ML20070R318
| ML20070R318 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/31/1993 |
| From: | ROCHESTER GAS & ELECTRIC CORP. |
| To: | |
| Shared Package | |
| ML17059A306 | List: |
| References | |
| NUDOCS 9405200158 | |
| Download: ML20070R318 (60) | |
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RG&E Senice Area / Business l l he Company supplies electne and gas service w holly l 1 within the State of New York, and is engaged in the j l T centering around the City of Roc production, transmission, distribution and sale of these services in a nine-coun:) area i The Company's territory, w hich ( l- has a population of approximately Rostrester i l one million, is w ell dis ersitied among l residential, commercial and indus- ' l I trial customers. In addition to the City of Rochester, which is the l l third largest city and a major I industrial center in the State. l it includes a large and prosperous farming area. i A 3
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llochest-r's mkyline higidights ItGRE** new ; energy-efficient logo sign atop corporate headquarter *. l Illending with the photo at the bottoin in !
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o i L Financial Highlights
-1993' -1992 Change
. Financial Data (Dollars in Thousan'ds)
Operating revenues: Electric $655,316 $633,808 3' a
.- Gas $293,708 $261,724 12 ,
Operating expenses $801,791 $761,588 5.- Operating income $147,23J $133,944 :10- ;
- Net income ,
$. 78,563 ' . $ 70,439 - 12 -
Eamings applicable to common stock ~ $ 71,263 $ 62,149 .15 ~ Rate of return on average common equity 10.25 % - 9.98%: .
- 3. -
6 Common Stock Data Weighted average number of shares outstanding (thousands) 35,599 33,258 ~ 7 Per common share: - Earnings - $2.00 $1.86 8 Dividends $1.72 - $1.68 . 2 Book Value (year end) - $19.70 . $18.92 '4-Year-end market price . $26.25 - $24.50 .7' ' Number of Common Stock Shareholders at December 31 38,102 39,017 (2); Operating Data Sales (thousands) Kilowatt-hours to customers 6,507,064 6,455,986 1 Kilowatt-hours to other utilities 743,588 1,062,738- .(30)- ; Therms of gas sold and transported 529,505 525,387- 1 Customers (year end) . . Electric 335,874 . 333,674 1 , Gas ~ '271,353 267,954 1 r Construction expenditures, less allowance for funds used during construction (thousands)- $139,407 $125,207-: 11 ' , Employees (year end) 2,536 2,702 '(6)~ t 9 khese nu ad t; ens owpune -
m ~N7 ~ +7M, a To Sharehohlers
~
Tineteen ninety-three was a good year for our shareholders, customers and employees alike. It's been a while since we could make a statement like that. All the indica-tors are favorable. Earnings were up, divi-dends were up, year-end common stock hhN market price was up, sales of electricity and , ph , natural gas to customers were up, and so f, p was favorable public opinion as measured b f[ r by our annual customer attitude survey. At ke the same time, operation and maintenance expenses came in under forecast. The { K .. w real driving force behind this improved performance is our highly motivated work force and a strong commitment to our Roger w. Kober Corporate ilusiness Plan. 'hj Our 1991 annual report described our business plan and its major objectivcF. We seek to improve customer service, make the price of our products more competitive, help ensure safety for employees and the public, maximize employee effectiveness and 7 b achieve higher degrees of public acceptance. We have recorded substantial progress in g g^ all these areas. And, as we predicted, progress in achieving these goals has improved $ 9" linancial performance. 3
.V 3 Itate Settlement Agreement .Tlilestone 0" M in covering what I believe to be the key accomplishments of 1993, I cite our successful negotiation of a rate settlement agreement with the New York State Public Service Commission (PSC) as a prime example of our new approach in managing this Company and the competitive forces it confronts. The rate settlement agreement was a long time in the making. More than a dozen interested parties debated and negotiated components of a settlement that could work to the advantage of customers and the Company. It was a long process, but the approved agreement sets new precedents in our ratemaking procedures.
The three-year rate settlement agreement sets caps on the amount of additional revenues the Company may seek through rate relief. These caps are in the range of a'% <
, ypp 436 g
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j&R Wf: ?$Yflkh&Q, current inflation rates. However, the agreement provides incentives where superior perfonnance brings rewards in shareholder eamings. Of course, penalties apply in the event our performance falls short of the negotiated goals. Our rate settlement agreement includes a unique perfonnance incentive. Our perfonnance will be measured against other New York investor-owned power companies in the areas of production, electric transmission and effectiveness of demand side management programs. We continue to move aggressively in the area of demand side management. or
$ Energy Utilization Services as we now call it. Successful efforts to curb electric load (.
Ap$ f& growth through promotion of energy efficiency programs and the creation of energy k ($g 2 pp - %g i
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'I 7 partnerships with commercial and industrial accounts will be recognized under the - %
k settlement agreement. d I We are fully committed to the rate settlement agreement and are prepared M to demonstrate it as a successful ratemaking method that benefits all. It's my intention g$ na jg-to do everything I can to avoid mereases m the price of our products. I've made Q h it clear to RG&E people that there's no such thing as an " uncontrollable cost." We < ;;2f y y{ should be able to find ways to exert influence on any expenses we encounter. And that $g includes taxes. We successfully reduced property taxes substantially at one of our power $g4, [/
$ plants through an exhaustive audit of the assessments. We are finding better ways to do
[' g{ things. I have great expectations for the rate settlement agreement and its role in W
% keeping us competitive.
Cost Control The price at which we can keep our products competitive is largely a It m die . <>nipany functi n of c ntr Iling ur operating expenses. In 1993 we managed to come in $13 million under our operation and wide determination or- maintenance forecast. This saving was achieved by improved employee pr ductivity and ingenuity. A cost saving of $4.4 million itG&E .cogile 1 that really was also br . ht about through aggressive refinancing of our turiml timine arointd. long-term 63t. c ^rgy [ y 4 MQl wggnm _ ;_gic ,
srw w fv _ 1 Mye,y To Shareholders mm. Iletirement I nliancemeiit it was time in 1993 as a result of the new competitive environment to take action to reduce the number of employees and payroll expense. That time came for us in late 1993. Two retirement enhancement programs were offered. Of the 217 eligible employees, 173 opted for early retirement. This is not a temporary measure;it's a permanent reduction in our complement. The downsizing of the work force will improve financial j performance and help us remain competitive in the years ahead. We're reshaping the M
.pn corporate culture and moving the Company and its people into the mainstream of the
;4 M competitive marketplace. We will remain competitive and we will remain the 4 w
L customers' energy supplier of choice. $ (( $$ [ I#roceSs Improve!HCHt N % s h, The system we use at RG&E to improve performance is very simple. We look at 2/ h, everything we do. We study the individual processes and procedures we use in our p F work. Then we take each process and ask ourselves how valuable it is to us and our
~
6 customers. If we decide a process is not contributing to the success of our Corporate g Business Plan, we get rid of it. If we see it as worthwhile, we keep it. If we can find a j H way to improve it. we do. And here's a key point. The "we" I refer to is not just the ( Executive Management Team sitting around a table makingjudgments. The "we" m our ( fb improvement efforts is our employees. They have been empowered and encouraged to step back, look at what we do, and then subject it to our improvement process tests. I , can tell you it's working. In 1993 dozens of procedures and practices were changed at 4
! RG&E. All for the better.
e Customer Serviec Center h pc Probably the most striking example of our rededication to improved customer service and satisfaction is our new Customer Service Center in Rochester. A completely 4 4 renovated, 153,000 square-foot industrial complex now houses %g g$ our strategy in eun i sent wit!' the majority of our Rochester District customer service opera- @ t Dq our intent to lireak away fron, tions under one roof. Customer contact telephone service, energy
~ '
control center, computer data center, customer service departments, alie olil, niore vulneral>le utili'i telecommunications, service vehicle garage and supply warehouse liuaincu tiiinking. are n w p sitioned in the complex to best accommodate customer needs and maintain the high level of energy reliability. Our vision had been to create a "one-stop-shopping" convenience for our customers and the highest degree of system reliability and response. Whatever the issue, our customers can now call or visit one location and get all of their needs accommodated. This new facility is a major milestone in our corporate history, and we feature it in this ieport. 99 y ,
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pmm-j&=f & *% [ Y??&h., Empire Pipeline The Empire State Pipeline was completed in 1993 as scheduled. We own a share of this major natural gas transmission pipeline project that runs 156 miles from Grand Island near Buffalo to Syracuse. The 24-inch-diameter pipeline brings another source of natural gas to Upstate New York from northern fields.The pipeline is expected to supply half of our gas customers' requirements. C0 Detector One of our corporate objectives is to maintain high levels of safety and safety M awareness on the part of our employees and the public. There had been two fatalities in [ our area a year ago as a result of carbon monoxide poisoning. We responded by devel-oping a safety awareness campaign that wamed people of the symptoms and dangers
&p K{ &., +
y and urged them to get their furnaces inspected annually. g b{' , wy
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d q Q. In a further effort to prevent carbon monoxide poisonings we launched an R, aggressive marketmg campaign m October that offers industry-approved carbon 0 4
% monoxide detectors at our cost. They're available to customers and non-customers alike.
, 2 u
Nearly 20,000 have been placed into operation, and we know of some 20 cases already ; where the detectors alerted residents to the presence of carbon monoxide. jg g This effort was conceived, developed and placed into action by RG&E people. sq i p Aside from its perfect fit into the corporate safety objective, I see it as another excellent j&j i 4
,a example of RG&E's growth as a thinking, progressive company with talented people
[F , M8 9c takmg mitiatives under our practice of empowerment and process improvement. h[$w Outlook 4> 1 I am very pleased with the progress we are making along the lines of the Corporate Business Plan. ThueN ample evidence that we have indeed turned the corner in the conduct of our business and gotten hold of our future. This is a new beginning for us, and our efforts to improve and prosper in the competitive marketplace continue with intensity. Roger W. Kober Chairman of the Board, President and Chief Executive Officer January 25,1994 k h _ig$ wi *smmy ? bI hkh
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G&E is looking for ways to make its dealings with customers as productive and supportive as possible and, in that process, bring
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and Electric Corporation brought life to a corporate f vision with the opening of . g." O a new Customer Service 'r Q [g. ' Center in Rochester. I<
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n Using advanced office - f. design and state-of-the-art g @}j j computer systems, the ,.4 c Center houses key components of RG&E customer account The modern, convenient f /g service groups along with computer, voice communications, iks pertice area allown caky, }lI$f 4%g p energy control and storm emergency response operations. p fg Just minutes from the heart of downtown Rochester "one-toi ahormini' i D at 400 West Avenue, the 153,000-square-foot facility took for en*iomer . shape from a complete renovation of a vacated industrial complex. It offers a centralized location for customers visit- ) ing the center along with the convenience of easy access and ample, free parking. fif%f4% 3 1
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Customer service and billing departments are located near the service area so h( T he Customer Service Centeri offe that customer account matters can be resolved at the Center in person or over ( P" the phone from one centralized location. [ f,5 ~
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- Advanced computer systems help experienced -
f MillW 6 $@g customer service repre- g ~ sentatives with a full ., 5% y range of instantly avail- g f able account information. More than one million g gj customer telephone calls a
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RG&E telephone service representatives and sersier negaariinent inatclica switchboard operators. extierienceal regirementalis ca I ' willi > tate-of-tlic-art alata symtenia offering "one-* top aliologning"
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] nergy reliability is crucial to good customer service. The West Avenue Customer Service Center houses a unique Energy Control Center from which electric and gas opera-tions are orchestrated and monitored 24 hours a day. New
.l3 computer systems precisely track real-time electric power and j natural gas systems status. A unique array of rear-screen projections
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y more effective restoration response in emergencies. Einergency Response Aside from its daily function as a customer service and energy control center, the Customer Service Center is specially designed to handle RG&E's emergency response activities. Restoration of electric or gas services disrupted by severe storms or other events will be directed and controlled from the Energy Control Center. The locations of the operations centers and the communication links that connect them are custom engineered to allow the most rapid and efficient energy service restorations using RG&E's emergency p response plans. H y 4 ja m _, Computer Data Center gg Advanced computer systems are central L. to the accumulation and retrieval of data. The Customer Service Center is home to RG&E's , J gg, main frame computers and company computer " support services. Voice communications activi-ties are also coordinated at the Center for RG&E's telecommunications systems. wg s.ug
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(Qfjg Truck Bay does at the Customer Service Center where a 22,000-square-W ho would think a g.: rage wou foot truck bay comfortably houses a fleet of electric and gas service trucks and vehicles-even those with heavy construe-tion equipment attached. With a large supply storehouse next door, equipment J for jobs is quickly and easily placed aboard the trucks. They can then quickly roll out of a warm, dry garage to the job sites on cold or wet days. Besides $i being easier on the crews and trucks, this convenience saves time and pro-h y: vides more efficient response in the field. /* Uninterrupted Electric Power One thing RG&E has to think about for its service facilities is what it y does if it loses power itself. The RG&E Customer Service Center is equipped -
- p. with redundant electric power sources and power switching units. Main frame computer operations ;
- l. are protected with alternative, uninterruptable
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.enice for all .pienn in tiie staffing the Customer Service Center, more than 2,000 other RG&E people go about theirjobs, on soiner senice center doing their best, too, for the one million residents in the Company's 2,700-square-mile service franchise territory.
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Management's Discussion and Analysis of Financial Condition and Results of Operations he following is Management's assessment of significant factors which affect the
,[ Company's financial condition and operating results.
Liquidity and Capital Resources a k4 During 1993 cash flow from operations, together with proceeds from external financing M activity (see Consolidated Statement of Cash Flows), provided the funds for construction '$ gg "2 expenditures and the retirement and refinancing of long-term debt and preferred stock. Capital requirements durir.g 1994, including debt maturity and sinking fund obligations, are anticipated f Q to be satisfied primarily from the use of internally generated funds. Some extemal financing, ] p'~ mainly in the form of short-term debt,is expected to be incurred. Any refinancing activity j $ would require additional external fmancmg. jj g< a . Projected Capital and Other Requirements The Company's capital requirements relate primarily to expenditures for electric
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generation, transmission and distribution facilities and gas mains and services as well as the '; repayment of existing debt. Construction programs of the Company focus on the need to serve y new customers, to provide for the replacement of obsolete or inefficient utility propeny and to D modify facilities consistent with the most current environmental and safety regulations.
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b The Company has no current plans to install additional baseload generation. The Company [ either has contracts or is continuing negotiations for the realization of approximately 24 megawatts of capacity savings being phased-in over the 1993-1996 period under its : 3 h demand side management program and, beginning in late 1994 or early 1995, expects n p- approximately 55 megawatts of capacity to be supplied by a cogenerator under contract with g(' the Company. The Company has no other obligations with non-utility generating companies at M, y this time. gq In June 1992 the Company filed with the New York State Public Sersice Commission (PSC) y T" an Integrated Resource Plan (IRP) which is a long-range plan examining options for the future j hy with regard to generating resources and alternative methods of meeting electric capacity gj @ y' requirements. The pian covers a 15-year period, beginning in 1992, and provides current strate- fr
& pies and alternatives for meeting customer energy requirements in a changing business and technological environment. The IRP takes into account anticipated capacity requirements and 7 %g" ~
available resource options, as well as factors such as reliability, price of product, public accep-tance, financial integrity, environmental issues, the competitive marketplace, demand side management and potential new technologies. One result of the IRP was the decision made by the Company in December 1992 to replace - the two steam generators at the Ginna nuclear plant in 1996. Like similar plants, the Ginna nuclear plant has experienced degradation in some of the tubes that make up each steam gener-ator. About 30 percent of these tubes have required repair. In addition, a chemical buildup in some of the tubes has reduced their heat transfer capability. Iloth conditions would continue to erode the plant's performance if the existing steam generators were left in place. Installation of new steam generators was determined by the Company to be the most cost-effective, reliable-and environmentally compatible option for the plant. The new steam generators should result in 3p , . .
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reduced maintenance costs and help sustain a high level of plant availability. Cost of replace-ment is estimated at $115 mi!! ion, and preparation to replace these generators began during the - plant's routine 1993 fuel outage. As a part of the on-going IRP process, the Company in mid-1993 made a decision to place Unit 1 at Russell Station (47 MW) on cold standby, while modifying Units 2,3 and 4 with new-burners to meet Federal Environmental Protection Agency standards. Unit 1 is expected to be in cold standby by early 1994. Modification of Units 3 and 4 is expected to be completed by March 1995 at a cost of approximately $4.6 million. In addition, Unit 12 at Beebee Station and Unit 2 at Russell Station will be adjusted to produce fewer nitrogen oxides (NOx) by converting a third of the burners in each to achieve overfire air capability at a cost of approxi-g mately $1.2 million. These actions will allow the Company to comply with Phase I-Title I, , M NOx contrcls requirements of the Federal Clean Air Act, to meet projected load demands ir its %.1 % service territory, and to maintain a mix of fuel generation whhe remaining competitive and
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h retaining wholesale sales opportunities. Outlined below are other results of the IRP process to date: $@ d k( [h
- The plan calls for evaluating the possibility of using either alternative generation or current generating equipment in partnership with certain large industrial customers.
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- The Company will continue to use demand side management programs to reduce the need for generating capacity. '
(i[ f i The Company will consider phasing out its coal-fired Beebec Station by the year 2000, unless - p it is converted to natural gas and operated under a partnership arrangement with a large ,h M customer. Aj g; The Company's capital expenditures program is under continuous review and will be revised 74d p depending upon the progress of construction projects, customer demand for energy, rate relief, M; %g government mandates and other factors. In addition to its projected construction requirements, the Company may consider, as conditions warrant, the redemption or refinancing of certain Qf MN( M long-term securities. Q Capital Requirements and Electric Operations. Electric production plant expenditures in . hglI k% 1993 included $42 million of expenditures made at the Company's Ginna nuclear plant, of hj g which $15 million was incurred for preparation to replace the steam generators. In addition, M; V nuclear fuel expenditures of $11 million were incurred at Ginna during 1993. A refueling outage at Ginna normally occurs annually for a period of approximately 40 to 50 days. Exclusive of fuel costs, the Company's 14 percent share of electric production plant expenditures at the Nine Mile Two nuclear facility totaled $6 million in 1993. Expenditures of
$5 million during 1993 were made for the Company's share of nuclear fuel at Nine Mile Two.
