ML20134B483
| ML20134B483 | |
| Person / Time | |
|---|---|
| Site: | Millstone, Haddam Neck, 05000427 File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 11/10/1993 |
| From: | Stolz J Office of Nuclear Reactor Regulation |
| To: | Miraglia F, Murley T, Russell W NRC |
| Shared Package | |
| ML20134B481 | List: |
| References | |
| FOIA-96-298 NUDOCS 9312090283 | |
| Download: ML20134B483 (79) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
- 2 WASHINoTON. o.C. 20MH001
\.....j November 10, 1993 Docket No. 50-245, 50-336 50-427, 50-213 MEMORANDUM FOR: T. Murley J. Zwolinski F. Congel F. Miraglia E. Adensam E. Butcher l W.- Russell B. Grimes W. Bateman, EDO l L. J. Callan J. Wiggins M. Slosson l D. Crutchfield B. D. Liaw Operations Center W. Travers A. Thadani R. Cooper, RGI l F. Gillespie M. Virgilio E. Merschoff, RGII l S. Varga C. Rossi E. Greenman, RGIII
! J. Calvo R. Zimmerman A. Bill Beach, RGIV l G. Lainas B. Boger K. Perkins, RGV l J. Roe C. Thomas THRU: John F. Stolz, Director Project Directorate I-4
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Division of Reactor Projects - I/II FROM: James W. Andersen, Acting Project Manager Project Directorate.I-4 Division of Reactor Projects - I/II
SUBJECT:
DAILY HIGHLIGHT - MILLSTONE NUCLEAR POWER STATION, UNITS 1, 2 AND 3, AND THE HADDAM NECK PLANT l
, NORTHEAST UTILITIES REORGANIZATION l l
On November 8,1993, the Executive Vice President-Nuclear of Northeast i Utilities (NU), John F. Opeka, announced a restructuring within the nuclear j group. All the appointments are effective as of December 5, 1993.
i Donald B. Miller. Jr. - Senior Vice President, Millstone Station. Since 1990, l he hcs been Vice President - Peach Bottom at Philadelphit Electric. Before l that, he worked for NU for almost 12 years. He replaces Steve Scace.
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l Steven E. Scace - Vice President, Nuclear, Operations Services. He replaces Wayne Romberg. John F. Opeka, Executive Vice President-Nuclear, will assume the responsibility for the Vice President, Nuclear, Operations Services position, as well as his own position, until December 5,1993.
L. A. Chatfield - Director Nuclear Safety Concerns. He replaces D. G.
Diedrick who will- become the Director of Special Projects.
I i_ Richard M. Kacich - Director Nuclear Planning, Licensing and Budgeting. He i previously was the Director Nuclear Licensing. The position of Director Nuclear Planning and Budgeting was eliminated and the functions were combined with Nuclear Licensing.
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l Multiple Addresses November 10, 1993 Eric A. DeBarba - Vice Presidant-Nuclear Engineering Services. He currently held this position, however, the Engineering Managers for all four plants now l
' report directly to him vice the specific Unit Directors. The engineering departments for all four plants have been reorganized and have new directors.
Michael B. Brown - Director Nuclear Training. He replaces Malcolm Black.
This change is effective November 8,1993.
Numerous other changes occurred below the director level as a result of the engineering integration and restructuring. The Unit Directors for each plant i did not change.
l ames W. Andersen, Acting Project Manager i Project Directorate I-4 j Division of Reactor Projects - I/II I
l cc: All NRR PDs l A. Chaffee, OEAB
! G. Zech, RPEB D. Norkin, RSIB l
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l Oct. 12, 1993 EAD-93-099 TO: Nuclear Directors and Managers FROM E. A. DeBarba
SUBJECT:
Engineering Integr'ation R
As the development of Engineering Integration has proceeded, its status !
has been communicated through various Nuclear News and TiaLine articles, and a mIno from J.F. Opeka. Now that the final phase of this project is nearing conpletion I want to share with you a summary of the' recommendations and impicnentation plans developed by the Integration Team and generally adopted by canior nuclear management earlier this week. I expect that the final version of ths' Integration Report will be completed by Oct. 15. Until the entire document is available I have attached those portions which contain many of the key clamants which should-be communicated with your employees. ,
The enclosed information describes how engineering will be restructured unasr one centralized and four unit directors. Some detail on the roles and ranponsibilities of the various engineering functions is also provided. Our objsetive is for an expeditious yet carefully planned transition to this new organization. This will begin with the selection of Directors through the use of the Nuclear Management Development Program. These new Directors will play a key role in implementing many of the approximately 80 integration recommendations over the next several months. Perhaps the most important of thsse tasks will be the selection of the most qualified candidates for new positions. The selection process which will be used is based on the model used
.throughout the corporation. Implementation plans target the naming of Directors and Managers for early November. Supervisors and other employees would be calected for the remaining positions around the end of November. The actual rsassignment and relocation of employees, however, will likely be phased throughout 1994 depending on current work commitments, outage schedules, the availability of facilities, etc.
I truly believe that successful implementation of the recommendations invaloped in this integration effort is our key-to becoming an even mo~re affsetive organization. That success will naturally depend on the full support and cooperation of you and your people. I therefore hope you will discuss the
- nclosed information with your employees. As we proceed with the implementation
-process it is my intent to fully communicate all aspects of the reorganization eith you. As additional information becomes available, including the final intsgration report, I will arrange group meetings in which they can be l' 1ssed.
- c: Nuclear Vice-Presidents E"
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l ENGINEERING INTEGRATION REPORT EXECUTIVE
SUMMARY
j This section of the engineering integration' report provides an executive summary or overview of-the project's recommendations.
Overall, the recommendations contained in this report should lead l
l to significant improvements in the effectiveness of engineering
- support to the Millstone and Haddam Neck units. Moreover,.they l should. lead to improvements in efficiency and productivity,
! supporting corporate goals to reduce costs while maintaining or l
improving current-levels of quality and safety. j L 1 The report contains about'80 recommendations to improve the I nuclear engineering function. The major changes to the
! engineering function that are recommended in the report are summarized below.
o A new position of Engineering Director should be reated at each unit. !
Addition of the Director positions will. improve accountability for engineering issues arising at the i units, and provide a higher decision-making authority i for engineering issues at each unit.
This addition will also allow the Unit Directors to focus on operations and maintenance. ~It must remain clear that the Unit Directors remain accountable and '
responsible for operationa; decisions at the units, and that the Unit Directors and Engineering Directors must-work closely together and share common goals.
o The unit engineering ano unitized Project Services organizations should be combined into one department at each unit, reporting to the new Directors Engineering for each unit.
- - Separation of design and system engineering functions should be retained at the Manager level, to foster continued control over the design basis of aach unit.
- Current levels of engineering and technical support in the Maintenance and I&C organizations should be L retained.
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Engineering roles and responsibilities should be l clarified, as described in detail in the report.
.The consolidation of currently separate organizations j under one management structure should lead to improved productivity as handoffs are reduced and people work j more closely together to solve problems. .
o The responsibilities, expertise, and size of the off-site corporate engineering organization in Berlin should be reduced, while the unit engineering organizations should be made essentially self-sufficient'for design work.
The corporate engineering organization should focus l
only on strategic issues and provision of specialized expertise such as fuels work and PRA.
l More routine support functions (such as stress
- analysis) should be transferred to the unit engineering I
organizations.
- The r* duction in size of the Corporate engineering organization will essentially be offset by increases in unit engineering staffing.
.The net impact of integration is expected to be a l reduction of approximately 100 positions - including open PVR's, contractors and possibly some NU personnel.
l o Those functions that primarily support maintenance rather l than engineering (such as construction, NDE, vibration i analysis, etc.) should be transferred out of the corporate L . engineering organization; the maintenance assessment team will determine whether to keep these functions and personnel within a centralized or unit-based organization.
- Maintenance Engineering functions (RCM, maintenance I rule) should not be transferred into engineering; these I functions will also be dispositioned by the maintenance 1 assessment team. l L l l
- Procurement Engineering should remain a part of Nuclear l
Operations Services. !
o Nuclear Safety Engineering should remain in the Quality !
j Services Department.
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The remaining engineering functions in Berlin should be o
combined.into one Department. Management and supervisory positions should be' combined to provide appropriate spans of control.
I - In addition, the management of this function should l
continue to examine nuclear engineering for additional l savings not identified as part of the engineering l integration review.
o The four. Engineering Directors of the units and the corporate Engineering Director should all report to the Vice I President of Nuclear Engineering.
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- A centralized reporting relationship will promote commonality and sharing of lessons learned across units, and allow for future sharing of resources and expertise when needed.
l o Staffing in the unit design groups should be reduced to reflect improvements in the new design change proc ss.and expected. reductions in the number of design changes.
f o Implementation of the systems engineering concept should be L
accelerated somewhat at Millstone; the proposed PEP -)
I staffing numbers for systems engineers can be reduced l somewhat at Millstone, taking into account clarification of I roles and responsibilities, and lessons learned from benchmarking and the experience to date at Connecticut Yankee.
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! o Program responsibilities should be clarified: the Corporate I organization will be responsible only for initial program development and program oversight; the unit engineering organizations will be responsible for implementation j
planning, implementation, and maintenance.
o Methods of controlling engineering work and controlling contractors should be improved, to enhance the businesslike culture of the nuclear group.
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- In addition, where appropriate, "outsourcing" of i engineering support should be considered. ]
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l Taken together, these recommendations for improvement should yield significant savings to the Nuclear Group. Savings will be derived from the elimination of some open PVRs and the ability to fill other vacancies with NU personnel, and through the l
elimination of some long-term contractors or the replacement of them with NU personnel. (Issue ER-3 provides recommendations on matching personal qualifications to positions to ensure.that we place people in the right positions and provide appropriate i training to people who need it.)
l l The next section of this report provides detailed organization I charts and a staffing summary for'The recommended organization. l The main body of the report presents the. findings and conclusions j
-for each issue, together with specific recommendations. The final l section of the report contains an implementation plan that l assigns responsibility for each recommendation and target completion dates.
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PROPOSED ENGINEhuNG ORGANIZATION V.REngineming sea. w Dic Dic Dic Dic Dic CYEngineesing MP-1 Engineesing MP-2 Engineering MP3 Enginesing Betin Engineming
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Proced.Rev.&Irpli ISIIIST Sys.fruesegatonsiTsolbleshoot ConputaStpp.(CY) EIC Coor.NornodineAcdvityonSys. DesignArshoorty OPAL .
BOPMoritoring MOV Proced. Review &Itpts CorngtsadonMdneenance SBO Specid Nucl.Matis. S)Gltsp. App.R SepolitChange Program Ck. Vdves EQ MEPL HELB DesignChangenogen.
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EMPLOYEE CONCERNS I
O THIS SUBJECT WAS ADDRESSED ON PAGE 2 OF THE NOVEMBER 3,1993 BRIEFING PACKAGE O THE ENCLOSED PAGES ARE NORTHEAST UTILITIES' PRESENTATION !
SLIDES ,
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i a f l EMPLOYEE CONCERNS l
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" ELU Nuclear Safety Concems Procram l We are mindful of the need to maintain an atmosphere conducive to i airing safety concerns. We continue to take actions to enhance that *
,i atmosphere.
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- An action plan in support of our Nuclear Goals has as its objective !
]" the fostering of a culture and work environment in which management encourages the raising and resolution of safety issues
- The action plan is to be completed in 1994 i
,i e The PEP Action Plan dealing with the Employee Concems Programs
!3 has been validated
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Validation results: each of the Action Plan's intended effects j were achieved
- Validation team recomrnendations are being irnplemented a
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- Enhanced management training has been implemented i n
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t EMPLOYEE CONCERNS (Cont.)
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- A Self-assessment of the NSCP is planned t
- The NSCP Director has been changed j -
2-year rotational position g
3 m Minimizes perception of line management link v :
l m Brings a fresh perspective to the position 1.0CFR 2.206 Petitions i
- Recent 10CFR2.206 petitions have alleged violations of 10CFR50.5 3 (Deliberate Misconduct) and 10CFR50.7 (Employee Protection) i 3 -
The public nature of allegations of wrongdoing calls for timely
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petition resolistion
- We will respond proactively to such petitions to previide the N Staff with information needed to act on the petitions a
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EMPLOYEE CONCERNS (Cont.)
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We encourage prompt Staff action, and would be pleased to further i contribute to timely resolution '
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j Suaaestions for the NRC Review Team '
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$ Share with licensees information regarding allegations brought l
e directly to the NRC. This recommendation is safety driven E !
= Reemphasize to the Department of Labor the importance the Commission places on the prompt resolution of dscrimination ;
- allegations
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- Issue clearer and more explicit guidance regarding the preferred j method of raising safety concems: Bring them to the licensees'
,e attention for resolution i i o ;
- Provide licensees with the NRC's view of the desirable aspects of ;
, employee concerns programs.
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y . NRC investigations should be limited to instances where a pervasive
- pattem of discrimination may have developed i
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1 BUDGET i
l l O THIS SUBJECT WAS NOT i ADDRESSED IN THE NOVEMBER 3, i 1993, BRIEFING PACKAGE ,
i l 0 THE FIRST EIGHT PAGES HEREIN l
,I ARE NORTHEAST UTILITIES' PRESENTATION SLIDES O THE LAST FOUR PAGES ARE FROM NORTHEAST UTILITIES' MONTHLY " MEASURES OF PERFORMANCE" DOCUMENT DATED SEPTEMBER 1993
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BUDGET DATA (Cont.)
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Assurance that approach to Seabrook budgets will be motivated by same pursuit of operational excellence that characteristics Millstone and Haddam Neck budgets j -
Commitments:
o l
u Complete Phase II of the PEP and docket results E
a Ensure that the PEP is acceptable to the NRR u
a Authorize additional of any resources necessary to
= implement the PEP 3 m Provide periodic updates on the progress of PEP 2 implernentation u
j u Keep the NRC Staff apprised of any significant changes in the O&M and capital budgets and projections for calendar
, years 1992-1995, including an explanation for any such 2 changes E
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TABLF OF CONTENTS EASA CHAPTER l. EXECUTIVE
SUMMARY
A. NQ's Integrated Resource Planning Process 1-2
- 8. Load Growth Projections 1-2 C. Existing Resources and Transmission System I-4 D. Need for Expansion of the System I-5 E. Resource Options Available for the Future 16 CHAPTER 11. ELECTRICAL ENERGY DEMAND FORECAST A. Introduction ll- 1 B. The Sales Forecast 11- 2 C. System Energy Output and Peak Load Forecast ll-2 D. Methodology 11- 5 E. Energy Peak Demand Levels 2003-2012 ll 7 CH APTER 111. CONSERVATION AND LOAD MANAGEMENT A. Introduction ill-1 B. Current Conservation and Load Management Programs 111 2 C. Twenty-Year DSM Forecast 111- 8 D. Interruptible Resources lil-8 CHAPTER IV. EXISTING AND PLANNED SUPPLY RESOURCES i
A. Introduction IV 1 B. Explanation of Tables IV-1 C. Energy Supply IV-2 D. Supply Resources for 1993 2012 IV-3 E. Long Term Planning issues IV-6 i
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CHAPTER V. EXISTING AND PLANNED TRANSMISSION FACILITIES A. Connecticut Summary V2 B. Massachusetts Summary V-4 C. New Hampshire Summary V-5 D. Planned Transmission Additions, 2003 2012 V-6 CHAPTER VI. MAPS OF SYSTEM Main Electric Systems of Connecticut MAP 1 Main Electric Systems of Northeast Utilities System in Massachusetts MAP 2 PSNH Existing Electric Transmission System MAP 3 New England Geographic Transmission Map through 2008 MAP 4 I
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LIST OF TABLES T.sh!n Enna CHAPTERI l1 Twenty-year Outlook for Energy and Peak Load 1-3 1
FIGURES 1-1 A NU's 20 Year Resource Plan (Summer) l-7 l-1 B NU's 20 Year Resource Plan (Winter) l-7 12 Short Term Uncertainty in Required Resources 1-8 r
CHAPTER ll ll-1 Summation of Sales by Class 11- 8 11- 2 Net Electrical Energy Output Requirements and Peak t Loads 11 9 11- 3 Principal Forecast Results and Comparison of Current and Previous Forecasts 1110 i
11- 4 1993 Long Run Reference Plan 1111 11 5 Net Electrical Energy Output Requirements and Peak Loads, Forecast 2002 2012 11- 1 2 l CH APTER 111 111- 1 Energy Alliance Peak Load MW impacts lil-3 111- 2 C&LM Program Summary 111-4 lil-3 System Annual Energy Savings, Summer and Winter Peak Reductions by Customer Class lll-9
! 111- 4 CL&P Annual Energy Savings, Summer and Winter Peak Reductions by Customer Class lil-10 lll 5 WMECO Annual Energy Savings, Summer and Winter Peak Reductions by Customer Class 11111 til-6 PSNH Annual Energy Savings, Summer and Winter Peak Reductions i by Customer Class 111- 1 2 i
til-7 Peak Impacts of Interruptible Resources lll-13 i
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FIGURES Fig. lil 1 Energy Alliance Peak MW impact 111- 3 i CHAPTER IV IV 1 Wholly-Owned Generating Units by Category and Company as of January 1,1993 IV 12 IV-2 Net Capacity Available by Generation and Supply Category as of January 1,1993 and August 1,1993 IV 16' IV-3 Generating Units Under Construction as of
- January 1,1993 IV-20 1
4 IV-4 Assumed Deactivations and Retirements of Generating Units: 1993 2012 IV-21 IV-5 1993 2012 Forecasted New Generating Additions IV-23 IV-6 1993-2012 Forecast of Capacity at the Time of i
Winter and Summer Peak IV 26 IV-7 Existing Customer Owned Facilities 1 MW and Above
} Providing Generation to the Northeast Utilities System
, During 1992 IV 31 CHAPTER V V-1 Transmission Circuits Under Construction in Connecticut V-9 V-2 Approved Transmission Circuits in Connecticut which are not yet Under Construction V 10 V-3 Proposed Transmission Circuits in Cont.ecticut on File with the Connecticut Siting Council V-11 J
V-4 Other Proposed Transmission Circuits in Connecticut V-12 l V-5 Transmission Circuits Under Construction in l Massachusetts V-13 V Exempt or Approved Transmission Circuits in Massachusetts V-14 V-7 Proposed Transmission Circuits in Massachusetts V-15 V8 Transmission Circuits Under Construction in New Hampshire V-16 V9 Approved Transmission Circuits in New Hampshire Which are not yet Under Construction V 17 iv i
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4 V-10 Prept: sed Transmission Circuits in N2w Hampshira on File with the New Hampshire Site Evaluation Committee V 18 V 11 Other Proposed Transmission Circuits in New Hampshire - V-19 i.
