. The Company has con-tributed to a study ofthe site and estimates that its share ofthe cost ofinvestigation and remediation would approximate $205,000.

The Company has been named as a PRP at three other sites and has been associated with another site for which the Company's share oftotal projected costs is not'expected to exceed $ 120,000. Actual Company expenditures for these sites are dependent upon the total cost ofinvestigation and remediation and the ultimate determination ofthe Company's share of'responsibility forsuch costs as well as the financial viabilityofother identified responsible parties since clean-up obligations are joint and several.

Federal Clean AirAct Amendments. The Company is developing strategies responsive to the Federal CleanAirActAmendments of 1990 (Amendments). The Amendments willprimarily. affect air emis-sions from the Company's fossil-fueled electric generating facilities. The Company is in the process of identifying the optimum mixofcontrol measures that willallow the fossil-fuel-based portion ofthe generation system to fullycomply with applicable regulatory requirements. Although work is continu-ing, not. all compliance control measures have been determined. A range ofcapital costs between

$20 millionand $30 millionhas been estimated for the implementation ofseveral potential scenarios which would enable the Company to meet the foreseeable NOx and sulphur dioxide requirements of the Amendments. These capital costs would be incurred between 1996 and 2000., The Company estimates that itcould also incur up to $2.1 millionofadditional annual operating expenses, excluding fuel, to comply with the Amendments. The Company anticipates that the costs incurred to comply with the Amendments willbe recoverable through rates based on previous rate recovery ofenvironmental costs required by governmental authorities.

Gas Cost-Recovery.

.As a result ofthe restructuring ofthe gas transportation industry by the Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and related decisions, there willbe a number of changes in this aspect ofthe Company's business over the next several years. These changes willrequire the Company to pay a share ofcertain transition costs incurred by the pipelines as a result ofthe FERC-ordered industry restructuring. Although the final amounts ofsuch transition costs are subject to continuing negotiations with several pipelines and ongoing pipeline filings requiring FERC approval, the Company expects such costs to range between $44 and $52 million.A,substantial portion ofsuch costs willbe on the CNG Transmission Corporation (CNG) system ofwhich approximately

$27 millionwas billed to the Company on December 3, 1993 and subsequently paid by the Company.

The Company has entered into a $30 millioncredit agreement with a domestic bank to provide funds forthe Company's transition cost liabilityto CNG. AtDecember 31, 1994 the Company had

$ 18.7 millionofborrowings outstanding under the credit agreement. The Company has begun collecting those costs through the Gas Clause Adjustment (GCA) in its rates.

The Company is committed to transportation capacity on the Empire State Pipeline (Empire) which commenced operation in November 1993, as well as to upstream pipeline transportation and storage services. The Company also has contractual obligations with CNG and upstream pipelines

~ ~

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whereby the Company is subject to charges for transportation and storage services for a period extend-ing to the year 2001. The combined CNG and Empire transportation capacity exceeds the Company's current requirements. This temporary excess has occurred largely due to the Company's initiatives to diversify its supply ofgas and the industry. changes and increasing competition resulting from the implementation ofFERC Order 636.

Under FERC rules, the Company may transfer its excess transportation capacity in the market. The Company is attempting to da that, whenever possible, The. Company also entered into a marketing agreement with CNG, pursuant to which CNG willassist the Company in obtaining permanent replacement customers for the transportation capacity the Company willnot require. While CNG has already secured letters ofintent for a substantial portion ofsuch capacity and has ordered compressors and other related equipment associated with the planned modifications to CNG's pipeline, whether and to what extent CNG and/or the Company can successfully negotiate the assignment ofthe excess capacity, or at what price, cannot be determined at the present time. The abilityofCNG to market this capacity may depend on FERC approval ofrolled-in (rather than incremental) rate treatment for the CNG new facilitycosts necessary to serve the letter ofintent customers. Several CNG customers have protested CNG's proposed rolled-in rate treatment, arguing that such costs should be borne as incre-mental by the letter ofintent customers. The FERC has issued a preliminary determination on non-environmental issues in which they concluded that itwould be in the public interest to authorize construction and operation ofthe proposed facilities. Subsequent to the protests filedin response to the proposed rolled-in rate treatment ofthe facilitycosts, the Company entered into an amended and restated marketing agreement with CNG.As a result ofthis agreement and the negotiations surrounding its implementation, CNG is prepared to file a settlement agreement with the FERC, reflecting certain changes in the facilities and their cost. The impact ofthe changes on rates is favorable to the approval ofrolled-in treatment ofthe facilitycosts. As a result, the Company anticipates that there willnot be significant objection to the settlement, however, the timing ofthe FERC decision on the settlement and with respect to environmental issues cannot be determined at the present time and that decision is necessary to implement the permanent assignment ofthe excess capacity. The Company has also exercised its option to postpone for one year. the commencement ofcertain Empire-related trans-portation service that was scheduled for November 1994, The Company willcontinue to pursue other options for the release ofthe capacity.