On October 2,1993 Nine Mile Two was taken out of service for a scheduled refueling outage. Refueling was completed and Nine Mile Two resumed full operation on December 3,1993. The prior refueling outage occurred in 1992 from early March to early July. The next refueling outage for Nine Mile Two is anticipated to begin in May 1995. Electric transmission and distribution expenditures, as presented in the table on page 16, totaled $29 million in 1993, of which $24 million was for the upgrading of electric distribution facilities to meet the energy requirements of new and existing customers. Capital Requirements and Gas Operations. Construction began in June 1993 on the Empire State Pipeline (Empire), an intrastate natural gas pipeline subject to PSC regulation between Grand Island and Syracuse, New York. The Company received its first gas deliveries through MW,% A N g$W
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the pipeline in early November 1993. This pipeline will provide capacity for up to 50 percent of the Company's gas requirements by its second year of operation. The Company is participating as an equity owner of Empire, along with subsidiaries of Coastal Corporation and Westcoast Energy Inc. In June 1991 the PSC authorized the Company to invest up to $20 million in Empire subject to certain conditions, notably that the investment not be included in rate base. In 1992 the Company formed a wholly owned subsidiary, Energyline Corporation, to acquire its ownership interest in Empire. The Company's share of ownership in Empire will be dependent upon final project costs and the timing and method of financing selected by the Company. In June 1993 Empire secured a $150 million credit agreement, the g proceeds of which are to finance approximately 75 percent of the total construction cost. At December 31,1993 the Companv had invested a net amount of $10.2 million in Energyline my h ($9.9 million in 1992 and $0.3 million in 1993) and was committed for $9.7 million of the borrowings under the credit agreement. In December 1993 the Company's investment in g@ h; Energyline was consolidated for accounting and reporting purposes into the accounts of the Q P ggF Company. Such consolidation resulted in a $0.5 million charge to Other Income during 1993. ' i In addition to the Empire project discussed above, construction expenditures in the Gas ,
? Department totaled $20 million and were principally for the replacement of older cast iron %
,m y mains with longer-lasting and less expensive plastic and coated steel pipe, the relocation of gas y M $;L mains for highway improvement, and the installation of gas services for new load. , s
%p EnvironmentalIssues :-)
The production and delivery of energy are necessarily accompanied by the release of p" by-products subject to environmental controls, in recognition of the Company's responsibility } to preserve the quality of the air, water, and land it shares with the community it serves, the Company has taken a variety of measures (e.g., self-auditing, recycling and waste s
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Capita! Requirements,_ , Actual - ~ Projected E hN 'b i , 1991' 1992 ' 1993 . . 1994S 1995 ' 1996 4 ,f ;-3
+
Type of Facihties . (Milhons of Dollars)' '
&u Electric Property:
%'T W,4 S Production - $ 44 $ 47 $ 54 $ 55 $661$76
[9 Transmission and Distribution ' 29 35 29 26 36i L40 M
; ~ Street Lighting and Other 2 2 2 1 ~2 '2 y b Subtotal ' 75 84 85 82 104 1118 gf 9 Nuclear Fuel 12 11 16 20~
20... _L22 Total Electric 87 95 101 102 1244 u140 m$y Gas Property 22 19 20 19 28 ~ '25 N Common Property 13 15 21 15 16 J
' ETotal 122 129 142 136. 168i ;181 Carrying Costs:
' Allowance for Funds Used During Construction
. (AFUDC) .
4 2 2 .23 L3! L3'
' Dcferred Financing Charges included in Other income 5 3 1. > 9: '2 n Total Constmetion Requirements 131 134 ,145 138, 31.71; E184 Securities Redemptions, Maturities and Sinking . . . .. ..
Fund Obligations * - 92 7 160.'212: l 39 ! ? 3 > c 21., 1T$thi Capital Requirements - $223 E $294 $357 [$ g $174[ $205
? Excludes prospeedve refinancings[ _, a gy . c r g.
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$RI l , , $, g , b y, x 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 of wastes 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 of such wastes. In such instances, the Company typically seeks to cooperate with those authorities and with other site users to develop cleanup programs and to fairly allocate the associated costs.
As a part ofits commitment to environmental excellence, the Company is conducting proactive Site Investigation and Remediation (SIR) efforts at Company-owned sites where past waste handling and disposal may have occurred. The Company currently estimates the total costs it could incur for SIR activities at Company-owned sites to be about $20 million. Thk estimate will vary as better site information is available. The Company anticipates spending $10 million over the next 5 years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 for recovery of SIR costs. To the extent actual g expenditures differ from this amount, they will be deferred for future disposition and recovery ,. as authorized by the PSC. Additional environmental issues are discussed in Note 10 of the g %y Notes to Financial Statements. g _ The Company is developing strategies responsive to the Federal Clean Air Act Amend- m p g ments of 1990 (Amendments). The Amendments primarily affect air emissions from the Company's fossil-fueled electric generating facilities (see Note 10 of the Notes to Financial h 4i 17 Statements). The Company is in the process of identifying the optimum mix of control ,M h' f measures that will allow the fossil fuel based portion of the generation system to fully comply with applicable regulatory requirements. Although work is continuing, not all compliance M g b control measures have been determined. The Company has adopted control measures for- ~h4 & NOx emissions which must be in effect by the federally mandated compliance date of May 31,1995. These control measures are discussed under Projected Capital and Other >Q h( i Requirements. Capital costs for NOx controls and the installation of continuous emission monitoring systems are not expected to exceed $6.8 million and will be incurred during "i l, $ % 1994 and 1995. A range - :apital costs between $20 million and $30 million (1993 dollars) MR %' has been estimated for the implementation of several potential scenarios which would enable
;di!
p the Company to meet the foreseeable future NOx and sulphur dioxide requirements of the y Amendments. These capital costs would be incurred between 1996 and 20(X). The Company J 94 currently estimates that it could also incur up to $2 million (1993 dollars) of additional gh E f annual operating expenses, excluding fuel, to comply with the Amendments. The use of M Q scrubbing equipment is not presently being considered. Likewise, the purchase or sale of 5,=
" emission allowances", as allowed by the A mendments,is not currently being considered The Company anticipates that the costs incurred to comply with the Amendments will be recoverable through rates based on previous rate recovery of environmental costs required by governmental authorities.
CompetHlon The Company is operating in an increasingly competitive environment. In its electric business, this environment includes a federal trend toward deregulation and a state trend toward incentive regulation. In addition, excess capacity in the region, new technology and cost pressures on major customers have created incentives for major customers to investigate different electric supply options. Initially, those options will include various forms of self generation, but may eventually include customer access to the transmission system in order to purchase electricity from suppliers other than the Company. As discussed under the Regulatory Matters section, the passage of the National Energy Policy Act of 1992 has accelerated these competitive challenges, Blke fQ~ s e u ; } h] M
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W~$&gp Ok The Company accepts these challenges and is working to anticipate the impact of the increased competition. Its Business Plan, both in detail for one year and in summary for five years, focuses on improving service while reducing expenses. The Company is engaged in a continuous process improvement program to find opportunities for improved service and efficiency and has implemented an early retirement program in which 173 people, representing approximately seven percent of its workforce, have retired early and will not be replaced. In addition, the Company has agreed to a three-year rate settlement which includes caps on rate increases that approximate or are less than projected intlation, contains incentive programs that y tie performance to earnings and stabilizes revenue through revenue adjustment mechanisms. i An agreement has been reached with the PSC Staff and others on the terms of a competitive k rate tariff that would allow negotiated rates with hirger industrial and commercial customers that have competitive electric supply options. These regulatory changes are discussed in more $g ~ detail in the Regulatory Matters section. K : Competition in the Company's gas business has existed for some time, as the larger k W t customers have had the option of obtaining their own gas supply and transporting it through the f Company's distribution system. This process has been accelerated with FERC Order 636, fi
% discussed in more detail in the Regulatory Matters section. In addition to the matters discussed de above, 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 it can (; take advantage of the unbundling of services that results from FERC Order 636. A major
^
O element of this strategy went into place in 1993 with the start-up of the Empire State Pipeline. g The Company is engaged in various aspects of capacity release and is investigating other ;
- gk options available to it to mitigate its cost and increase its revenue in the new gas regulatory ;
environment. [hi FM Beyond the Company's efforts to remain competitive in its core business,it is conducting a broad review of its general business strategy to identify opportunities that will exist in this y U changed environment. This may result in expansion of various elements of the core business or ;j b f engaging in new, but related, business activity. f b w Redemption of Securities a' y Gw Discretionary first mortgage bond redemptions totaled $120 million during 1993. A ,, ,
'~; $75 million first mortgage bond maturity and $17 million of sinking fund obligations were also A Y1 a part of the Company's capital requirements in 1993. Q M
Capital requirements in 1992 included a $75 million first mortgage bond maturity, and discretionary first mortgage bond redemptions of $79.5 million. D y n' V? s x CaplialRequirements-Summary gf The Company's capital program is designed to maintain reliable and safe electric and natural V- gas service, to improve the Company's competitive position, and to meet future customer service requirements. Capital requirements for the three-year period 1991 to 1993 and the current estimate of capital requirements through 1996 are summarized in the table on page 16. For the period 1994 through 1996, the Company anticipates construction requirements to total approximately $493 million. Replacement of the steam generators at the Ginna nuclear plant is scheduled to be completed in 1996. Electric production plant expenditures over the period include $16 million in 1994, $29 million in 1995, and $50 million in 1996 for that replacement. In addition to its construction expenditures, the Company has security maturities and sinking fund obligations totaling $63 million over the three-year period 1994 through 1996. Excluded from the capital requirements table on page 16 are expenditures associated with the Company's obligations to the United States Department of Energy for nuclear waste disposal
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M W and the Department of Energy's uranium enrichment facility decommissioning (see Notes 1 and 10 of the Notes to Financial Statements). Financing and CapitalStructure Capital requirements in 1993 were satisfied by a combination of long-term debt and equity issues, internally generated funds, and short-tenn borrowings. Common shareholders equity increased during 1993 as the result of a public issue of one and one-half million shares of Common Stock in September. Favorable market conditions allowed the Company to refinance
$120 million of its higher-cost long-term debt in 1993. In addition. the Company was able to refinance at a lower interest rate $75 million of its First Mortgage,8.609F flonds, Series LL, .
p which matured on August 1. Such refinancing activity over the past three years has helped to
$g reduce the annual cost of long-term debt by approximately $8.8 million and contributed to a g drop in the Company's embedded cost oflong-term debt from 8.6r7e at year-end 1990 to 44 f" 7.49F at the end of 1993. p M
"j The Company believes that an average of approximately 85 percent to 90 percent of the funds required per year for its 1994 through 1996 construction program will be generated inter-j%gg i {p nally and the balance will be obtained through the issue of securities and short-term bor ow-1 ings. The Company is utilizing its credit agreements to meet any interim external financing needs prior to issuing any long-term securities. As financial market conditions warrant, the l @Q
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% Company may, from time to time, issue securities to permit the early redemption of higher-cost senior securities. The Company's financing program is under continuous review and may be n g[ t j revised depending upon the level of construction, financial market conditions, rate relief, cost j p of capital and other factors. 3~ ^ Financing. Interim financing is available from certain domestic banks in the fann of short-term borrowings under a $90 million revolving credit agreement which continues until g l December 31,1996 and may be extended annually. Borrowings under this agreement are ; secured by a subordinate mortgage on substantially all of the Company's property except cash ^ ' r m and accounts receivable. In addition, the Company entered into a Loan and Security Agreement ,g f with a domestic bank until December 31,1994 providing for up to $20 million of short-term debt. Borrowings under this agreement, which can be renewed annually, are secured by the ;j; H Company's accounts receivable. The Company also has unsecured short-tenu credit facilities ,f*' M totaling $70 million. At December 31,1993 the Company had short-term borrowings
.s outstanding of $68.1 million, consisting of $51.3 million of unsecured short-term debt and g $16.8 million of secured short-term debt. p, N Under provisions of the Company's Certificate of Incorporation (Charter), the Company may *f not issue unsecured debt if immediately after such issuance the total amount of unsecured debt p$g, ,
,c outstanding would exceed 15 percent of the Company's total secured indebtedness, capital, t{Q and surplus without the approval of at least a majority of the holders of outstanding Preferred Na
$W Stock. Under this restriction, the Company as of December 31,1993 was able to issue P
$19.2 million of additional unsecured debt. Additional interim financing capability remains available with secured borrowings under the Company's credit agreements, as discussed above.
During 1993 the Company sold several issues of First Mongage Bonds, Designated Secured - Medium-Term Notes, Series A aggregating $200 million principal amount. Proceeds from the sale of the medium-term notes were used to redeem prior to maturity, at lower interest rates,
$120 million principal amount of first mortgage bonds, to pay at maturity $75 million principal amount of first mortgage bonds and to repay short-tenn debt of $5 million.
In July 1993 the Company filed a shelf registration on Form S-3 providing for the offering of
$250 million of new securities. The Company may use the shelf registration to offer, from time to time, its first mongage bonds in one or more series, its Preferred Stock in one or more series and/or its Common Stock depending on market conditions and Company requirements. This S ). ' ? p [} .
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# ?- 'W hh&d Registration Statement became effective August 1993 and allows the Company financing flexibility regardmg the timing of new issues. The net proceeds from the sale of the securities will be used to finance a portion of the Company's capital requirements, to discharge or refund certain outstanding indebtedness or preferred stock of the Company, to satisfy certain sinking fund obligations. or for general corporate purposes.
In September 1993 the Company sold 1,500,(XX) shares of new Common Stock in a public offering under the shelf registration discussed above. The offering raised $43.1 million in net proceeds, which were used to retire short-tenn debt incurred in the Company's construction program. During 1993 approximately 515,000 new shares of Common Stock were sold through the
*@ Company's Automatic Dividend Reinvestment and Stock Purchase Plan (ADR Plan),
providing approximately $14.1 million to help finance its capital expenditures program. New (A $3 fP shares issued in 1992 and 1993 through the ADR Plan were purchased from the Company at a market price above the book value per share at the time of purchase. 1 t(jjf Mf? Capital Structure. The public sale of Common Stock in 1992 and 1993 strengthened the Company's common equity. The Company's retained earnings at December 31,1993 were ,," g
$75.1 million, an increase of approximately $8.1 million compared with a year earlier. ]f W Common equity (including retained earnings) comprised 44.0 percent of the Company's W j, capitalization at December 31,1993, with the balance being comprised of 6.6 percent ,
{, preferred equity and 49.4 percent long-term debt. At December 31,1993 the Company had
, S21.3 million of long-term debt due within one year and $6.0 million of preferred stock 'q redeemable within one year which, if included in capitalization, would increase the long-term debt component of capitalization at 1993 year-end to 49.8 percent, raise the preferred equity to 4w L. 6.9 percent and reduce common equity to 43.3 percent of capitalization. As presented, these percentages are based on the Company's capitalization inclusive ofits long-term liability to the '!
f United States Department of Energy (DOE) for nuclear waste disposal as explained in Note 1 '; J of the Notes to Financial Statements. It is the Company's long-term objective to move to a less y [ leveraged capital structure and to increase the common equity percentage of capitalization j z toward the 45 percent range. To improve its capital structure, the Company anticipates the $ issuance of new shares of common stock, primarily through the Company's ADR Plan, and ,i
, will consider the redemption of higher-cost senior securities. je w
Regulatory Matters \a, g- New York State Public Service Commission (PSC). The Company is subject to regulation 'h jg of rates, service, and sale of securities, among other matters, by the PSC. 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. This agreement resolves the Company's rate i f" h[ f case proceedings initiated in July 1992. Retroactive application of new rates to July 1,1993 was authorized by the PSC. The 1993 Rate Agreement will determine the Company's rates g% through June 30,1996 and includes certain incentive arrangements providing for both rewards and penalties. A summary of recent PSC rate decisions is presented in the table on page 22. 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% will be absorbed / retained by the Company. Eamings above 14.50% will be 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 seek relief by petitioning the PSC for a review of the 1993 Rate Agreement tenns. h p -
jd48W6 pdna A%qh 7% The following measures were incorporated into the 1993 Rate Agreement:
- Incentive mechanisms that have the potential to either increase or reduce earnings from 5 to 70 basis points each, depending on the Company's ability to meet a variety of prescribed targets in the areas of electric fuel costs, demand side management, senice quality, and inte-grated resource management (relative electric production efficiency). Durir.g the rate year ending June 30,1994, these incentives have the potential to affect earnings by approximately _
$12 million.
- Mechanisms for sharing costs between customers and shareholders for operation and maintenance expenses. In ' general, non-fuel operation and maintenance expense variations are treated in three different ways depending upon the amount of control the Company can exert over them. Those costs that are directly manageable (approximately $172 million in the first rate year) have no sharing and are absorbed by the Company, those costs that are not signifi-cantly affected by management action in the short run (approximately $34 million in the first rate year) are trued up 100% and variances resulting from all other such costs (approximately
$110 million in the first rate year) are shared 50% by customers and 50% by the Company.
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- Mechanisms for 'aring 50% of overspending variances between forecasted and actual y electric capital expenditures related to production and transmission facilities. The Company 4 will retain the savings for cost of money and depreciation on underspending varianc'es.
{ The settlement also provides for a sharing mechanism regarding the replacement of the ()g 43 ,f. Ginna nuclear station steam generators. A graduated sharing percentage is applied for up to id $15 million of variances, plus or minus, from the forecasted cost of $115 million. Variances @$ig g? above $130 million or below $100 million are absorbed by the Company. Oh h + An Electric Revenue Adjustment Mechanism (ERAM) designed to stabilize electric revenues { g by eliminating the impact of variations in electric sales. A gas weather normalization clause prevmusly m place was retained. W[$ p ( ( h' To the extent incentive and sharing mechanisms apply, the negotiated rate increases shown in the table on page 22 may be adjusted up or down in the second and third year of the agreement.. f d N:gotiated electric rate increases could be reduced to zero or increased up to an additional j% S k( l.5% in year two,1.6% in year three and 1.8% in the subsequent year. Negotiated gas rate increases could also be reduced to zero or increased up to an additional 0.8% in year two, <M NK 0.9% in year three, and 1.1% in the subsequent~ year, exclusive of the impact of the Empire h M P State Pipeline going into service.
~
in July 1993 the Company requested approval from the PSC for a new flexible pricing tariff h T
$ for major industrial and commercial electric customers. A settiement in this matter was filed .
J with the PSC on November 19,1993 and a decision on whether or not to approve the settle-
) ment is expected early in 1994. Such a tariff would allow the Company to negotiate competi-tive electric rates at discount prices to compete with alternative power sources, such as customer-owned generation facilities. Under the terms of the settlement, the Company would absorb 30 percent of any net revenues lost as a result of such discounts through June 1996, while the remainder would be recovered from other customers. The ponion recoverable after June 1996 is expected to be determined in a generic proceeding currently being conducted by the PSC.
In September 1993 the PSC instituted a formal proceeding to investigate what the Company - believes are undercharges to gas customers for certain gas purchases for the period August 1990 to August 1992. The Company's estimate of these undercharges is approximately
$7.5 million, of which $2.3 million had been previously expensed and $5.2 million had been deferred on the Company's balance sheet. The PSC has made the Company's current gas rates under the 1993 Rate Agreement temporary solely to consider the impact of these under-bb
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%r2A Ratelacreases Granted O .
Authorized Amount of Increase
' Rate of Return on Class of ' - Effective (Annual Basis) Percent Serwce . Date of increase - (000's) lacrease Rate Base - : Equity Electric July 12,1990 $36,059 6.6% 9.91 % .12.10%
July 1,1991 33,133 5.5 9.66 11.70 ; July 1,1992 32,220 52 9.31 11.00 g c July 1,1993* 18,500 2.8 9.46 : 11.50:' f[ July 1,1994* 20,900 2.9 . 9.39 " L 11.50
. July 1,1995* 21,800 2.9 9.41 11.50) k.0 e{
1 s Gas : July 12,1990 4,250 1.7 9 91- 12.10 V b h6 5 '
. July 1,1991 July 1,1992 1,148 12,316 0.4 4.1 9.66 -
9.31
, 11,70 :
11.00 ; $sp. July 1,1993* 2,600 1.1 9.46) .- 11.50 ' g"< July 1,1994* 4,400 1.8 : 9.39 11.50 <
;' July 1,1995* 4.300 ~ 1.7- --9.41 . 11.50 %
b y-
*See under heading Regulatory Matters l'or additional details.