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l CHAPTERI EXECUTIVE
SUMMARY
This 20-year forecast of loads and resources focuses on the needs of Northeast Utilities 1 (NU) system retail and wholesale customers in New Hampshire, Connecticut, and Massa- )
chusetts and on how those needs are to be served by existing and planned programs and )
facilities. ;
Based on the Company's current projections, customers' needs can be met with existing demand and supply resources until 2007. This two-year extension in the Company's time )
of resource need as compared to last year's filing is due to two major factors.
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- The Company's continued commitment to economic conservation and load manage- I ment (C&LM) programs. !
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- A lower projection of regional growth due to the weakness in the current regional' j' economy.
Since new resources are not projected to be needed for 14 years, the Company has no plans to solicit or build new resources at this time. Without a need for new resources the l Company's goals are reducing the cost of energy, optimizing our existing resources l
including increasing energy efficiency through C&LM, and providing reliable electric service. These goals are discussed in Chapters I V of this filing.
Oraanization of the Report
- This report contains six chapters. This chapter, Chapter l, provides a summary of the entire report along with a description of NU's planning process, the need for new resourc-l es and resource options for the future.
Chapter il provides NU's forecast of peak loads, sales, and energy requirements through the year 2012. This chapter is summarized in section B below.
Chapter ll1 discusses the planning, implementation, and evaluation of conservation and load management programs in NU's long term reference load forecast. This chapter is
- summarized in sections C and E below, j Chapter IV provides information on existing and planned generating resourges through the year 2012. This cha'pter is summarized in sections C, D, and E below.
! Chapter V provides data on existing and planned transmission facilities. This chapter is summari::ed in sections C and D below.
Chapter VI contains maps of the NU and New England transmission system.
I
l2 A. NU's Inteorated Resource Plannino Process NU makes its resource decisions based on its overall objective of being a financially sound, environmentally responsible, reliable and reasonably priced provider of electricity and related energy services. This is accomplished through an integrated resource planning process. In this process, the Company considers the demand options that either reduce or reshape the demand for electricity and the supply options available to meet that demand, it then seeks to identify the most suitable cost effective combination of resources, while considering the sensitivity to changes in key input variables and exploring appropriate actions to respond to probable l
contingencies. l The planning process at NU is not rigid or fixed. Rather,it is a continuously evolv-ing, dynamic process which takes into account current and projected system circum-stances. NU's planning process addresses both the long and short term. Over the ;
long term, the integrated planning process considers supply-side and demand side i options and evaluates them as potential candidates in meeting future resource needs l to provide an adequate, reliable and cost effective supply of electricity, in the short term, NU considers the cost of the current resource plan and the management of existing resources which may provide short-term benefits. Such items as fuel conversions, ger.erating plant betterments, conservation and load manage... ant implementation considerations, energy and capacity sales and purchases, md unit '
l retirements / deactivations are examples of current planning activities.
State and federal energy initiatives and implementing regulations have become an important resource planning consideration for NU. The Clean Air Act Amendments
. of 1990 and the Energy Policy Act of 1992 are expected to significantly influence NU because of their broad scope. Nuclear plant licensing reform, fleet requirements for electric vehicles, renewable resource, SO, and NO, control tax credits and, i transmission policy, are addressed in these laws and will provida direction to the industry for years to come. Additionally, the national debate over energy taxes continues, a subject that could impact the cost of energy to our customers.
i B. Load Growth Projections Table 11 shows the projected levels of summer and peak demand 10 and 20 years into the future and projected peak load and energy growth rates for selected periods.
Winter peak demand for the Northeast Utilities system is forecasted to grow at an annual rate of about 1.6 percent over the period 1992-2012.
.. ~ - - . . . . . - . .-.---.~-.-.~.- - - . . - ~ .~ . ..
l i
1-3 I
TABLE l 1 NORTHEAST UTILITIES SYSTEM 20 YEAR OUTLOOK FOR ENERGY & PEAK LOAD Energy Summer Peak Winter Peak
! 2002 39218 7022 2002/2003 6986 2012 46237 8241 '2012/2013 8255
- Estimated winter peak subject to change; unadjusted for losses
! Forecast l Growth Rates 1
(including impacts of C&LM) t Summer Winter Egned Energy Peak Load Peak Load 1992 2002 1.6% 2.0 % 1.5 % !
2002 2012 1.7 % 1.6% 1.7 %
1992 2012 1.6% 1.8 % 1.6%
l A breakdown of the load forecast shows that over the next 10 years (1992/93 through i 2002/03), the Company's winter peak load (without the effects of incremental demand management programs) is projected to grow at approximately 2.4 percent per annum.
Inclusion of the incremental demand management options, currently part of the NU Resource Plan, reduces the peak growth to 1.5 percent per annum over the same 10 years.
Durin0 the same 10-year period, the Company's summer peak load (without the effects of incremental demand management programs) is projected to grow 2.8 percent per annum.
Inclusion of the incremental demand management options reduces the growth to 2.0 percent per annum over the same 10 years.
These projections include, as in past years, the Company's explicit recognition of the throet of customer self-generation, as the utility industry continues to experience increased competition. Even with programs to manage our own costs, to increase the level and i value of our service to customers, and to reduce the subsidies embedded in certain rates which give commercial and industrial customers an incentive to bypass the System, w?
have again included an estimated loss, which in 2002, amounts to some 410 GWh or L
j about 1.1 percent of NU System sales at that time. This loss reflects the belief that
- certain customers have, and will exercise the option of obtaining their electricity require-f ments from sources other than NU.
l l
I l-4 C. Existina Rs -ywees and Transmission System j l
- 1. Existirm DemEnd Side Resources NU has been, and continues'to be,'a regional and nanonalleader in the devel-opmerit and implementation of cost-effective and comprehensive demand sid management programs. Over the past decade the Company's efforts in ;
demaru8 management programs have continued to evolve as new initiatives were developed and new electricity end use markets targeted. These past efforts have resulted in significant reductions to the Company's peak load. l The effects of these past efforts, which are embedded in the Company's load 1 forecast, are expected to continue into the future. At the end of 1992, the . I cumuistive effects were estimated at 296 MW in summer and 214 MW .
winter (see Table 111 1).
- 2. Exish Sunolv-Side Resources A major component of NU's Resource Plan is the MW (Net Unit Entitlements -
Winter Rating) of utility owned generating capacity, as detailed in Chapter IV. 1 These resources, broken down by energy source, are as of January 1,1993:
Percent of Total ;
Winter Summer 38- )
2960 MW 2917 MW Nuclear 2970 MW 39 l Fossil 3047 MW 4 j 314 MW 309 MW Hydro 822 MW 11 l Pumped Storage 823 MW 8 636 MW- 652 MW _
Cogeneration 100 7780 MW 7670 MW TOTAL The above capacity has been reduced by capacity sales and purchases. As most of the contracts terminate between 1993 and 1998, the bulk of tr:st capacity will be available to the Company to meet the demand of its custom-ers.
The Company's decision to retire five internal combustion units in 1992 ref! acts both the current surplus of capacity in New England and the continuing efforts by NU to lower its operating and maintenance costs. in an effort to reduce the near-term cost of energy, the Company is studying the deactivation of Montville Station for the period January 1995 through October 1998. While a finst decision has not been made, this deactivation is included in this plan.
- 3. 5 r&.a Transmission Svstem A summary of the total mileage of the existing transmission system by operat-ing company is included in Chapter V. The only changes from the previous year are the rebuilding of an existing 115 kV line from Newtown to Plumtree and the removal of several unenergized 69 kV lines.
15 D. Need for Exoansion of the System
- 1. New Resource Needs NU's resources are adequate to meet customer' needs for the next 14 years, until 2007, at reference ! cad growth assumptions. Figures 11 A and 1-1B depict the combined NU system resources and resource requirements over the 20 year period 1993-2012 at the time of the summer and winter peak loads, respectively.
The states regulating NU subsideries have integrated planning regulations to determine if a solicitation for new resources is necessary. Because NU's projected need for such additional resources isn't until 2007 (Figure 11B), the
. Company does not anticipate making a solcstations for additional resources in the near term.
In light of the current economic downturn, increased focus on near-term electric rates and projected levels and duration of surplus capacity, the Compa-ny continues to reassess the projected pace of its C&LM program efforts and expenditures over the next several years. NU believes that the implementation rate of some programs can be moderatedin the near term to redu< e rate i.mpacts without materially advancing the need for resources or impairing the efte,ctive long term development of the C4LM resource. Thee issues are the subject of ongoing discussion by the Company and the state commissions and the non-utility parties (NUPs) within the respective C&LM collaboratives.
Reasonable upper and lower bounds to any forecast of load growth should always be considered in resource planning. Assuming first a high load growth scenario in which loads grow at 2.4 percent per annum including the effects of C&LM, the Company's first year of capacity need would be 2002. The Company also examined a low growth scenario where loads grow at 0.8 per-cent per annum over the next 20 years. These scenarios are depicted for winter and summer peak periods in Figure F2. Even under the high load growth scenario, there is more than ample time to evaluate resource . options.
- 2. Near Term Sitino Raouirements for New Generatina Facilities Because of the Company's generating capacity surplus and the long lead time ;
before any new resource need must be met, the Company does not need to i commit to any future resources at this time. The Company envisions using I cost effective demand side management resources to the extent possible to i delay the need for additional supply-side resources, and, if need be, then l considering repowering its older fossil-steem units at the existing generating stations, purchasing power fre" non-utility generators (NUGs), or appropriate new technologies, j
- 3. Need for New Transmission Facilities /Uoarades The tables in Chapter V detail the proposed transmission additions for the next 10 years. A discussion of the longer term needs is given in Section D of Chapter V.
l 1
. ~ _ _ . _ _ _ .
i 1-6 i
E. Resource Ontions Available for the Future
[
i
- 1. Future Demand Side Manaoement Ontions j i
l Today's options for demand management include helping customers increase j- the efficiency with which they use electricity (for lighting, cooling, heating, and l j industrial processes) and shifting load from higher-cost, on-peak periods to ;
lower-cost, off peak periods in response to cost based price signals.
i NU's future demand side resources in its resource plan include a comprehen- j j i sive mix of programs for residential, commercial and industrial customers, Certain C&LM programs are given first consideration in the resource plan.
These are:
- Programs mandated by government in the interest of public policy, l
- Programs in new construction (including replacement) which if not imple- l mented, would result in significantly higher costs through retrofits at a i later date, and
- Retrofit programs necessary to maintain an adequate infrastructure so i that the C&LM resource can be effectively developed over the long term.
- Programs which promote , economic development by assisting ir *he ,
retention or attraction of business and industry to the area.
Beyond these core programs, the resource plan includes additional program activity designed to achieve cost effective efficiency improvements as well as !
to assure a broad distribution of program benefits to customers. j
- 2. Future Sunolv Side Ootions j New supply options available to the Company include combined cycle, coal gasification and fluidized bed coal technologies, combustion turbines, fuel cells and renewable resources. NU's future supply options are evaluated using a screening process. The results of the latest screening analysis indicate that the lowest cost new base and intermediate load option is a combined cycle unit fired by natural gas. That supply resource also serves as a proxy unit ,
I against which the Company's demand management programs are evaluated for determination of capacity savings.
Another option involves the purchase of power from new generating facilities built by others. NUGs, including Qualifying Facilities (OFs) and independent power producers (IPPs), offer a considerable choice of potential resource additions to meet the combined system's future resource requirements.
Additionally, periodic reviews of near term opportunities for conversion from oil to gas are performed in order to enhance NU's position as a least-cost, envi-ronmentally responsible provider of electricity. NU continues to pursue eco-nomic opportunities to enhance its fuel mix, to reduce environmental impacts and to reduce oil dependency and the accompanying risks of abrupt changes in oil prices and supply interruptions.
T
. . . ....__-..._.m _ _ . _ . _ . . . . . . _ . _ . _ _ _ _ - . . . . _ _ . _ . . _ _ . . . - _ . _ . . -
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l-7
. FIGURE l-1A l
NU'S 20. YEAR RESOURCE PLAN SUMMER 1993-2012- '
l l
010 6 TT8 11 Resource Requiremente 10 - -
- Total Resources s Existing \
C&LM Resources #8W g _ _j
.....-- C&
L.M... Resources.., .
QF/IPP Resources .
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N ~
l Company Supply Resources l 7 i
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! ! l l l l 6 l l l 1993 1996 1997 1999 2001 2003 2005 2007 2009 2011 i i !
I l l 1 FlOURE l-18 NU'S 20 YEAR RESOURCE PLAN WINTER 1993-2012 OlGMTTS 11 Resource Requiremente Total Resources
\ -
10 - --- - -
Existing C&LM Resources New ~
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,.T. . . . ~ ' ~ T.~....~-~pggR. .e.i.b. uidii N 4 ....... ' _
ortiPe Resources 7
Company Supply Resources
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1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 l
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1-8 FIGURE I-2 SHORT TERM UNCERTAINTY IN REQUIRED RESOURCES (SUMMER)
MEGAWATTS 9000 Resource Requirements 8500 -
p CAPACITY
~ -
8000L
,K ,,..... ** AlGH 7s00 -
'.. .. REFERENCE -- -
7000
- , . ....... ... . ............ .... ..... ~ - - g g - ~ ~ ~ ~
6500 -
' l l l l 6000 l l l 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 l (WINTER)
MEGAWATTS 9000 Resource Requirements l i
A l a500 - ',..../---
, HIGH l CAPACITY ',,,...... -
8000 -
-- b
'.- .. * ...... - REFERENCE 7500 - -
y* - --
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yogo
'.'. ,............. - - ..... ........- " ,,,,.g,oy l l l l 6500 l l l l 92/93 93/94 94/96 95/96 96/97 97/98 98/99 99/00 00/01 01/02 l l
l
- l. I l
- l CHAPTER 11 l ELECTRICAL ENERGY DEMAND FORECAST. 1993-2002 l A. lNTRODUCTION The demand forecast, which provides input to the planning of future resources, focuses in part on the forecasted total annual consumption of electric energy. This is referred to as the energy forecast and it is expressed in terms of kilowatt hours (kWh), megawatt hours (MWh), or gigawatt-hours (GWh). It is made up of forecasts )
of sales to customers, company use, and associated transmission, distribution, and j transformation losses, which together make up the electrical energy requirements that must be supplied by generating plants to meet customer needs.
i The f orecast of the anticipated consumption of _ electrical energy is one guide for )
resource planning, but it does not include consideration of the expected maximum l rate of use of electricity, termed demand, and measured in kilowatts (kW) or
[ megawatts (MW). The facilities available to an electric utility system must be
- capable of generating, transmitting, and distributing electricity at that rate of use. l otherwise loads must be cut back to prevent overloads and/or system failure, i The demand for electricity fluctuates from hour to hour, week to week, and season to season. Normally, the heaviest consumption in the winter occurs during daytime hours, rising to a peak generally in midmoming and again in the lat
- . afternoon or I early evening. The heaviest consumption in the summer normally occurs between late morning and early evening, with 12 3 p.m. being the peak load period. The time when residential appliances, industrial machinery, commercial requirements for _j lighting and heating or cooling, and all other loads combine to produce the highest coincident hourly load of the year is the time of the annual peak for the system.
i Many factors can influence the timing and level of the peak load, including extreme '
weather, economic conditions and load management.
After the annual sales forecasts are developed for each customer class, correspond-ing hourly sales values are also developed. Estimated hourly company use and transmission, distribution, and transformat, ion losses are subsequently added to forecasted hourly sales. The summation of hourly sales, company use and losses determines the forecast of hourly net electrical energy requirements. The highest hourly load in the year or season becomes the forecasted annual or seasonal peak demand.
The NU load forecast reflects the expectation that substantial improvements in the efficiency of electric use can and will occur over the forecast period.
Although resource planning is done for the Northeast Utilities operating companies as a single system and data in this chapter are presented on that basis, the forecast itself is derived from a summation of the forecasts of electric loads in the service i areas of each of the four NU System operating companies.
I i
i
ll 2 The forecast is presented four ways:
- Trend Forecast - the results of the end-use models described in NU's '1993 l i
Economic and Load Forecast For 1993-2002 and 2003 2012,* _ unadjusted for
- 1) self-generation, including both committed projects that are scheduled to !
start up or come to full capacity in 1993 and unknown future projects,2) NU l oconomic development efforts including business retention, expansion and recruitment and 3) forecasted Company-sponsored demand-side management J (DSM) programs.
- Baseline Forecast the Trend Forecast minus sales losses due to self- J generation.
- Economic Development Scenario - the Baseline Forecast adjusted for sales due to NU economic development efforts.
- Reference Plan - the Economic Development Scenario minus energy savings due to DSM programs. This is the official forecast filed in Connecticut.
B. THE SALES FORECAST ,
Table Il-1 shows sales levels by type of customer for the historic period, 1970 1992, and for each year of the 1993 2002 forecast period. The 1993 forecast projects a ,
compound annual growth rate in total sales of electrical energy of 1.4 percent between 1992 and 2002. In preparing a sales forecast, retail customers are divided into five classes: Residential, Commercial, industrial, Streetlighting, and Railroad. In addition, NU's forecast includes its projection of " Wholesale Sales for Resale," which accounted for 4.3 percent of NU's total electric sales in 1992 and represents firm sales to municipal and private electric systems. " Bulk power sales" are excluded t
from " wholesale sales for resale" in this forecast. The sum of the retail and whole-sale forecasts is the system sales forecast. Sales to the three major retail customer ,
classes (Residential Commercial, and Industrial) are forecast to increase at compound annual growth rates of 1.1,2.2, and 1.3 percent, respectively, from ;
1992 to 2002. Over this same period, wholesale sales are projected to decrease at a compound annual rate of 4.2 percent, primarily due to the reclassification of Wallingford sales as bulk power sales. By 2002; sales to whciesale customers are forecast to represent 2.4 percent of NU's total electric sales. P C. SYSTEM ENERGY OUTPUT AND PEAK LOAD FORECAST Table ll 2 provides an overview of the historic output and summer and winter peaks for the 197D-1992 period, and forecast output and peaks for the 1992-2002 period.