Areconciliation ofgas costs incurred and gas costs billed to customers is done annually, as ofAugust 31, and the excess or deficiency is refunded to or recovered from customers during a subsequent period. In October 1994, the Company submitted to the PSC its ann'ual GCA reconciliation providing for recovery of $24 million,ofdeferred gas costs, which was substantially higher'than in previous years principally due to factors mentioned above.

The StafFof the PSC has reviewed the Company's application for recovery ofdeferred costs 'and the Consumer Protection Board, along with certain individuals or groups ofratepayers, has requested that the PSC conduct hearings to determine whether and on what terms the deferral should be recovered. On December 19, 1994, the PSC instituted a proceeding to review the Company's practices regarding acquisition ofpipeline capacity, the costs ofthe capacity and the Company's recovery ofthose costs.

The costs included in the deferral have ordinarily been recovered in the past and the Company believes that they should be recovered in this instance; however, it is possible that with respect to these costs, the PSC may not recognize all ofthem in rates. Ifthat were to occur, the Company would be compelled to discontin'ue deferring and recovering costs above the allowed amount, and would recognize the disallowed costs as they were incurred as a charge against earnings. In addition, in a more adverse decision, the PSC could order the Company to refund a portion ofsuch costs previously collected from ratepayers. Pending conclusion ofthe proceeding, the PSC directed the Company to recover Order 636 transition costs over a five-year period and all other unrecovered gas costs over 18 months.

As an interim measure, on February 1, 1995 the PSC directed the Company to remove from existing rates $ 16 millionofgas revenues representing a portion ofthe costs attributable to excess capacity over the remaining term ofthe contracts. Prospective capacity release credits obtained by the Company are to be used to offset such amounts. These deferred costs are subject to recovery by the Company from customers, with interest, to the extent the Company's actions are found prudent.

The Company cannot predict to what extent the deferred costs described above would be recoverable in rates.

(Note lOeontlnttrd on'page SO)

teaarinued Paar page 49)

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The Company's purchased gas expense charged to customers willbe higher during the 1994-95 heating season for the reasons described above. In addition, beginning in January 1995 and continuing until May1995, the Company'elected to discontinue the operation ofits weather normalization clause (see Note I) in circumstances where the weather is warmer than normal because ofthe unusually mild weather that has been experienced in its service territory and the adverse effects on customer bills.The earnings impact ofthis decision in 1995 willrange between $3.5 and $8.7 milliondepending on the duration ofmildweather for the heating season.

Gas Purchase Undercharges.

The Company became aware during 1993 that itdid not account properly for certain gas purchases for the period August 1990-August 1992 resulting in undercharges to gas 'customers ofapproximately

$7.5 million.Qfthe total undercharges,

$2.3 millionhad previously been expensed and $5.2 million had been deferred on the Company's balance sheet. InMarch 1994, the PSC approved a December 1993 settlement among the Company, PSC Staff and another party providing for the recovery in rates of$2.6 millionover., three years. The Company wrote off$2.0 millionofthe undercharges as of December 31, 1993reducing 1993 earriings by four cents per share, net oftax. In April1994, the Company wrote offan additional $0.6 millionreducing 1994 earnings by approximately one cent per share, net oftax. Due to rate increase limitations established for the second year ofthe rate settlement, the Company is precluded from recovering the undercharges until the third year ofthe rate settlement, which begins July 1, 1995.

Assertion ofTax Liability.

The Company's Federal income tax returns for 1987 and 1988 have been examined by the Internal Revenue Service (IRS) which has proposed adjustments ofapproximately $29 million.-

The adjustments at issue generally pertain to the characterization and treatment ofevents and rela-tionships at the Nine Mile7wo project and to the appropriate tax treatment ofinvestments made and expenses incurred at the project by the Company and the other co-tenants. Aprincipal issue is the year in which the plant was placed in service.

The Companyhas filed a protest ofthe IRS adjustments to its 1987-88 tax liabilityand the appeals officers have indicated a decision may b'e forthcoming on the service year issue in 1995. The Company believes it has sound bases for its protest, but cannot predict the outcome thereof. Generally, the Company would expect to receive rate reliefto the extent it was unsuccessful in its protest except for that part ofthe IRS assessment stemming from the Nine Mile'Avo disallowed costs, although no such assurance can be given.

The IRS has also completed in 1994 its audit ofthe Company's Federal, income tax returns for 1989 and 1990, which has resulted in a proposed refund of $600,000. Since this refund arises from the contentious issues from the prior audit, the Company has filed a protest with theIRS.

Regulatory and Stranded Assets.

Certain costs are deferred and recognized as "expenses when they are reflected in rates and recovered from customers as permitted by Statement ofFinancial. Accounting Standard No. 71, "Accounting of the Fffects ofCertain +pcs ofRegulation." These costs are shown as Regulatory Assets. Such costs arise from the traditional cost-of-service rate setting approach where all prudently incurred costs are recov-erable through rates. Deferral ofthese costs is appropriate while the Company's rates are regulated under a cost-of-service approach.

In a purely competitive pricing approach, such costs might not have been incurred or deferred.

Accordingly, ifthe Company's rate setting were changed from a cost-of-service approach and itwas no longer allowed to defer these costs under SFAS /1, certain ofthese assets may not be fullyrecoverable.