?
w?: w_ s <t f' ? charges. On December 30,1993, a proposed settlement among the Company, PSC Staff and .;;pj g another party was filed with the PSC. It provides for the recovery in rates of $3.2 million over $ three years, subject to audit and to limitations on rate adjustments established in the August 24 1 Order. The Company wrote off the $2.0 million balance of the undercharges as of December 31, 1993. That write-off amounts to a reduction in 1993 earnings of approximately $.04 per share, s net of tax. Although no party, to the Company's knowledge, opposes the proposed settlement, the Company is unable to predict whether the PSC will approve it. A PSC decision on whether g to approve this settlement is not expected before March 1994. j4 p" in its June 1992 rate decision, the PSC allowed the Company to defer and recover through rates over a period of ten years approximately $21.3 million of non-capital incremental storm- O* damage repair costs which the Company had incurred as a result of a March 1991 ice storm. y" g The PSC has permitted the unamortized balance of these allowed costs to be included in T. rate base. Rate recovery of an additional $8.2 million of non-capital storm-damage costs l<
- < incurred by the Company was denied by the PSC and the Company accordingly recorded in the second quaner of 1992 a charge to earnings in the amount of $8.2 million, equivalent to 3m g'99 approximately $.15 per share, net of tax, after issuance of the two million shares of stock m g
$@3 August 1992. Pursuant to a November 1991 Order approving a settlement agreement between the PSC g M h Staff and the Company relating to the Staff's audit of the Company's fuel procurement prac- M {j3r tices, the Company refunded $10 million to its electric customers through adjustments to their
';, energy bills over a twelve-month period beginning in January 1992. The Company recorded a
( $6.6 million net-of-tax reduction to net income, thereby reducing earnings per share by approx-y imately $.21 for the fourth quarter of 1991. National Energy Policy Act of1992. The National Energy Policy Act (Energy Act) was signed into law in 1992. Major provisions of the Energy Act, as they relate to the Company, include energy efficiency, promoting competition in the electric power industry at the whole-sale level, streamlining of federal licensing of nuclear power plants, encouraging development and production of coal resources, and ensuring that a new class of indepc,derd power producers established under the bill, as wcIl as qualified facilities and other electric utilities, can achieve access to utility-owned transmission facilities upon payment of appropriate prices. l _q.__ y G [ ' }gg egg g[ , fh"
gy b f5 g Under the Energy Act, FERC may order utilities to provide wholesale transmission services for others only if, among other things, the order meets certain requirements as to cost recovery and fairness of rates. FERC is prohibited, however, from ordering retail wheeling, i.e. transmitting power directly to a customer from a supplier other than the customer's local utility. The law, however, does not prevent state regulatory commissions from allowing or ordering intrastate retail wheeling; and, New York State is currently considering the issue of retail wheeling through various studies and hearings. The Company believes this Act could lead to enhanced competition among the Company and other service providers in the electric industry. FERC Order 636. In April 1992 FERL issued Order No. 636 with the intention of fostering competition and improving access of customers to gas supply sources. In essence, FERC Order No. 636 requires interstate natural gas companies to offer customers "unbundled", or separate, sales and transportation services. FERC Order 636 enables the Company and other gas utilities to contract directly with gas producers for supplies of natural gas. With the unbundling of a services, primary responsibility for reliable natural gas supply has shifted from interstate
, pipeline companies to local distribution companies, such as the Company. Since 1988 the p$ Company has endeavored to diversify both its natural gas supply sources and the pipelines on - i R' which that supply is delivered to the Company's distribution system. The unbundling of %
hh services as required under FERC Order 636 and the commencement of Empire State Pipeline PR operation have enabled the Company to achieve those goals, which should enhance its competitive position. As a result of FERC Order 636, the Company does face certain
@k
@. Q tg restructuring transition costs as explained under the heading Energy Costs and Supply-Gas. g g flesults of Operations %' @2P h The following financial review identifies the causes of significant changes in the amounts of p g y revenues and expenses, comparing 1993 to 1992 and 1992 to 1991. The Notes to Financial Statements on pages 36 to 53 of this report contain additionalinformation. ((]Q [
- y. Operating Revenues and Sales %g$g d
Compared with a year earlier, operating revenues rose six percent in 1993 following a five percent increase in 1992. Gains in retail customer electric and gas revenues offset a decline in k s ; electric revenues from the sale of electric energy to other utilities. Customer revenue increases @g gi in 1993 resulted primarily from rate relief and the impact of warmer weather on air condi- p 'R tioning usage. Details of the revenue changes are presented in the table on page 24. As f h presented in this table, the base cost of fuel has been excluded from customer consumption and is included under fuel costs, revenue taxes are included as a part of other revenues, and y% unbilled revenues u : included in each caption as appropriate. O' Unbilled revenues are the estimated revenues attributable to energy which has been delivered to customers but for which the metered amount has not been read and recorded on the Company's books. Such revenues do not enhance the Company's cash position. The Company records monthly accruals for unbilled revenues. The Company's Statement of Income reflects net unbilled revenues of $18.7 million in 1993, $(0.8) million in 1992, and $2.6 million in 1991. Primarily as a result of the seasonal nature of gas revenues, unbilled revenues can flue-tuate from month to month and will normally be near their maximum around January and at their minimum near the end of June. Under the ERAM provisions of the 1993 Rate Agreement, as discussed under Regulatory Matters, the Company is comparing, on a monthly basis, actual results to forecast electric gross margins as defined (basically, revenues less incremental cost of fuel) and utilized in estab - lisi ites. Oriations between these target margins and the Company's actual margins may - h
} fkA Q be deferred and either recovered from or returned to customers. As discussed earlier, the 1993 Rate Agreement " caps", that is limits, the amount of revenue increases that can be obtained each rate year. At the end of each rate year (i.e. June 30) any balance for ERAM will be taken into consideration along with other balances eligible for passback or surcharge to customers (primarily incentive and expense sharing provisiono to detetmine the final disposition of the balance. As of December 31,1993 no provisions to ..ccrue or defer revenues associated with any of the ERAM incentive or sharing provisions under the 1993 Rate Agreement had been made, except for fuel adjustment clause revenues.
Changes in fuel and purchased power cost revenues are normally earnings neutral. The m Company, however, does have fuel clause provisions which currently provide that customers N and shareholders will share, generally on a 509/509 basis subject to certain incentive limits, g" the benefits and detriments realized from actual electric fuel costs, generation mix, sales of gas
$j$ to dual fuel customers and sales of electricity to other utilities compared with PSC-approved (
forecast, or base rate, amounts. As a result of these sharing arrangements, discussed further in Note I of the Notes to Financial Statements, pretax earnings were increased by $4.4 million
$[$
$]Q H in 1992 and in 1993, primarily reflecting actual experience in both electric fuel costs and generation mix compared with rate assumptions. Fuel clause revenues also include the recovery %{h 7' of incremental margins that vary from those provided for in base rates for the implementation ,
; - of the Company's energy efficiency programs (discussed below in this section). Beginning in ,%
October 1993, the Company also began the recovery through its fuel adjustment clause of , @1 deferred costs associated with the DOE's assessment for future uranium enrichment decontami- 4 nation. For the 1992 comparison period, fuel clause resenues were reduced due to a refund to j 7 electric customers resulting from a PSC fuel audit settlement as de.,cribed in the last paragraph Qt under the heading New York State Public Service Commission. '! [ The effect of weather variations on operating revenues is most measurable in the Gas j Department, where revenues from space heating customers comprise about 85 to 90 percent of gj total gas operating revenues. Variation in weather conditions can also have a meaningful impact , y on the volume of gas delivered and the revenues derived from the transportation of customer-owned gas since a substantial portion of these gas deliveries is ultimately used for space 4 g 3 heating. After experiencing unseasonably mild weather during the 1991 heating season, pd 77 weather in the Company's service area during 1992 and 1993 was colder than normal. Gas N y 7 sales were enhanced as a result of this cooler weather, while unseasonably warm summer weather during 1993 boosted electric energy sales to meet the demand for air conditioning ,$N N eo usage, compared with the cool, wet 1992 summer weather conditions. The decoupling, or ,J q pu n es L Operating Revenues Q
$% increase or (Decrease)from Prior Year N
*t Electric Department Gas Department -
(Thousands of Dollars) 1993 1992 1993 1992 Customer Revenues (Estimated) from: _.M' Rate increases $21,827 $28,138 $ 8,087 . $' 3,644 Fuel Costs 9,093 (0,633) - 25,593 -11.512 Weather Effects (IIeating) 200 1,236 700 7 5.722
; Customer Consumption 4,374 (2.826) . 1,381 11,098 Other . (4,806) 2,422- (3,777) : ~ 4.020.
Total Change in Customer Revenues 30,688- 19.337 : 31,984 ~ 25,996 Electric Sales to Other Utilities (9,180) (3,071) t> w Totiil Change in Operating Revenuet $21,508 : $16.266 - i$31,984 L $25.996 jg,p y+% rec sp o y:y. s cc - nn
. pghg
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,T*%s sep2 ration, of sales level fluctuations from revenue through the ER AM provisions, discussed under Regulatory Matters, and a gas nonnalization weather clause (see following paragraph) may mitigate the effect of abnonnal weather conditions on earnings.
As part of the June 1992 rate decision, retail customers who use gas for spaccheating became subj: et to a weather normalization adjustment to reflect the impact of variations from normal weather on a billing cycle month basis for the months of October through May, inclusive. The weather normalization adjustment for a billing cycle will apply only if the actual heating degree days are lower than 97.5 percent or higher than 102.5 percent of the normal heating degree days. Weather nonnalization adjustments lowered gas revenues in 1993 by approximately
$1.2 million and in 1992 by approximately $1.8 million. The potential for such adjustments continues through June 1996 under the terms of the 1993 Rate Agreement.
Compared with the prior year, kilowatt-hour sales of energy to retail customers in 1993 climbed about one percent after being nearly flat in 1992. Electric demand for air conditioning usage had a significant impact on such sales in 1993 and 1992. L)uring 1993, an increase in sales to both residential and commercial customers more than offset a decline in sales to industrial customers. Kilowatt-hour sales of energy in 1993 reflect the impact of approximately %[@ g, 2.200 new electric customers, which follows the addition of nearly 2,400 customers a g "y year earlier. Like many other electric utilities, the Company is encouraging energy efficiency through Q fg ff$ demand side management (DSM) programs. Objectives of the DSM programs include increasing the efficiency with which electricity is used and shifting electric load from peak (p W "g to non-peak times, thus helping to save energy and delay the need to add new generating Md 9 capacity. DSM programs include rebates for energy-efficient equipment, audits which [M q k;s focus on potential techniques for saving energy, consumer infoimation and outreach, and design assistance to encourage energy-efficient new construction. In general, the Company is aW e" $? being allowed to amortize major DSM program expenditures over a five-year period. An Y# incentive allowance (award) of approximately $0.6 million was provided for in the Company's rates based on the Company's DSM performance during 1992. Lost margins resulting from 4 g pi DSM activities are estimated and recovered in base rates. Variances between actual results N)I-Wh and such estimates are recovered through fuel clause revenue adjustments, subject to certain
% incentive limitations. @M:k h4 Fluctuations in revenues from electric sales to other utilities are generally related to the MM k Company's customer energy requirements, New York Power Pool energy market and transmis-sion conditions and the availability of electric generation from Company facilities. Such 1 %* revenues in 1992 and 1993 reflect the sale of energy at a lower average rate per megawatt hour, a result, in part, of competition and greater availability of energy. With more 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 will be increased competition for the sale of electric energy to other utilities.
The transportation of gas for large-volume customers who are able to purchase natural gas from sources other than the Company remains an important component of the Company's marketing mix. Company facilities are used to transport this gas, which amounted to 12.4 million dekatherms in 1993 and 12.6 million dekatherms in 1992. These purchases have caused decreases in customer revenues, with offsetting decreases in purchased gas expenses, but do not adsersely affect earnings because transportation customers are billed at rates which, except'for the cost of gas, approximate the rates charged the Company's other
. gas service customers. Gas supplies transported in this manner are not included in Company thenn sales, depressing reported gas sales to non-residential customers.
$ y -
~
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% ~
l Therms of gas sold and transported, including unbilled sales, were nearly flat in 1993, following an 11.8 percent increase in 1992. These changes reflect, primarily, the effect of weather variations on therm sales to customers with space heating. If adjusted for normal weather conditions, residential gas sales would have decreased about 0.3 percent in 1993 over 1992, while nonresidential sales, including gas transported, would have decreased approxi-mately 2.1 percent in 1993. The average use per residential gas customer, when adjusted for normal weather conditions was slightly down in 1993, following a modest inen : in 1992. Total therms of gas transponed increased in 1992 primarily as a result of higher utes to certain large industrial and municipal transportation customers. Sales to these customers in 1993 were down compared with 1992 sales. A Fluctuations in "Other" customer revenues shown in the table on page 24 for both 4@
$ comparison periods are largely the result of cevenue taxes, deferred fuel costs, and g
gh miscellaneous revenues. Operating Expenses fhS
- Compared with the prior year, operating expenses were up $40.2 million in 1993 after increasing $33.1 million in 1992. Approximately two-thirds of the increase in 1993 operating g 7,;s expenses resulted from highrr gas purchased for resale costs. The increase in operating
{ expenses for the 1993 comparison period was mitigated by the Company's continuing efforts to a curtail increases in other operation expenses. Operating expenses are summarized in the table -W h' on page 27. % Energy Costs-Electric. An electric generation mix favoring less expensive nuclear fuel, j g k compared with the cost of coal or oil, resulted in fuel expenses not increasing at the same rate '] F as electric generation for the 1993 comparison period. For the 1992 comparison period, fuel expense for electric generation was lower by $16.7 million due,in part, to a refund to electric H customers as described in the last paragraph under the heading New York State Public Service 4 a Commission. For both comparison periods, the average cost of coal declined. < l9J x ' ll' Average rates for purchased electricity declined in 1993, after increasing in 1992. Such $( average rates partially offset an increase in kilowatt-hours purchased in 1993. For the 1992 comparison period, the increase in purchased electricity expense was caused by higher average G pa rates during the year. Energy Costs and Supply-Gas. As a result of the implementation of FERC Order 636, and [@ the commencement of operation of the Empire State Pipeline, the Company now purchases all of its required gas supply directly from numerous producers and marketers under contracts {(j> g T containing varying temis and conditions. The Company holds firm transportation capacity on j nine major pipelines, giving the Company access to the major gas-producing regions of North ;E lm e America. In addition to finn pipeline capacity, the Company also has obtained contracts for
- firm storage capacity on the CNG Transmission Corporation (CNG) system (10.4 billion cubic
$ feet) and on the ANR Pipeline system (6.4 billion cubic feet) which are used to help satisfy its e
customers' winter demand requirements. With the commencement of operation of the Empire State Pipeline, the Company placed into operatien its new Mendon gate station which is capable of supplying up to one-half of the Company's gas supply needs while also maintaining the various gate station interconnections with the CNG system that, prior to Empire, had supplied all of the Company's needs. The transportation service to be provided by Empire was scheduled to phase in over 12 months, at which point the combined CNG and Empire transportation capacity would have exceeded the Company's current requirements. Therefore, the Company recently entered into a marketing agreement with CNG, pursuant to w hich CNG will assist the Company in obtaining permanent replacement customers for the transportation capacity the Company will not require. It may renegotiate its arrangements with CNG and/or Empire or it may negotiate assignment, o 3' .k, # 4 Q afu
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on a permanent or temporary basis, of the transportation capacity that exceeds the requirements ofits customers. In addition, under FERC rules, the Company may sell its excess transportation capacity in the market. While CNG has already secured letters of intent for a substantial ponion of such capacity, whether and to what extent CNG and/or the Company can successfully negotiate the assignment or sale of the excess capacity, or at what price, cannot be determined at the present time. The retention of some or all of this excess transportation capacity may cause an increase in the Company's gas supply costs. This would be in addition to any increase caused by other aspects of the gas transporta-tion restructuring. As a result of the restructuring of the gas transportation industry by the FERC, there will be a number of changes in this aspect of the Company's business over the next several' years. These changes, which will apply throughout the industry, will affect different companies differently and may result, at least initially, in increases in the gas transportation costs of the Company. j The Company will also be required to pay a share of certain transition costs incurred by the pipelines as a result of the FERC restructuring. These include costs related to restructuring p existing gas supply contracts, unrecovered gas costs that would otherwise have been billable (g f{J ( to pipeline customers under previous regulation and other related costs dcemed reasonable by 'g $$ the FERC. Although the final amounts of such transition costs are subjec to continuing $ negotiations with several pipelines and ongoing pipeline filings requiring ERC Tauval, the hp g" Company expects such costs to range between $43.5 and $52.0 million. A substantial ponion Mf M of such costs will be on the CNG system of which approximately $27 million was billed to y the Company on December 3,1993 payable over the following three years. The Company % d recorded a regulatory asset on its 13alance Sheet and concurrently recognized a liability ,/ h totaling approximately $43.5 million for estimated restructuring transition costs under FERC g p Order 636. The Company expects these transition costs to be recoverable in its rates. > e The volume of gas purchased increased in both comparison periods primarily due to higher 9 j combined residential and commercial spaccheating sales, reflecting colder weather. The effect of higher-volume purchases was partially offset by lower average rates in 1992. In contrast to 3 }1 pl,, ~ 1992, however, it was primarily an increase in these rates that pushed up the cost of gas M f purchased for resale in 1993. These higher rates reflect, in pan, increased demand charges %gj 2 and, to a lesser extent, newly assessable gas service restructuring charges as a result of FERC g( Order 636. g$ Td OR
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e c . , , , ~
^
operatingExpenses > 3 r Increase or (Decrease)from Prior Year . (Thousands of Dollars) 1993-S]O1992) Fuel for Electric Generation $ (2,505) . ~ $(16,729j Purchased Electricity . 1,857 32,023y Gas Purchased for Resale 25,593 . 111,512 t Other Operation - 8,757 _l18,1843 Maintenance (1,027) ((2.695). Depreciation ' .. (176) j :478j Amortization of Other Plant '(675) ' e3691 Taxes Charged to Operating Expenses ,j h Local, State and Other Taxes - 2,640' > 10,603 { Federal Income Tax 1 5,739 . 9,332i Total Change in Operating Expenses / . $ 40,203 $ c $ 33.077k
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Operating Expenses, Excluding Fuel. Other operation expenses rose over both comparison periods as shown by the table on page 27. The recording of certain postretirement benefits other than pensions, as required by Statement of Financial Accounting Standards No.106 (SFAS-106) and discussed in the following paragraph, increased other operation expenses in 1992 by $4.9 million. Compared with a year earlier, other operation expenses in 1992 also reflect an increase of $3.0 million for transmission wheeling charges, $1.9 million due to increased amortization of costs associated with the Company's demand side management programs, and additional expenses of about $1.6 million associated with the Company's share of Nine Mile Two operation expenses. As stated earlier, the growth in other operation expenses was significantly less over the 1993 comparison period, a direct result, in part, of enhanced cost control efforts by the Company's employees. Compared with 1992, operating expenses _ associated with fire and liability insurance, transportation, materials and supplies, legal expenses, and the Company's share of Nine Mile Two operation expenses declined in 1993. The change in other operation expenses for the 1993 comparison period reflects primarily
- increased payroll costs and demand side management expenses. .;
% During the first quarter of 1992, the Company adopted the Financial Accounting Standards
.kg M
g Board's (FASB) SFAS-106 for financial accounting purposes. Among other things, SFAS-106 requires accrual accounting for postretirement benefits other than pensions. Based on accrual J Wp accounting required by SFAS-106, the Company's net periodic cost for postretirement benefits g% g other than pension was $7.5 million in 1993 and $7.8 million in 1992. The PSC has allowed the f Company revenues in rates based on SFAS-106. In September 1993, the PSC issued a "q ;a h74W
" Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and
{l'l ' Postretirement Benefits Other Than Pensions."The Statement's provisions require, among p other things, ten-year amortization of actuarial gains and losses and deferral of differences b between actual costs and rate allowances. The Company adopted the Statement in 1993 for Q regulatory accounting purposes. "g h G, in November 1992, the FASB issued SFAS-112 entitled " Employees' Accounting for Postemployment Benefits" which is effective for fiscal years beginning after December 15,1993.