The historic combined system peaks were calculated by adding the initial NU system peaks and the PSNH peaks together because the data required to merge hourly loads and extract the true peak were not available and the frequency of coincidence is high For the 18 months prior to merger (December 1990 to May 1992), combined ,
system peaks were calculated on a more rigorous level by NU's Intercompany Arrangements Department. Historical peaks and output are not normalized for weather. Also, the 1987 through 1989 seasonal peak loads have been adjusted to reflect the effects of emergency measures (such as voltage reduction and interruptible contracts) that reduced peak demand. The forecasted peak demands do
. . _ _ _ _ _ _ _ ~ _ _ _ . _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _
l l
11 3
)
I not reflect any potential reductions caused by utility-initiated emergency load control measures. The table shows electrical energy output growing at a compound rate of
, 1.6 percent per year over the forecast period. Table 11-2 also shows summer peak
} load growing at a compound rate of 2.0 percent and winter peak load increasing by l 1.5 percent annually from 1992 to 2002.
} Table 11-3 presents actual and forecast sales, output and peak loads and compares 1 this year's forecast with last year's forecast. For 1992, output was 0.7 percent
- j. below the 1991 level. For the year 2002, the output level in the current forecast is j 2.7 percent below last year's forecasted level and the annual peak in 2002 is 4.8 percent below the level forecasted last year. As previously noted, forecasted output and peak load reflect projected impacts of DSM ::rograms that are aimed at reducing NU system energy sales and peaks. They also reflect projected self-generation by NU's commercial and industrial customers, which displaces electricity that otherwise
- would be supplied by the NU system and increased load due to economic develop-
! ment. The Trend sales forecast, unadjusted for projected DSM and self generation 2 reductions and economic development, displays a more robust growth path of 2.2 percent compounded annually over the period 1992-2002 (see Table 11-4). The unadjusted output and peak forecasts display comparable growth rates.
The self-generation load loss projections developed for the forecast reflect NU's analysis that certain customers within the commercial and industrial classes have sufficient incentive, in response to electric, gas and equipment prices, to adopt on-site electric generation technologies now available in many sizes and configura-tions. Customers may elect to generate some or all of their own electric needs, if their cost of purchasing electricity from NU exceeds the cost of generating that electricity, in most cases, natural gas is assumed to be the primary fuel at self-generation facilities. Rate structures, overall price level, fossil fuel prices, facility costs, and gas supply availability will be the primary determinants of the eventual.
magnitude of customer self-generation. In the first several years of the current forecast, it is assumed that NU will be able to offer flexible rates and DSM programs to these customers and therefore make it less attractive for them to self-generate.
The current analysis of NU's future position in a competitive environment indicates an incremental 50 MW load loss by 2002 and an incremental sales loss of approxi-mately 410 GWhs due to the gradual penetration of self-generation beginning in the year 1993 for PSNH,1997 for WMECO, and 2001 for CL&P. These totals include committed projects totaling 113 GWhs or 14 MW in 1993. (Losses from existing projects are already reflected in the Trend forecast.) Self-generation is forecasted to have a greater impact in the second ten years but the effect in the first ten years is assumed to be mitigated by marketing efforts. The consequences of these potential losses, along with current estimates of sales being displaced by Oualifying Facility self-generation projects, are incorporated into the load forecast.
The Company continues to monitor customer self-generation potential. A combina-tion of field information and economic analysis yielded the level of self generation reflected in the forecast. Actual self generation losses could be greater or less than the forecasted losses depending on the economic factors that potential self-generators consider in their decision making process. However, the Company's cost containment efforts, rate design initiatives and customer service improvements,
.ll-4 including its conservation activities, are < designed to make.NUite petAerred provider of electric energy services and, therefona, lessen potardiahsetLgenerrion losses.
Beginning in 1991 in CL&P and WMECO. NWarististc$ discourned @ectric rates to retain the load of businesses that might otherwise iesve tbs NU $stvice territory, generate a portion of their own electnc needs or failL Mao. N3. io cooperation witn the Connecticut and Massachusetts economic development agencies, has offered discounted rates as part of a package of incentives to encourage employers to expand or to locate new facilities in the NU service territory. Recently PSNH has also been authorized to negotiate contracts for similar purposes in New Hampshire.
The models that were used to produce the Trend forecasts of energy output require-ments and peak demands incorporate assumptions.that reflect the price of electricity and fossil fuels, governmental regulations and standards, embedded technological changerand other factors that affect the consumption of electricity. The projected effects of Company sponsored DSM programs (see Chapter lil) and self-generation were then subtracted from the Trend forecast and the projected effects from economic development were added. Over the next ten years DSM programs are forecast to have significant impacts on the growth of sales and peak demands.
Table 114 presents the Trend forecast as well as the projected impacts of incre-mental DSM programs, ; elf-generation and economic development.
As Table 11-4 shows, retail sales in 1992 increased by 0.4 percent. The forecast redects the expectation that economic conditions willimprove during 1993.
Howeve , forecasted regional economic growth will be slower over the next ten years compared to the previous ten for a few basic reasons.- While the maturation of the work force and the restructuring of the major economic engines (e.g., manufac-turing and finance and insurance) will imply relatively low and stable unemployment rates, employment growth will be constrained by slowing population growth. As a consequence, growth in personal income and the production of goods and services i will be slow. Therefore, the Trend forecast indicates slower electric sales growth in '
line with forecasted long term trends in the growth of the regional and U.S. econo-l mies.
j As Table ll-4 demonstrates, DSM programs significantly reduce sales growth, i
causing the 1992-2002 compound growth rate to fall by 0.7 percentage points from '
2.1 to 1.4 percent. The reductions vary by class. While the DSM programs have a relatively small impact on the residential class, reducing sales growth from ,1.4 percent to 1.1 percent, they reduce the commercial class growth rate from 3.4 percent to 2.2 percent and the industrial class growth rate from 2.1 percent to 1.3 percent. Incremental self generation primarily affects the industrial class, although minimally in the first ten years of the forecast.
From 1970 through 1992 the initial Northeast Utilities System's annual peak has occurred fifteen times in the winter and eight times in the summer. Seven of those summer peaks occurred in the last ten years. On a combined system basis, the annual peak has occurred in the winter from 19701989 and in the summer in 1990 and 1991. A winter peak occurring in January or February is recorded as the winter l' peak of the preceding calendar year. For example, the peak that occurred in February 1979, the peak of the 19781979 winter season, is listed as the winter 1
i j- 11- 5 .
3
! peak for 1978. The preliminary NU System 1992 annual peak is 6000 MW and occurred on Monday, February 1,1993 from 6 7 p.m.
i j D. METHODOLOGY L
The development of a sales foreca:t requires a service area forecast of economic and demographic conditions. Separate economic / demographic forecasts for the NU
' Connecticut, New Hampshire and Massachusetts service areas are based on Data Resources, Inc. (DRI) forecasts for tha states of Connecticut, New Hampshire and the Commonwealth of Massachusetts and the Springfield and Pittsfield, Massachu-
- setts Metropolitan Statistical Areas (MSA). Detailed descriptions of the NU t
economic / demographic forecasts and NU's forecast methodology are available in l Chapters il and lli of the NU report entitled,1993 Economic and Load Forecast for -
- 1993-2002 and 2003-2012. The sales forecast is developed by class by various
} end uses and incorporates assumptions to reflect customers' responses to price!
4 changes and conservation programs. Sales forecasts are disaggregated by end use to study detailed trends the offect energy consumption and to provide input to the hourly energy and peak load forecasts.
The peak load forecast is the maximum sum of the hourly forecasts of load for each
}
customer class, company use and associated losses. The sum of the class hourly loads for each year, company use and associated losses is the annual ferecast of system electrical energy requirements or output. This is the amount of energy which must be supplied by generating plants to serve the loads on the systm.
Incorocration of Assumotions into Models and their Sources The forecast is based on regional economic / demographic forecasts, a price of electricity forecast, and assumptions about numerous factors that affect electric usage. Assumptions used in the models are based on such sources as NU's DSM programs, NU's survey of appliance ownership (the " saturation survey"), load research by NU and other companies into customers' patterns of electricity use, federal and state mandated appliance efficiencies, appliance industry marketing data, construction standards,~ analyses made by NU staff of the effects of advanced I insulation standards and size of dwellings on the use of energy for heating, judg-ments regarding the penetration of appliances into the residential market in future years, etc.
The forecast of hourly loads requires temperature data for each hour of the year.
Hourly temperature data from Bradley Field, Windsor Locks, Connecticut were collected for the 42 year period, 1950-1931, to construct a weather year based on the National Oceanographic and Atmospheric. Administration (N.O.A.A.) 30-year (1951-1980) normal weather data for Brat'iey Field. From the 42 years of monthly data, the weather year was constructed / rom actual months such that the weather year has a normal annual mean temperature and normal monthly mean temperatures, while also displaying typical weather patterns. This weather year was used for the initial NU companies. For PSNH the hourly temperatures in the NU weather year were adjusted for the difference between the monthly mean temperatures recorded by N.O.A.A. at Windsor Locks, Connecticut (Bradley Field) and Concord, New Hampshire for 1991.
.-~ . . - - . -. . ~ - - . . ~ ~ . - - - . - - . - - . - - . . ~.
4
'U B f Numerous assumptions, based p6ma4y son.loadJesearch data, are also used. These
! assumptions deal with the demand pattems of.sppliances tand commercial and industrial hourly load profiles. Included virtbEhew assernpt' crus arehr effects of load control devices and rates on custcma' mage puttams Irmed, thre hourly load models contain thousands of specific.essumpt. ion nqpediqq1%we Xactors.
The assumptions incorporated into the load Josecasbng nro6eb wins noviewed by an l NU staff group representing several areas of expertise inckeng e:omomics, engineer-i ing, consumer research, rate research, system planning, and enesgy utilization:
. Role of Econometric and End use Models >
In the 1993 forecast, end use models are used to forecast energy consumption.
Economic analysis of the effects of economic drivers and the price of electricity on sales are used to supplement end-use assumptions. End use models, such as the NU residential appliance model, are based on maxims which,if known with certainty, would yield perfect forecasts of consumption. The residential appliance modelis based on the fact that residential sales equal the product of the number of appli-ances and the kilowatt-hour (kWh) usage of each of those appliances. Estimates about the number of appliances in use, use per appliance and hourly usage character-istics are developed based on survey, market research, and load test data. Lo -run price effects, such as appliance efficiency improvements, are incorporated into the end-use modelimplicitly through decrements to appliance kWh usage. Short run price effects are also included explicitly through the use of a price elasticity coeffi-cient from an econometric analysis of NU residential sales.
~ An econometric model measures the historic relationships between a dependent variable to be forecasted (in the case of NU, the consumption of electricity) and causative factors which determine consumption such as price, number of customers, employment levels, or income. Econometric models estimate historic relationships which may or may not hold true for the future. For example,if some discrete change were to occur, such as a government mandate for more energy efficient building codes, an econometric forecast would tend to overestimate sales because the inherent assumption that historic trends will continue would only be partially true. Another limitation of econometric models is the inability to reflect certain types of detailed assumptions. For instance, an econometric model is unable to directly incorporate an assumption that water heaters shall have average thermostat settings of 120*F. The end-use models, by contrast, can accommodate such detail, and are usefulin demonstrating the effects of policy changes. The NU forecast blends econometric and end use models in order to incorporate the strengths of both methodologies.
Forecast of the Price of Electricity Each forecast for the major retail classes contains a price-of electricity term. Annual historic prices of electricity used in the model estimations are developed from rate schedules for each operating company and class of service. The forecast of electri-city prices for the years 1993 and beyond is based on near term revenue projections, trends in return on equity, and discussions with NU's Resource Planning Department.
These annual escalation factors were applied to the 1992 price estimates by retail class to produce forecasted electricity prices. Prior to final analysis, all nominal j i
i
l
' 11 7 i
l 4 (current) electric price forecasts are adjusted to provide real (constant, inflation adjusted) prices.
Copies of the 1993 Economic and Load Forecast for 1993-2002 and 2003 2012 are available from the Economic and' Load Forecasting Department, Northeast Utilities Service Company, P.O. Box 270, Hartford, Connecticut, 06141-0270.
l l E. ENERGY AND PEAK DEMAND LEVELS. 2003-2012 Forecasting peak demand two decades into the future is a highly speculative activity.
The impact of new uses for electricity, new or alternative sources of energy supply, uncertainties f. bout the effects of conservation measures and utility-supported economic development initiatives, price induced conservation, new technologies for both production and use of energy, and future levels of economic activity, all of which affect electricity consumption, are subject to major uncertainties. The 2003-2012 forecast is a continuation of the forecast for the 1993 to 2002 period.
As a result, the 2003 2012 forecast assumes that the trends forecasted for the 1993 to 2002 period continue and significantly different future events which could affect electricity consumption do not occur.
l The reference forecast for the 2003-2012 period draws upon a Data Resources. Inc.,
forecast which projects a slower rate of growth for the nation than was projected in last year's forecast. In this forecast, the economy of the.NU service area is project-ed to lag somewhat behind the nation's because of a population growth rate that is expected to be slightly lower than the nation's.
I Table ll-5 shows the potentiallevels of energy output requirements and summer and winter peak demand for the 2002-2012 period. The ten year compound annual growth rates for 2002-2012 for output and summer and winter peak load are 1.7 percent,1.6 percent and 1.7 percent, respectively.
l l
l l
i i
I
1 ll-8 TABLE 11 1 WORTNEAST UTILITIES SYSTEM IIAetAfl0N OF SALES BY CLASS NISTORY 1970 1992*
PCRECAST 1993 2002 GIGAWATTNOURS TOTAL ANNUAL tRIOLE AmuuhL ANNUAL RESI- CONM INDUS- STREET RAIL RETAIL CNANGE SALE / CRAN 0E TOTAL CalANGE YEAR DENTIAL ERCIAL TRIAL LIGHTING 2040 SALES (X) RESALE (X) SALES (E)
(*) (*)
N!$ TORY 1970 6674 4514 5511 174 0 16873 1924 - 18797 -
1971 7225 5010 5A29 177 0 17842 5.7 2047 6.4 19899 5.8 1972 7870 5621 5783 20A 0 19482 9.2 2241 9.5 21722 9.2 1973 8295 6176 6146 213 0 20830 6.9 2310 3.1 23139 6.5 1974 8352 5929 5869 211 0 20361 2.3 2332 1.0 22693 1.9 1975 8301 6200 5394 212 0 20107 -1.2 2295 -1.6 22402 -1.3 1976 8805 6486 5815 214 0 21320 6.0 2487 8.4 23807 6.3 1977 8938 6719 6014 220 0 21890 2.7 2615 5.1 24505 2.9 1978 9080 6958 6349 218 0 22606 3.3 2739 4.7 25344 3.4 1979 9241 7176 6657 218 0 23292 3.0 2801 2.3 26093 3.0 1980 9306 7343 6522 217 0 23388 0.4 2813 0.4 26202 0.4 i 1981 9241 7542 6546 209 1 23539 0.6 2638 e6.2 26177 0.1 1982' 9123 7705 6083 204 0 23117 1.8 2076 21.3 25193 3.8 1983 9372 8112 oJ15 197 34 24031 4.0 2133 2.7 26164 3.9 1984 9721 8602 A739 197 87 25346 5.5 2230 4.5 27576 . 5.4 1985 9814 8981 6707 190 131 25823 1.9 2232 8.1 20055 1.7 ;
1986 10405 9610 6830 184 148 27177 5.2 1929 13.6 29106 3.7 1987 11084 10275 6934 179 123 28595 5.2 1269 36.2 29864 2.6 1988 11800 10816 7094 '179 126 30016 5.0 1208 -4.8 31224 4.6 1989 12031 11109 7123 176 134 30574 1.9 1354 12.1 31928 2.3 1990 11861 11347 6987 1 73 137 30507 0.2 1241 -8.3 31748 0.6 1991 11823 11179 6686 1 72 137 29997 -1.7 1405 13.2 31402 1.1 :
I 1992 11956 11201 6643 171 142 30112 0.4 1346 -4.2 31458 0.2 COMPOUND RATES OF GROWTH (1) 1970 1992 2.7 4.2 0.9 0.1 2.7 1.6 2.4 FORECAST 1993 12200 11368 6630 171 145 30514 1.3 886 34.2 31400 -0.2 1994 12366 11621 6729 168 147 31031 1.7 914 3.2 31945 1.7 i 1995 12466 11944 6736 169 147 31462 1.4 954 4.4 32416 1.5 1996 12678 12374 6962 170 216 32400 3.0 973 2.0 33373 3.0 1997 12792 12663 7104 170 215 32964 1.7 992 2.0 33936 1.7 1998 12938 12975 7282 170 215 33580 1.9
- 993 0.1 34573 1.9 1999 13052 13271 7413 173 215 34124 1.6 1011 1.8 35135 1.6 l 2000 13192 13526 7511 174 216 34619 1.5 935 -7.5 35554 1.2 l 2001 13258 13693 7524 175 215 34865 0.7 859 -8.1 35724 0.5 ;
2002 13338 13913 7546 176 215 35188 0.9 87/ 0 36064 1.0 l l
COMPOUND RATES OF GROWTM (X) 1992 - 2002 1.1 2.2 1.3 0.3 1.6 4.2 1.4 -
- NISTORY NAS BEEN RESTATED TO INCORPORATE PSNN DATA.