Below is a summarization ofthe Regulatory Assets as ofDecember 31, 1994.

Millionsof Dollars

- Income Taxes Deferred Ice Storm Charges Uranium Enrichment Decommissioning Deferral FERC 636 Transition Costs Demand Side Management Costs Deferred Deferred Fuel Costs Gas Other, net Total Regulatory Assets

$205.8 19.1 20.2 32.5 19.8 33.8 337

$364.9

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~ Income Taxes This amount represents the unrecovered portion oftax benefits from accelerated depreciation and other timing di6erences which were used to reduce tax expense in past years. The recovery ofthis deferral is anticipated when the effect ofthe past deductions reverses in future years.

~ Deferred Ice Storm Charges: These costs result from the non-capital storm damage repair costs followingthe March 1991 ice storm.

~ Uranium Enrichment Decommissioning Deferral: This amount is mandated to be paid to DOE over the next 13 years. The Energy PolicyAct of 1992 requires utilities to contribute such amounts based on the amount of uranium enriched by DOE for each utility.

~ FERC 636 Transition Costs: These costs are payable to gas supply and pipeline companies which are passing various restructuring and other transition costs on to RGgtE, as ordered by FERC.

~ Demand Side Management Costs Deferred: These costs are Demand Side Management costs which relate to programs initiated to increase efficiency with which electricity is used.

~ Deferred Fuel Costs Gas: These costs are recoverable over future years and arise from an annual reconciliation

'ofgas revenues and costs (as described in Note 1).

Stranded assets (or other costs) arise when investments are made in facilities or costs are incurred to serve customers and such costs may not be fullyrecoverable in rates.'Examples include purchase power contracts (i.e., the Kamine contract) or uneconomic generating assets.

Excluding the Kamine contract described above, estimates ofstranded asset costs are highly sensitive to the competitive wholesale price assumed in the estimation for electricity. The amount ofstranded assets at December 31, 1994 cannot be determined at this time, but could be significant.

While the Company currently believes that its regulatory and stranded assets are probable. of recovery in rates, industry trends have moved more toward competition, and in a purely competitive environment, it is not clear to what extent, ifany, writeoffs ofsuch assets may occur.

~ DlVOOISit 01 ONDWIPWIKMIWLKCCOOItIIÃaN'ii%S price Jraterhouse ue gP To the Shareholders and Board ofDirectors of Rochester Gas and Electric Corporation 1900 Chase Square Rochester, New York 14604-1984 January'20, 1995 (except for Note 10, as to which the date is February 1, 1995)

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements ofincome, retained earnings and cash. flows present fairly,in all material respects, the. financial positiori of Rochester Gas and Electric Corporation and its subsidiaries at December 3l, 1994 and 1993, and the results oftheir operations and their cash flows foreach ofthe three years in the period ended december 31, 1994 in conformitywithgenerally accepted accounting principles. These financial statements are the responsibility ofthe Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accountmg principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.

As discussed in Note 1 to the financial statements, the Companyadopted the provisions of Statement ofFinancial Accounting Standards No. 112, "Employers'Accounting for Postemployment Benefits" in 1994.

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7 The management ofRochester Gas and Electric Corporation has prepared and is responsible for the consolidated financial statements and related financial information contained in this Annual Report. Management uses its best judgements and estimates to ensure that the financial statements reflect fairlythe financial position, results ofoperations and cash flows ofthe Company in accordance with generally accepted accounting principles.

Management maintains a system ofinternal accounting controls over the preparation ofits financial statements designed to provide reasonable assurance as to the integrity and reliabilityofthe financial records.

This system ofinternal control includes documented policies and guidelines and periodic evaluation and testing by the internal audit'department.

The Company's financial statements have been examined by Price Waterhouse LLP, independent accountants, in accordattce with generally accepted auditing standards.

Their examination includes a review ofthe Company's system ofinternal accounting control and such tests and other procedu'res necessary to express an opinion as to whether the Company's financial statements are presented fairlyin all material respects in conformity with gener-ally accepted accounting principles. The report ofPrice Waterhouse LLP is presented on page 51.

The AuditCommittee ofthe Hoard ofDirectors is responsible for reviewing and monitoring the Company's financial reporting and accounting practices. The Audit Committee meets regularly with management and the independent accountants to review auditing, internal control and financial reporting matters. The independent accountants have direct access to the AuditCommittee, without management present, to discuss the results of their examinations and their opinions on the adequacy ofinternal accounting controls and the quality offinan-cial reporting.

Management believes that, at December 31, 1994, the Company maintained an effective system ofinternal control over the preparation ofits published. financial statements.

8/W Roger K Kober Chairman ofthe Board, President and Chief Executive Officer January24,1995 Th ocm as $. Richards Senior Vice President, Corporate Services and General Counsel 77'5 a

8 a

In the opinion ofthe Company, the followingquarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fairstatement ofthe results ofoperations for such periods. The

'ariations in operations reported on a quarterly basis are a result ofthe seasonal nature ofthe Company's business and the availabilityofsurplus electricity.