,y g
This Statement requires the Company to recognize the obligation to provide postemployment g g[g benefits to former or inactive employees after employment but before retirement. Employers Jy 7 must accrue an obligation if the benefits are attributable to service already rendered, the gg 92 benefits accumulate or vest, payment is probable, and the amounts can be reasonably estimated. g Y The Company must adopt SFAS-112 not later than the first quarter of 1994. The Company is F eurrently evaluating the impact of SFAS-112; however, based on studies the Company has Q* performed to date, the adoption of SFAS-Il2 is not expected to have a material effect on the Company's financial condition or results of operations. Reduced maintenance expense in both comparison periods was largely due to lower maintenance expenses incurred at nuclear production facilities and the effect of increased activity in 1991 associated with electric distribution facilities. Despite an increase in depreciable plant in both comparison periods, depreciation and amor-tization of other plant fluctuated only moderately due mainly to a decrease in the depreciation and accrued decommissioning expenses related to the Ginna nuclear plant because of a three ~ year extension of its operating license and the completion in July 1992 of amortization of the Sterling property previously abandoned. Taxes Charged to Operating Expenses. The increase in lucal, state and other taxes in both comparison periods resulted primarily from an increase in revenues combined with an increase in the revenue tax rate, and increased property tax rates aru M@rr property assessments. The 1993 increase in local, state and other taxes was mitigated by me effect of the relative magni-tude of these factors compared with 1992. The inercase in these taxes for the 1992 comparison O
w n g' %. gf,f s lmyfff
}Wf period reflects an adjustment for a one-half percent increase in the New York State gross revenue tax rate accounted for beginning in October 1991 retroactive to January 1,1991.
During the first quaner of 1993, the Company adopted SFAS-109 entitled " Accounting for Income Taxes" issued by the FASB in February 1992. Among other things, SFAS-109 requires that a deferred tax liability be recognized on the balance sheet for tax differences previously flowed through to customers. The Company's adoption of SFAS-109 in the first quarter of 1993 did not have a material effect on the Company's results of operations 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 of the Notes to Financial Statements. for further discussion of SFAS-109 and an analysis of Federal income taxes. In August 1993, the Revenue Reconciliatien Act of 1993 (1993 Tax Act) was signed into law. Among other provisions, the 1993 Tax Act provides for a Federal corporate income tax rate of 35% (previously 3&k) retroactive to January 1,1993. The Company has adjusted its tax reserve balances to reflect this new rate. There was no earnings impact since the effects of the f tax change have been deferred. The Company petitioned the PSC in late 1993 for recognition
/ and recovery of this incremental tax liability ahich was not reflected in the provisions ofits ;.
h> 1993 Rate Agreement. The Company's ability to recover this cost is dependent upon the PSC issuing a generic ruling on the treatment of the 1993 Tax Act. $g . b' [; @? 3 3 s L Other Statement ofIncome Items n
+
{w AFUDC variances are generally related to the amount of utility plant under construction and * }[y not included in rate base. AFUDC levels also reflect decreases in the cross rate to 3.90 percent g effective September 1,1993 from earlier rates of 4.50 percent,5.50 pewt, and 7.10 percent. b Variations in non-operating Federal income tax reflect mainly accountinF adjustments related J t to retirement enhancement programs (see following paragraph), regulatory disallowances, and a N an employee performance incentive program (discussed below in this section). h@f
%[
Recorded under the caption Other income and Deductions is the recognition of retirement enhancement programs designed to reduce overall labor costs which were implemented by the .h %
& Company during the third and fourth quarters of 1993. A total of 173 employees elected to M Jl participate under these programs. The Company does not plan to replace any of those f
% employees. Total estimated pretax costs of $8.2 million associated with these programs were
%g hgg recognized by the Company in its 1993 Statement of income, thereby reducing after-tax earnings by approximately $.15 per share for the year. The Company estimates that the net ] pre-tax savings through 1997 resulting from these programs will amount to about $8.9 million.
Recorded under the caption Regulatory Disallowances is the recognition of the 1991 PSC order associated with the Company's fuel procurement practices, the 1992 PSC order related to the March 1991 ice stonn, and the 1993 settlement with the PSC regarding certain alleged gas purchase undercharges, each discussed under the heading New York State Public Service Commission. Other Income in 1992 includes $3.5 million of proceeds received in settlement of lawsuits filed against certain contractors involved in the construction of the Nine Mile Two nuclear plant. Non-cash eamings associated with the amortization of customer prepaid Nine Mile Two financing costs of $4.8 million in 1991, $2.5 million in 1992, and $1.2 million in 1993 are also - included in Other income. The dec:ine in Other-Net income and Deductions for the 1993 comparison period results mainly from the recognition of an employee performance incentive program for 1993. This program recognizes employees' achievements in meeting corporate goals and reducing expenses. Compared with a year earlier, Other-Net income and Deductions also reflects lower miscellaneous interest revenues in 1993 and the recognition of
-I ySohm MM% ' /MfkLMQW .
J
pm v - . '7 -- ng m gi@b '~'i fyg ' Energyline camings (losses) upon consolidation with the accounts of the Company as discussed under Capital Requirements and Gas Operations. Both mandatory and optional redemptions of certain higher-cost first mortgage bonds have helped to reduce long-term debt interest expense over the three-year period 1991-1993, despite the issuance of additional long-tenn debt in 1991 and 1992. In 1992, the effect of lower interest rates on debt expense was partially offset by increased short-term borrowings. The level of s.. p short-term debt borrowings decreased in 1993. farninp/Smumary
%o$
P Presented below is a table which summarizes the Company's Common Stock earnings on a g k per-share basis. Certain non-recurring items and their effect on earnings per share have been identified in this table. Compared with a year earlier, earnings per share w tre up in 1993 and 1992 despite the effect of a public issuance of Common Stock in each yeat Future earnings i) k will be affected, in part, by the Company's success in achieving demand sice management and 'f h[h ]Q
+g other incentive goals, as well as controlling operating and capital costs, withic levels provided for in rates under the terms of the 1993 Rate Agreement.
g
%q W' In December 1992 the Company announced a quarterly dividend increase trom $.42 to 1' $.43 per share of Common Stock payable in January 1993. Subsequently, in December 1993 ,
the Company announced a new quarterly dividend rate of $.44 per share payable in January 4^ ' . 1994. The Company's Charter provides for the payment of dividends on Common Stock out of u the surplus net profits (retained earnings) of the Company. Accordingly, dividend payments are dependent on future earnings, in addition to financial requirements and other factors. M
%d f
r EarningsperShars-Summary . (Donars per Share) ' 1993 1992' '1991: l Earnings per Share Before Non-recurring hems $2.19 $1.91 $1.811 4 Non-recurring items Gas Under-recovery Writeoff (.04) Retirement Enhancement Programs (.15) d 7j3 , Nine Mile Two Litigation Proceeds .10 ;Si N , Ice Storm Disallowance (.15) ' h Fuel Procurement Audit' - (.21) A@ f$ [ Total Non-recurring items $ (.19) $ (.05)' f $(.21)~ heported Earnings per Share $2.00 $1.86 $1.60 $
~~~.
- hk .
Financial Reports - Statement of income - . '33 ' Statement of Retained Earnings ~ 33 Balance Sheet. 34 3 Statement of Cash Flows 35' Notes to FinancialStatements 36 Report of Independent Accountants. 53 Report of Management - 54 , Interim Financial Data ~ 54 Common Stock and Dividends ~55 Selected Financial Data 56 Electric Department Statistics 58-Ga,t Department Statistics - 59 a. >
-I i
1 d 1
-i 31
- I (Financial Profile !
- .. J l
Electrie 31arket Profile Gas Market l'rofile Degree Day Variations phnu<amla of mwh sehh (milliorus oftherms scht and trans;mnnb ygognNorunal c] l 1 E E ~ l2 7 E ileating ikgree Dan 1.0 14 IJud 744 fj';",',,, i 126 . g E coolmgtkpee %p "0 M Other 12 , 12,2 -]
" 13 . ._ " -- Nu inal 268 f.926 1.917 M94 Industnal 79 cy,,,,,t i,, ig3 :i 72 -
- Nonnal 13$sm-I,9% 1,987 C'"""'dl I.923
-2tM
?a5 2% 402 Reudenual t
' I 2fm9 2,085 2.121 Reudennal l_ 5t,7 ,
1991 1992 IW3 1Al IW2 IW3 1991 IW2 1993 Operating Itn ennes Earnings Der Slure Diviilends Per Share (mdthms ofdolhan t ()[ConIthan Stoca Of Coininon Stock t uhollnn) Idallan) 949 2m g g E 1E. -
?" G3$
LML 232 ht7 634 fi35 l'.kdric
))
l99/ 1992 1993 1991 1992 1993 1991 1992 1993 - i lletained Earnings Capitalization Embethled (Annual) Cost Of , At Deecmher 31 At Decerr' er 31 Iong-Term Debt At Year End l (mulkons of dollant imillbms of<lullan) Ipercent) 22_ 113 #dl 7 ,,
'i 7.lt 119 ]
g ? i 44m {"a" am :4= ;
- 1 .
Em- ;= ;- . l-1991 32-kW2 1993 1991 Sm 1992 u.3 1993
.im ggenn 1991 100? 1993'
- _ _ _ _ - - _ = _ - _ _ _ _ _ - - - _ =____________-_.-____
Consolidated Statement ofInconie (Thousands of Dollss) Year Ended December 31 1993 1992 1991 Operating Revenues Electric $ 638,055 $ 608.267 $ 588,930 Gas 293,708 261,724 235,728 932,663 869.991 824.658 Electne sales to other utilities 16,361 25.541 28,612 Total Operating Resenues 949,024 895.532 853.270 Operating Expenses I uel Expenses Fuel for electric generation 45,871 48 3'6 65,105 Purchased electricity 31,563 29.706 27.683 Gas purchased for resale 166,884 141.291 j'29.779 Total Fuel Expenses 244,318 219.373 2'_2,567
~
Operating Revenues Len Fuel Expenses 104,706 676.159 630.703 Other Operating thpenses Operations excluding fuel expenses 235,381 226.624 208.440 Maintenance 61,693 62,720 65,415 Depreciation and anairtization 84,177 85.028 84.181 Taxes-local, state and other 126,892 124,252 113.649 Federal mcome tax 49,330 43.591 34.259 Total Other Operating Expenses 557,473 542,215 505.944 Operating Income 147,233 133.944 124,759 Otherincoine andDeductions Allowance for other funds used during construction 153 164 675 Federal income tax 9,827 4,195 4.580 Pension Plan Curtailment (8,179) - - Regulator) disallon ances (1,953) (8.215) (10,000) Other, net (7.074) 6.155 6.078 Total Other income and (Deductionu (7.226) 2,299 1.333 Income Before Interest Chargn 140,007 136.243 126.092 Interest Charges
'Long term debt 56,451 60.810 63,918 Other, net 6,707 7.178 7,082 Allowance for bornmed funds used during construction (1,714) (2,184) (2,905) .
Total Interest Charges 61,444 65.804 68.095 Net income 78,563 70.439 57,997 Dividends on Preferred Stock 7,300 8.290 6.963 Earnings .1pplicable to Common Stock $ 71,263 $ 62.149 $ 51,034
\\~e ighted Arcrage Number of Sharesfor Period ((KNYs) 35.599 33.258 31,794 Earnings per Common Share $ 2.00 $ 1.86 $ 1.60 Consolidated Statement of Retained Earnings (Thcusands of Dollars) Year Ended December 31 1993 1992 1991 Italance at Beginning of Period $ 66,968 $ 61,515 $ 62.542 Add Net income 78,563 70,439 57,997 <
Adjustment Associated with Stock Redemption (933) - - Total 144,598 131.954 120.539 ) Deduct l Dividends declared on capital stock l Cmnulative preferred stock 7,300 8,290 6,963 Common stock 62,172 56.696 ' 52.061 i
' I Total 69,472 64,986 59,024
#alance at End of Period $ 75,126 $ 66.968 $ 61,515
'lbc .iccompan.3ing notes are an mtegral part of the fmanual statements.
ma mu,a," 33
Consolidated Balance Sheet At December 31 1993 19W Uhousands et DoHam ] Assets
!!tility 1*lant
$ 2,234,530 $ 2,175.255 Elecdic 341,466 Gas 356.484 125,428 123.034 Common 158,826 174.357 Nudear fuel 2,890,799 2.798,581 1,190,801 1,125.502 i ess. Accumulated depreciation 127,615 144,282 Nuclear fuel amortization 1,555,716 1,545,464 112,750 83.834 Construction work in progress 1,668.466 1,629 298 Net Utihty Plant Current Anets 1,759 Cash and cash equnalents 2,327 Accounts receivable, net of allow ance for doubtf al accounts:
104,753 92,292 1993-Smt 1992-1500 61,330 60,184 Unbilled res enue receiuble Statenah anJ supplies, at as erage cost 5.983 12,273 I ossil fuel 13,130 Construction and other supplies 13,644 38,989 9.998 Gas stored underground 21,563 19.985 Prepay ments Total Current Assets, 248,589 209 621 38,560 9,846 In vestment in Empire Deferred Debits 241,741 - Regulatory Asset-Licome Taxes 19,242 20.492 Deferred t'inance charges-Nme hiite Two Deferred iec storm charges 21,621 24.197 23,421 28,613 Uranium ennchment decommissioning defenal 38,930 29.549 Nudear generating plant decommissioning fund 34,513 34,300 Nme N1ile Two deterred costs 41,265 - FERC 6% Transition Costs Unamortized debt expense 19.326 13.553 61,956 49,972 Other 502.015 200.676 Total Deferred Debits Total Assets $ 2.457,630 $ 2.049.441 Capitalization andliabilities Capitalization Long term debt-mortgage bonds 1 655.731 $ 566.980 91,900 91,900
-promissory notes 67,000 67,000 Preferred stock redeemable at option of Company 42,000 54,000 Pieferred stock subject to mandatory redemption Conunon shareholdere equity 652,172 591.532 Conunon stock 75,126 66 E8 Retamed earnines Total Common Shareholders' Equity 727,298 658 500 1,583,929 1,438 380 Total Capitalitanon long Term liabilities (ikpartment of Energyk Nuclear waste dispmal 68.055 65.989 Uranium enrichment decommissioning 21,749 28.613 Total Lime Term Liabilities 89.804 94.602 Current liabilities I ong term debt due within one year 21,250 110.250 Preferred stock redeemable within one year 6,000 6.000 Note Payable-Empire 29,600 -
68,100 50.800 Short term debt , 52,596 40.578 Accounts payable 18.066 17,035 Dn idends paphie 6,472 13,743 Taxes accrued 12.955 15,461 Interest accrued 19,491 13 409 Other 234.530 267,276 Total Cunrnt Liabihties Deferred Credits and Other I.iabilities 425,648 171.673 Accumulated deferred incoine taxes Deferred f nance charges-Nine N1ile Two 19,242 20.492 Pension costs accrued 31,919 20.278 Other 72,558 36.740 549.367 249,183 Total Deferred Credits and Othet Liabilities Commitments and Other Matters tNote 101
$ 2.457,630 ,$ 2.049,441 Total Capitalization and I iabiliues The accompany mg notes are an integral part of the financial statements.
u em mmu,m ( wuim
Consolidated Statement of Cash Flows (Thousands of Donars) Year Ended December 31 1993 1992 1991 Cash flow trotn Operations Net income $ 78,563 $ 70,439 $ 57,997 Adjustments to reconcile net income to nel cash prorided from operating activities: Depreciation and amortization 84,177 85,028 84,181 Amortization of nuclear fuel 18,861 18,803 23,606 Deferred fuel-electric (2,072) 2,543 4,122 Deferred fuel-gas (11,500) 4,896 2,166 Deferred income taxes 15,232 10,466 9,124 Allowance for funds used during construction (1,867) (2,348) (3,580) Unbilled revenue, net (5,107) (6,631) (8,931) lee storm costs 2,576 12,234 (36,431) Nuclear generating plant decommissioning (9,381) (10,328) (15.581) Changes in certain current assets and liabilities: Accounts receis able (12,461) (8,239) (4,773) Materials and supplies-fossil fuel 6,290 (1,507) 7,506
-construction and other supplies (514) (591) (315)
Gas stored underground (28,991) (2,942) (7,057) Taxes accrued (7,271) 1,693 1,444 Accounts payable 12,018 (13,404) 6,914 Interest accrued (2,506) (852) 1,722 Other current assets and liabilities, net 6,113 (2,528) (592) Other, nel 10,966 (5,832) (2,075) Total Operating $ 153,126 $ 150,900 $ 119,447 Cash flow frotn investing Activilles Utility Plant Plant additions $ (125,744) $ (115,792) $ (114,579) Nuclear fuel additions (15,530) (11,763) (13,058) Less: Allowance for funds used during construction 1,867 2.348 3,580 Additions to Utility Plant (139,407) (125,207) (124,057) Investment in Empire-net 884 (9,846) - Other. net (1,907) 490 (685) Total ins esting $ (140,430) $ (134,563) $ (124,742) Cash Flow from Financing Activilles , Proceedsfrom: Sale / Issue of common stock $ 61,254 $ 63,928 $ 13,446 Sale of preferred stock - - 30,000 Sale of long tenn debt, mortgage bonds 200,000 160,500 100.000 . Short term borrowings 17,300 (8,700) 17,100 l Retirement oflong term debt (200,249) (160,000) (92,334) Retirement ofpreferred stock (12,000) - - i CapitalstocA expense (615) (1,735) (495) Discount and expense ofissuing long term debt (7,909) (6.368) (3,310) Dividends paid on preferred stock (7,548) (8,290) (6.396) Diridendt paid on common stock (60,893) (55.216) (51,308) Other, net (1,468) (185) (464) Total Financing $ (12,128) $ (16,066) .$ 6.239 increase in cash and cash equivalents $ 568 $ 271 $ 944. Cash and cash equivalents at beginning of year $ 1,759 $ 1,488 $ 544 Cash and cash equivalents at end of scar $ 2,327 $ 1.759 $ 1.488 i Supplemental Disclosure of Cash Flow Information (Thousands of Dollars) Year Ended December 31 1993 1992 1991 Cash Paid During the Year interest paid (net of capitali:ed amount) $ 60,852 $ 64,431 $ 63,848 Income taxes paid 5 32,779 $ 22.911 $ 20.399 The acaimpanpng notes are an mtegral part of the fmanaal statementt . - - - 35 l
Notes to Financial Statements Note 1, Summary of Accounting Principles General. The Company is subject to regulation by the Public Service Conunission of the State of New York (PSC) under New York statutes and by the Federal Energy Regulatory Conunission (FERC) as a licensee and public utility under the Federal Power Act. The Company's accounting policies confonn to generally accepted accounting principles as applied to New York State public utilities giving effect to the rate-making and accounting practices and policies of the PSC, , in June 1988, the Board of Directors authorized the creation of Utilicom, Inc. as a wholly owned subsidiary. Utilicom develops and markets computer software to assist customers in complying with state and federal environmental and safety regulations. On August 31,1993, the Company sold the assets of Utilicom and liquidated the subsidiary. The subsidiary activity prior to and including disposition was insignificant to the Company's financial position and results of operation. In April 1990, the Board of Directors authorized the creation of Energyline Corporation, a wholly owned subsidiary, w hich was incorporated m July 1992. Energyline was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. On November I,1993 Empire commenced service to the Company's gas distribution facilities. The Company has authority to invest up to $20 million in Empire. In June 1993 Empire secured a
$150 million credit agreement, the proceeds of w hich are to finance approximately 75 percent of the total construction cost and initial operating expenses. Energyline is obligated to pay up to 20% of the balance outstanding subject to a commitment of $9.7 million under the credit agreement. Excluding the loan commitment, at December 31,1993 the Company had invested a net amount of $10.2 million in Energyline.