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TABLE Il 2 NORTIEAST UTILITIES SYSTEM NE1 ELECTRICAL ENERGY alTPUT REQUIREMENTS AND PEAK LOADS NISTORY 1970 1992 FORECAST 1993 - 2002 NET ELECTRICAL ENERGY OUTPUT REQUIREMENTS (1) SulOIER (4) WINTER (4)
ANNUAL ANNUAL LOAD ANNUAL LOAD YEAR CUTPUT CHANGE PEAK CNANGE FACTOR PEAK CNANGE FACTOR GWH (%) NW (1) (2) MW (S) (2)
NISTORY (5) 1970 20640 -
3384 . 0.696 3899* -
0.604-1971 21693 5.1 3614 6.8 0.685 4096* 5.1 0.605 1972 23725 9.4 3858 6.8 0.700 4567* 11.5 0.591 1973 25028 5.5 4348 12.7 0.657 A426* 3.1 0.646 1974 24605 -1.7 4035 7.2 0.696 4371* 1.2 0.643 1975 24450 0.6 4190 3.8 0.666 4704* 7.6 0.593
, 1976 26003 6.4 4271 f.9 0.693 4957* 5.4 0.597 l 1977 26471 1.8 4679 9.6 0.646 5004* 0.9 0.604 1978 27174 4.2 4796 2.5 0.656 5124* 2.4 0.614 1979 28109 1.9 4746 -1.0 0.676 5114* 0.2 0.627 1980 28550 1.6 5013 5.6 0.648 5327*- 4.2 0.610 1981 28112 1.5 4916 2.0 0.653 5223* 1.9 0.614 1982 27224 3.2 5005 1.8 0.621 5124* 1.9 0.606 1983 28413 4.4 5051 0.9 0.642 5147* 0.4 0.630 1984 29779 4.8 5248 3.9 0.646 5618* 9.2 0.603 1985 30406 2.1 5464 4.1 0.635 5622' O.1 0.617 1986 31631 4.(; 5357 1.9 0.674 5546' -1.3 0.651 ,
1987 32459 2.6 5708 6.5 0.649 6136* if . 0.604
- 19R8 34123 5.1 6085 6.6 0.638 6261* 2.0 0.620 1989 34847 2.1 6023 1.0 0.660 6194* -1.1 0.6/.2 1990 34139 2.0 5943* 1.3 0.656 5939 -4.1 0.656 1991 33829 -0.9 6143' 3.4 0.629 6024 1.4 0.641 1992 (3) 33591 0.7 5781 5.9 0.661 6000* 0.4 0.637 COMPOUND RATES OF GROWTH (1) 1970 1992 2.2 2.5 2.0 FORECAST 1993 34139 1.6 6069 5.0 0.642 6189* 3.1 0.630 1994 34752 1.8 6197 2.1 0.640 6296* 1.7 0.630 1995 35341 1.7 6304 1.7 0.640 6431* 2.1 0.627 1996 36273 2.6 6453 2.4 0.640 6541* 1.7 0.631 1997 36870 1.6 6594 2.2 0.638 6658* 1.8 0.632 1998 37569 1.9 6717 1.9 0.638 6767* 1.6 0.634 1999 38176 1.6 6831 1.7 0.638 6839' 1.1 0.637 2000 38647 1.2 6885* 0.8 0.639 6871 0.5 0.640 2001 38839 0.5 6959* 1.1 0.637 6920 0.7 0.641 2002 39218 1.0 7022* 0.9 0.638 6986 1.0 0.641 COMPOUND RATES OF GROWTM (%) 1992 2002 1.6 2.0 1.5
- 1. SALES PLUS LOSSES AND COMPANY USE.
- 2. ALL LOAD FACTORS AND ANNUAL PERCENT CMANGES ARE CALCULATED USING ACTUAL DATA (NOT NORMAll2ED). IN PARTICULAR,
- TM LOAD FACTM e (mlTPUT (NWH)) / (8760 NOURS X SEASON PEAK ( 8Rd)).
- 3. THE 1992 WINTER PEAK IS PRELIMINARY.
i 6. SUBO4ER AND WINTER PEAKS FROM 1970 TNRQUGH 1981 INCLLSE 04EEC LOAD.
- 5. HISTORICAL DATA NAVE BEEN RESTATED TO REFLECT CONSOLIDATED NU SYf. TEM AND PSNN ENERGY CUTPUT AND PEAK LOADS.
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l I
ll-10 TABLE 11 3 NORTNEAST UTILITIES STSTEM PRINCIPAL FORECAST RESULTS AND-COMPARISON OF CURRENT AND PREVIOUS FORECASTS COMPOUND RATES 0F GROWTH **
ACTUAL
- FORECAST (FOR YEAR 2002) ................
PERCENT 1992 1993 PERCENT 1991 1992 DIFF. FORECAST FORECAST DIFF. (91 02) (92-02)
(3) (4) (4)/(3) (5) (6)
(1) (2) (2)/(1)
SALES (GWh) 13338 0.5% 1.1% 1.1%
11823 11956 1.1% 13266 REllDENTIAL 13913 1.3% 1.9% 2.2%
11179 11201 0.2% 13733 COMMERCIAL 7546 9.2% 2.0% 1.3%
INDUSTRIAL 6686 6643 0.6% 8308 176 -13.9% 1.6% 0.3%
172 171 0.6% 204 STREET LIGHTING 142 215 51.4% 0.3% 4.3%'
RAILRDAD 137 142 3.1%
35188 1.3% 1.6% 1.6%
RETAIL 29997 30112 0.4% 35654 1573 876 44.3% 1.0% 4.2%
WOLESALE 1405 1546 4.2%
36064 3.1% 1.6% 1.4%
TOTAL 31402 31458 0.2% 37226 OUTPUT AND PEAKS 40289 39218 -2.7% 1.6% 1.61 DUTPUT (GWh) 33829 33591 0.7%
7022 4.4% 1.6% 2.0%
SUMMER PEAK (MW) 6143 5781 -5.9% 7347 6986 5.2% 1.9% 1.5%
6024 6000 0.4% 7373
- WINTER PEAK (MW)
- - History has been restated to incorporate PSNH data.
- Colum (5) growth rates are actunt 1991 to the 1992 forecast of 2002 sales and cotan (6) are actual 1992 to the 1993 forecast of 2002 sales.
- - The 1992 winter peak is preliminary.
l
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11- 1 1 TABLE II 4 NORTMEAST UTILITIES SYSTEM 1993 LONG RUN REFERENCE PLAN (GWM) 2002 2002 ECON DEV REFERENCE 2002 SCENARIO (TRt 6 .*.0J 2002 BASELINE (TREW ADJ FOR SELF-GEN 1992 1993 TREND (TREW ADJ FOR SELF GEN ECON DEV ACTUAL
- FORECAST FORECAST FM SELF GEN) 8 ECON DEV A2 DSM RESIDENTIAL SALES 11956 12200 13794 13794 13794 13338 1 CNC 1.1 2.0 COMPCUND RATE OF GROWTM 1.4 1.4 1.4 1.1 COMIERCIAL SALES 11201 11368 15751 15648 15671 13913 1 CNG 0.2 1.5 COMPOUND RATE OF GROWTH 3.5 3.4 3.4 2.2 INDUSTRIAL SALES 6643 6630 8163 7856 8174 7546 1 CMG -0.6 0.2 COMPOUND RATE OF GROWTM 2.1 1.7 2.1 1.3 STREETLIGHT!NG SALES 1 71 171 182 182 182 176 1 CMG 0.6 0.0 COMPOUND RATE OF GROWTM 0.6 0.6 0.6 0.3 RAILROAD SALES 142 145 215 215 215 215 1 CMC 3.1 2.4 COMPOUND RATE OF GROWTN 4.3 4.3 4.3 4.3 TOTAL RETAIL SALES 30112 30514 38105 37695 38036 35188 1 CMG 0.4 1.3 COMPOUND RATE OF GROWTM 2.4 2.3 2.4 1.6 WMOLESALE SALES 1346 886 876 876 876 876 1 CMG ' 4.2 34.2 COMPOUND RATE OF GROWTH 4.2 4.2 -4.2 4.2 i TOTAL SALES 31458 31400 38982 38572 38913 36064
! 1 CMG 0.2 0.2 COMPOUND RATE OF GROWTH 2.2 2.1 2.1 1.4 l
PEAK DEMAND ** 6000 6189 7598 7548 7605 7022 1 CNG -2.3 3.2 COMPOU@ RATE OF GROWTM 2.4 2.3 2.4 1.6 t
- NISTORICAL DATA NAVE BEEN RESTATED TO INCORPORATE PSNN DATA.
- 1992 PEAK IS PRELIMINART.
I
I fl.12 TABLE II 5 NORTNEAST UTILITIES SYSTEM NET ELECTRICAL ENERGT GUTPUT REGUIREMENTS AND PEAK LCADS FORECAST 2002 2012 NET ELECTRICAL ENERGY CUTPUT WINTER (4)
REGUIREnENTS (1) SLSetER (4)
AmuuAL LOAD AmmuAL AmmuAL LOAD PEAK CNANGE FACTOR CNANGE PEAK CNANGE FACTOR TEAR OUTPUT .... ...... ......
GWu (%)
0.638 6986 1.0 0.641 2002 39218 1.0 7022* 0.9 0.638 7064 1.1 0.641 2003 39646 1.1 7099* 1.1 0.636 7154 1.3 0.640 2004 40240 1.5 7202* 1.5 0.637 7232 1.1 0.641 2005 606t3 0.9 7279* 1.1 0.637 7378* 2.0 0.635 2006 41064 1.1 7358 1.1 0.08 7533* 2.1 0.635 2007 41922 2.1 7498 1.9 1.9 0.639 7682* 2.0 0.636 2008 42902 2.3 7639 0.636 7792 2.0 0.639 7B33* 2.0 2009 43611 1.7 1.7 0.637 1.9 7948 2.0 0.638 7967*
2010 44444 1.9 0.636 1.8 8092 1.8 0.639 8118*
2011 45262 1.7 0.638 2.2 8241 1.8 0.639 8255*
2012 46237 COMPOUND RATE $ OF GROWTH (%) 2002 2012 1.7 1.7 1.6
- DENOTES COMPANY PEAK
_ _.. _ _ _. _ .. _ _ _ _ _ . __ - _ _ _ _ - . . _ . - __m_
l CHAPTER IV l EXISTING AND PLANNED SUPPLY RESOURCES 1993 2012 I
A. Introduction NU's existing and planned capply resources comprise a diversified mix of generating units that are anticipated to be adequate to meet demand over the ne'xt 15 years.
These resources provide environmentally sound and reliable energy for its customers.
' Since NU's year of capacity need is 2007, no supply resources beyond an additional 68 MW of NUG capacity are planned at this time. During 1992, Silver Lake Units 10-13 and Tracy (89 MW) were retired.
i B. Exolanation of Tables The capacity tables in this chapter display estimates of NU's supply resources dunng the 1993-2012 forecast period. All generating units are given winter and summer ratings in megawatts to reflect the effects of varying ambient air and water tempera-i tures on thermal units' ratings and river flow conditions on hydro units' ratings, Throughout this chapter, winter ratings are used in assessing NU's capacity situation f relative to the forecast winter peak demand, and summer ratings are used in i assessing its capacity situation relative to the forecast summer peak demand.
The forecasts of winter and summer peak demands used in this chapter are cons;s-tent with those presented in Chapter ll, Tables ll-2, ll 3, and 114. That demand forecast reflects NU's most recent assessment of customer conservation and load 4 management potential, the potential losses due to customer self-generation and the increase in demand resulting from the Company's marketing efforts. Not reflected in l the demand forecast are direct load control devices and interruptible service con- !'
tracts which, if called upon during New England Power Pool (NEPOOL) demand emer-gencies, would further reduce peak demand. These measures contribute to reducing I the system's capability responsibility as required by NEPOOL, and thus lower overall l resource needs. (The reader is referred to Chapters ll and 111 for additional details.) l Net capacity available to serve load is developed from: l
- the existing wholly-owned generating units detailed in Table IV-1;
- NU's current share of the capability of other units and capacity purchases, sales and exchange contracts with other companies, as detailed in Table IV 2;
- generation additions shown in Table IV-3; and
- retirement of generating units shown in Table IV-4.
With respect to capacity purchases, sales, and exchanges with other utilities, the amounts shown on the tables reflect executed contracts or letters of understanding and contracts under negotiation which have a reasonable likelihood of being exe- !
cuted in the near future. Contracts to purchase, sell, and exchange capacity and
IV-2 energy.ere reviewed no an ongmng bass and xe ,ettranad !rteo tardy if they will lower customers' cosis ed nsh Table IV-5 shows ths: no gerocatAon addf ora ars 'fascasted art this time.
Table IV 6 summar'rzes the twenty ysyi Acad and capacity stoation for the NU system during the winter and summer peak periods of 1993 through 2012. The table also shows the system's reserve expressed in megawatts and as a percent of peak load. Not shown on the table are commitments to the Hydro-Quebec Phases 1 -
and 11 contracts, interruptible load contracts, and load control measures. These elements of the resource plan contribute to reducing NU's Capability Responsibility to NEPOOL.
Table IV-7 provides details on the capacity and energy contribution from existing cogeneration and small power production f acilities 1 MW and greater.
C. Enerav Suoolv The table below shows the extent to which the system has been able to reduce its reliance on oil by comparing the 1973 (pre-oil embargo) energy contribution by source with 1980 and 1992.
In 1980 NU's energy resources consisted of a mix of nuclear, oil, and hydroelectric energy. By 1992, the energy mix had become less oil dependent and included coal, natural gas, and power from non-utility generation. NU has diversified its energy resources and has reduced oil dependence over the long term.
ENERGY CONTRIBUTION BY SOURCE (Percent)
.1912 1989 .UlE2' Hydro 5 3 5 Nuclear 19 50 48 Coal 1 0 11 Gas 1- 0 3 . ;
Oil 74 47 25 -
Non Utility Sources - -
1 ;
TOTAL 100 100 100 Energy Requirements (GWh) 19,600 21,679 30,204
Oil Dependence (millions of barrels) 28.0 18.6 12.9
- Contribution from initial NU system in first half of 1992 and combined system for second half of 1992.
includes non-utility generation.
During 1992, the nuclear plants operated at an aggregate capacity factor of approxi- I mately 60 percent and, along with purchased nuclear energy, contributed about 48 percent of the NU system's total energy requirements, thereby reducing NU's j
)
l 1
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I IV-3 i
system oil dependence by nearly 27 million barrels from what it could have been in j the absence of nuclear power. The 1992 nuclear capacity factor is considered an )
aberration. Capacity factors are expected to improve as NU implements a nuclear performance enhancement program.
D. Suoolv Resources for 1993-2012 y
! The planned supply resources for the 1993 2012 forecast period include:
i ,
e hydro units and most of the existing fossil-fired units; I I
- non-utility generation under contract and with NHPUC orders: j l
- capability credit associated with the NEPOOL purchase of firm energy over the Hydro-Quebec interconnection;
- all existing nuclear units until license expiration; and !
!
- purchases, sales, and exchanges of capacity and energy with other utilities to lower customers' costs, j Screening studies done by the Company indicate the rnost likely options are as follows: ,l
- repowering of some older oil-fired units as natural-gas fired combined-cycle generating units, e mstallation of new, more efficient peaking gas turbine generating units, and
- minor additions of capacity at existing hydro sites.
Additionally, because of the short lead times (4-7 years) required to develop these options and the ease with which they can be located at existing sites, they can be considered good supply candidates in tL4 event contingency decisions must be made. Such contingencies might arise as a result of load growth being higher than forecast, or lower than anticipated demand reductions from planned demand side management measures.
Continued Ooeration of Existina Fossil Fired and Hvdro Units .
Given the difficulty in siting new generation and transmission facilities, NU believes it is sound policy to preserve existing generating sites and resources, rather than to dispose of them and later have to develop new ones. Most existing fossil-fired and l hydro resources provide an economic and reliable source of generation. Accordingly, I NU will continue to maintain these sites in a manner that will preserve their long-term usefulness and availability as long as they are economic. Several units are forecast to be either retired or deactivated, and these are shown on Table IV-4. In i
order to reduce costs to customers in the short term, NU is studying the deactivation of Montville Station for the period January 1995 through October 1998. While a final decision has not been made, this deactivation is included in this plarf.
. . - . _ - - . . ~ - - . - . . . . - _ _ - . . - _
i IV-4 i l
i Non-Utility Generation With the recent addition et iP Me Sersica of Amrw Hampshire to the Northeest Utilities f amily, there :are 54 WUGs of 1 :MW re staraWwsize tharsold power to NU during 1992.
Of these 54 facilities,45 NOGS with a capacity of approximately 643 MW sell power to NU under long term contracts or rate orders. Currently, the total capability for NUGs interconnected to the NU system is 636 MW (Winter) and 598 MW (Summer).
The_ remaining 9 NUGs do not operate under long term contracts or rate orders but rather sold energy to NU at non-firm energy rates. Therefore, under NEPOOL rules these facilities do not provide capability credit to the NU system.
By 1995, with the planned contractual additions of Rimmon Pond (1 MW),
MassPower (54 MW) and Lisbon (13.5 MW), NU estimates that the resulting '
48 NUGs operating under long-term agreements or rate orders will have an associat-ed capacity of 712 MW. NU anticipates a resulting 1995 capacity rating of 703 MW (Winter) and 666 MW (Summer) from these NUG capacity commitments to its electric system, it should be noted that this estimate of the 1995 capability rating is a reduction to ;
the 764 MW (Winter) and 751 MW (Summer) estimated in last year's report. This reduction is due mainly to the termination of purchase agreements with Bio-Gen (13 MW). ARS (32.2 MW) and Brockton Wood (Tamal) (16.9 MW). The Connecticut Legislature required the DPUC to order the buy-out of the Bio-Gen and ARS Electrici-ty Purchase Agreements by CL&P. In addition,in November 1992, the Massachu-setts DPU disapproved the Electricity Purchase Agreement for the Brockton Wood project.
On February 8,1993, NU issued a " Reverse Request for Proposal" (RRFP) for consideration by non-utility generators. Its purpose is to solicit proposals to reduce the anticipated ratepayer impacts from NUGs, with emphasis on the next 6 years.
Hydro-Quebec interconnection The New England portion of Hydro-Quebec Phases I and 11 facilities entered commer-cial operation on October 1,1986, and November 1,1990, respectively.
For capability responsibility purposes, the benefits from Hydro-Quebec interconnec-tion and associated contracts are converted into equivalent capacity values during the firm energy contract period. NU's share of these equivalent capacity values are 166 MW in winter and 246 MW in summer for Phase I and 239 MW in winter and 354 MW in summer for Phase 11. This aggregates to 406 MW in winter and 601 MW in summer. The Phase ll contract currently extends to the year 2000 with an extension period through 2004 to receive undelivered energy. If no new contract takes its place, the interconnection will still provide tie benefits.' in light of this, NU .
assumes that its Hydro-Quebec capability credit will be reduced to 70% of its current value beginning in the fall of 2004.
t'
+ -----e - +r- w - - --~= m
l l
IV-5 l
Purchases and Sales of Bulk Power t
NU has long recognized that energy purchases and sales are an important way of l minimizing electricity costs and improving generation mix. For example, NU's energy purchase arrangements have helped to substantially reduce the overall cost of serving customer load. Power purchases include buying power from other New England utilities as well as from utilities in New York State and in the Pennsylvania-Jersey-Maryland (PJM) interconnection. NU's contracts with utilities outside of New England provide a means to improve the availability of economy energy to NEPOOL and to reduce NU's energy costs. The Northfield Mountain Pumped Storage Facility plays an important role in NU's ability to make energy purchases and sales. NU can buy relatively inexpensive power during the off peak periods and store it at Northfield
- by pumping water into an upper pond. This stored energy is used during peak l
- periods, thereby reducing NU's cost of peak period generation and providing more l opportunities to make energy sales. NU purchased about 2.1 million MWh of i economic energy during 1992, and NU sold approximately O.3 million MWh of l energy for economy purposes to others during 1992.