(Thousands of Dollars)

Quarter Ended December 31, 1994 September 30, 1994>>

June 30, 1994 March 31, 1994 December 31, 1993>>>>

September 30, 1993>>'>>

June 30, 1993 March 31, 1993 Operating Revenues

$2437697 229,982 217,083 310,052

$256,219 217,278 203,252 272,275 Operating income

$42,249 41,007 24,578 47,178

$43,756 38,058 21,295 44,124 Net Income

$25,618 4,912

'9,608 34,237

$22,366 20,204

',909 29,084 Earnings on Common Stock

$23,751 3,046 7,742 32,467

$20,541

. 18,379 5,084 27,259 Earnings per Common Share (in dollars)

$.63

.08

.20

.87

$.55

,51

.15

.78 December 31, 1992

$244,290

$41,744

$29,146 September 30, 1992 198,341 33,006 17,507 June 30, 1992'>>>>>>

195,154 16,460 (4,579)

March 31, 1992 257.747 42,735

'8.355 Includes recognition of52Lp millionnet.of tee pension plar curtailment.

"Includes recognition of$ 1.9 millionnet-of-tax pension plan curtailment.

"'"Indudes recognition of$3.4 millionnet-of-tax pension plan curtailment.

'""Indudes recognition of$5.4 millionnet-of'-tax ice storm disallowance.

$27,073 15,435 (6,651) 26,293

$.77

.45

(.20)

.81

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Earnin s/Dividends 1994 1993 1992 Shares/Shareholders 1994 1993 1992 Earnings per weighted average share Dividends paid

'ershare

$1.79

$2.00

$1.86

$1.76

$1.72

$1.68 Number ofshares (000's)

Weighted average Actual number at December 31 Number ofshareholders at December 31 37,327 35,599 33,258 37,670 364911 34,797 37,212 38,102 39,017 Rochester Gas and leek Corporation Tax Status of Cash Dividends Cash dividends paid in 1994, 1993 and 1992 were 100 percent taxable for Federal income tax purposes.

Dividend Policy The Company has paid cash dividends quarterly on its Common Stock without interruption since itbecame publiclyheld in 1949. The Company believes that future dividend payments willneed to be evaluated in the context ofmaintaining the financial strength necessary to operate in a more competitive and uncertain business environment. This willrequire consideration, among other things, ofa dividend payout ratio that is lower over time, reevaluating assets and managing greater fluctuation in revenues, While the Company does not presently expect the impact ofthese factors to affect the Company's abilityto pay the current dividend, future dividends may be affected. The Company's Certificate ofIncorporation provides for the payment ofdividends on Common Stock out ofthe surplus net profits (retained earnings) ofthe Company.

Quarterly dividends on Common Stock are generally paid on the twenty-fifthday ofJanuary, April,July and October. In January 1995, the Company paid a cash dividend of$.45 per share on its Common Stock, up $.01 from the prior quarterly dividen'd payment of$.44. The January 1995 dividend payment is equivalent to $ 1.80 on an annual basis.

Common Stock Trading Shares ofthe Company's Common Stock are traded on the New YorkStock Exchange under the symbol "RGS".

1994 1993 1992 Common Stock Price Range High 1st quarter 2nd quarter 3rd quarter 4th quarter Low 1st quarter 2nd quarter 3rd quarter 4th quarter AtDecember 31 26%

25%

23i/i 21 i/i 28N 28 29i/i 29/i 23'/i 24i/i 20i/i 25i/i 19i/i 27i/i 20 i/i 24/i 20i/i 26'/i 23/i 24 24i/i 25i/i 20%

21'/i 22i/i 23'/i 24'/i

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, g.

thousands of Oollars)

Year Ended Oecember 31 1994 1993 1992 1991 1990 (Oo)444400 G<<0 <<04) 2)444430 CO790404)On Consolidated Summary of Operations

,Operating Revenues Electric Gas Electric sales to other utilities Total Operating Reveriues Operating Expenses-Fuel Expenses Electric fuels Purchased electricity Gas purchased for resale Total Fuel Expenses Operating Revenues Less Fuel Expenses Other Operating Expenses Qpeiations excluding fuel expenses

Maintenance, Depreciation and Amortization Taxeslocal, state and other Federal income tax

'current

deferred Total Other Operating Expenses Operating Income Other Inconre and Deductions Allowance for othe'r funds used during construction Federal income tax Pension plan curtailment

'egulat6ry disallowancts Other,net' Total Other Income and (Deduclions)

Income before Interest Charges, Interest Charges Long term debt Shortterm debt Other, net

'llowanceforborrowed funds used.durmg construction Total Interest Charges Net Income Dividends on Preferred Stock Earnings Applicable to Connnon Stock 658,148 326,061 984,209 16,605 1,000,814 44,961 37,002 194,390 276,353 724,461 235,896 55,069 87,461 129,778 35,658 25,587 569,449 155,012 396 16,259 (33,679)

(600)

(4,853)

(22,477) 132,535 53,606 1,808 4,758 (2,012) 58,160 74,375 7,369 67,006

$638,955 293,708 932,663

'6,361

~

949,024 45,871 31,563 166,084 244,318 704,706 235,381 61,693 84,177 126,892 33,453 15,877 557,473 147,233 153 9,827 (8,179)