A descriptmn of the Company's principal accounting policies follows. Rates and Revenue. Revenue is recorded on the basis of meters read. In addition, the Company records an estimate of unbilled revenue for sersice rendered subsequent to the meter-read date through the end of the accounting period. Tariffs foi electric and gas service include fuel cost adjustment clauses which adjust the rates monthly to reflect changes in the actual average cost of fuels. The electric fuel adjustment provides that ratepayers and the Company will share the effects of any variation from forecast monthly unit fuel costs on a 507/50% basis up to a $5.6 million cumulative annual gain or loss to the Company. Thereafter,100 percent of additional fuel clause adjustment amounts are assigned to customers. The electric fuel cost adjustment also provides that any vuiation from forecast margins below $7.1 million or above $8.5 million on sales to electrie utilities be shared with retail cedomers on a 50%/50% basis. In addition, there is a similar 50%/50% sharing process of variances from forecasted margins derived from sales and the transportation of privately 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. Other performance incentives or penalties were established in the settlement and under some circumstances could be recognized periodically. However, through December 31,1993, no amount was recognized as recoverable or payable to customers. Retail customers who use gas for spaccheating are subject to a weather normalization adjust-ment to reflect the impact of variations from normal weather on a billing month basis for the months of October through May, inclusive. The weather nonnalization adjustment for a billing cycle will apply only if the actual heating degree days are lower than 97.5 percent or higher than 102.5 percent of the nonnal heating degree days. Weather normalization adjustments lowered gas revenues in 1993 and 1992 by approximately $1.2 million and 36 - o" *-
$1.8 million respectively. These adjustments will continue through June 1996 in accordance with the 1993 muhi-year rate settlement agreement.
Deferred FuelCosts. The Company practices fuel cost deferral accounting as described above. A reconciliation of recoverable gas costs with gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from the customers during a subsequent twelve-month period beginning in December. These deferred fuel costs are included as a component of unbilled revenues. Utility Plant Depreciation and Amortization. The cost of additions to utility plant and replacement of retirement units of property is capitalized. Cost includes labor, material, and similar items, as well as indirect charges such as engineering and supervision, and is recorded at original cost. The Company capitalizes an allowance for funds used during construction approximately equivalent to the cost of capital devoted to plant under construction that is not included in its rate base. Replacement of minor items of propen) is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve. Depreciation in the financial statements is provided on a straight-line basis at rates based on the estimated useful lives of property, which have resulted in provisions of 2.9%,2.97c and 3.39 per annum of average depreciable property in 1993,1992 and 1991, respectively. The decrease in depreciation provision percentages from 1991 to 1992 is principally the result of a 3% year extension of the Ginna Nuclear Plant license tenu and lengthening estimated useful lives at other property. Nuclear FuelDisposalCosts. The Nuclear Waste Policy Act ( Act) of 1982, as amended, requires the United States Department of Energy (DOE) to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high-level nuclear waste repository is not expecteJ to be operational before the year 2010. The DOE is pursuing effons to establish a monitored retrievable interim storage facility which may allow it to take title to and possession of nuclear waste prior to the establishment of a permanent repository. The Act provides for a detennination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7,1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected by the Company in June 1985. The Company esti-mates the fees, including accrued interest, owed to the DOE to be $68.1 million at December 31,1993. The Company is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long-term liability and interest is accrued at the current three-month Treasury bill rate, adjusted quarterly. The Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6,1983, for a charge of one mill ($.001) per KWH of nuclear 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 facility is operational. NucIcar Decommissioning Costs. Decommissioning costs (costs to take the plant out of service in the future) for the Company's Ginna Nuclear Plant are estimated to be approximately $150.7 million, and those for the Company's 147c share of Nine Mile Two's decommissioning costs are estimated to be approximately $34.3 million (January 1993 dollars). Through December 31,1993, the Company has accrued and recovered in rates $61.2 million for this purpose and is currently accruing and recovering decommissioning costs at a rate of approximately $8.9 million per year based on the use of a combination of internal and external sinking funds. (See Note 10.) (hte I omrinued on page 38) m-,,*"~ 37
umsuesjn,m The decommissioning costs, which form the basis for current accruals, were derived from rau m the record of thn Company's prior rate proceeding (PSC Opinion 93-19, issued August 1993) and were estima'ed principally by reference to a formula prescribed by the NRC for the purpose of providing for adquate funding at the time of the decommissioning. Uranium Enrichment Decontamination and Decommissioning Fund. As pan of the National Energy Act (Act) issued in October 1992, utilities with nuclear generating facihties are assessed an annual fee payable over 15 years to pay for the decommissioning of Federally owned uranium enrichment facilities. The assessments for Ginna and Nine Mile Two are estimated to total $24.1 million, excluding inflation and interest. The first installment of $1.6 million was paid in 1993 and recovered through the fuel adjustment clause. A liability has been recognized on the financial statements along with a corresponding regulatory asset. The Company i,cikw that the full amount of the assessment will be recoverable in rates as described in the Ac: FERC Order 636. Under this order, gas supply and pipeline companies are allowed to pass restructuring and transition costs associated with the implementation of the order on to their customers. The Company, as a customer, has estimated a total of $43.5 million w hich will be paid to its supjJiers. A regulatory asset and related deferred credit have been established on the balance sheet to account for these estimated costs. Approximately $2.2 million of these costs were paid during 1993 to various suppliers, and have 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 of borrowed 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 Statement ofincome as Allowance for Borrowed Funds Used During Construction, an offset to interest Charges, and Allowance for Other Funds Used During Construction, a part of Other income.
The rates approved by the PSC for purposes of computing AFUDC were: 3.9% from September 1,1993 through December 31,1993; 4.5% from September 1,1992 through August 31,1993; 5.5% from April 1,1992 thn,gh August 31,1992; 7.I'7c from July 1,1991 through March 31,1992; 8.6% from Fel;ruary 1,1991 through June 30,1991; 9.6% from January 1,1991 through January 31,1991. In 1984, the Company discontinued accruing AFUDC on a portion of its investment in Nine Mile Two for which a cash retum was allowed. Amounts were accumulated in deferred debit and credit accounts equal to the rmount of AFUDC which 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 Mile Two, and the balance in the deferred debit account would then be collected from customers over a longer period of time. The current balances of $19.2 million are expected to remain on the Company's books for future application by the PSC as a rate moderator. Federallacome Tat For income tax purposes, depreciation is generally computed using the most liberal methods permitted. The resulting tax reductions are offset by provisions for deferred income taxes only to the extent ordered or permitted by regulatory authorities. Statement of Financial Accounting Standards (SFAS) 109, Accounting for Income Taxes, was adopted by the Company during the first quarter of 1993. SFAS-109 requires that a deferred tax liability must be recognized on the balance sheet for tax differences previously flowed through to customers. Substantially all of these flow-through adjustments relate to property plant and equipment and related investment tax credits and will be amortized
"- "-"~-
38
consistent with the depreciation of these accounts. The net amount of the additional liability at December 31,1993 was $241 million. In conjunction with the recognition of this liability, a corresponding regulatory asset was also recognized. SFAS-109 also requires that a deferred tax liability or asset be adjusted in the period of enact-ment for the effect of changes in tax laws or rates. During the year the statutory income tax rate was increased one percent to 35% This resulted in increases of $.6 million and $1.3 million for current and deferred tax liabilities. respectively. There was no carnings impact since the effects of the tax change have been deferred for future recovery. The Company uses the separate-period approach in calculating the interim quarterly tax provision. Retirement 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 of the Company's employees may become eligible for these benefits if they reach retirement age while working - for the Company. These and similar benefits for active employees are provided through insurance policies whose premiums are based upon the experience of benefits actually paid. In December 1990, the FASB issued SFAS-106 entitled " Accounting for Postretirement Benefits Other than Pensions" effective for fiscal years beginning after December 15,1992. Among other things, SFAS-106 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-yea mortization of actuarial gains and losses and deferral of differences between actual costs and rah. allowances. The effects of applying the ten year amortization of actuarial gains were deferred. Postemployinent Benefits. In November 1992, the FASB issued SFAS-112 entitled " Employees' Accounting for Post-employment Benefits" which is effective for fiscal years beginning after December 15,1993. This Statement requires the Company to recognize the obligation to provide post-employment benefits to former or inactive employees after employment but before retirement. The Company must adopt SFAS-112 not later than the first quarter of 1994. The Company is currently evaluat-ing the impact of SFAS-ll2; howeser, based on studies the Company has performed to date, the adoption of SFAS-112 is not expected to have a material effect on the Company's financial condition or results of operations. . Earnings Per Share. Earnings applicable to each share of common stock are based on the weighted average number of shares outstanding during the respective years. 4 4 9 R>mtwurt ban amiiinuw Gewum
i i I Nnte 2. Federal income Taxes The provision for Federal income taxes is distributed between operating expense and other income based upon the treatment of the various components of the provision in the rate-making ; process. The following is a summary of income tax expense for the three most recent years. l (Thousands of Dollars) 1993 1992 1991 Charged to operating expense: Current $33,453 $36,101 $28,766 Deferred 15,877 7,490 5.493 Total 49,330 43.591 34,259 Charged (Credited) to other income: Current (9,182) (7.171) (8.211) Deferred (645) 2,976 3.631 Total (9,827) (4,195) (4.580) Total Federal income tax egense $39,533 $39.396 $29.679 The following is a reconciliation of the difference between the amount of Federal income tax expense reported in the Statement of Income and the amount computed by multiplying the income by the statutory tax rate. (Thousa' ids of Dollars) _ 1993 1992 195
% Of *e of % of Pretax Pretax Pretax Amount income Amount income Amount income Net income $ 78,563 $ 70.439 $57,997 Add: Federal income tax expense 39.503 39.396 29.679 Income before Federal income tax $118,066 $109.835 $87,676 Computed tax expense $ 41,323 35.0 $ 37,344 34 0 $29,810 34 0 increases (decreases)in tax resulting f rom:
Dif ference between tax depreciation and amount deferred 6,337 5.4 6.775 6.2 5.606 6.4 investment tax credit (2,432) (2.1) (2.426) (2 2) (2,432) (2.8) Miscellaneous items, net (5,725) (4.8) (2,297) (2.1) (3.305) (3.7) Total Federal income tax expense $ 39,503 33.5 $ 39.396 35.9 $29.679 33.9 A summary of the components of the net deferred tax liability is as follows: (Thousands of Dollars) 1993 1992 Nuclear decommissioning $ (11,518) $ (13,087) Nine Mile disallowance (15,200) (19,569) Alternative minimum tax (27,908) (27,611) Accelerated deoreciation 164,821 174,237 Investment tax credit 34,305 55,206 Ice storm 5,642 6,519 Depreciation and ITC presiously flowed through 246,127 - Other 29,379 (4.022) Total $425.648 $171,673 In 1993, the regulatory asset recognized by the Company as a result of adopting SFAS No.109 is attributed to $222 million in depreciation $18 million to property taxes, $18 million of deferred finance charges-Nine Mile Two and $4 million of miscellaneous items offset by
$21 million attributed to investment tax credits.
i l l 40 "*'a " '~"" w -
Note 3. l'ension 11an and Otlier Itetiremi.nt llenefits The Company has a defined benefit pension plan covering substantially all of its employees. The benefits are based on years of service and the employee's compensation during the last three years of employment. The Company's funding policy is to contribute annually an amount consistent with the requirements of the Employee Retirement Income Security .Act and the Internal Res enue 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 folknvs: (MJaons) 1993 1992 Accumulated benefit obligation, including vested benefits of
$286.I in I993 and $249.6 in 1992 $(309.3)* $(268.1)*
Projected beneht obligation for service rendered to date $(429.5)* $(378.0)* Less-Plan assets at fair value, primarily listed stocks and bonds 490.3 449.9 Plan assets in excess of projected benefits 60.8 71.9 Unrecognized net loss (gain) from past experience different from that assumed and effects of changes in assumptions (110.6) (102.4) Prior sersice cost not yet recognized in net periodic pension cost 13.7 5.4 Unrecogni/ed net obligation at December 31 4.2 4.8 Pension costs accrued $(31.9)** $ (20.3)
- Actuanal present ulue
' Includes $9.2 millwl pension plan curtadment charge.
Net pension cost included the following components: (Mecns) 1993 1992 1991 Sers ice cost-benefits earned during the period $ 8.7 $ 8.8 $ 7.1 Interest cost on projected benefit obligation 30.0 27.9 26.4 Actual return on plan assets (60.2) (35.1) (58.6) Net amonization and deferral 24.3 5.5 33.1 Net periodic pension cost $ 2.8 $ 7.1 S 80 The projected benefit obligation at December 31.1993 and 1992 assumed discount rates of 7% percert and 7% percent, respectively and long-term rate of increase in future compensation levels of 6 percent and 6% percent, respectisely. The assumed long-tenn rate of return on plan assets for 1993 and 1992 was 8% pcreent. The unrecognized net obligation is being amortized oser 15 years beginning January 1986. In September 1993, the PSC issued a " Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other than Pensions" (Statement). The 1993 pension cost reflects adoption of the Statement's provisions which, among other things, requires ten-year amortization of actuarial gains and losses and deferral of
~
differences between actual costs and rate allowances. In addition to providing pension benefits, the Company provides cenain health care and life insurance benefits to retired employees and health care coverage for surviving spouses of retirees. Substantially all of the Company's employees are eligible provided that they retire ; as employees of the Company. In 1993, the health care benefit consisted of a contribution s of up to $175 per month towards the cost of a group health policy provided by the Company. The life insurance benefit consists of a Basic Group Life benefit, covering substantially all employees, providing a death benefit equal to one-half of the retiree's final pay. In addition, I certain employees and retirees, employed by the Company at December 31,1982, are entitled to a Special Group Life benefit providing a death benefit equal to the employee's , December 31,1982 pay. I (Note 3 cominued <m j age G l l 1 .m%. _ 4j
l (connnuafn,m The Company adopted SFAS-106," Accounting for Postretirement Benefits Other than ; t w 411 Pensions" as of January 1,1992 for financial accounting purposes. Subsequently, with the i issuance of the Statement referenced above, the Company's application of SFAS-106 will ! extend to ratemaking purposes as well. The Company has elected to amonize the unrecognized, unfunded Accumulated Fostretirement Benefit Obligation at January 1,1992 over twenty years as provided by SFAS-106. The Company intends to continue funding these benefits on a pay-as-you-go basis. j The plans' funded status reconciled with the Company's balance sheet is as follows: (Mdhons) 1993 1992 Accumulated postretirement benefit obligation: Retired emplo)ees $(39.9) $(35.3) Actise employees (24.9) (23.6)
$(64.8) $(58.9)
Less-Plan assets at fair value 0.0 0.0 Accumulated postretirement benefit obligation (in excess oO less than fair value of assets (64.8) (58.9) Unrecognized net loss (gain) from past experience different from that assumed and effects of changes in assumptions 2.9 0.0 Prior service cost not yet recognized in net periodie pension cost 1.7 0.0 Unrecognized net obligation at December 31 50.7 53.6 l Accrued postretirement benefit cost $(9.5) $ (5 3) Net periodic postretirement benefit cost included the following components: (MAons) 1993 1992 Service cost-benefits attributed to the period $0.7 $01 Interest cost on accumulated postretirement benefit obligation 4.6 4.3 Actual return on plan assets 00 0.0 Net amortization and deferral 2.2 2.8 Net periodic postretirement benefit cost $7.5 g The Accumulated Postretirement Benefit Obligation at December 31,1993 and 1992 s assumed discount rates of 7% percent and 7% percent, respectively and long-term rate of increase in future compensation levels of 6 percent and 6% percent, respectively. 42 ""*""**r*"-
hte 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 following is the operating data for each of the Company's departments, and no interdepartmental adjustments are required to mive at the operating data included in the Statement of Income. (Thousands of Dollars) 1993 1992 1991 Electric Operating litformation' Operating revenues $ 655,316 $ 633.808 $ 617,542 Operating ey3enses, excluding provision for income taxes 486,951 482.968 478,101 Pretax operating income 168,365 150.840 139.441 Provision for income taxes 43,845 38.046 31.390 Net operating mcome $ 124,520 $ 112.794 $ 108.051 Other Information Depreciation and amortization $ 72,326 $ 73 213 $ 72,746 Nuclear fuel amorti/ation $ 18,861 $ 18.803 $ 23.606 Capital expenditures 5 112,022 $ 100,974 $ 97,294 investment information Identifiable assets (a) $1,978,009 $1.671,492 $1,607,210 Gas Operating information Operating res enues $293.708 $261.724 $ 235,728 Operating eysenses, eu'.uding pioc ;on for income taxes 265,510 235.029 216.151 Pretax operating income 28,198 26,695 19,577 Prosision for income taxes 5,485 5.545 2,869 Net operating income $ 22,713 $ 21.150 $ 16.708 Other Information Depreciation and amortization $ 11,851 $ 11,815 $ 11 A35 Capital expenditures $ 27,385 $ 24.231 $ 26.763 Int estment Information identifiable assets (a) $491,563 $354.528 $ 325.451 M Euludes cash. tmamoni/ed den cywnse and other wmmon acms. Ltc 5. ,lointl -On 3 ned Facilitie.- The following table sets forth the jointly-owned electric generating facilities in which the Company is participating. Both Oswego U. nit No. 6 and Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated by Niagara Mohaw k Power Corporation. Each participant must provide its own financing for any additions to the facilities. The Company's share of direct expenses associated with these two units is included in the appropriate operating expenses in the Statement of Income. Various modifications will be made throughout the lives of these plants to increase operating efficiency or reliability, and to satisfy changing environmental and safety regulations. Nme Mde Oswego Point Nuclear umt No 6 Umt No. 2 Net megawatt capacity 850 1,080 RG&E's share--megawans 204 151
-percent 24 14 Year of completion 1980 1988 Milhons of Dollars at December 31.1993 Plant in Senice Halance $97.7 $869.8 Accumulated Prosision For Depreciation $32.0 $441.1 Piant Under Construction 50.5 $ 12.4 The Plant in Service and Accumulated Provision for Depreciation balances for Nine Mile Point Nuclear Unit No. 2 shown above have been increased by the disallowed costs of $374.3 million.