Likewise, NU's contracts for sales of surplus capacity and associated energy to other l utilities have helped to significantly reduce the overall revenue requirements from l- NU's customers. in 1992 NU's wholesale marketing efforts resulted in the sale of an additional 1,000 MW-years of surplus capacity. The level of future NU c::pacity pur-chases and sales will depend on the bulk power market in New England and adjacent regions, on extemal influences such as regulatory policies and deci .ons, and on the NU system's capacity situation.
l The capacity market in New England is expected to continue to be very competitive in the next few years. This is a result of the regional economic downturn and resultant lowering of load growth projections, along with aggressive DSM program l
implementation by many utilities, and several recent capacity additions in New England including Seabrook, Hydro-Quebec Phase 11, and various NUGs. However, NU will contmue to attempt to sell its available capacity at rates which at least recover the marginal costs of such capacity.
l Hydro Canecity NU has no plans to install additional hydro capacity during this planning horizon.
WMECO's FERC license for the Gardners Falls hydroelectric project in Buckland, and Shelburne, MA, expires at the end of 1993. An application for a new license, filed by WMECO on 12/23/91,is currently under FERC review. Public Service Company of New Hampshire's FERC Ih:enses for the Ayers Island, Gorham, and J. Brodie Smith hydroelectric projects in New Hampshire will expire on 12/31/93. Applica-tions for new licenses, filed by PSNH in December 1991, are currently undergoing FERC review. With the exception of environmental and recreational enhancement
- measures, PSNH is not proposing any physical or operational changes to these i facilities.
i On August 11,1992, the FERC issued orders granting exemptions from licensing for i the Company's four hydroelectric projects on the Chicopes River: Red Bridge, Putts
[ Bridge, Indian Orchard, anri Dwight. The Company is in the process of developing a l
l f-
IV 6 )
plan to implement the environmental and recreational enhancements included with the FERC exemption orders.
Fuel Mix Diversification Conversion of existing oil-fired units to multiple fuel firing capability does not add any resources to overall system capacity; its potential value lies in further reducing oil dependence as well as reduced emissions, thereby helping to assure service reliability, while reducing costs to customers. NU continues to study the technical and economic feasibility of providing its oil-fired units with interruptible natural gas firing capability. NU converted its Newington Station (406 MW) to dual fuel capability (oil / gas) during 1992 and continues to study the conversion of Devon I Units 7 and 8 to burn interruptible natural gas.
E. - Lono Term Plannina lasues ,
Plannmg supply options for the longer term, i.e., post-2OOO, requires considering a number of relevant issues. Some of them are briefly discussed here. They include environmental issues, uncertainty of resource need, availability and price of fuels, r progress on developing new technologies, using existing sites and relicensing of t
existing nuclear plants.
Environmental issues The pursuit of "least cost" plans has become a more complex activity in recent years as environmental matters have moved to the forefront. Because future environmen-tal regulations and their associated costs are uncertain, planners must allow for -
unknown factors in postulating what is "least cost." Today t;mre are several key environmental issues that are important to consider in resource planning: the new '
acid rain regulations, NO, compliance, and other CAAA issues (air toxics, fleet vehicles). These issues are related to provisions of the Clean Air Act and the 1990 Amendments. Most important are the regulation of SO, and NO, for the purpose of controlling acid rain rTitle IV), attainment of Ambient Air Quality Standards, most notably ozone (Title 1) and other issues such as monitoring and air toxics control.
r The following summarizes where the Company stands on the major areas of compli-ance with the 1990 Clean Air Act Amendments and its implementing regulations, as well as the Massachusetts and New Hampshire Acid Rain Laws compliance efforts.
The two principal areas of CAAA compliance are NO, and SO, emissions reductions.
The principalimpacts of the CAAA on NU consist of some modest SO, reductions from the acid rain portion of the law (Title IV), and NO, reductions at all of our fossil stoom units from the non-attainment portion (Title 1).
Acid Rain ,
PhaseI The first major compliance activity for the acid rain portion of the CAAA was the filing of Title IV permit applications by February 15,1993 with EPA Region I for our Phase I units. The only two designated Phase i units on the NU system (and in New England) are Merrimack 1 and 2. Beginning in 1995, l
_ .__ ~. _ . - -_
- - - . - . - . - - . - - - . ~ . . . . - . . . - - . - . - . - . - . _ . - - .
IV 7 these units will be granted allowances by EPA and the units' emissions will be subject to Title IV regulation. An allowance is the right to emit one ton of SO,.
In its Phase I Application the Company also included Newington and Mount Tom as conditional substitution units to provide an additional margin for compliance with Phase 1. These substitution units,if needed, will also be granted allowances based on historical performance. Continuous emissions monitors (CEMs) will be installed at these four units. The Company is planning to use the combination of fuel sulfur levels that will minimize the fuel costs for these four Phase I units and maintain a sufficient surplus of emission allowanc-es to cover uncertainties.
In addition to the CAAA Acid Rain requirements, the Company will continue to comply with the New Hampshire acid rain regulations that have been in effect since 1991. These regulations cap the total Merrimack 1 and 2, Newington, and the three Schiller units' annual SO, emissions at 55,150 tons.
The Massachusetts Acid Rain regulations require that, starting in 1995, WMECO and HWPCO units on the system have an average emissions rate of 1.2 lbs/MBtu. In calculating this rate the Company can take into account conservation credits and cogeneration installed in the period .1989-94. West l
Springfield 3 by virtue of using 1.0% sulfur oil and interruptible gas will comply. Mount Tom will likely comply by changing to a lower sulfur fuel.
Phase ll Phase 11 of the CAAA acid rain section begins in 2000 and affects all units greater than 25 MW. These units will require allowances starting in that year l for all of their SO, emissions. These Phase li units will require CEMs to be installed and operating by 1/1/95 and permit applications to be submitted by -
l 1/1/96. All affected units in Connecticut are already in compliance with Phase l
! Il by virtue of their use of fuel with 1.0% sulfur or less. In Massachusetts, West Springfield 3 is already in compliance, but Mount Tom will likely comply with a shift to a lower sulfur fuel (i.e. below 1.0%). The New Hampshire units
! at Merrimack and Newington stations will likely shift to lower sulfur fuels to
~
l comply with Phase 11.
\
l SO, Allowance Surplus in Phase I the allowances granted to the four units appear to be sufficient for
( them to comply with an adequate margin. In Phase 11 the Company expects to l
l have surplus allowances after accounting for a reasonable range of operational
(
uncertainties. The Company is examining ways to maximize the benefit of this to the ratepayers and shareholders. This principally consists of ways to sell a portion of the surplus in a way that moderates the risks of the allowance i
market uncertainties.
NO. Comoliance i
! The Company is currently evaluating ways to achieve compliance with lower NO, emission levels to help achieve attainment of the ozone standard under l
IV 8 .
Title I of the CAAA, and to comply with acid rain provisions under Title IV.
- The final state regulations for Title i NO, are expected to be issued during ,
1993.. The recent NO, proposalin New Hampshire by PSNH and other parties will achieve about a 50% reduction in NO, from PSNH units in the summer and a 30% reduction on an annual basis from 1994 through 1998. The proposal includes the possibility of a capacity reduction of about 25% in the summer months. For 1999 and beyond, NO, emissions must be further reduced by additional pollution control equipment, repowering, or retirement. ,
The Connecticut and Massachusetts DEPs have issued draft regulations and held public hearings on NO, emissions and on a system for banking and trading Emission Reduction Credits (ERCS). NU has been actively involved in develop-ing those regulations to assure that a workable, consistent system for trading ERCS across the region is developed.
The Company expects to be in compliance with Title i by the required date, May 15,1995. Additional NO, reductions for acid rain compliance are unlikely since the NO, compliance measures taken under Title I are expected to meet the Title IV requirements.
Other CAAA Reauirements Other portions of the CAAA are restrictions on mobile sources and required -
fuel changes. In Fairfield County,' the Company will need to implement a 25%
increase in employee commuter vehicle occupancy. Less polluting vehicles must be phased into the company fleet over time, which must in tum be fueled
' by cleaner fuels.
Air toxics is another major section of the CAAA but there are no regulations yet for electric utilities. Air toxics impacts are unknown at this time but they have the potential to be significant. The CAAA also requires CFCs and Halon to be phased out of production by 1996.
Environmental Externalities The Massachusetts DPU established monetized values for environmental externalities in Docket 91-131. These are to be used in evaluating new resources in the Integrat-ed Rescurce Planning Process. NU, along with other New England utilities, had
- argued strongly in that docket for externality values be properly based on damage '
costs. However the DPU's final values reflect their original approach based on control costs. Use of these values will cause a large distortion in relative economics of future resource options, and NU has joined in a National Coal Association, Massachusetts Electric Co., and Boston Edison Co. appeal of the DPU's decision in 91-131.
Neither Connecticut nor New Hampshire has a system of externalities for energy evaluations in place, but the Connecticut DPUC is required to explore this subject. A ,
Connecticut Public Act requires the DPUC to conduct a study of external costs and l benefits related to energy consumption and look into whether a system of allowanc-es, offsets, or adders should be established when analyzing new energy projects.
The DPUC must submit a report of its findings and recommendations to the Joint
. . - . ~ . - --- . . - .. - -. - - - - - ..- .. - -- - -- .-...-. - - - -
l IV 9 Standing Committee of the General Assembly on or before 1/1/94. The Company i
will cooperate fully with the DPUC to efficiently explore this matter.
a j
Availability and Price of Fuels i
The principal fossil fuel options for long term supply are coal,' oil, and natural gas.
[ Renewable resources are expected to play a role, especially as newer technologies such as photovoltaics become more competitive through further progress in their development. The extent of renewable technology contributions will depend on availability of acceptable sites and their economics.
1 Coal will likely remain the most stable and economic fossil fuel but requires capital-intensive generating technologies and pollution control equipment to be feasible.
{
! Any CO, reduction efforts may add significant costs to using this fuel.
With increased availability and the CAAA push for cleaner SO, emissions, natural gas l
! l l' has become a popular choice for new generation. Whether gas will continue to be the preferred choice over the long term will depend on the reliability of its supply during times of system need.
Because of its major dependency on foreign sources and the availability of more secure fossil fuels on this continent, i.e., natural gas and coal, oil will not likely be an J l
option for new utility supply except as a supplemental or backup fuel.
Technoloav Proaress While the progress in new technology can be projected, any unforeseen advances or delays can influence the availability and attractiveness of a specific supply techno-logy for the long term. The Company continually monitors the progress of all practical supply options to stay abreast and alert to any opportunities for use of improved technologies in its service area. NU's Sunolv Screenino document will be updated during 1993.
Existina Sites The future solicitation of new supply resources willlikely be through competitive RFPs. Such an environment may result in both proposed projects by third parties and utilities being selected to meet future needs. in either case, for projects of any significant size, i.e., greater than 50 MW, the availability of suitable sites will be critical. Therefore, existing sites with their established land use, environmental impacts, and existing transmission system interconnections will continue to be desired and very competitive locations for future electric generation plants. As the Company moves closer to its year of need,it wi!! need to examine carefully its options at its existing sites and to plan for the continued use of these critical resources.
Nuclear Relicensina NU operates five nuclear units: Millstone Units 1,2, and 3 (in Connecticut);
Connecticut Yankee (in Connecticut); and Seabrook (in New Hampshire). NU also has entitlements in two other nuclear units: Vermont Yankee and Maine Yankee.
IV-10 The Nuclear Regulatory Commission (NRC), initially the Atomic Energy Commission (AEC), issued operating licenses that expired 40 years from the date of construction permit issuance. In more recent years, NRC practice has been to issue operating licenses valid for 40 years from operating license issue date, which adds at least several years to the length of actual plant operation. For those units whose licenses were based on construction permit issuance, the NRC has authorized amendments to cover the years of construction,if the unit's operator applies for the extension.
l
' Except for Maine Yankee, all of the units in which NU has entitlement have licenses that reflect the longer operating interval. . These license expiration dates are given l j
below, ;
License Exo# ration Unit 1 Connecticut Yankee 06/2g/2007 Maine Yankee 10/21/2008
' Millstone 1 '
10/06/2010 Vermont Yankee 03/24'/2012-Millstone 2 07/31/2015 Millstone 3 11/25/2025 Seabrook 10/17/2026 Beyond these license extensions that recapture the construction period NU has not <
pursued nuclear plant license renewal (operation beyond 40 years) although this option remains open. In 1991, the NRC issued new regulations goveming the license renewal process. In addition to reaffirming the continuation of rigorous '
review, oversight, inspection, and maintenance, licensees must demonstrate that any potential age-related degradation is identified and satisfactorily addressed.
The nuclear plants that NU operates have historically performed better than the industry average. However, in the past two years, nuclear plant performance at NU has not met NU's high standards, in response to this, NU has developed and is implementing a Performonce Enhancement Pr > gram to improve regulatory and operating performance at the Connecticut Yankee and Millstone Stations. The program is focused on the improvement of the critical areas impacting the overall performance of the nuclear program.
The Company monitors the effectiveness of the process, initiatives, and programs under way at NU to achieve excellence. Performance is reviewed in detail periodical-l
- j. ly, with corrective action taken to change performance which shows signs of not achieving desired goals, l
in addition, a pilot incentive program is in place for 1993 for key managers in the nuclear program. This program is designed to help focus Nuclear Group resources on the achievement of key operational performance and reliability results while at the same time meeting budget goals.
I The collective objective of these programs is to restore the reliability of the NU generation units to the desired level.
l h
IV-11 i TABLE lV 1 NORTHEAST UTILITIES WHOLLY OWNED GENERATING UNITS BY CATEGORY AND COMPANY AS OF JANUARY 1,1993 This table shows the list of all wholly owned generating units presently installed on the Northeast Utilities combined system, arranged in BASE LOAD, INTERMEDIATE. PEAKING, PUMPED STORAGE. and HYDRO categories. Base load units are typically operated around the clock, intermediate units are those used to supply additional load required over a substantial part of the dey, and peaking units supply power usually during the weekday hours of highest demand. On occasion, some of the more efficient intermediate units operate as base load units, while others may be called upon to operate as peaking l
capacity. Accordingly, these categories are intended to be generally descriptive yet not definitive. Pumped storage units store low cost energy available during off peak penods for re-use during high cost on-peak periods. Hydroelectric units may operate as base load.
intermediate, or peaking capacity depending nn the availebility of water, which tends to vary seasonally. The ownership of all units is designated by operating company and location by town and state.
Deferred Retirement Units and Reactivated Units are listed separately. These units are l-l operating beyond their original planned retirement dates. The decision to remove these
(
units from service will depend on many factors, in addition to the wholly-owned generating capacity listed in Table IV-1, the NU combined system has contractual interests in other generating capacity in New England by virtue of long- and short term purchase contracts. A complete summation of net capacity available l (including capacity purchases and sales) as of January 1,1993, and as of August 1, 1993, is presented in Table IV-2.
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l\/.12 TABLE IV 1 (Page 1 of 3)
NORTMEAST UTILITIES STSTEM WN0LLY OWNED GENERATING UNITS SY CATEGORY AND COMPANT AS OF JANUARY 1, 1993 (NOTE 1) l WINTER SLMMER OWNER $ NIP 7.