(1,953)

~(7,074 (7,226) 140,007 56,451 1,487 5,220 (1,714) 61.444 78,563 7,300

$ 71,263

$608,267 261,724 869,99'l 25.541 895,532

$588,930 235,728 824,658 28,612

~

853,270 48,376 29,706 141,291 219.373 676,159

'I 226,624 62,720 85028 124,252 36,101 7,490 542,215 133,944 65,105 27,683 129,779

'222,567 630,703 208,440 65,415 84,181 113,649 28,766 5,493 505,944 124,759 164 4,195 (8,215) 6,155 2,299 675 4,580 (10,000) 6,078 1,333 60,810 1,950 5,228

. (2,104) 65,804 70,439 0.290

, 62,149 63,918 2,623 4,459 (2,905) 68,095 57,997 6,963

$ 51,034

'136.243 126,092

$551,930 236,496 788,426 42,465

'30,891 76,420 34,264 132,512 243,1 96 587,695 194,594 62,391 77,767 101,035 20,661 13,829 470,277

~ 117,418 2,689 2,459 4,062 9,210 126,620 64,873 1,070 3,523 (2,719) 66.747 59,881 6,025

$ 53,056

$543,096 264,573 807,669 38,028 845,697 75,873 39,645

152,623 268,141 577,556 173,764 64,316 75,063 95,341 20,509 17,330 446.323 131,233 2,261 1,439 (2,'100) 8,328 9,928 141,1 61 68,628 3,115 (2,026) 69,717 71,444 6,025

$ 65,419 Weighted Average Number ofShares For Period (000's)

Earnings per Coni mon Share Cash Dividends Paid per Common Share 37 327

$1.79

$1.76 35,599

$2.00

$1.72 33,258

$1.06

$1.68 31,794

$ 1.60

.$1.62 31,293 31,090

$1.72

$ 2.10

$1.56

$(.50

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Condensed Consolidated Balance Sheet (Thousands of Dollars)

At December 31 1994 1993 1992 1991 1990 1989 Assets UtilityPlant Less: Accumulated depreciation and amortization '2,981,151

$2,890,799

$2,798,581 1,423,098 1,335,083 1,253,117

$2,706,554 1,178,649

$2,310,294 812,994 2,208,158'30,621 Construction work in progress Net utilityplant CurrentAssets Investment in Empire Deferred Debits and Regulatory Assets Total Assets I:apitalizatlon and Liattltlties Capitalization Long term debt Preferred stock redeemable at option ofCompany Preferred stock subject to mandatory redemption Common shareholders'quity Common stock Retained earnings Total common shareholders'quity Total Capitalization Long Term Liabilities (Department ofEnergy)

Current Liabilities Deferred Credits and Other Liabilities Total Ca italization and Liabilities Flnanclal Data 1,558,053 1,555,716 1,545,464 128,860 112,750 83,834 1,686,915 1,668,466 1,629,298 236,519 248,589 209,621 38,560 38,560 9,846 504,204 507,769 200,676 1,527,905 76,848 1,604,753 189,009 160,034 1,497,300 82,663 1,579963 176,045 108,451 1,477,537 68,784 1,546,321 190,321 102,729

$2,466,196

$2,463,384

$2,049,441

$1,953,796

$ 1,864,459

$ 1,839.371 55>000

'2,000 54,000 60,000 30,000 30,000 670,569 74,566 652,172 75,126 591,532 66,968 529,339 61,515 516,388 62,542 513,560 57,983 745,135 727,298 658,500 1,602,313 1,583,929',438,380 590,854 1,390,176 578,930 1,397,542 571,543 1,433,170 87,826 89,804 94,602 181,327 234,530 267,276 594,730 555,121

'49,183

$2,466,196

$2,'463,384

$2,049,441 63,626

'67,601 232,393

$1,953,796 59,989 183,720 223,208

$1,864,459 55,502 137,899 212,800

$1,839,371 735,178 747,631 658,880 672,322

$ 721,612 764,627 67,000 67,000 67,000 67,000 67,000 67,000 At December 31 1994 1993 1992 1991 1990 1989 53.6 6.7 39.7 100.0

$18.42 49.4 48.2 6.6 8.0 44.0 43.8 100.0 100.0

$19.70

$18.92 11.56(c) 8.60 8.32 6.97 33.9 3.05 2.94 8.74 6.72 33.8 3.25 2.96 7AO 6.26 37.7 2.69 2.62 Capitalization Ratios(a) (percent)

Long term debt 48.2 50.6 55.1 Preferred stock 7.3 8.7 6.5 Common shareholders'quity 44.5 40.7 38.4 Total 100.0 100.0 100.0 Book Value per Common Share Year End

$19.78=

$18.41

$18.28 Rate ofReturn on Average Common Equity (percent) 11.73(b) 10.25(b)

'.98 9.29 Embedded Cost ofSenior Capital (percent)

Long term debt 7.36 7.91 8.59 Preferred stock 6.69 6.98 6.72 Effective Federal Income Tax Rate (percent) 33.5 35.9 34.8 Depreciation Rate (percent) Electric 2.62 2.69 3.33

Gas 2.60 2.78 2.94 Interest Coverages(c)(d)

Before federal income taxes (incld. AFUDC) 3.55 3.03 2.74 2.38 2.32, 2.53 (excld. AFUDC) 3.51 3.00 2.70 2.33 2.25 2.47 After federal income taxes (incld. AFUDC) 2.61' 2.35 2.12 1.91 1.86 2.02 (excld. AFUDC) 2.57 2.32 2.08 1.86 1.78 1.96 (a)lndudes Company's long term liabnityto the Department ofEnergy (DOE) for nuclear waste disposal. Exdudes DOE long term liabilityfor uranium enrichment decommissioning and amounts due ot'edeemable within one year.