Such costs, net ofincome tax effects, were previously written off in 1987 and 1989. m, w.m .. %.- 43 M
Ltc 6. long Term 1)cht Fkst Mortgage Bonds (Thousands) Pnncbal Amount i Decernber 31
% Senes Dae 1993 1992 4% U Sept.15,1994 $ 16,000 $ 16.000. )
$.30 V May 1,1996 18,000 18.000 6% W Sept.15,1997 20,000 20,000 67 X July 1,1998 30,000 30.000 8.(K) ' Y Aug.15,1999 30,000 30.000 9% Z Sept.1, 2(XX) -
30.000 9% B11 June 15,2006 - 50.000 8% CC Sept.15,2(X)7 50,000 50,000 - 9M DD Dec.I,2003 - 40,000 6% EE (a) Aug.1, 2009 10,000 10,0M 10.95 If Feb.I5,2005 2,750 5.500 13% JJ June 15,1999 15,000 17,500 8.6 LL Aug.1,1993 - 75.000 8% 00 (a) Dee 1,2028 25,500 25,500 9% PP Apr,1, 2021 100,000 100.000 8M QQ (b) Alar.15, 2002 100,000 100.000 6.35 RR (a) May 15,2032 10,500 10.500 6 50 SS (a) May I5,2032 50,000 50,000 73K) (b)(c) J an.14. 2(XM) 30,000 - 7.15 (b)(c) Feb.10,2003 39,000 - 7.13 (b)(c) Mar. 3, 2(X)3 1,000 - 7.64 tc) Mar.15,2023 33,000 - 7.66 (c) Mar.15,2023 5,000 - 7.67 (c) Mar.15,2023 12,000 - 6.375 (b) (c) July 30,2003 40,000 - 7.45 (c) July 30,2023 40,000 - 677,750 678,000 Net bond discount (769) (770) Less: Due within one year 21,250 110,250 Total $655,731 $566.980 (a) The Serie.s EE, Series 00, Series RR and Senes SS First Mortgage Honds equal the principal amount of and provide for al, payments of principal, premium and interest corresponding to the Pollution Control Resenue l Ilonds Series A, Series C, and Pouution Contml Refunding Revenue Bonds, Series 1992 A, Series 1992 B 1 (Rochester Gas and Electric Corporation Projects), respectively, issued by the New York State Energy.Research ' and Development Authority through a participation agreement with the Company. Payment of the principal of, and interest on the Series 1992 A and Series 1992 B Bonds are guanmtced under a Bond Insurance Policy by Municipal Bond Ins estors Assurance Corporation. The Series EE Bonds are subject to a mandatory sinking fund beginning August I,20lM) and each August I thereafter. Nine annual deposits aggregating $3.2 million will be made to the sinking fund, with the balance of $6.8 million principal amount of the bonds becoming due August 1,2009. (b) The Series QQ First Mortgage Bonds and 7%,7.159,7.13% and 6.375% medium-tenn notes described below are generally not redeemable prior to maturity. (c) In 1993 the Company issued $200 million under a medium-tenn note program entitled "First Mortgage Bonds, Designated Secured Medium.Tenn Notes, Series A" with maturites that range fmm seven years to thirty years. The First Mongage 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 annurn under the First Mongage, excluding mandatory sinking funds ofindividual series. Such requirements may be met by certification of additional property or by depositing cash with the Trustee The 1992 and 1993 requirements were met by certification of additional property. My m v.,,m e,-
Sinking fund requirements and bond maturities for the next five years are: (Thousands) 1994 1995 1996 1997 1998 Series FF (d) $ 2.750 Series JJ (c) 2.500 $2.500 $ 2.500 $ 2.500 0 2,500 Series U 16.000 Series V 18.000 Series W 20,000 Series X 30.000
$21.250 $2.500 $20.500 $22.500 $32,500 ;
(d) The Series FF First Moitgage Bonds are subject to a nundatory sinking fund of $2.75 milhon annually each I ebruary 15. (c) The Series JJ First Mortgage Bonds are subject to a mandatory sinking fund of $2.5 million annually each June 15. Promissory Notes (Thousands) Decernber 31
!ssued Due 1993 1992 Nosember 15,19S4 (f) October 1. 2014 $51,700 $51,700 December 5,1985 (g) Nos ember 15,2015 40,200 40,200 Total $91.900 $91,900 (f) The $51.7 million Promissory Note was issued in connection with NYSERDNs Floating Rate Monthly Dernand Pollution Control Resenue Bonds (Rochester Gas and Electrie Corporation Project) Series 1984.
This obligation is supported by an irresocable Letter of Credit expiring October 15,1994. The interest rate on , this note for each monthly interest payment period will be based on the evaluation of the yields of short term l tax-exempt securities at par hasing the same credit ratmg as said Series 1984 Bonds. The aserage interest rate l was 2.199 for 1993. 2.749 for 1992 and 4.32% for 1991. The interest rate will be adjusted monthly unlew conserted to a tised rate. (g) The 540.2 milhon Promissory Note was issued in connection with NYSERDNs Adju . table Rate Pollution Control Res enue Bonds t Rochester Gas and Electric Corporation Project). Series 1985. This obligation is supported by an irremeable Letter of Credit expiring Nos ember 30,1996. The annual interest rate w as adjusted to 4.509 effective Nosember 15,1991, to 3.109 effective Nos ember 15.1992 and to 2.75G effective Nos ember 15.1993. The interest rate will be adjusted annually unless converted to a tised rate. The Company is obligated to make payments of principal, premium and interest on each I Promissory Note which correspond to the payments of principal, premium,if any, and interest on certain Pollution Control Resenue Bonds issued by the New York State Energy Research and Development Authority (NYSERDA) as described above. These obligations are supported by certain Bank Letters of Credit discussed above. Any amounts advanced under such Letters of Credit must be repaid, with interest, by the Company. Based on an estimated borrowing rate at year-end 1993 of 6h8% for long term debt with ; similar terms and average maturities (14 years), the fair value of the Company's long term debt outstanding (including ' romissory Notes as described above) is approximately S816 million at December 31,1993. 1 l us.cw % me."" ~ 45 -
i Note 7. Preferred and Preference Stock Type, by Order of Senienty Par Value Shares Authorized Shares Outstanmng
$100 2.000.000 1.150,000*
Preferred Stock (cumulatise) Preferred Stock (cumulative) 25 4,000,000 - Preference Stock j 5.000.000 -
*see below for mandatory redemption requirements No shares of prefe:Ted or preference stock aie reserved for employees, or for options, warrants, conversions, or other rights.
- 4. Preferred Stock, not subject to mandatory redemption:
ousands) Optional Shares Outstanaing December 31 Redemption
% Senes December 31.1993 1993 1992 (per share)#
4 F 120,000 $12,000 $12.000 $105 4.10 11 80,000 8.000 8.000 101 "4% 1 60,000 6,000 6.000 101 4.10 J 50,000 5,000 5.000 102.5 4.95 K 60,000 6,000 6.000 102 4.55 M 100,000 10,000 10,000 '01 7.50 N 200,000 20,000 20.000 102 Total 670,000 $67,000 $67.000
#May be redeemed at any time at the option of the Company on 30 days minimum notice, plus accrued dividends in all cases
#. Preferred Stock, subject to mandatory redemption:
Shares omnN Optional Outstand:ng December 31 Redemption
% Senes December 31.1993 1993 1992 (per share) 8.25 R '180,000 $18,000 $30,000 $102.00 Before 3/1/94+
7.45 S 100,000 10,000 10.000 Not apphcable 7.55 T 100,000 10,000 10,000 Not applicable 7.65 U 100,000 10,000 10,000 Not applicable 480,000 $48,000 $60.000 Lest Due within one year 60,000 6,000 6.000 " Total 420,000 $42,000 $54.000
+Thereatter at 5100 00
lkludes 56 million optional redemption effectise March I.1993 ofandatory 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. Mandatory redemption of 60,000 shares per year at $100 per share commenced on March 1,1993 for Series R and on each March 1 thereafter, so long as any shares remain - outstanding. In addition, the Company has the non-cumulative right to redeem up to an additional 60.(X)0 shares on the same terms and dates applicable to the mandatory sinking fund redemptions. The Company redeemed 120,000 sh res on March 1,1993 and the Company ', has the right to redeem up to the remaining 180,000 shaies on March 1,1994. Series S, Series T, Series U, All of the shares are subject to redemption pursuant to manda- ! tory sinking funds on September 1,1997 in the case of Series S, September 1,1998 in the case ' of Series T and September 1,1999 in the case of Series U; in each case at $100 per share. Based on an estimated dividend rate at year-end 1993 of 5.25% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (3.25 years), the fair value of the Company's Preferred Stock, subject to maadatory redemption,is approximately ) 553 million at December 31,1993. I i it k h'estd Guh erwl Lkvizw GWT,iMWes l h o -__t-______-_
Note 8. Common Stock At December 31,1993, there were 50,(X)0,(XX) shares of $5 par value Common Stock autho- , rized, of which 36.911,265 were outstanding. No shares of Common Stock are reserved for options, warrants, conversions, or other rights. There were 1,193,613 shares of Common Stock resened and unissued for shareholders under the Automatic Disidend Reinvestment and Stock Purchase Plan and 253.090 shares resen ed and unissued for employees under the RG&E Savings Plus Plan. Common Stock Shares Amount Per Share Outstanding (Thousands) Halance, January 1,1991 31.421.268 $516.388 - Automatic Dividend Reinvestment and Su>ek Purchase Plan $18.750-$23.163 571,669 11,252 Sasings Plus Plan $19.375-$23.563 108.202 2,194 Capital Stock Expense (495) Halance. December 31,1991 32,101.139 $529.339 Sale of Stock $24 000 2,000,000 48.000 Automatic Dividend Reinvestment and Stock Purchase Plan $21.325-$24 850 584.854 13,338 Sasings Plus Plan $22.063-$25.188 110.666 2,590 Capital Stock Espense (1.735) Halance, Decen her 31.1992 34.796,659 $591,532 Sale of Stock $29 625 1,500.000 44,438 Automatic Dividend Reinvestment and Stock Purchase Plan $25 475-$29 413 515.036 14.076 Sasings Plus Plan $25.813-$29.250 99,570 2.741 Capital Stock lixpense (615) Halance, December 31,1993 36.911.265 $652,172 Note 9, Short Term Debt At December 31,1993 and December 31,1992, the Company had short term debt outstand-ing of $68.1 million and $50.8 million, respectively. The weighted average interest rate on short l term debt outstanding at year end 1993 was 3.469 and was 3.48% for borrowings during the year. For 1992, the weighted average interest rate on short term debt outstanding at year end was 3.99% and was 4.28% for borrowings during the year. , On December 1,1988 the Company renewed its $90 million revolving credit facility for a j period of three years and this agreement has been regularly extended. In November of 1993 the Company was granted a one-year extension of the commitment termination date to Decem-ber 31,1996. Commitment fees related to this facility amounted to W.000 in 1993, $169,(XX) in 1992 and S149,(XX)in 1991. The Company's Charter provides that unsecured debt may not exceed 15 percent of the , Company's total capitalization (excluding unsecured debt). As of December 31,1993, the i Company would be able to incur S19.2 million of additional unsecured debt under this provi-sion. In order to be able to use its revolving credit agreement, the Company has created a subor-dinate mortgage which secures borrowings under its revolving credit agreement that might othenvise be testricted by this lirovision of the Company's Charter. Since June 1990 the Company has had a credit agreement with a domestic bank providing for up to $20 million of short term debt. Borrowings under this agreement, which has been r extended to December 31.1994, are secured by the Company's accounts receivable. Also, additional unsecured short term borrowing capacity of up to $70 million is available from domestic banks, at their discretion. P.x4wr Oe , mil km.tru ( gnetw f
Note 10, Comtnitments anMhher Matters CapitalExpend!tures. The Company' .1994 construction expenditures program is currently estimated at $138 million, including $16 mi ! ion related to replacement of the steam generators at the Ginna Nuclear Plant and
$2 million of Anowance for Funds Used During Constmetion. The Company has entered into certain commitments for purchase of materials and equipment in connection with that program.
Nuclear-Related Matters. Deconunissioning Trust. Under accounting procedures approved by the PSC, the Company has been collecting in its electric rates amounts for the eventual decommissioning of its Ginna Plant and for its 14% share of the decommissioning of Nine Mile Two. The operating licenses for these plants expire in 2009 and 2026. respectively. The Company has collected approximately $61.2 million through December 31,1993. The Nuclear Regulatory Commission (NRC) requires reactor licensees to submit funding plans that estabbsh minimum external funding levels for reactor decommissioning. The Company's plan consists principally of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990, the Company has contributed some $36.9 million to this fund. In addition, the Company maintains an internal reserve to fund the rernoval of non-radioactive strue-tures, a feature not coscred by the NRC minimum funding. In connection with the Company's rate settlement completed in August 1993, the PSC approved the collection during the rate year ending June 30.1994 of an aggregate $8.9 million for decommission-ing, covering both nuclear units. The amount allowed in rates is based on estimated ultimate decom-missioning costs of $150.7 million for Ginna and $34.3 million for the Company's 14% share of Nine Mile Tw o (January 1993 dollars). This estimate is based principally on the application of a NRC formula to determine minimum funding. Site-specilie studies of the anticipated costs of actual decommissioning are required to be submitted to the NRC at least live years prior to the expiration of the license. The Company intends to fund the external decommissioning trust in the amount of the NRC minimum funding requirement. The dilTerence between the amount to be collected and the NRC minimum will be held in an internal reserve. The Company is aware of recent NRC actisities related to upward revisions to the required minimum funding levels. These activi. ties, primarily focused on disposition of low level 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. Uranium Enrichment Decontamination and Decommissioning Fund. Nuclear reactor licensees in the U.S. are assessed annually for the decontamination and decommissioning of Department of Energy (DOE) enrichment facilities. The Company made the first of 15 annual payments for this purpose in September 1993, remitting approximately $1.6 million ($1.5 million for the Ginna Plant and $0.1 million for its share of the Nine Mile Tw o plant). For the two facilities the Company , recognized liabilities at December 31.1993 of $23.4 million ($21.7 million as a long-term liability ) and $1.7 million as a current liability). In October 1993, the Company began recovery of this deferral through its fuel adjustment clause. ! Insurance Program. The Price-Anderson Act establishes a federal program, providing indemnifi- ! cation and insurance against public liability, applicable in the event of a nuclear accident at a licensed I U.S. reactor. As a result of amendments to the Act in 1988, the limit of liability has increased to i approximately $9.4 billion. Also in 1988 coverage was expanded to include precautionary evacua-tions and the Act was extended until the year 2002. Under the program, claims would first be met by insurance w hich licensees are required to carry in the maximum amount available (currently l
$200 million). If claims exceed that amount, licensees are subject to a retrospective assessment up !
to $75.5 million per licensed facility for each nuclear incident, payable at a rate not to exceed !
$10 million per year. Those assessments are subject to periodic inflation-indexing and to a 59 sur-charge if funds prove insufficient to pay claims. In addition, the retrospective assessments would be subject to a three percent charge for premium tax. The Company's interests in two nuclear units could thus expose it to a potential liab:lity for each accident of $86.! million through retrospective assess- l ments of $11.4 million per year in the event of a sulliciently serious nuc! car accident at its own or another U.S. commercial nuclear reactor. i Beginning in 1988. coverage for claims alleging radiation? induced injuries to some workers at nuclear reactor sites was removed from the nuclear liability insurance policies purchased by the 4g am c.~,m,w -
l l Company. Coverage for workers first engaged in nuclear-related employment at a nuclear site prior l to 1988 continues to be provided under then-existing nuclear liability insurance policies. Those ' workers first employed at a nuclear facility in 1988 or later 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 53.1 million over the life of the insurance coverage. The Company is a member of Nuclear Electric Insurance Limited, which provides insurance coverage for the cost of replacement power during certain prolonged accidental outages of nuclear generating units and coverage for propeny losses in excess of $500 million at nuclear generating units. As of December 31,1993, the Company is purchasing a weekly indemnity limit of
$3.5 million in the NEIL I replacement power expense program and full policy limits of $1.4 billion in the NEIL 11 Property Insurance Program for the Ginna Nuclear Power Plant. Coverage under the ,
Propeny lasurance Program includes the shortfall in the NRC required external trust fund resulting i from the premature decommissioning of a nuclear power plant following an accident with property damage in excess of $500 million. The Company currently has designated $166 million as a sublimit for this coverage at the Ginna Nuclear Power Plant. For its share in the generation of Nine Mile Two the Company purchases a weekly indemnity limit of $.5 million in the NEIL I replacement power expense program. The owners at Nine Mile Two purchase the full policy limit of
$1.4 billion in the NEIL 11 Property Insurance Program and the Company pays its proportionate share of those premiums. The owners at Nine Mile Two have selected the maximum available sublimit of $250 million for premature decommissioning. If an insuring program's losses exceeded its other resources available to pay claims, the Company could be subject to maximum assessments in any one policy year of approximately $4.9 million and $14.9 million in the event of losses under the replacement power and property damage coverages, respectively.
EnvironmentalMatters. The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. In recognition of the Company's responsibility to preserve the quality of the air, water, and land it shares with the community it serves, the Company has taken a variety of measures (e.g., self-auditing, recycling and wasic minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental efTects from its energy operations and, specifically, to manage and appropriately dispose of wastes cunently 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 of such wastes. In such instances, the Company typically seeks to cooperate with those authorities and with other site users to develop cleanup programs and to fairly allocate the associated costs. As part of its commitment to environmental excellence, the Company is conducting proactive Site Investigation and Remediation (SIR) efforts at Company-owned sites where past waste handling and disposal may have occurred. The Company currendy estimates the total costs it could incur for SIR activities at Company-owned sites to be about $20 million. This estimate will vary as better site information is available. The Company anticipates spending $10 million over the next 5 years on SIR initiatives. Approximately $4.5 million has been provided for in rates through June 1996 for recovery of SIR costs. To the extent actual expenditures differ from this amount, they will be deferred for future disposition and recovery as authorized by the PSC. In 1985, the New York State Department of Environmental Conservation (NYSDEC) identified property in the vicinity of the Lower Falls of the Genesee River (the Lower Falls)in Rochester as an inactive hazardous waste disposal site. The Company owns, and was the prior owner or operator of, a number of locations within the Lower Falls. In mid-1991, NYSDEC advised the Company that it had delisted the Lower Falls site, i.e., removed it from its Registry of Inactive Hazardous Waste Disposal Sites. The effect of delisting is to terminate the Company's status as a potentially responsible pany for the Lower Falls site, to discontinue the pending NYSDEC review of a joint Company / City of Rochester proposal for a limited funher investigation of the Lower Falls, to defer the prospect of remedial action and perhaps to end any Company sharing of the cost thereof. However, NYSDEC also stated its intention to consider listing individual coal gasification sites within the larger, original site once the State of New York adopts new federal hazardous waste (Note 10 continued on page 30) %, - c.- 49
nonnnuespom criteria. There is at least some material at one of the individual coal gasification sites that could paxe 4W trigger relisting. The Company is unable to predict what further listing action NYSDEC may take, but regards the delisting as a positive development. The Company and its predecessors fonnerly owned and operated coal gasification facilities within j the Lower Falls. In September 1991 the Company initiated a study of subsurface conditions in the t vicinity of retired facilities at its West Station property and has since commenced the removal of J soils containing hazardous substances in order to minimize any potential long-tenn exposure risks. 1 Cleanup efforts have been temporarily suspended while the Company investigates more cost effective remedial technologies. Activities are expected to resume within a year. On a portion of the Company's property in the Lower Falls, and elsewhere in the general area, the , I County of Monroe has installed and operates sewer lines. During sewer installation, the County constructed over Company property, pursuant to an casement which the Company granted the County, certain retention ponds which reportedly received from the sewer construction area certain fossil-fuel-based materials ("the materials") found there. In July 1989 the Company received a letter from the County asserting that activities of the Company left the County unable to etreet a regulatorily-approved closure of the retention pond area. The County's let,ter 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 of discussions over this matter, the County has claimed, without o!Tering any evidence, that the Company was the original generator of the materials. It assens that it will hold the Company liable for all County costs-presently estimated at $1.5 million-associated both with the materials' excavation, treatment and disposal and with effecting a regulatorily-approved closure of the retention pond area. The Company could incur costs as yet undetermined if it were to be found , liable for such closure and materials handling, although provisions of the casement afford the Company rights which may serve to offset all or a portion of any such County claim. To date, the Company has agreed to pay a 20% share of the County's investigation of this area, which commenced in September 1993 and w hich is estimated to cost no more than $150,000, but no commitment has been made toward any remedial measures which may be recommended by the investigation. In the letter announcing the delisting of the Lower Falb site, NYSDEC indicated an intention to pursue appropriate closure of the County's former retendon poed srea, suggesting that it will be evaluated separately to determine whether it meets the criteria of a hazardous waste site. The Company is unable to assess what implications the NYSDEC letter may have for the County's claim against it. At another location along the River where the Company owns property, a boting taken in Fall 1988 for a sewer system project showed a layer containing a black viscous material. The Company undertook an investigation to determine the extent of the layer. The study found that some of the soil and ground water on-site had been adversely impacted by the hazardous substence constituents of the black viscous material, but evidence was inadequate to detennine 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 in the nearly three and one-half years since the report's submittal. In August 1990 the Company was notified of the 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 list of approximately 25 potentially responsible panies I (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, utilizing a two-tier structure, EPA's cost of a contractor-perfonned removal action intended to stabilize the site. The Company, in the lower tier of PRPs, paid its
$27,500 share of such cost. The NYSDEC has not yet made an assessment for certain response and im estigation costs it has incurred at the site, nor is there as yet any infonnation on which to base an estimate of the cost to design and conduct at the site any remedial measures which federal or state authorities may require.