RATING RATING YEAR - -
(MW) (MW) INSTALLE0 LOCATION CL&P WMEC0 MWP PSNN BASE LOAD I Nuclear l Mittstone Unit 1 659.50 641.03 1970 Waterford, CT 81.0 19.0 l Millstone Unit 2 874.50 873.10 1975 Waterford, CT 81.0 19.0 l Nuclear Subtotal 1,534.00 1,514.13 fossit Steam Middletown Unit 3 245.00 236.00 1964 Middletown CT 100.0 Mount Tom . 147.00 146.00 1960 Notyoke, M 100.0 Merrimack Unit 1 113.50 '112.50 1960 sow, NH 100.0 Merrimack Unit 2 320.00 320.00 1968 sow, NH 100.0 Fossit steam Subtotal 825.50 814.50 Base Load Total 2,359.50 2,328.63 INTERMEDIATE Fossit Steam Devon Unit 7 109.00 107.00 1956 Milford, CT 1 00.0 Devon Unit 8 109.00 107.00 1956 Milford, CT 100.0 Middletown Unit 2 120.00 117.00 1958 Middletown, CT 100.0 Middletown Unit 4 400.00 400.00 1973 Middletown, CT 100.0 Montville Unit 5 82.00 81.00 1954 Montvitte, CT 100.0 Montville Unit 6 410.00 410.00 1971 Montvitte CT 100.0 horwalk Harbor Unit i 164.00 162.00 1960 morwalk,67 100.0 Norwalk Harbor Unit 2 172.00 168.00 1963 Norwalk CT 100.0 West Springfield Unit 3 106.30 107.30 1957 W. Springfield, MA 100.0 Schitter Unit 4 47.50 47.50 1952 Portsmouth, MN 100.0 Schitter Unit 5 49.60 49.60 1955 Portsaouth, MN 100.0 i Schiller Unit 6 48.00 48.00 1957 Portsmouth, NH 100.0 j Newington Unit 1 406.00 406.00 1974 Newington, NH 100.0 Suetotal 2,225.40 2,210.40 Intermediate Totat 2,225.40 2,210.40 PEAKING Cas Turbine and Oleset Cos Cob Units 10,11 and 12 68.60 54.65 1969 Greenwich CT 1 00.0 Devon Unit 10 19.20 17.20 1966 Milford,6T 1 00.0 Middletown Unit 10 22.00 17.20 1966 Middletown, CT 100.0
! Montvitte Units 10 811 5.50 5.50 1967 Montvitte CT 1 00.0 l Norwalk Harbor Unit 10 17.00 12.30 1966 Norwalk,61 100.0 l South Meadow Units 11 14 195.60 155.80 1970 Hartford, CT 100.0 West Springfield Unit 10 22.00 14.30 1968 W. Swingfield, MA 100.0 Swans Fatts Units 1 3 3.00 3.00 1948 F. W rs. ME 100.0 Lost Nation CT 18.30 13.65 1969 North e rland, NN 100.0 Schitter Jet 22.00 17.00 1970 Portsmouth, NN 100.0
, Merrimack Jet 1 2 44.60 34.00 1968,1969 Sow, NH 100.0 l White Lake Jet 22.15 18.70 1968 Tamworth, NH 100.0 Subtotal 459.95 363.30 1
1
l\/-13 TASLE IV 1 l (Pope 2 of 3) l NORTNEAST UTILITIES SYSTEM WHOLLY OWNE0 GENERATING UNITS SY CATEGORY AND COMPANY A5 OF JANUARY 1, 1993 (NOTE 1)
I 1
WlutER SUMMER OWNER $MIP 1 RA1FMG RAffmE FEAA - - ..... I W)
W) IW51ALLEO LOCATION CL&P WMEC0 MWP PSNH I
PEAKING (CON'T) l
............... I 1
Deferred Retirement Units:
Doreen Unit to 21.20 16.60 1969 Pittsfield, MA 100.0 Franklin Drive Unit 10 22.00 17.20 1968 Torrington, CT 1 00.0 Torrington Terminal Unit 10 21.80 17.20 1967 Torrington CT 100.0 i Tunnet Unit 10 20.80 16.85 1969 Preston,Cf 100.0 Woodland Road Unit 10 21.20 16.60 1969 Lee, MA 100.0 Subtotal 107.00 84.45 Reactivated Units:
arenford Unit 10 21.00 14.90 1969 Branford, CT 100.0 Subtotal 21.00 14.90 Gas turbine and Dieset smotet 587.95 462.65 Peaking Total 587.95 462.65 i
PUMPED STORAGE l l
i Northfield Mt. Unit 1 270.00 270.00 1973 Erving, MA 81.0 1o.0
- Northfield Mt. Unit 2 270.00 ' 270.00 1973 Erving, MA 81.0 19.0 l Northfield Mt. Unit 3 270.00 270.00 1973 Erving, MA 81.0 19.0 Northfield Mt. Unit 4 270.00 270.00 1972 MA 81.0 19.0 i
Rocky River 30.35 29.35 1929 Erviglford,CT New Mi 100.9 Pumped Storage Total 1,110.35 1,109.35 l
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IV.14 TABLE IV 1 (Pepe 3 of 3)
NORTMEAST UTILITIES SYSTEM WHOLLY OWNED GENERATING UNITS BY CATE00RY AND COMPANY As DF JANUARY 1, 1993 (NOTE 1)
WINTER tuleqER OWNERSHIP - 1
- +**-
RATING RATING YEAR (led) (NW) INSTALLED LOCAfl0N CL&P 6SIECO NWP P$NH CONVENTIONAL NYORO 0.28 0.06 1905 L1tchfield, CT 100.0 Sentes Unit 1 New Mitford, CT 100.0 Butts Bridge Units 1 6 8.40 8.40 1903 53.00 53.00 1915,1916,1917 Montaeus, MA 100.0 Cabot Units 1 6 Chicopee MA 100.0 Owleht Units 2,3 4 1.70 1.52 1920 9.74 1914 Canaan,df 100.0 FallsVitleseunlts13 11.00 3.70 3.70 1904,1914,1925 sucktend, MA 100.0 Gardners Fetts unitt 2 5 Notycke NA 100.0 Notyoke Water Power Co. (NOTE 2) 43.56 43.56 Indien Orchard Units 3 3.70 3.70- 1928 springfletd,MA 100.0 Putts Bridge Units 2,3,4 4.10 3.97 1918 Ludlow MA 100.0 4.50 4.50 1926,1934 Witbre$sm,MA 100.0 Ped erldee units 3,4 Colebrook CT 100.0 Robertsvitte Units 1,2 0.62 0.31 1924 2.20 1.67 1937 Wincties,67 100.0 scottend unit 1 42.95 1955 southbury CT 100.0 shepous Unit 1 43.40 28.90 28.95 1919,1936 Monroe 100.0 1906,1926,1949 Norwic$,Cl Stevenson Units 1-4 CT 100.0 Taftvitle units 1 5 2.03 2.03 Tunnet Units 1,2 2.10 1.42 1919,1949 Preston, CT 100.0 Turners Falls Units 1 3,5,7 6.25 6.25 1905,1910,1913 Montague, MA 100.0 17.50 1923 Manchester, NH 100.0 Amoskees 17.50 100.0 9.08 9.08 1925 New Neopton, MN Ayers lateruf V 100.0 Ceneen 1.10 1.10 1927 6.47 1937,1983 Consenln,T Frankl NH 100.0 Ecsts.an Fet ts 12 6.47 100.0 Gervins 1 4 10.55 10.55 1925,1981(1&2) sow, NH 1920 Gorham, NH 100.0 Gorham 2.05 2.05 100.0 1.90 1.90 1927 Nooksett, NM Nookset NILtsboro, NH 100.0 Jackman 3.55 3.60 1925 100.0 setth 15.31 13.08 1948 serLin, NH Conventional Nydro Totet 286.95 281.06 NORTHEAST UTILITIES SYSTEM neELY OWNED GENERATING CAPACITY .
EXCLUDING DEFERRED RETIREMENT UNIT $ AND REACTIVATED UNITS 6,442.15 6,292.74 ,
DEFERRED RETIREMENT UNITS j GENERATING CAPACITY 107.00 84.45 CEACTIVATED UNITS GENERATING CAPACITY 21.00 14.90 TOTAL GENERATING CAPACITY 6,570.15 6,392.09 NOTEst (1) This table does not ref test long term or short term cepecity purchases or setos, life of wilt contract er a listing of generating units in which the merged system has joint ownership with other estes,ies.
utilit That inforsetlem appears on TABLE IV 2.
The mits are dispatched (2) Notyoke Water Power Co. hydro mits are powered from a cosemon const system.The units' Individual retings together. The reported capabilities are the e9ere9ete for the cogtex.
and instellation detes are:
StatlerVunf t Name Plate Retines(MW) Year instetted 2 0.60 1947, 1948 Beebe toottockNottrook Units 1-Units 1,3 2.90 1921, 1924, 1924 units 1,2 1.60 1935, 1935 chealce1 1952, 1983 i
Medley Fetts Units 1,2 31.00 Riverside Units 4,5,7,8 7.00 1920, 1905, 1921, 1931 l 1924 Skimer unit 1 0.30 l
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IV-15 l
TABLE IV-2 NORTHEAST UTILITIES SYSTEM NET CAPACITY AVAILABLE BY GENERATION AND SUPPLY CATEGORY AS OF JANUARY 1,1993, AND AUGUST 1,1993 Table IV 2 identifies the Northeast Utilities actual net capacity available by generation and supply category as of January 1,1993 (Winter 1992/1993) and August 1,1993 (Summer l 1993). it includes the Northeast Utilities system's wholly owned capacity and entitlements in other New England units, together with contracted short-term capacity purchases and sales and life-of-unit contract sales with other utilities. and contracted non-utility generation. The item under each unit category entitled " Wholly Owned" refers to l
capacity totals for that category listed in Table IV-1.
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~ .. . _- _- - -- -- _. .- -. _ . _ _ ._ -. . - - -
l\/.16 TABLE IV 2 (Pope 1 of 4)
NORTNEAST UTILITIES SYSTEM WET CAPACITY AVAILABLE BY GENERATION AND SUPPLY CATEGORT AS of JANUARY 1, 1993.AND AUGUST 1, 1993 (NOTE 1)
Winter Ratins SUNuor Rating
- --- - 1992/93 1993 (MW) (MW)
BASE LOAD ............. .............
Whetty owned Nuclear 1,534.00 1,514.13 Muclear Entitlements: 773.19 Mittetone Unit 3 781.33 Connecticut Yankee, Neddam, CT 280.03 265.84 Vermont Yankee, Vernon, VT 72.73 69.46 Meine Yankee, Wiscosset, ME 153.91 152.16 Seebrook 1 455.74 455.74 subtotal Nucteer 5,k77$71 $$k5b$55 Millstone Unit 1 Sales to: .(29.16)
Boston Edison (30.00)
Canat Electric (4.29) (4.17)
Fitchburg (2.15) (2.09)
MMWEC (3.76) (3.65)
Monteup (4.29) (4.17)
NEPC0 (16.10) (15.64)
UNITIL (4.29) (4.17)
Rowley (0.03) (0.03)
Millstone Unit 2 Sales to: (30.39)
Boston Edison (50.44)
Canat Electric (4.32) (4.32)
Fitchburg (2.18) (2.17)
MMWEC (3.81) (3.80)
Montaup (4.32) (4.32)
NEPCO (16.21) (16.18)
UNITIL (4.35) (4.35)
Rowley (0.03) (0.03)
Mittstone Unit 3 Sales to:
Boston Edison (59.62) (59.00)
Canat Electric (6.97) (6.90)
Fitchburg (3.49) (3.45)
MMWEC (6.10) (6.04)
Montaup (6.97) (6.90)
NEPC0 (26.14) (25.87)
UNITIL (6.97) (6.90)
Rowley (0.03) (0.03-Seabrook Sale to Rowley (0.03) (0.03)
NMEC Buyback 25.00 25 . 00 Nuclear Life of Unit Contract Sales to CMEEC ( 68.76 ) (67.47)
Nuclear Life of Unit Contract Setes to Watlingford (NOTE 2) (31.15) (30.55)
EXCHANGES OF CAPACITY:
Millstone Unit i From CNEEC 3.80 3.74 Net Nucteer subtotat '2,959.74 2,917.48 825.50 814.50 Wholly owned Fosell Steam:
Middletown Unit 3 Sales to:
Canal Electric (24.10) (2.02)
Chic y (2.58) (2.48)
Fitch W e (1.05) (1.01)
MMWEC (1.84) (1.77)
Monteup (2.10) (2.02)
MEPC0 (7.87) (7.58)
UNITIL (2.10) (2.02)
Rowley (0.08) (0.08)
Merriseck Units 1 & 2 Sete to Rowley (0.06) (0.06) l Lone Ters Fossil Satest (100.00)
Merrimack Unit 2 Sale to VELCO (100.00) j Fossil Steam Life-of Unit Contract Sales to CNEEC (9.48) (9.13)
Fossil Steam Life-of unit Contract Sales to Watlingford (NOT (9.62) (9.27)
System Power Sete to CU (5.00) (5.00)
Net Fosell Subtotet 659.62 672.06 3,619.56 3,589.54 NET BASE LOAD TOTAL i
I l\/.17 l TABLE IV 2 (Pege 2 of 4)
NORTHEAST UTILITIES SYSTEM
-NET CAPACITY AVAILABLE BY GENERAT!DN AND SUPPLY CATEGORY AS OF JANUARY 1, 1993 AND AUGUST 1, 1993 (NOTE 1) ,
Winter toting Summer anting 1993 1992/1993 l I I (MW) (MW)
INTERMEDIATE Whotly owned Fossil Steen Excluding Deferred astirement Units 2,225.40 2,210.40 j
Subtotet 2,225.40 2,210.40 l Fosell Steam Entitlements:
farmouth Unit 4, Yarmouth, ME 19.46 19.32 Long Tern Fossil Seleen j Newineton sale to CU (2.50) (2.50)
(
SNORT TERM SALES:
l Middletown Unit 2 Sales to:
Chicopee (1.26) (1.23) sowley (0.08) (0.08)
Middletown Unit 4 Sales to:
Canal Electric (33.42) (3.42)
Chic y (4.21) (4.21)
Fitchwrg (1.71) (1.71) ;
MMWEC (3.00) . (3.00) 1 Monteup (3.42) (3.42) l NEPCO (69.84) (69.84)
UNITIL (3.42) (3.42) sowtw (0.30) (0.30)
Montvitte Unit 5 Sales to:
Chicopee (1.33) (1.32) .
a Montville Unit 6 Sales to:
Canet Electric (3.51) (3.51)
! Chic y (6.67) (6.67)
Fitchwrg (1.75) (1.75)
MMWEC (3.07). (3.07) konteup (3.51) (3.51) i NEPCO (13.15) (13.15) l UNITIL (3.51) (3.51)
Rowley (0.30) (0.30)
Newington Sale to Routey (0.08) (0.08)
Yarmouth Unit 4 Sale to Rowley (0.08) (0.08)
Norwalk Harbor Unit 1 Setes to: ;
Canal Electric (1.40) (1.39) l Fitchburg . (0.70) (0.69) !
MMWEC (1.23) (1.21) nonteup (1.40) (1.39)
NEPCC (5.27) (5.20) l UNITIL (1.60) (1.39) l (0.08) i nowley (0.08) l Norwalk Narbor Unit 2 Sales to: (1.44)
Cenet Electric (1.47) i Fitchburg (0.74) (0.73)
MMWEC (1.30) (1.27) l honteup (1.47) (1.44) l NEPCO (5.52) (5.39)
UNITIL (1.49) (1.45) sowley (0.08) (0.08) l.
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T TABLE IV 2 (Pepe 3 of 4)
NORTHEAST UTILITIES SYSTEM .
NET CAPACITT AVAILABLE BY GENERAfl0N AND SUPPLY CATEGORY AS OF JANUARY 1, 1993 AND AUGUST i, 1993 (NOTE 1)
Ule - . Rating Sueuer Rating 1992/1993 1993 gag) )
gmyj INTEEBEDIATE (CON
..................'T)
(60.57) (60.04).
feasil Steam Life of Unit Contract Sales to CMEEC (63.63) (62.73) .
Feesit Steam Life of Unit Contract Sales to Wallingford (NOT (7.67)
System Sale to Borrah (7.67)
EXCNANGES OF CAPACITY:
(10.00) (10.00)
Morwalk Harbor Unit 1 to CMEEC (10.00) (10.00)
Norwalk Marbor Unit 2 to CMEEC 35.00 25.00 New Neven Narbor from U1 0.00 25.00 l System Exchange from UI ......... ......... ;
1,944.31 1,976.06 NET INTERMEDIATE FOSSIL STEAM TOTAL J
....... )
PEAKING I Wholly owned Gas Turbines and Olesels:
1 459.95 363.30 Emetuding Deferred Retirement Units 107.00 84.45 Deferred Retirement Units 21.00 14.90 Reactivated Units ........ ........ ,
i 587.95 462.65 SetotaL SHORT TERM SALES:
Coe Cob Units 10-12 Sales tot (0.67) (0.52)
Canal Electric (0.33) (0.26)
Fitchburg (0.46)
IpIWEC (0.59)
(0.67) (0.52) stonte@ (2.49) (1.96)
NEPCC (0.67) (0.53)
UNITIL South Meadow Units 11 14 Sales to: l (1.91) (1.52) '
Canal Electric (16.00) (12.74)
Chicopee (0.76) l Fitchburg (0.96) ~
(1.67) (1.32)
MMWEC (1.91) (1.52)
Montaup (7.11) (5.67)
NEPCC (21.87) (1.52)
UNITIL (7.99) 0.00 vtGAT (0.70) (0.53)
Iterrimack CT Units 1 & 2 Sale to Rowley ,
(2.46) (2.03)
Peeking Llfe of Unit Contract Sales to CMEEC (7.99) (6.39)
Peeking Llfe of Unit Contract Sales to Ustlingford (NOTE 2)
l\/.19 J
l I TABLE IV 2 l
(Pege 4 of 4) l NORTHEAST UTILITIES SYSTEM NET CAPACITY AVAILABLE BY GENERAflou AND SUPPLY CATEGORY AS OF JANUARY 1, 1993 AND AUGUST 1, 1993 (NOTE 1)
.....................p...........................................
Winter Rating Super Rating 1992/1993 1993
............... gng) guy)
PEAKING (CON 8T) l ...............
EXCHANGES OF CAPACITY:
South Norwich 1 From CMEEC 5.07 4.95 South Norwich 2 5 From CMEEC 10.50 10.12 0.63 1.94 Norwich Jet From CMEEC Cos Cob Units 10 12 to United Illuminating (42.00) (45.00)
South Meadow Units 11 14 to United Illuminatine (42.00) (75.00)
Net cas Turbine and Olesel Subtotal 444.17 321.39 NET PEAKING FDS$1L TOTAL 444.17 321.39 I PUMPED STORAGE I
1,110.35 1,109.35 Wholly Owned Ptaped Storage:
Northfletd Units 1*4 Sales to: (180.00)
Boston Edison (180.00)
Canal Electric (10.72) (10.72) 4 Fitchburg (4.96) (4.96) l MMWEC (8.68) to.68) i i
Monteup (10.72) (10.72)
NEPCO (40.16) (40.16)
UNITIL (9.92) (9.92) i l
Northfield Life-of unit Contreet Sales to CMEEC (12.60) (12.60)
Northfield Life of Unit Contract Sales to Wettingford (NOTE (10.00) (10.00) l 822.59 821.59 NET PUMPED STORAGE TOTAL 1
.................. ]
1 CONVENTIONAL MYDRO 286.95 281.06
! Whatty owned Conventional Hydro:
Cony. Hydro Life-of-Unit Contract Sales to CMEEC (6.64) (6.61) l Conv. Hydro Life.of Unit Contract Sales to WelLingford (NOTE (3.01) (2.99)
Cobble Mountain Purchase, Springfielo, MA 33.96 33.98
" " ~ " " " ~~~~~~~~~
311.26 305.44 NET CONVENTIONAL HYDRO TOTAL C0(,ENERAfl0N AND SMALL POWER PRODUCTION .
635.61 652.25 Capacity Committed to NU: 635.61 652.25 NET COGENERATION AND SMALL POWER PRODUCT!0N
............................... 2.99 3.39 NEW YORK P:.vER AUTHealTY (NYPA)
............................... 3.39 Nff NYPA 2.89 WORfKsAST UTILITIES COMBINE 0 SYSTEM 7,730.19 7,6b9.66 TOTAL NET CAPACITY AVAILABLE ......... .........
NOTES:
i (1) Flpures in perenthesis are negative and indicate cepetity setes from the NU system.
(2) The Wettingford loads have not been included in the tood forecast.
It is expected that the agreement will be finettred in 1993.
i IV-20 TABLE IV-3 NORTHEAST UTIUTIES SYSTEM GENERATING UNITS UNDER CONSTRUCTION AS OF JANUARY 1,1993 NONE 4
e 9
l l
._. . . . _ . - . . _ _ . _ _ . _ . _ _ . _ _ _ _ _ . _ _ . _ _ _ . . ~ . _ . . _ _ _ _ _ . _ _ .
IV 21 TABLE IV-4 NORTHEAST UTILITIES SYSTEM n ASSUMED DEACTIVATIONS AND RETIREMENTS OF GENERATING UNITS l 1993 2012 Listed below are existing generating units which will become candidates for deactivation or retirement during the forecast period. Also provided are their current winter MW rating, location, type, ownership percentage, and the assumed date of deactivation or retirement, as reflected in Table IV-6.
It is important to note that these dates are accounting deactivation dates, not engineering retirement dates. The physical conditions of the units will allow them, with routine maintenance and repair, to _ operate beyond the assumed accounting deactivation dates.