(b)Rate ofreturn on average common equity excludes the effects t7fretirement enhancementprograrns recognized by the Company in 1994 and 1993.

(c)Excludes disallowed Nine Mile'Avoplant costs written oifin 1989, (d)The recognition by the Company in 1991 ofa fuel procurement audit approved by the New YorkState Pu)71ic Service Commission (PSC) has been exduded from 1991 coverages. Likewise, recognition by the Company in 1992 ofdisallowed ice storm costs as approved by the PSC has been exduded from 1992 coverages. Coverages for 1994 and 1993 exclude the effects ofretirement enhancement programs recognized by the Company during each year and certain gas purchase undercharges written offin 1994 and 1993.

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I)rrororo2ooeeooro3or otlllttllletfllot)-"I Year Ended Oecember 31 1994 1993 1992 '.

1991 1990 1989 Rodeo)rrr 4

G66 Ar)4) 04441(r Corporotlor)

ElectricRevenue (000's)

Residential Commercial Industrial Other (Includes Unbilled Revenue)

'lectric revenue from our customers Other electric utilities Total electric revenue,

~

Electric Expense (000's)

Fuel used tn electric generation

, Purchased electricity Other operation Maintenance Depreciation and Amortization Taxes lo'cal, state and other Total electric expense Operating Income before Federal Income Tax Federal income tax Operating Income from Electric Operations (000's)

Electric OperatingRatio,%

Electric SalesKWH(000's)

Residential e

<<Commercial

'ndustrial Other '

Total billed Unbilled sales Total customer sales Other electric utilities Total electric sales Electric Customers at December 3I Residential Commercial Industrial Other Total electric customers Electricity Generated and Purchased KWH (000's)

Fossil Nuclear.

Hydro

,, Pumped storage Less energy for pumping Other Total generated Net Purchased Total electric energy System Net Capability-KWat December 3L Fossil Nuclear Hydro Other Purchased Total system'net capability Net Peak Load,KW Annual Load FactorNet e%

$243,593 206,910

~ 150,690 56,955

$235,286 196,456 147,396 59,817 658,148 638,955 16,605 16,361

$220,866 184,815 142,392 60,194 608,267 25,541

$212,327 181,561'41,001 54,041 588,930 "28,612

$197,612 165,445 130,012 58,861 551,930 42.465

$191,732 155,0?6

'24,634'1.654

5'43,096 38,028

'74,753 655,316 633,808 617,542 594,395 581,'1 24 44,961 37,002 187,594 47,295

,75,211 97,919 45,871 31,563 188,684 52,464 72,326 96,043 48,376 29,706 183,118 53,714 73;213 94,841 65,105 27,683 168,610 57,032 72,746 86,925 76 420

'34,264 155,289 53,880 67,302 77,323 75,873 39,645 137,458 55,915 65,287 71,361

$131,929

. $124.520 47.0 48.6

$112,794

'9.7

$108,051 51.6

$ 99,247 53.8

$ 105,698 53.2 21111,468 2,0321811 1,867,972 51 6.775 2,124,763 ',084,466 1,987,490 1,937)950 1,894,026,1,929,498 505,341 503,330 6,529,026 6,511,620 6,455,244 (8,739)

(4,556) 742 6,5203287 6507,064

',455,986 1,021,733 743,588 1,062,738 2,085,429 1,928,?30 1,917,796 507,765 6,439,720 7;657 6,447,377 1,034,370 2,075,072 2,072,047 1,897,583 1,832,521 1,931,633 1,906,429 490,077 491,905 6,394,365 6,302,902 (25,421)

'3,406 6,368,944 6,336,308 1,316,379 1,255,282 7,542,020 7,250,652 7.518,724 7,481,747 7,685323 7,591,590 304,494 302,219 29,984 29,635 1,361 1,382

. 2,670 2,638 300,344 29,339 1,386 2,605 298440 296,110 28,856 28,804 1,388 1,428 2;558 2.563 293,418 28,386 1,422

. '2.512 338,509 335,874 333.674 331,242 328,895 325,738 1,520,936 4,495,457 199,239 233,477 (355,725) 2,559 1,478,120 4,527,178 218,129 24?,550'371,383) 1,245 6,095,943 1,646,244 6,100,839 1,998,882 8,099,721 7,742,187 2,197,757 4191 035 278,318 226,391 (344,245) 811 6,550,067 1,389,875 7,939,942 2,146,664 4,391,480 174,239 240,206 (364,520) 1,269 6,589,338 1,451,208 2,505,110 4,016,721 244,539 269,966 (405,966) 20,408 6,650,778 1,498,089 2,578,006 3,659,185 175,085 290,582, (429,895) 54,893 6,327,856 1,757,413 8.040.546 8,148,867, 8,085,269 532,000 617,000 47,000 29,000 375,000 541,000