50
On May 21,1993, the Company was notified by NYSDEC that it was considered a potentially responsible party (PRP) for the Frontier Chemical Pendleton Superfund Site hicated in Pendleton, NY. The Company has signed a PRP Agreement with approximately 15 parties and is participating in negotiations for an Administrative Order on Consent with NYSDEC. The PRPs have negotiated a workplan for site remediation and have retained a consulting finn to implement the workplan. Preliminary estimates indicate site remediation will be between $6 and $8 million. The Company is participating with the group to allocate costs among the PRPs. An allocation scheme has yet to be developed. Monitoring wells installed at another Company facility in 1989 revealed that an undetermined amount of leaded gasoline had reached the groundwater. The Company has continued to monitor free product levels in the w ells, and has begun a modest free product recovery project. reports on both of which are routinely furnished to the NYSDEC. Free product levels in the wells have declined, but authorities may requite further remediation once most of the free product has been recovered. The Company is developing strategies responsive to the Federal Clean Air Act Amendments of 1990 ( Amendments). The Amendments will primarily alfeet air emissions from the Company's fossil-fueled electric generating facilities. The Company is in the process of identifying the optimum mix of control measures that will allow the fossil fuel based portion of the generation system to fully comply with applicable regulatory requirements. Although work is continuing, not all compliance control measures have been determined. The Company has adopted control measures for nitrogen oxides (NOx) emissions w hich must be in effect by the federally mandated compliance date of May 31,1995. The chasen NOx control measures consist of the installation of low NOx burners on some units, the derating of unit generation by taking burners out of service on other units and placing one unit on cold standby with the redistribution of load to the remaining more eflicient units. Capital costs for NOx controls and the installation of continuous emission monitoring systems are not expected to exceed $6.8 million and will be incurred during 1994 and l_995. A range of capital costs between $20 million and $30 million t 1993 dollars) has been estimated for the implementation of several potential scenarios which would enable the Company to meet the foreseeable future NOx and sulphur dioxide requirements of the Amendments. These capital costs would be ircurred between 1996 and 2000. The Company currently estimates that it could also incur up to $2 million (1993 dollars) of additional annual operating expenses, excluding fuel, to comply with the Amendments. The use of scrubbing equipment is not presently being considered. L.ikewise, the purchase or sale of" emission allowances " as allowed by the Amendments,is not currently being considered. The Company anticipates that the costs incurred to comply with the Amendments will be recoserable through rates based on previous rate recovery of environmental costs required by governmental authorities. Gas Cost Recovery, Many interstate gas pipeline companies entered into contracts with gas producers which required the pipeline companies to pay for a minimum amount of gas whether or not the gas is actually taken from the producer (take-or-pay costs). Pursuant to FERC authorization, the Company's gas suppliers have included certain amounts of their take-or-pay costs in the rates charged to the Company. The PSC instituted a proceeding in October 1988 to determine the extent to which the gas distri-bution companies in New York State would be permitted to recover in rates the take-or-pay costs imposed upon them. Through a series of subsequent settlements between the StafT of the PSC and the Company, the Company was permitted to recover in rates 87.5(7c of the first $12 million of the pipeline take-or pay costs imposed upon it and all such costs in excess thereof except for a maximum of $562,500. As of December 31.1993 the Company had been billed for $17.6 million of take-or-pay costs and has thus far recovered 516.4 million from its customers. The Company expects only insignificant amounts of take-or-pay costs remain to be billed to the Company. As a result of the restructuring of the gas transportation industry by the FERC, there will be a number of changes in this aspect of the Company's business over the next several years. These changes, which will apply throughout the industry, will affect different companies differently and I may result, at least initially, in increases in the gas transponation costs of the Company. The Company will also be required to pay a share of cenain transitiori costs incurred by the pipelines as a result of the FERC restructuring. Although the final amounts of such transition costs are subject to continuing negotiations with several pipelines and ongoing pipeline filings requiring FERC l (Note 10 anntmurd on page 52) ne%mw e- 51
l l puum sfmm approval, the Company expects such costs to range between $43.5 and $52.0 million. A substantial wm portion of such costs will be on the CNG Transmission Corporation (CNG) system of which approd imately $27 million was billed to the Company on December 3,1993 payable over the following three years. The Company expects these transition costs to be recoverable in its rates, in a related matter,in connection with the development of the Empire State Pipeline (" Empire"), ; the Company is committed as of November 1993, to transportation capacity from Empire, to upstream pipeline transportation and storage service and to the purchase of natural gas in quantities corresponding to these transportation and storage arrangements. The Company also has certain con-tractual obligations with CNG whereby the Company is subject to demand charges for transporta-tion capacity for a period of eight years. In October 1993, the etTective date ofimplementation of pipeline restructuring pursuant to FERC Order No. 636 and CNG's individual restructuring in Docket No. RS92-14, CNG's transportation rights on upstream pipelines w ere assigned to its cus-tomers, including the Company. The Company has concluded the corresponding contracts with those upstream pipelines. The transportation service to be provided by Empire was scheduled to phase in over 12 months, at which point the combined CNG and Empire transportation capacity would have exceeded the Company's current requirements. Therefore, the Company recently entered into a marketing agreement with CNG, pursuant to which CNG will assist the Company in obtaining permanent replacement customers for the transportation capacity the Company will not require, it may renegotiate its arrangements with CNG and/or Empire or it may negotiate assignment on a permanent or temporary basis, of the transportation capacity that exceeds the requirements ofits customers. In addition, under FERC rules, the Company may sell its excess transportation capacity in the market. While CNG has already secured letters of intent for a substantial portion of such capacity, whether and to what extent CNG and/or the Company can successfully negotiate the l assignment or sale of the excess capacity, or at w hat price, cannot be determined at the present time.
- The retention of some or aH of this excess transportation capacity may cause an increase in the l Company's gas supply costs. This would be in addition to any increase caused by other aspects of the gas transportation restructuring.
Gas Purchase Undercharges. The Company became aware during 1993 that it did not account properly for certain gas purchases for the period August 1994 August 1992 resulting in undercharges to gas customers of approximately $7.5 million. The Company had previously estimated the elTect to approximate as much as $10 million; however, further review determined that the magnitude of the error on previously reported operations was substantially less. The undercharges arose from the increased complexity arising from the federal deregulation of l .he gas industry and the Company's transition from a full requirements customer of one gas supplier to the purchase of gas transportation service and natural gas on the open market. Problems of this type are routinely corrected through the Gas Adjustment Clause process and appropriate amounts are collected from or refunded to customers. Of the total undercharges, $2.3 million has previously i been expensed and $5.2 million had been deferred on the Company's balance sheet. l The Company advised the PSC and all parties to the Company's most recent rate proceeding of the undercharges. In its August 24,1993 Order approving the Company's three-year rate settlement the PSC made the Company's current gas rates temporary solely to consider the impacts of the- erro-neous gas accounting, and in a September 13,1993 Order the PSC instituted a proceeding to investi-gate the resuhing undercollections and the recoverability of such amounts from customers. In its September 13 Order the PSC directed the Company to demonstrate fully the existence and amount of the undercharges, to explain the reasons for the errors, and to address possible general and specific legal limitations on the Company's right to iecover portions of the undercharges. The Company filed evidence and analysis responsive to that Order on October 27,1993. On December 30,1993, a proposed settlement among the Company, PSC Staff and another party was filed with the PSC. It provides for the recovery in rates of $3.2 million over three years, subject to audit and to limitations on rate adjustments established in the August 24 Order. The Company wrote off the $2.0 million balance of the undercharges as of December 31,1993. That write-olT amounts to a reduction in 1993 earnings of four cents per share, net of tax. Although no party, to the Company's knowledge, opposes the proposed settlement, the Company is unable to predict whether the PSC will approve it. M 52 " " * -
~
Other Matters, ' Regulatory Disallowances. In June 1992 the Company recorded a charge to earnings of
$8.2 million in connection with ice stonn restoration costs disallowed by the PSC. In December 1991, the Company recorded a non-cash charge against earnings of $10 million for refunds to be made to customers in connection with a PSC fuel procurement audit.
Nuclear FuelEnrichment Services. The Company has a contract with the United States Enrichment Corporation (USEC), formerly with the DOE, for nuclear fuel enrichment services which assures provision of 700/c of the Ginna Nuclear Plant's requirements throughout its service life or 30 years, whichever is less. No payment obligation accrues unless such enrichment seri !ces are needed. Annually, the Company is permitted to decline USEC-furnished enrichment for a future year upon giving ten years' notice. 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' notice for 2003. The Company has secured the remaining 30% of its Ginna requirements for the reload years 1994 through 1995 under different arrangements with USEC. The Company plans to meet its enrichment requirements for years beyond those already committed by making funher arrangements with USEC or by contracting with third parties. The cost of USEC enrichment services utilized for the next seven reload years (priced at the most current rate) ranges from $4 million to $7 million per year. Assertion of Tax 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 of approximately $29 million. The adjustments at issue generally pertain to the characterization and treatment of events and relationships at the Nine Mile Two project and to the appropriate tax treatment of investments made and expenses incurred at the project by the Company and the other co-tenants. A principal issue appears to be the year in which the plant was placed in service. The Company has tiled a protest of the IRS adjustments to its 1987-88 tax liability and has had an initial hearing before the appeals officers. The Company believes it has sound bases for its protest, , but cannot predict the outcome thereof. Generally, the Company would expect to receive rate relief to the extent it was unsuccessful in its protest except for that part of the IRS assessment stemming from the Nine Mile Two disallowed costs, although no such assurance can be given. Report ofIndependent Accountants 1900 Chase Square
/'riec flille/Yttittse h Rochester, New York 146( 4 1984 January 14,1994 To the Shareholders and Board of Directors of l Rochester Gas and Electric Corporation i
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements i of income. retained earnings and cash flows present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation and its subsidiaries at December 31,1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31,1993 in confonnity with generally accepted accounting principles. These finan- i cial statements are the responsibility of the Company's management; our responsibility is to express j an opinion on these financial statements based on our audits. We conducted our audits of these state- ) ments in accordance with generally accepted auditing standards which require that we plan and l perform the audit to obtain reasonable assurance about whether the financial statements are free of tnaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and ; significant estimates made by management, and evaluating the overall financial statement presenta-tion. We believe that our audits provide a reasonable basis for the opinion expressed above. ! As discussed in Note 1 to the financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No.109," Accounting for Income Taxes"in 1993. f stx.x YN "' u .-. - - c ,.- 53
Report of Manageriiciit The management of Rochester Gas and Electric Corporation has prepared and is responsible for the financial statements and related financialinformation contained in this Annual Report. Management uses its best judgements and estimates to ensum that the financial statements reflect fairly the financial position, results of operations and cash flows of the Company in accordance with generally accepted accounting principles. Management maintains a system of internal accounting controls over the preparation ofits financial statements designed to provide reasonable assurance as to the integrity and reliability of the financial records. , This system of internal control includes documented policies and guidelines and periodic evalua-tion and testing by the internal audit department. The Company's financial statements have been examined by Price Waterhouse, independent accountants, in accordance with generally accepted auditing standards. Their examination includes a review of the Company's system ofinternal accounting control and such tests and other procedures necessary to express an opinion as to whether the Company's financial statements are presented f airly in all material respects in conformity with generally accepted accounting principles. The report of Price Waterhouse is presented on page 53. 4 l The Audit Committee of the Board of Directors is responsible for reviewing and monitoring the Company's financial reporting and accounting practices. The Audit Committee meets regularly with i management and the independent accountants to review auditing, internal control and financial reporting matters. The independent accountants have direct access to the Audit Committee, without management present, to discuss the resuhs of their examinations and their opinions on the adequacy of internal accounting controls and the quality of financial reporting. Management believes that. at December 31.1993, the Company maintained an elTective system of internal control over the preparation of its published financial statements. aW l$kr- ~ WTM Roger W. Kober Thomas S. Richards Chairraan of the 11oard. President and Chief Executise Officer Semor Vice President. Finance and General Counsel January 22,1994 Illteriin Fiiiaricial Data In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the availability of surplus electricity. (Thousands of Do!!ars) Earnings per Operating Operating Net Earnings on Common Share Quarter Ended Revenues income income Common Stock (in dollars) December 31.1993* $256.219 $43,756 $22,366 $20,541 $.55 September 30,1993" 217,278 38,058 20,204 18.379 .51 June 30,1993 203,252 21,295 6,909 5.084 .15 Marrh 31,1993 272.275 44,124 29,084 27,259 .78 ~ December 31,1992 $244.290 $41.744 $29,146 $27,073 $.77 September 30.1992 198,341 33.006 17.507 15.435 .45 June 30,1992*** 195,154 16.460 (4.579) (6.651) (.20) March 31.1992 257,747 42,735 28.365 26.293 .61 December 31.1991* " * $229.331 $38,578 $14.911 $12.467 $ .38 Septernber 30.199l 195.629 31.752 17,262 15.756 .49 June 30.1991 182,637 17.230 1,538 32 - March 3 t,1991 245.673 37,198 24.286 22.780 .72 -
*lndudes recogrution of $1.9 milhon net-of-tax pension plan curtailment.
** Includes recognition of 53.4 million net-of-tax pension plan curtailment.
'* Includes recognition of $5.4 million net-of-tax ice stonn disallowance.
"*
- Includes recognition of $6 6 million net-of-tax fuels audit disallowance.