NU retired the internal combustion units Silver Lake Units 10-13 and Tracy on May 1, 1992.
The current dates of deactivation for units is based upon the NU system's forecasted reserve requirements,its present commitments for capacity sales, and the regionalload and capacity outlook. Changes in either NU's or the regions' load and capacity situation could affect the deactivation dates shown. Consequently, the timing and order of such
. deactivations will remain under continual review and, as circumstances change, this schedule could be altered. -
As discussed in Chapter 1, the Company continues to evaluate the continued operation of its units. These evaluations may require changes to this list in the future.
Assumed .
Date of Deferred Winter Retirement or Retirement Unit MW Ownership Deactivated ML Betr}g Location Tvne Percentane Reserve Units Tunnel 10 20.8 Preston, CT Jet Turbine CL&P- 100.0 05/01/1996 Woodland Road 10 21.2 Lee, MA Jet Turbine WMECO 100.0 05/01/1996
. Torrington Termenal 10 21.8 Tomngton, CT Jet, Turtine CL&P- 100.0 05/01/1996 Franklin Drive 10 22.0 Tomngton, CT Jet Turbine CL&P- 100.0 05/01/1996 l 21.2 Pittsfield, MA WMECO 100.0 05/01/1996 f Doreen 10 Jet Turbine
. Reactivated Unit Branford 10 21.0 Branford, CT Jet Turbme CL&P 100.0 05/01/1996 i Deactivations Montville 5- .82.0 Montville, CT Steam CL&P 100.0 01/01/1995*
Montville 6 410.0 Montville, CT Steam CL&P 100.0 01/01/1995' Montville 10&11 5.5 Montville, CT Diesel CL&P 100.0 01/01/1995'
'For planning and budgeeng purposes, these units will be reactivated on 11/01/98.
l
, - . - . . . - .- ,. . = - - ~ . -~. ... - - . - - . . _- ..-.-.- ...
IV 22 t
Nuclear unit retirement dates generally correspond to operating license expirations. Analyses of life extension l are required to determine whether or not these units would retire on these dates.
4 Assumed Other Wwiter Ownership Metirement i Wholly-Owned Unit MW Iygg. Percentane Date Units A BallDA Location i
3.0 Fryeburg, ME Diesel Engine PSNH 100.0 11/01/1993 Swans Falls 13 659.5 Waterford, CT Nuclear CL&P 77.5" 10 46/2010 4 Millstone 1 WMECO 19.0 1 i
1
- *CL&P originally owned 81% of this unit CMEEC negotiated a long-term purchase for 3.4936 percent ownership entitlement in this unit.
9 t
1 i Life of Urwt Entitlements 1
590.0 Haddam Neck, CT Nuclear CL&P 33.0 06/29/2007 Connecticut YarAce WMECO- 9.5 PSNH - 5.0 880.0 Wiscasset ME Nuclear CL&P 10.3 10/~
- t2008 Maine Yankee WMECO- 2.7 PSNH - 4.5 Vemon VT Nuclear CL&P - 8.2 03/24/2012 Vermont Yankee 519.3 WMECO- 2.3 PSNH - 3.6
l 1 c
, l IV-23 I
l TABLE IV 5 NORTHEAST UTILITIES SYSTEM 1993-2012 FORECASTED NEW GENERATING ADDITIONS !
i '
l
)
l Forocasted New Generating Additions
{
l I
l NONE CONTEMPLATED DURING THE 1993 2012 FORECAST PERIOD. !
! I 1
i !
l l
l l
l l I
i l
l 8
I N
1 I
IV-24 :
TABLE IV-6 NORTHEAST UTIUTIES SYSTEM ,
1993 2012 FORECAST OF l
GENERATING CAPACITY AT THE TIME OF WINTER AND SUMMER PEAK The format of Table IV-6 develops the total NET CAPACITY AVAILABLE and relates this l
~
capacity to the peak system demand forecast for 1993 2012, as given in Chapter 11.
NET CAPACITY AVAILABLE is made up of existing wholly owned generating units as -
detailed m Table IV-1, generating additions as shown in Table IV-3, the NU system's ,
entitlements in other units, and the NU system's share of the capacity from exchange and ,
purchase contracts with other utilities and non-utility generators like those shown in l Table IV-2. .
This subtotal is then reduced by assumed retirements as shown in Table IV-4, sales under capacity exchange contracts and long-term and short term contract sales like those shown !
in Table IV 2, resulting in NET CAPACITY AVAILABLE to meet system peak load. require- j ments.
NU SYSTEM ENTITLEMENTS IN OTHER UNITS represent the system's entitlemen'.s in Millstone Unit 3, Seabrook 1, Yarmouth 4, and other New England Yankee nuclear units.
The Yankee entitlements shown are a result of power purchase contracts with each of the ;
Yankee corporations. The purchase contracts are for the life of the unit. This line item
- decreases to reflect license expirations as shown in Table IV-4. The system companies
' also have a stock ownership in each of the Yankee companies generally proportional to their enutlements in the units.
t CAPACITY EXCHANGES: ltemized in this category are agreements to exchange entitle-ments in the Northeast Utilities system units for entitlements of capacity in other units.
These arrangements are shown as RETURN OF CAPACITY EXCHANGES and Cf.F'ACITY T
EXCHANGES. These are not exchanges in ownership of a unit, but rather contractual exchanges in the unit's output, designed to accommodate short-term surpluses and l shortfalls in the different generating mix of each system. The purpose of an exchange-retum arrangement is not only to improve a system's generation mix, resulting in a mo:e i
economic dispatch and lower costs, but also to spread the risk of outages by reducing the i dependence of a system on a particular generating unit. The NU system exchanges ;'
capacity on a week to-week or month-to-month basis to achieve overall system econom-ies.
PURCHASES: The entries in this category include the Cobble Mountain hydroelectric !
facility, the NU system's share of Connecticut's allocation associated with the St.
Lawrence Hydroelectric Project as operated by the New York Power Authority (NYPA), !
short-term system purchases from sources outside of New England which are being mada ,
to reduce customers' costs, and capacity purchased from cogeneration and small power production projects for which the system has regulatory approval (including the results of '
the 54 MW WMECO solicitation). Additional projects may become available in the period covered by this report. Purchases from outside of New England are shown net of transmission losses. ,
i i
~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _
. - .- .- ~. . . - . --. .. .. . - . -. - ._. . . . . _ - . . - . . - - . . - _
l IV 25 DEACTIVATIONS / RETIREMENTS: This category is comprised of the " deferred retirement units," the "refectivated units," and "other wholly-owned units" details for which are shown on Table IV-4. The amounts shown are based on assumptions current as of this forecast preparation. Consequently, the timing and amount of deactivations will be under l
continual review, and as circumstances change, the schedule will be altered. 1
(
CAPACITY SALES: The first item refers to life-of-unit contracts from certain Northeast Utilities system generating units including the New England Yankee nuclear units to the Connecticut Municipal Electric Energy Cooperative (CMEEC) and to Wallingford.
Wal lingf ord's load has been removed from the load forecast. The sales agreement is expected to be finalized in 1993.
l l- The other item under this heading refers to contracts of varying durations with other utilities, f
J j Similar long term sales not known at this time may be made for periods covered by this report.
l I
NORTHEAST UTILITIES SYSTEM CAPACITY SITUATION 1993-2012: Table IV 6 summa- !
rizes the twenty-year load and capacity situation for the system during the winter and summer peak periods of 1993 through 2012. The table also shows the system's reserve margin expressed in megawatts and as a percent of forecasted coincident peak loads. Not shown on the table are the NU system's commitments to the Hydro-Quebec Phase I and 11 contracts, interruptible load contracts, and load control measures. These elements of the '
l resource plan will reduce forecasted reserve requirements.
I l
1 i
l I
4 0
TASLE IV-e (PAGE 1 0F 5)
NORTMEAST UTILITIES SYSTEst 1993-2012 FORECAST OF CAPACITY AT THE TIME OF WINTER AND SU,44ER PEAK (AS OF JANUARY 1, 1993)
............................................................................ i 1NR$
99 1 1
R$ .......
99$ 1 1
....... ....... 7
$ $ ""sN N 'RRENTfRfiqN' SITS 6,44g15 6,292.74 6,44}.15 6,292.74 6,44g15 6,292.74 6,44)15 74 6, . 6,79. '
10 00 84.45 to .00 84.45 10 84.45 6,292.E4 1E.4 OEFERREO RETIRE 8EENT UNITS
=ACTimTED uun$ .. 2 h" ..!h" . 23= ,,33= ,,23,, 8 ,,33w to E
,,2h.. ..I..h.. ....:..
...t:.. I susT0TAL EXISTING WHOLLY OldNED GENERATION 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09
[
NU SYSTEM ENTITLEMENTS IN OTNER U, TITS t MiItatone Unie 3 781.33 773.19 781.33 773. 781. 773.19 781. 19 781. .19 i seetrook untt 1 455.74 455.74 455.74 460. 460. 460.46 460. 48 40. !
Existine Yankee Units 506.67 487.47 506.67 487.4 506. 487.47 506. 47- 506. i Yannouth 4 19.46 19.32 19.46 19.32 19.46 19.32 19. 19.32 19.46 19.
, G
""g" [C ,$' [,"*""" R:3 R:2 R:" R:2 R:3 R:2 R:3 R:2 4:R 4:5 I
chepeounteln .96 33.98 33.96 33.98 .96 33.98 33.96 .98 96 .98
- s f,,9=1) : :P .... g : :q :
.,.$..:P1.G.5.j:[ 3:$.. .,.3...f.i Cogeneret en and Smett Pouac h tfen .... P.1 .,
3...:[..
.... . .. .... 6. .d.e. .
'1 9,153.87 8,910.99
.... [ ..
t SUBTOTAL 9,085.81 8,91?.18 9,155.31 8,918.24 9,140.37 8.931.74 9.173.87 8,931.74 R to RETIREIENTS/SEACTInfl0NS tNOTE 4) m ceferred Retirement units .g 0.00 .g g.00 0.00 . (1 . . !
d '* ..."." ...
..!". b . . !'.';".". I !$#{} .{ {} {w,.jn,,)
,, { m,{w) { {
{n,jn,,b
, l 0.00 (598.85) 5 RETIREMENTS /SEACTi mTIONS SUBTOTAL 0.00 (3.00) (3.00) (500.50) (499.50) (500.50) (598.85) (628.50) .
i
- "E'c'EI.,0 e, t ten IR:E (IR:2 (1R:2 (IR:2 (15:2 (1R:2 (IR:2 (15:2 oJ:R> oJ:Ri !
CAPACITY SALES i tll,:,'ua'=caa*=
o 15:2 15:2 flR:2 IIR:2 15:2 !M:E IRt:E IM:E IM:2 IM:E ....... ....... ....... .......
I susT0TAL (Larg/SI, ort-Tenn 1stes) (1,305.62) (1,243.52) (985.59) (969.12) (T35.67) (T23.89) (672.53) (660.76) (662.53) (450.76) 7,780.19 7,669.66 8,166.72 7,946.12 7,924.20 7,708.35 8,000.84 7,672.13 7,862.84 7,461.38 NET CAPACITY A MILABLE Lead 6,000.00 6,089.00 6.189.00 6,19T.00 6,176. 3 6,304.00 6,431.00 6,453.00 ~6,541.00 6,594.00 E em P
,(,,0TE 6) 1,780.19 i,e00. 6 i,977.72 i,749.52 i,628.20 i,404.35 i,5 9. 4 i,22 ,.i3 1,32i.84 i. 67.38 l
. .R. .
29.67 26.37 31.96 28.23 25.86 22.28 24.41 18.89 20.21 16.19 j TOTAL RESERVE - x i
i
TAttE IV-6 (PAGE 2 0F 5)
NORTMEAST UTILITIES SYSTEM 1993-2012 FORECAST Or CAPACITY AT inE TIME OF ulNTER AND SUMMER PEAK (AS OF JANUARY 1, 1993)
WINTER SLpoER WINTER SupeER WINTER StroER WINTER SLpuER WINTER mpeER 1997 1998 1999 2000 2001 2001/02 .. 2002
..../.98 .. ....... 1998/.99
.... . ....... 1999/.00
.... .. ....... 2000/.01.... ......... ...... ..
EXISTING WMOLLY CWNED GENERATION 6,292.74 6,292.74 6,442.15 6,292.74 6,44 .15 6'292*74 15 ENCLtSING DEFERRED RETIREMENT tpflTS DEFERRED RETIREMENT UNITS 6,44p15 10 00 84.45 6,44).15 10 .00 84.45 107.00 84.45 10 00 84.45 6'h.*00 6'k"74 45 14 14 14.90 14.90 21.= 14.90 REACTIVATE 9 UNITS . 21.00
.... .... 90 .. . 21.00.... .... 90 .. . 2.1.00 ... ....... . 2.1'.00 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6[EE$b9 6[5fb$i5 6,Ei[bh SusTOTAL EXISTING WMOLLY OWNEO GENERATION "U I M t 3 781 33 III 19 781 33 II3 19 781 33 II3 19 781 33 19 781 33 II3 19 Seebr Unit 1 460.48 460 48 460.48 460.48 460.48 460.48 460.48 II3.48 460 460.48 460 46 506.67 487.47 506.67 487.47 506.67 487.47 506.67 487.47 506.67 487.'47 Extet Yankee Units 19.46 19.32 19.46 19.32 19.46 19.32 19.46 19.32 19.46 19.32 Yorumut 4 RETWW W IgEXCMS 0.00 0.00 50.00 0.00 50.00 0.00 50.00 0.00 50.00 0.00' 50.00 O.00 50.00 0.00 50.00 0.00 0.00 0.00 0.00 g!Ced litum. (NOTE 2) 50.00 33.96 33.98 33.96 33.98 33.96 33.98 33.96 33.98 33.M 33.98 co,,Ne peamtain .00 .. .= 25.00 25.00 0.= 0. 0.= 0.= o..
N EC w) .71 .71 71 3.71 3.71 3.71 3. 1 3.71 3.71 NYPA (WTE 3 66 .75 70 .11 665.75 703.11 665.75 703. 1 665.75 700.52 66t'.71' .16 Cogeneration and sent( Power Production 70. 11 _
SUOTOTAL 9 55b 8 95b b 9, 55 b 8[95b$ b 9$555$8h 8[bb5$ U 9$558$bk 8$bb5$ h 9[bhb$k8 8$b55$db I M
4 RETIREMENTS / DEACTIVATIONS (NOTE 4) 107 84.45 (107.00p (84.45 (107.00 (84.45D (107.00 (84.459 (107.00? (84.45
.00 (14.90 (14.90 (14.90b (14.90 Defer $edRettromentUnite (g.001 (2 . (2 .
..!!:"a ..!j:g J
React veted Otwr *t 'raa'd Units
='t' !...:5..a ($'
!...:h.. (2h00
..!.:003 . ..!!:" ..i.i..(2gg . .. ..!!:"a ..!j:ga . .. ..!!:"
(628.50) (598.85) (131.00) (102.35) (131.00) (102.35) (131.00) (102.35) (131.00) (102.35)
RETIREMENTS / DEACTIVATIONS SUSTCTAL CAPACITY EXC 0.00 0.00 0.00 0. 0.00 0.00 0.00 0.00 0.00 0.00
@lc'yned iitum. (NorE 2) (120.00) (i20.00) (120.00) (i20. % (120.00) (120.00> (120.00) (i20.00) 0.00 0.00 i
CAPA:ITY SALES tg:,* "a c="ta"=
o .
IM:2 <!n:m(469.73)
....... ....... <!B:2(462.95)
....... ....... <!B:m ......
(449.92)
'.!!!:S.......
(443.40)
<!B:2 (449.92)
(73:2 .......
(443.40)
'!B:m (314.92)
<!E:m (308.40)
<!R:2 SUOTOTAL (Long/Short-Term Setee) (549.08) (442.29) 7,976.29 7,869.85 8,553.14 8,345.69 8,57'.9' 8,340.24 - 8,547.95 8.340.24 8,630.36 8,422.65 NET CAPACITY AVAILA8LE 6,658.00 6,717.00 6,767.00 6,831.00 6,839.00 6,885.00 6,871.00 6,959.00 6,920.00 7,022.00 PEAK EstimatedLOAD (NOTE Peat 5) Lead 1,318.29 1,152.85 1,786.14 1,514.69 1,733.95 1,455.24 1,676.95 1,381.24 1,710.36 1,400.65 RESERVE . MW (NOTE 6) 19.80 17.16 26.39 22.17 25.35 21.14 24.41 19.85 24.72 19.95 TOTAL RESERVE . 1
[
TAeLE tv-6 (PAGE 3 0F 5) l NORTMEAST U11LITIES SYSTEM-1993-7012 FORECAST OF CAPACITY AT iME TIME OF WINTEC AND SUPOEER PEAft (AS Of JANUART 1, 1993)
WINTER 5tDNER WINTER 5tsWER WINTER StseEER - WINTER R8NER WINTER 2002./.03
.. . .. 2003 ...
2003/04 2004 2004/.05 2005
....... 2005/.06
... . .....20062006/.07.. .. ......
EXISTING WNOLLY GENERATION IEfMBED .!!ll!ERT uil!!"'"' ""'
uncuvaTE0 uun$
'-@igR:E'W:2f:E'i'g3gf:2'"R:E'W:)',',g;7'~M
,,13:= . 23:= .. 3:= .. . 33:= ,,23 . ,,
',y:2
, , = ,{:g 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6,392.09 6,570.15 6.392,0@
SusTOTAL EXISTING WHOLLY CWNEO GENERATION 6,570.15
' "' .1'
- E$t unit 1 781.
460.
773.19 460.
487.
781.3 460.
506.6 773.19 460.46 487.47 781.
460.
506.6 773.19 460.46 487.47 781.33 460.48 506.67 773.19 460'48 45r.47 781. 1 460.
506.
vankee Unite 506. 19.32 19.40 19.46 19. 19.46 19.32 19.46 19.32 19.46 .
Yonnout 4 0.00 0.00 0.00 0.00 0.00 0.00 0.60 0.06 6.