'" 620,000 47,000 29,000 347,000 54'l,000 617,000 47,000 29,000 348,000 541,000 622,000 47,000 29,000 354,000 541,000

'621,000 47,000 29,000 356,000 541,000 621,000 47,000 29,000 369,000 1,600,000 1,584,000 1,582,000 1,593,000 1,594,000 1.607,000 17374,000 1,333,000 1,252,000 1,297,000 58.8 59.1 62.5 '61.7 e

1,208,000 1,249,000 64.6 62.4 489,982 486.951 482,968

'78,101 464,478 445,539 184,771 168,365

'f50,840 139,441 129,917 135,585 82,842 43,845 38,046 31.390

'0,670 29,887

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Year Ended December31 1994 1993 1992 1991 1990 1989 Gas Revenue (000's)

Residential Residential spaceheating Commercial Industrial Municipal and other (Includes Vnbilled Revenue)

Total gas revenue Gas Expense (000's)

Gas purchased for resale Other operation Maintenance Depreciation Taxeslocal, state and other Total gas expense Operating Income before Federal Incotne Tax Federal income tax Operating Income frotn Gas Operations (000's)

Gas Operating Ratio 4y(7 Gas Sales Therms (000's)

Residential Residential spaceheating Commercial Industrial Municipal Total billed Vnbilled sales Total gas sales Transportation ofcustomer-owned gas Total gas sold and transported Gas Customers at December 31 Residential Residential spaceheating Commercial Industrial Municipal Transportation Total gas customers Gas Thernts(000's)

Purchased for resale Gas from storage Other Total gas available e

Cost ofgas per therm (cents)

Total DailyCapacity-Therms at Decentber 31 0 Maximumdaily throughput Therms Degree Days (Calendar Month)

For the period Percent colder (warmer) than normal 6,770 165,832 46,897 9,371 6,508 159,501 43,534 9,674 6,456 183,405 44,274 6,418 6,354 157,458 40,196 6,761 5,526 196,411 45,620 6,346 5,935 221,927 50,318 7,254 17,270 236,496 35,703 264,573 24,959 235,728 21,171 261,724 39,805 293,700 40,627 326,061 152,623 36,306 8,401 9,776 23,900 132,512 39,307 8,510 10,465 23,711

= 129,779 39,830 8,383 11,435 26,724 141,291 43,506 9,006 11,815 29,411 166,884 46,697 9,229 11,851 30,849 194,390 48,302 7,774 12,250 31,859 33,487 7,952

$ 25,535 74.6 21,991 3,020

$ 10,171 76.3 31,486 8,403 28,198 5,485 26,695 5,545 19,577 2,869

$ 16,708 75.5

$ 23,003

$ 22,713

$ 21,150 75.9 74.1 76.8 10,321 277,267 9,644 262,458 77,617 18,536 13,350 6,735 289,252 77,326 11,792 11,947 9,068 253,655 71,509

~ 13,000 10,580 6,533 290,241 74,647 11,823 10,500 8,780 287,614 78,993 12,437 11,410 84152 17,873 12,319 393,744 '97,052 399,234 357,812 381,605 (10,110) 0,017 13 3,291 (22,840) 401,932 20,320 422,252 105,303 361,103 358,765 109,835 101,985 405,069 399,247 124,436 126,140 383,634 136,372 520,006 529,505 525,387 470,938 460,750 527,555 18,389 231,937 18,636 924 1,001 466 23,321 2'l5,120 17,677 1,095 1,067 367 22,410 219,242 17,920 960 984 401 21,448 222918 18,151 921 983 423 19,114 228,096 18,378 932 1,010 424 267,954 17,836 235,313 18,742 905 988 558 264,844 261,917 258,647 274,342 271,353 r

366,684 426,941 2,525 1,764 262,267 347,778 134,802 76,378

. 2,959 1,039 384,643 16,755 1,617 360,493'3,757 1,061 400,020 425,195 415311 403,015 369,209 428,705 50.005 36.79) 35.35(

32.96t!

36.03t0 35.74) 4,485,000 3,539,820 5,625,000 3,864,850 4,485,000 3,719,050 5,625,000 4,485,000 3,768,470 4,485,000 3,539,260 4,735,690 7,044

~

6,981 6,146 5,924 7,109 4.4 3.4 (8.4)

(11.8) 5.9 network analysis, reflects the mssimnm demand which the 6,699 (0 6)

"Method for determining daily capacity, based on current transmission systems can accept without a deficiency.

294,575 265,510 235,029 216,151 214,505 231,086

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Roottottof t

Gaa and nontto Corporation Requests forinformation Investors and security analysts seeking information about the Company should contact David C.

Heiligman, Vice President, Finance and Corporate Secretary.

Form fO-KAnnual Report Shareholders may obtain a copy of the Company's 1994 annual report on Form IO-K, as filedwith the Stacurities and Exchange Commis-sion, without charge, by writing'to the Secretary.