54 "***""~ m-
Common Stock and Dividends Earnings / Dividends 1993 1992 1991 Sharrs/ Shareholders 1993 1992 1991 i Earnings per weighted Number of shares ((KX)'s) I ascrape share $2.00 $1.86 $1.60 Weighted average 35,599 33.258 31,794 i Dividends paid Actual number at per share $1.72 $1.68 $1.62 December 31 36,911 34,797 32,101 Number of shareholders at December 31 38,102 39.017 39.157 Tax Status of Cash Olvidends Cash dividends paid in 1993,1992 and 1991 were 100 percent taxable for Federal income tax purposes. OlvidendPolicy The Company has paid cash dividends quarterly on its Conunon Stock without interruption since it became publicly held in 1949. The level of future cash dividend payments will be dependent upon the Company's future earnings, its financial requirements and other factors. The Company's Certificate of incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company. Quarterly dividends on Common Stock are generally paid on the twenty-fifth day of January, April, July and October. In January 1994, the Company paid a cash dividend of 5.44 per share on its Common Stock, up $.01 from the prior quanctly dividend payment of $.43. The January 1994 dividend payment is equivalent to $1.76 on an annual basis. ' Common Stock Trading Shares of the Company's Common Stock are traded on the New York Stock Exchange under the symbol "RGS" 1993 1992 1991 Common Stock-Price Range liigh 1st quarter 28 % 23 % 20 % 2nd quarter 28 24 20 % 3rd quarter 29 % 24 % 20 % 4th quarter 29 % 25 % 23 % 1mw ist quarter 24 % 20 % 17% 2nd quarter 25 % 21 % 19 3rd quarter 27% 22 % 19 4th quarter 24 % 23 % 20 % At December 31 26 % 24 % 23 % , _ ,_,,,, . ~ 55 mas
Selecte<l Financial Data (Thousands of Dollars) Year inded Decerntier 31 1993 1992 1991 1990 1989 1988 Consolidated Summary of Operations Operating Rerenues Electric $C38,955 $608 A $588,930 $551,930 $543,096 $514,637 Gas 293,708 261,724 235,728 236,496 264,573 231,217 932,663 869,991 824,658 788,426 807,669 745,854 Electric sales to other utihties 16,361 25,541 _28,612 42,465 38,028 29,966 Total Operating Revenues 949,024 895,532 853,270 830.891 845.697 775.820 Operating Expenses Fuel Expenses Electric fuels 45,871 48,d6 65.105 76,420 75,873 65,787 Purchased electricity 31,563 29,706 27,683 34,264 39,645 30.299 Gas purchased for resale 166,884 141.291 129.779 132,512 152.623 129,596 Tota 1 Fuel Expenses 244.318 219,373 222,567 243,196 268,141 225,682 Operating Rerenues less Fuel Expenses 704,706 676,159 630,703 587,695 577,556 550,138 Other Operating Expenses Operations excluding fuel expenses 235,381 226.624 208,440 194,594 173,764 159,689 Maintenance 61,693 62,720 65,415 62,391 64,316 52,575 Depreciation and Amortir.ation 84,177 85,028 84,181 77,767 75,063 69,703 Taxes--local, state and other 126,892 124,252 113,649 101,035 95.341 88,635 Federal income tax-current 33,453 36,i01 28,766 20,661 20,509 20,363
-defeired 15,877 7,490 5 493 13.829 17,330 20,299 lotal Other Operating Expenses 557,473 542.215 505,944 470.277 446.323 411,264 Operating Income 147,233 133.944 124,759 117,418 131,233 138.874 Other income and Deductions Allowance for other funds used during construction 153 164 675 2,689 2,261 2,047 Federal income tax 9,827 4,195 4.580 2,459 1,439 1,683 Pension plan curtailment (8,179) -- - - - -
Regulatory disallowances (1,953) (8,215) (10,000) - (2,100) - Other, net (7,074) 6.155 6,078 4,062 8,328 6,901 Total Other income and (Deductions) (?,226) 2,299 1,333 9,210 9,928 10.631 Income IInfore Interest Charges 140,007 136,243 126,092 126,628 141,161 149.505 Interest Charges 1.nng term debt 56,451 60,810 ba,i,;3 64,873 68,628 72,270 Short term debt 1,487 1,950 2,623 1,070 - - Other, net 5,220 5,228 4,459 3,523 3,115 2.898 Allowance for borrowed funds uwd during construction (1,714) (2,184) (2,905) (2,719) (2,026) (1,777) Total Interest Charges 61,444 65,804 68.095 66,747 69,717 73,391 Net Income 78,563 70,439 57,997 59.881 71.444 76,114 Dividends on Preferred Stock, at Required Rates 7,300 8,290 6,963 6,025 6,025 7,348 Earnings Applicable to Common StocA $ 71,263 $ 62,149 $ 51,034 $ 53,856 $ 65,419 $ 68,766 M' righted Average Number of Shares Outstanding in Each Period ((XX)'s) 35,599 33.258 31,794 31,293 31,090 30,513 Earnines per Commun Share $2.00 $1.86 $1.60 $1.72 $2.10 $2.25 Cash Dividends Paid per Common Share $1.72 $1.68 $1.62 $1.56 $1.50 $1.50 56
Condensed Consolidated Balance Sheet (Thousands of Dollars) At December 31 1993 1992 1991 1990 1989 1988 Assets Utility I'lant $2,89R799 $2.798,581 $2,706.554 $2,310.294 $2.208,158 $2,122,922 Less: Accumulated depreciation and amortization' 1,335,08J 1.253.117 1,178.649 812.994 730.621 653.876 1,555,716 1,545,464 1.527,905 1,497;300 1,477.537 1,469,046 Construction work in progress 112,750 83.834 76.848 82,663 68.784 41.044 Net utility plant 1,668,466 1,629,298 1,604,753 1,579.963 1,546,321 1,510.090 Current Assets 248,589 209.621 189.009 176,045 190,321 213,626 Investment in Empire 38,560 9.846 - - - - Deferred Debits 502,015 200.676 160,034 108.451 102.729 102,015 Total Assets $2,457,630 $2.049.441 $1.953.796 $1.864.439 $1.839.371 $1.825.731 Capitalization andHabilities Capitali:ation Long term debt $ 747,631 $ 658,880 $ 672,322 $ 721,612 $ 764.627 $ 792.976 Preferred uock redeemab!e at option of Company 67,000 67,000 67,000 67.000 67.000 67.000 Preferred stock subject to mandatory redemption 42,000 54.000 60.000 30,000 30,000 30.000 Common shareholders' equity Common stock 652,172 591,532 529.339 516,388 513.560 504,907 Retained earnings 75,126 66.968 61.515 62.542 57,983 39.710 Total conunon shareholders' equity 727,298 658.500 590.854 578.930 571.543 544,617 Total Capitalization 1,583,929 1.438.380 1.390.176 1.397,542 1,433,170 1,434.593 limg Term Liabilities fDepartment ofEnergyJ 89,804 94 602 63.626 59.989 55,502 51,016 Current I.iabilities 234,530 267,276 267.601 183,720 137,899 126.661 Deferred Credits and Other Liabilities 549,367 249.183 232.393 223.208 212,800 213,461 Total Capitalization and Liabihties $2,457,630 $2.049.441 $1.953.796 $U64.459 $1,839.371 $1.825.731 Financial Data At December 31 1993 1992 9 91 1990 1989 +JS8 Capitali:ation Ratios (a)(percent) Long term debt 49.4 o2 50 6 53.6 55.1 56.8 Preferred stock 6.6 8.0 8.7 67 6.5 6.5 Common shareholders' equity 44.0 43.8 40.7 39.7 38.4 36 7 Total 100.0 100 0 100.0 100.0 100 0 100.0 I Rool Falue per Common Share-Frar End $19.70 $18.92 $18,41 $18 42 $18.28 $17.69 I Rate ofReturn on Average Common riquity (percent) 10.25 9.98 8 60 9.29 11.56(b) 12.68 Embedded Cost of Senior Capital (percent ) Long term debt 7.36 7 91 8.32 8.59 8.74 8.71 Preferred stock 6.69 6.98 6.97 6 72 6.72 6.72 Effectne federalineame Tax Rate (percent) 33.5 35.9 33 9 34.8 33.8 33.9 Depicciation Rate (percent)-Electric 2.62 2.69 3.05 3.33 3.25 3.56
-Cas 2.60 2.78 2.94 2.94 2.96 2.96 Interest Coveragestb)(e)
Before federal income taxes (incid. AFUDC) 3.03 2.74 2.38 2.32 2.53 2.53 (excid. AFUDC) 3.00 2.70 2.33 2.25 2.47 2.48 After federal income taxes (incld. AFUDC) 2.35 2.12 1.91 1.86 2.02 2.01 (excid. AFUDC) 2.32 2.08 1.86 1.78 1.96 1.96 (aif acludes Company's long term liabihty to the Department of Energy (LX)E) for nuclear w aste disposal. Excludes IX)E long term liabihty for l uranium ennchment deconunissionir.g and amounts due or redeemable within one year. I tbifhcludes disallowed Nine Mile Two plant etwts written of f in 1989. 1 (c)The recognition by the Company in 1991 of a fucl procurement audit approsed by the New York State Pubhc Service Commission (PSC) has been enladed from 1991 coverag+s. Likewise. rxognaion by the Company in 1992 of disallowed ice storm costs as appros ed by the PSC has been excluded from 1992 coserages. Cmerages for 1993 cxclude the effects of retirement enhancement programs recogni7ed by the Company during the year and certain gas purchase undercharges written off in December 1993. mm .,m,a '
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57
Electric Department Statistics Year Ended December 31 1993 1992 1991 1990 1989 1988 Electric Revenue ((KMTs) . Residential $235.286 $220,866 $212,327 $197,612 $191,732 $188,451 Commercial 196,456 184,815 181,561 165,445 155,076 149,663 Industrial 147,396 142,392 141.001 130.012 124,634 120,490 Other fincludes Unbilled Revenue) 59,817 60,194 54,041 58,861 71,654 56.033 Electric revenue from our customers 638,955 608.267 588.930 5S1,930 543,096 514,637 Other electric utilities 16,361 25,541 28,612 42,465 38.028 29 966 Total electric resenue 655,316 633.808 617,542 594,395 581.124 544.603 Electric Expense (fKKYs) Fuel used in electric generation 45,871 48.376 65,105 76,420 75,873 65,787 Purchased electricity 31,563 29,706 27,683 34,264 39,645 30,299 Other operation 188,684 183,118 168,610 155,289 137,458 124,871 Maintenance 52,464 53,714 57,032 53,880 55,915 44,060 Depreciation and Amortization 72,326 73,213 72,746 67,302 65.287 60,444 Taxes-local, state and other 96,043 94.641 86.925 77.323 71,361 _ S6,426 Total electric expense 486,951 482,968 478.101 464.478 445,539 391,887 Operating income before Federallncome Tax 168.365 150,840 139,441 129,917 135,585 152,716 Federal income tax 43,845 38.046 31,390 30.670 29.887 34.093 i Operating incomefrom Electric Operations ((XHrs) $124,520 $112,794 $108.051 $ 99.247 $105,698 $118,623 Electric Operating Ratio % 48.6 49 7 51.6 53.8 53.2 8 48.7 Electric Sales-Killi KXMTs) Residential 2,124,763 2.084,466 2,085A29 2,075,072 2,072,047 2,051,808 Cotnmercial 1,987,490 1,937,950 1,928,730 1,897,583 1,832,521 1,792,162 Industrial 1,894,026 1,929.498 1,917,796 1,931,633 1,906,429 1,869,417 Other 505,341 503.330 , 507,765 490,077 491.905 483,730 Total billed 6,511,620 6,455,244 6,439,720 6,394,365 6,302,902 6,197,117 Unbilled sales (4,556) 742 7,657 (25.421) 33,406 - Total customer sales 6,507,064 6,455,986 6.447,377 6.368,944 6,336,308 6,197,117 Other electrie utilities 743.588 1,062.738 1.034,370 1,316.379- 1,255,282 1,149,900 Total electric sales 7,250,652 7,518.724 7,481,747 7,685,323 7,591,590 7,347,017 Electric Customers at December 31 Residential 302,219 300,344 298A40 296,110 293,418 290,037 Commercial 29,635 29,339 28,856 28,804 28,386 27,888 Industrial 1,382 1,386 1,388 1,428 1,422 1,392 Other 2,638 2.605 2.558 2,553 2,512 2,326 Total electric customers 335,874 333.674 331.242 328.895 325,738 321,643 Electricity Generatedand Purchased-K1111 (w KTs) Fossil 1,520,936 2,197,757 2,146.664 2,505,110 2,578,006 2,214,588 Nuclear 4,495,457 4,191,035 4,391,480 4,016,721 3,659,185 3.884,884 ilvdro 199,239 278.318 174.239 244,539 175,085 169,002 Pumped storage 233,477 226,391 240,206 269,966 290,582 292,305 Less energy for pumping (355,725) (344,245) (364,520) (405,966) (429,895) (430,401) Other 2,559 811 1,269 20.408 54.893 2,195 Total generated-Net 6,095,943 6,550,067 6,589,338 6.650,778 6,327.856 6,132,573 Purchased 1,583,582 1,389.875 1,451,208 1,498.089 1Z57.413 1,705,755 Total electric energy 7.679,525 7,939.942 8,040,546 8,148,867 8.085,269 7,838.328 System Net Capability-KW at December 31 Fossil 541,000 541,000 541,000 541,000 541,000 541,000 Nuclear 620,000 617,000 622,000 621,000 621,000 621,000 Ilydro 47,000 47,000 47,000 . 47,000 47,000 47,000 Other 29,000 29,000 29.000 29,000 29,000 29,000 Purchased 347,000 348,000 354.000 356,000 369,000 360,000 Total splem net capability 1,584,000 1.582,000 1,593,000 1,594,000 1.607.000 1,598,000 Net Peak lead-KW 1,333,000 1,252,000 1,297,000 1,208,000 1,249,000 1.275,000 Annualload Factor-Net 9 59.1 62.5 61,7 64.6 62.4 59.7 58
Gas Department Statistics ! Year Ended December 31 53 1992 1991 1990 1989 1988 Gas Revenue ((XXTs) Residential $ 5,526 $ 6,456 $ 6,354 $ 6,508 $ 6.770 $ 6,439 Residential spaceheating 196,411 183,405 157,458 159,501 165,832 150,383 Commercial 45,620 44,274 40,196 43,534 46,897 44,781 Industrial 6,346 6,418 6,761 9.674 9,371 9,859 Municipal and other (includes Unbilled Revenue) 39,805 21,171 24,959 17,279 35,703 19,755 Total gas revenue 293,708 261.724 235,728 236,496 264.573 231,217 Gas Expense (fXXTs) Gas purchased for resale 166,884 141,291 129,779 132,512 152,623 129,596 Other operation 46,697 43,506 39,830 39,307 36,306 34,818 Maintenance 9,229 9,006 8,383 8.510 8,401 8,515 Depreciation 11,851 11.815 11,435 10,465 9,776 9.259 Taxes-kieal, state and other 30,849 29,411 26,724 23,711 23.980 22.209 Total gas expense 265,510 235.029 216,151 214.505 231,086 204,397 Operating income before Federallncome Tax 28,198 26,695 19,577 21,991 33,487 26,820 Federal income tax 5.485 5,545 2,869 3,820 7,952 6.569 Operating incomefrom Gas Operations ((XKrs) $ 22,713 $ 21,150 $ 16,708 $ 18,171 $ 25.535 $ 20,251 Gas Operating Ratio % 75.9 74.1 75.5 76.3 74.6 74.8 Gas Sales-Therms (00(Vs) Residential 6,735 8,780 9,068 9.644 10.321 10,374 Residential spaccheating 289,252 287,614 253,655 262,458 277,267 267.697 Commercial 77,326 78,993 71,509 77,617 84,152 86,413 Industrial 11,792 12,437 13,000 18,536 17,873 20,174 Municipal 11,947 11,410 10.580 13,350 12.319 15.514 Total billed 397,052 399.234 357,812 381,605 401,932 400,172 Unbilled sales 8,017 13 3,291 (22,840) 20,320 - Total gas sales 405.069 399,247 361,103 358,765 422,252 400,172 Transportation of customer-owned gas 124,436 126,140 109,835 101,985 105,303 83,594 Total gas sold and transported 529,505 525.387 470,938 460,750 527,555 483,766 Gas Customers at December 31 Residential 18,389 19,114 21,448 22,410 23,321 24,139 Residential spaccheating 231,937 228.096 222,918 219,242 215.120 210,710 Commercial 18,636 18.378 18.151 17,920 17,677 17,213 Industrial 914 932 921 960 1,095 1,042 Municipal 1,001 1,010 983 984 1,067 1,039 Transportation 466 424 423 401 367 270 Total gas customers 271,353 267,954 264,844 261,917 258.647 254,413 ' Gas-7herm s ((XNTs) Purchased for resale 347,778 360,493 384.643 366,684 426,941 408,044 Gas from storage 76,378 53,757 16,755 - - - Other 1,039 1,061 1,617 2.525 1,764 1,967 Total gas available 425,195 415.311 403,015 369.209 428,705 410,011 l Cost of gas per therm (cents) 35.79e 35.35e 32.96c 36.03e 35.74c 31.76e i Total Daily Capacity- i 7herms at December 31* 4,485,000 4,485.000 4,485,000 4,485,000 4,485,000 4,485,000 Maximum daily throughput-Therms 3,864,850 3,768,470 3,539,260 3,539.820 3.719,050 3,744,500 Degree Days (Calendar Month) For the period 7,044 6,981 0.146 5,924 7,109 6,862 Percent colder (warmer) than nomial 4.4 3.4 (8.4) (11.8) 5.9 1.6 , 1
- Method for determining daily capacity, based on current network analyus, reficcts the maximum demand which the I transmission 9 stems can accept w ahout a deficiency. ,
l m ,, - % , u .r. " 59
< iln stoHnformati0ip .
Officers (as ofJanuary I.1994) I g
/
N Requests forInformalled . anvestors and security analysts DuplicateMallings .. Shareholders with more than one-f3- ' Roger W. Kober Chairman of the Board. President 7 seking information about the = account generally receive duplicate : and Chief Executive Officer
- Company should contact David C. - mailings of annual, and other reports, ,,
Age 60, Years of Senice,28
> lieiligman, Vice President, Secretary To climinate additional mailingsE DavidK. Laniak and Treasurer _ write to our transfer agents Enclose - Senior Vice President Gas I r label infmnadon, where - Electric Distribution and
- !"cfm!MAi.eua/ Report p>ssible. Separate dividend checks . Customer Senices Sharehohlers may obtain a copy of and 17mxy material will continue to be Age 58, Years of Service,39
' the Compnny's 1993 annual report -
wnt Mr ead account of record' Thomas S. Richards on Form 10-K. as filed with the J Securities and Exchange Commis- Stock Listings . Senior Vice President, Finance l siori, without charge, by wrhing to RG&F/s Common Stock is listed on - and General Counsel the Secretarv.' the New York Stock Exchange and is - Age 50, Years of Senice,2 identilicd by the stock symbol RGS- Robert E, Smith ShareholderServices The Preferred Stock issues are traded Senior Vice President. Shareholders with questions about n the over-the-counter market- Production and Engineering dividend payments, address changes. missing certificates, ownership Corporate Dffice Age 56. Years of Senice. 34 changes and other account informa- Rochester Gas and DavidC. Belligman tion shouki contact our transfer Electric Corp 3 ration Vice President,
. agent. 89 East Avenue Secretary and Treasurer Rochester, NY I4M94XXH Age 53. Years of Senice,30 DividendPaymentDates (716)546-2700 Robert C. Mectedy ' RG&E% Board of Directors meets Agent for Automatic Vim President, 2 cpiarterly to consider the pay ment of dividends. Dividends on Common DiridendReinrestmentand Ginna Nuclear Production Skick are normally paid on or about Stock Purchase Plan Age 48. Years of Senice,22 ' the 25th of January, April. July and The First National Bank of Boston WilfredJ. Schrouder, Jr.
October. Disidends on the. Preferred Disidend Reinvestment Unit Vice President. Stocks are payable, as declared. on Mail Smp: 45-01-06 Employee Relations. Public
- or about the 1st of March, June. P.0, Box 1681 Affairs and Materials Management September and December. Boston. M A 02105-1681 Age 52, Years of Sen ice,31
' DividendDirectDeposit
(*U'h M13H Danle!J. Baler Shareholders can elect to have their TransferAgentandRegistrar }j Assistant Controller quarterly cash dis idends electroni- The First National Bank of Boston ;j Age 47, Years of Service,10
. cally deposited into their personal Sharehokler Services Division John M. Kueber l Auditor benk accounts. Deposits are made on Mail Stop: 45-024)9 .
.the date the dividend is payable. If P.O. Bos M4 r. Age 58, Years of Senice. 29 you would like to take advantage of Boston MA 02102-0644
' this service, contact our transfer (80(b 442-2001 "E'"' L First Mortgage Bond Trustee .
00tcer&po.tInent nn DividendReinvestment Common Stock shareholders who andPayingAgent Bankers Trust Company }1 l' wish to acquire additional shares f ree Attn: Security lloider Relations '
' of brokerage commi% ions or service P.O. Box 9006 l
charges are invited tojoin RG&E's Church Street Station ' ~
- ' Automatic Dividend Reinvestment New York. NY 10249 - -
l and Stock Purchase Plan. Unden the (800)735-7777
; plan, shareholders authorize an inde- .
.I f .. '.
pendent agent to purchase shares of :. w' l ; RG&E Common Stock with their cash .
' ' ' ~
T '
-1 ' dividends. Shareholders may aho l ;, '
i participate in the plan by making ..
. 1
- optional cash payments, even if they . +
i l decide not to reinvest their dividends. .. I For further information, contact our !
.' transfer agent.
l l in October 1993. Thomas S. I Richards w as elected Senior Vice l President, Finance and General
.. o: . Counsel Mr. Richards had Priruedon recycledpapqr b) previously been General Counsel l
n of the Company.
,9 j 60 .
l l
l I$0ard O[ OirtTlors N'"**'h'r (un usul / lertos ( 'or'/nsnition (as ql Januarr 1.199-1) i 1 Williatn Balderston ill *t, M'* o' YM , Former Executise Vice President, , Q"[,$'[y'"* ' l i The Chase Manhattan Corporation rosnum a Angelo J. Chiarella t t stant u or Cosnurni osugum President and Chief fixecutise 00icer. , sinnu n ot Nosnwiw l Midtown iloidings Corp. roson Trr < l Allan E. Dugan * + Senior Vice President. Corporate Strategie Services, Xerox Corporation William F. Fowble +t Former Semor Vice President and Executise Vice President. Imaging. 1 Eastman Kodak Company Jay T. Holmes , Senior Vice President-Corporate
- Atf airs and Secretary. Class ll-Term Expiring in 1994, from left.
Bausch & l.omb Incorporated M. Richard Rose, Theodore L. Levinson, Roger W. Kober
- Arthur M. Richardson, Allan E. Dugan.
Chairman of the Board, President and Chief fixecutise Olticer. Rochester Gas and Electric Corporunon Theodore L. Levinson t Former President and w
, Chief fixecutive Otheer.
Star Supermarkets. Inc. k N.g - Constance M. Mitchell +, Former Program Director, Industrial Management Council of Rochester. New York, Inc.
; Cornelius J. Murphy *t Senior Vice President, 4 Goodrich & Sherwood Company Arthur M. Richardson * *,.
President, Richardson Capital Corporation Class ill-Term Expirina in 1995, from left. M. Richard Rose +t Cornelius J. Murphy Angelo J. Chiarella. l 1:ormer President, llarry G. Saddock, Jay T. liolmes. Rochester Institute of Technology
. Harry G. Saddock *; f Former Chainnan of the Board and Chief Executne 00icer. l Rochester Gas and Electric Corporation i
I e Class I-Term Expiring in 1996, from left. '. Roger W. Kober, William Balderston Ill. Wilham F. Fow ble. Constance M. Mitchell. J
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