""" =fi "c,M, n.$,W . u 05
- 0. 0.= 0.= 0.00 0.. 0.= 0.= 0.= 0.= OR 33.96 33.98 33.96 33.98 33.96 33.98 33.96 3 U.S6 33.98 cetbfe Isounteln
- M o 15: ?2"i) jM i:M ,,j:M ,,j:g :
.48.g -
c - est- ens ii Pe er Prese=Tien ... ,,j:H.. . .,.,..:i6 700.52
...a6 d':M 8,832.48 52
.66(: 24
_.... , 64._ ')*iJ , . ,
susTOTAL 9,076.28 8,833.40 9,076.28 8,833.40 9,076.28 9,068.74 4,813,sf 3,65iae 8,53bM $ l
$$ f nETIREMENTS/0EAgvnfl0NSjupTE4) 19:g,l. 91,:k, m;@ ,
e '!G gl 19 ,gll 917-ll ; 19:gl 4G;gl 111:21 ,5;,:,11,:g} ,,$,:,,a 4;:n ,,57...)
r
- m%"s
- r *enrw Unm"' ""no .,5,i,, .,5.1,. .5.1,, .5,,. ,,5 ,. ,,53:=a (131.00) (102.35) (131.00) (102.35) (131.00) (102.35) (131.00) (102.351 Nkt.06) (102.6) ,
RETIREMENTS /0EACTIVAfl0NS SUBTOTAL ,
""MUL T I(Nm n 3:5 I:R 8:5 8:5 8:5 8:2 8:5 8:88 !# 8:39 CAPACITY SALES W:p """ **"""" '5:2 'R:21 '5:El 'R:El '5:m 'R:El '5:2 '23:@ 9:iP tl:ii' ....... ....... ....... ....... ....... ....... m .... u....:
(311.08) (304.56) (311.08) (304.56) (311.08) (304.56) (295.87) (289.58) (285.8f) 12T1.14I susTOTAL (Lene/sleert-Tene Setes) 8,634.20 8,426.49 8,634.20 8,426.49 8,634.20 8,425.57 8,641.87 8,421.94 8,&34.73 8,159.54 NET CAPACITY AvalLASLE 6,986.00 7,0W.00 7,064.00 7,202.00 7.154.00 7,279.08 7,232.00 7,358.00 7,378.00 7,498.00 ENeeEPe'dLead 661.54 1,648.20 1,327.49 1,570.20- 1,224.49 1,480.20 1,146.57 1,409.87 1,063.94 1,256.73 ,
RESERVE - MW (NOTE 6) 18.70 22.23 17.00 20.69 15.75 19.49 14.46 17.03 8.82 TOTAL F. SERVE . x 23.59 o
___.r. . . - , - _ . , - . ,
- e .-
-1 t
i -!
TABLE IV-6 (PAGE 4 0F 5)
NORTNEAST UTIIITIES SYSTEN '
1993-2012 FORECAST OF CAPACITY AT THE TIME OF WINTER AND StpufR PEAst (45 0F JANUARY 1, 1993) +
l i WINTER SINGER WINTER SLNWER WINTER SLpuER WINTER SLNWER UtNTER SIEWER 2008 2008/09 2010
.. 2012 2007/.08
... .. ....... ....... .. 2009 .... 2009/.10
.... . ....... 2010/.11.
... .. 2011 .. . 20.11/.12 EXISTING WHOLLY OWNEO GEllERATION '
6,442.15 6,292.74 6,442 15 6,292.74 6,442.15 6,292.74 5,782.65 5,651.71 5,782.65 5,651.71 ENCLWING OEFERREO RETIRESENT tNelTS 107.00 84.45 10r.00 84.45 107.00 84.45 107.00 84.45 107.00 84.45 OEFERREO RETIREMENT 19117S REACTIVATE 0 UNITS . 2!:= ..!!:= . 3;m 2 ,,33 n ,,23 m ,,33:n ,,23 = ,,33:n ,,23 = ,,33:n sugTOTAL EMISTING WHOLLY f u n EENERATION 6,570.15 6,392.07 6,570.15 6,392.09 6,570.15 6,392.09 5,910.65 5,751.06 5,910.65 5,751.06 Nu SYSTEN ENTITLEpENTS IN OTNER UNITS 773.1' . '
Willstone unit 3 T73 19 781. 773 19 781. 773.19 781. 773.19 781.
781.g 460. 460.48 4M. 460. 40.48 460.48 Sestroek Unit 1 2
.64 2 72. 69. 4 R. 460:M 71 59 72. 71.89 46_q:
g 0. !
Existina Yankee Units .4 19. 4 19.32 19. 4 19.32 19. 4 19.32 19. 4 19.00 32 Yonmouth 4 RETWN Wp{
(,o NS 0.00 0.00 0.g
- 0. g.g 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.g 0.
i un d I t tua. (NOTE 2) .
j 33.96 33.98 33.96 33.98 33.96 33.98 33.96 33.98 33.96 33.98 .
CotubfeMounteln I: f:P 9",I:l, I- l:l *:]
wl : :9f FJ Comn-ei N@laa)and ==tt *=- Pr**'et'= .?!l.: .
[..
- i ].. 52l:28 .".:.. l:9f
.t!.:2' l:M
.t,..:95 3,',a,;,l, ,30,6::f
, 3<, ,284: _
5 8, m .77 8,u e.23 8.4a .02 8,i,3.w 8,360.02 8,i57.62 7,64.52 7 u 2.5 , 7,582.81 7,3 a.59-Su TOTAt w to RETIREIENTS/DEACj'lWTIONS juGTE 4) ,
Pen;i*d'atunf'4"' "" "
te ot** **t tr-==d uai" 'll':ll
..!.:.. I Ift g8) 9 'If7 ..!.i..j Ig," !?!:fl (!!?-ll
..!!:..J ..!!i.. ..!.I.. [f'I fl '!!?:..!!:E..l .!!:88).Ift: ..!!:..2 1 ..!.!..IEIt' '5l l
'!!?:l (131.00) (102.35) (131.00) (102.35) (131.00) (102.35) (131.00) (102.35) (131.*10) (102.35) i RETIREIENTS/ DEACTIVATIONS SUBYOTAL .
0.00 :
CAPACITYE"*"""'1S EC E )
U$n ted(yI tun. (NOTE 2) g.g .
g.g gg 0.g 8.
0.00 0.00 0.00 0.00 0.00 0.00 g.00
.00 0.
0.g 0.00 CAPACITY SALES gg,.o.,i.Corre... a73.g) a7g.g> . a7g.g) (ag;g> arg gg> a6g g) (ag g> aeg;g) (ag g) a4g g) .
....... g SUBTOTAL (Lang/Sfiert-Tenn Setes) (276.80) (271.14) (272.66) (267.02) r272.66) (267.05) (249.62) (244.65) (249.62) (242.78) l 8,304.97 8,095.74 8,060.36 7,823.79 7.956.36 7,788.22 7,265.90 7,115.59 7,202.19 6,981.4 [
NET CAPACITY AVAILAeLE i i
7,533.00 7,639.00 7,682.00 7,792.00 7,833.00 7,948.00 7,967.00 8,092.00. 8118 8241 l PEAK Estimated LOAD (NOTE Peet 5) Lead '
771.9T 456.74 378.36 31.79 123.36 (159.78) (701.10) (976.41) (915.81) (1,259.5*)
RESERVE . Inf (IIOTE 6) 10.25 5.98 4.93 0.41 1.57 (2.01) (8.80) (12.07) (11.28) (15.28)
TOTAL RESERVE - 1 L b
t 6
m TABLE IV-6 (PAGE 5 OF 5)
NORTMEAST UilllllES SYSTEM 1993 2012 FORECAST OF CAPACliY AT THE ilME Of Ulster AND SU MER PEAK (AS Of JANUARY 1, 1993)
NOTES:
(1) This contract consists of an exchange of CMEEC's entitlements in Mittstone 1. South Norwelk 1. South Norwelk 2-$, and Worwich Jet for entitlements in Norwelk Marbor 182. Details regarding the megewett levels for specific units are shown in Tobie tv-L (2) This contract is en exchange of united Ittssninstine's entitlement in Bridgeport nerbor 3 for entitlements in Coe Cab 10-12 and South Meadow 11-14. Detalls regarding the megewett levels for specific units are shown fn Tabte tv-2.
(3) CLsp's contract for NTPA power ends Jime 30, 2001. It is assismed that CL&P will continue to receive the same share of WYPN powet beyond the end of the current contract period (Winter 1994/1995) es It currently does in Winter 1994/1995.
k (4) As per the mestamed retirement /deactt /etion schedute shown on Tebte IV-4. C (5) 1992/93 winter peek toed is pretteinery. Peak toede shown are constetent with the data shown on Tebtes 11 1 and 113 el Chapter II.
(6) These reserves do not include the ef fects of inteertetible service contracts, load control devices, or Nu's poetitinedm1 In the hydro cumbec Intercomection. ,
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! ENCLOSURE 2 4
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l' UPDATED PROFILES i k
i l.
o B. M. Fox
! o J. F. Opeka 4
o T. C. Feigenbaum l
,, s. . .m.- " .. n E 6696 P.03 FMMrrHEIA!iT Ifril.lTIEP.i
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1 P 50 *I.I! PROF Lli VO F - l '(?
F asell w t c irw 6."e , s p . I ,1 0 ] /(.
HERNARD M. FOX ,
1 i
Bernant.11. For n president amiehief executive etfieer of Northeast Ikilities
, (NI U lie s also a uu3 tee of NU and president and cinef executive office and a agd director of the Connecticut Yankee Atomic Power Company.
d ,b Born in New York City Fox was yr.nloated from Regis High Schoolin 1959, Manhanan College in 1963 with a bachelor of science degree in electrical engineering. and in 1964 from Rensselaer Polytechnic Institute with a mastes 's degiee in the same discipline. In 1979, For cornpletW the Program for Management Deselopment at the Harvard Business Schoci. In 1981 he
$ completed a special program of study in auditing, legal affairs and financing act mes, meluthng a three month assigmnent with Morgan Sta:dey and Company in New York City.
For ..ined The flattford Fles tuc 1.iyht fonipany tilEl.C(): in 1964 as a cadet engineer. In 1966, after l Hl .I CO had besome a subsidi.nr of NU. he w a, named an enpneet m NU's System Planning Depanment, I and scmor cnrincer in 1971. lle uansfern d to the utility's Suelear lingineering and Operation 3 group in 19D in 19'O. he was appomted spiem director--Engineering Management Services, and system diresi-Transmissmn Engmeering and Construction in 1980. He was appointed to the post of vice prestdent and general mana g er (ias m 1981 and was elected to the position of vice president and chief financial officer m 1983 in 1986 he was elected escutive vice paesident and chief operating and financial oft me. In 1957 he became president and chief operatmg and financial officer,and relinquished the position of emet financial officer m 1990. He assumed his pre >ent postion in 1993.
For n chainnan of the board of the Institute of 1 iving. He aho serves on the board of directors of Shawmut Baid ('onnecticut. N.A.. Shawmut Bank, N. A., and Shawmut National Corp., Dexter Corporation, the Conne. ticut Business and indnstrv Awociation, and Group Amerwa,a subsidiary of CM Alhance Companies.
Jn miditmn, he is a member of The Mouni !!vlyoke College Bo.ud of Tnistccs , a member of the Board of Ihe 1995 Special Olympics World Sununer Games urgamzation, a member of The liispanic Health Council's Capital Campaign Fundraising Committee Dmner Chairman of the 1994 Manhattan College De 1,a Salle Me dal i hnner. chairman.of the Fidelce 1904 W.*Run Ridc Event, and Tickc! Sale 3 Chairman of thc 1994 Girl Smnts Woman of Meat Dinner lic is a senior member of the Institute of Electrical and Electronics Engmccrs (IEEH and has held a number of IEEE state and national offices. In addition, he served as cha.rman of Leadership Greater lhtriford from 1988-91, chairman of the Connecticut Special Olympics Hailfe!d Corporate Advisory Committee from 1988-91, chairman of the 1992 United Way of the Capital Ajea Campaign, and is past chairman of the Open IIcarth Capital Campaign. He is a fellow and founder of the American 1.cadership Forum and has taught graduate courses in electrical power systems analysis and related fields as an adjunct professor at the University of Connecticut.
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. ; ,.+. r .c. ;ua cr o ocx r. U4 e
Fox and his wife Marilyn have tfEee cluldren and hve in Avon, Connecticut. ;
- NUis a rrgistervalholding cornp,m.s f.>r encJm lu6n a hvupnncipaloperatmg company subsidsarws are 7he Connecticurlight
- and hnorr Company. Holyoke Water Pon er Company. Public Sernce Company ofNew Hampshire. and Western Massachusens Electnc Company. und n hase pimnpai nonoperating substJuarses are Nonh A tlantic Energy Corporation. Nonh Attontic Energy Service Cnrporution. Nonhtast Nun irar Energy Company. andNonheast t!stistses Service Company in addition. Charter Oak Energy int, and HFC Inc.. are Nil's nonuriferv subsidiants.
OctoNr 1993 1
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, .. .;. 2.. ,- . . . rc y 4.e. W. 6 ses se96 P 05 4 NOtrl'HEAST trrll.ITIES
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- * 1.T.7,,~.% :
PEOPI.E PitOPILE 7 1
I EEE=
vm o..,
v ,..,-
.,. n . n i .o to JOHN E Ol'EKA
/vh r F. OpeAa is executise ucc president Nuclear for Nuithc.nt Utilities (NU).* He is responsible for in ni technical support and opeiation of .N U's nuclear facilitics.
A n. . s.e of Fore t ( ity, Pemoyb ama.OpeAn received a bachelot ofscience degree in eteenicalengineering fro . Pennsylvama State t'mversin and a mastei s degree in business administration from Rensselaer Puh tn.hnic Institine at the llaittord Giaduate Center. lie aho completed the Program foi Management De Opment course at the liarvard liusiness School. He served in the United States Navy from 1962 to 19f -
Opi Lt began lus unhty career with NU in 1970 as an engineer in the Nuclear Production Departmeit at ik o He was anigned to the company's Millstone Nuclear Power Stanon in that capacity in 1972 andhas n i. -
muor engmeer there in lim. He obt.oned a denior reactor operator's license in 1975 and later'that yc. w as named Millstonc plant .ser vices supenntendent. In 1977 he becamc assistani station superintendent an.: .tas named statwn supenntendent in 1978. In this position. Opeka was responsibic for the overall ope aion and maintenance of Milhtone Units I and 2. He was named system superintendent- Nuclear On aaons, m 1980, becoming responsible (91 the ovelall operation and maintenance of both Millstanc units an, ne (. onnecticut Yankee nuclear plant. lie was elet.ted s ice president- Nuclear Operationsin June 1981 w.e aamcJ.semor sice president Nucle.n Ungmeermy and Operations in 1985,an lexecutive vice piedident of f wmeering and Operations in 1956 He assumed his precent position in November 1991.
He -
member of the Arnencan Nucie.u Society and the Pennsylvania State University'< Alumni As . ..aion and is a fellow of the American Leadership Forum. He is also on the board of directors for the opp nunihe3 Indu.,trializatwa Centes e1 New London County and on the board of tro.stees for the Tharnc>
Ss. .:e ( ' enter.
O/ :r n and his wife Jacqueline have two dau;lhters and hve m Old L.yme, Connecticut.
l'
- oett<ter ed holdsng corn;>av.s t..r nor J un lut.h sch,o o prun opa! vperatinga ornpany substdrarus are Ths Conna tu ut
- and hmer Cornpany, flo!> vie n earr l'o cr Cerrupany Putrhc .%nu e Cornpany of Nos Hurnp>hure. undWatern 1 . . ! .nett., E la Irw Con: pain an.1 u han prencipal non. pcturing subsrdrarws are Nunh Atlantic Energy Carporation i
- s:lann< E n.~rgv Service Crupsratoon. N.ortlwast Nucicar Energ\ Cornpany. andNortheast iItihties semre Carnpain
- dau.n. Charter OnL Ene e s. In, amt Hn'Im ., are NU's norrutitory subsuJiaries.
N., ember 149.4
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- - H, : i 4 m -i NO. c0.i 665 5896 i
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DiO O trl'H li A S T 88T ILI TIIiiG !
pp. p m q .
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s.o4.s, . n.
u .,.,, n.,~. . m . , m .c,;. t. ..
! JOHN E Ol'EKA l
/uh , F. Opeka is exceptisc ucc president Nuclear for Nutthcast Utilities (NU).* He is responsible for j osc ul technical support and opetation of NU's nuclear facilitics. )
f A n. . s e of Forest ( ity. Pennq h ama. Opeka received a bachelor of science degree in electrical engineering ,
fro... Peansylvama State l'niversiis and a mastei s degree in business administration from Rensselaer l l Polstcshme Instirnie at the ll.uttmd Giaduate Center. He also completed the Program foi Management l Dc' Opment course at the liarvaril ilusine.s School. He setwd in the United States Navy from 1962 to ;
19t 1
! l Opi lut began his utility career with NU in 1970 as an engmcer in the Nuclear Production Departmeht at l lh o ile was assigned to the company's Millstone Nuclear Power Station in that capacity in 1972 andhas
! m. . waior engmeer there in Is03. He obtained a senior reactor operator's license in 1975 and later that yc. w as named Millstone plant set vices superintendent. In 1977 he became assistant station superintendent anc a as named station supenntendent in 1978. In this position, Opeka was responsibic for the overall j ope oion and maintenance of Millstone Units I and 2. He was named system superintendent- Nuclear l On a; ions,in 1980, becoming respen.sible foi the overalloperation and maintenance ofImth Millstonc units an., "e(.onnecticut Yankee nucicar plant. He was elected vice pre.<ident- NuclearOperationsin June 1981, w.e aamed semor vice president Nucleai Engineermg and Operatuins in 1985,and executive vice president I of t lymeering and Operations in 19Sh. lie assumed his present position in November 1991.
l He .- member of the Amencan Nuclear Sociciy and the Pennsylvania State University's Alumni As . naion and is a fellow of the American Leader > hip Forum. He is also on the boaid of directors for the Op: nunitie> 1ndustrialization Ccuter of New London County and on the board of tru.stees for the Tharnes Sc .:e Center.
Or, n and his wife Jacqueline have two daughters and live m Old Lyme, Connecticut.
l l~ . a repoter c,I halding coun;mn,s theem J un 1%t, wlm. prim apal o.perating.conspany subsidiarses are The conna tu ur l
c - ra and (*emer Company tiolyvie Wnter 1%,cr Cimopany. put>Hc Scnice Company of New flampshire, umlWatern
..w!cnett., E % Inc Comp.un, artJ u hass pronripalnonapctuting subs:Jiaries are North Atlantic Energy carporation
+ A rlaran E n.~rp Sen ice Corp..oarran. Nonheast NucIcar Energy Compan). und Northeast iItihties Service Compan)
.:Jotu un. Charter (kok Enro vs. In. . aml HEC Inc., arc NU's norturility subsidiaries.
I Ni. ember 1493 sr.e e.? >