Shareholder Services Shareholders with questions about dividend payments, address changes, missing certificates, ownership changes and other account informa-tion should contact our transfer'gent.

Dividend Payment Dates RG&E's Board ofDirectors meets quarterly to consider the payment of dividends. Dividends on Common Stock are normallypaid on or about the 25th ofJanuary, April,July and October. Dividends on the Preferred Stocks are payable, as declared, on or about the 1st 'ofMarch, June, September and December.

Dividend Direct Deposit Shareholders can elect to have their quarterly cash dividends electroni-cally deposited into their personal bank accounts. Deposits are made on the date the dividend is payable. If you would liketo take advantage of this service, contact our transfer agent.

Dividend Reinvestment Common Stock shareholders who wish to acquire additional shares free ofbrokerage commissions or service charges are invited to join RG&E's Automatic Dividend Reinvestment and Stock Purchase Plan. Under the plan, shareholders authorize an inde-pendent agent to purchase shares of RG&ECommon Stock with their cash dividends. Shareholders may also participate in the plan by making optional cash payments, even ifthey decide not to reinvest their dividends..

Fdr further information, contact our transfer agent.

Duplicate Nailings Shareholders with more than one account generally receive duplicate mailings ofannual and other reports.

To eliminate additional mailings, write to our transfer agent. Enclose labels or label information, where.

possible. Separate dividend checks and proxy material willcontinue to be sent for'ach account ofrecord.

Stock Listings RG&E's Common Stock is listed on the New YorkStock Exchange and is identified by the stock symbol RGS.

The Preferred Stock issues are traded on the over-the-counter market.

Corporate Office Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649-0001 (716) 546-2700 Agent forAutomatic Dividend Reinvestment and Stock Purchase Plan The First National Bank ofBoston Dividend Reinvestment Unit MailStop: 45-01-06 P.O. Box 1681 Boston, MA02105-1681 (800) 736-3001 Transfer Agent and Registrar The First National Bank ofBoston Shareholder Services Division MailStop: 45-02-09 P.O. Box 644 Boston, MA02102-0644 (800) 736-3001 First Nortgage Bond Trustee and Paying Agent Bankers Trust Company Attn: Security Holder Relations P.O. Box 9006 Church Street Station New York,NY 10249 (800) 735-7777 Printed on reoycled paper. 4P

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d Board ofDirectors (as ofjanuary 1, 1995)

II'IHamBalderston ill"4/

Former Executive Vice President, The Chase Manhattan Corporation Angelo J. Chiarella t President and Chief Executive Officer, Midtown Holdings Corp.

Allan E. Dugan "t Senior Vice President, Corporate Strategic Services, Xerox Corporation NiHiam F. Fowble tg Former Senior Vice President and Executive Vice President, Imaging, Eastman Kodak Company Jay T. Holmes/

Senior Vice President and ChiefAdministrative Offtcer, Bausch 8c Lomb Incorporated Roger N Kober'hairmanofthe Board, President and Chief Executive Offtcer, Rochester Gas and Electric Corporation David K. Laniak Executive Vice President and Chief Operating OAicer, Rochester Gas and Electric Corporation Theodore L. Levinson t Former President and Chief Executive OAicer, Star Supermarkets, Inc.

Constance M. Mitchellt/

Former Program Director, Industrial Management Council of Rochester, New York, Inc.

Cornelius J. Murphy"g Senior Vice President, Goodrich 8c Sherwood Company ArthurM. Richardson "g/

President, Richardson Capital Corporation M. Richard Rosette Former President, Rochester Institute ofTechnology Officers (as ofJanuary 1, 1995)

Roger N Kober Chairman ofthe Board, President and Chief Executive Offtcer Age 61, Years ofService, 29 David K. Laniak Executive Vice President and Chief Operating OAicer Age 59, Years ofService, 40 Thomas S. Richards Senior Vice President, Corporate Services and General Counsel Age 51, Years ofService, 3 Robert E. Smith Senior Vice President, Customer Operations Age 57, Years ofService, 35 David C. Heiligman Vice President, Finance and Corporate Secretary Age 54, Years ofService, 31 Robert C. Mecredy Vice President, Nuclear Operations Age 49, Years ofService, 23 yyiHredJ. Schrouder, Jr, Vice President, Customer Development Age 53, Years ofService, 32 Daniel J. Baier Controller Age 48, Years ofService, 11 Mark Keogh Treasurer Age 49, Years ofService, 23 John M. Kuebel Auditor Age 59, Years ofService, 30 Officer/Director Appointment MEhlBER OF ExECUTlvE AND FINANCE CohlMITTEE t MEhl BER OF AUDIT Cohlh!ITTEE 4 hIEXIBEROF CohlhllTTEEON MANACEhlENT

/hIEMBER OF CohlhlITTEE ON DIRECTORs 7 "rI In August 1994, David K. Laniak was appointed Executive Vice President and ChiefOperating OIflcer and also a direc-tor ofthe Company. Ile was formerly Senior Vice President, Gas, Electric Distribution and Customer Services.

ri