ML20072E570

Ma Municipal Wholesale Electric Co 1993 Annual Rept

ML20072E570
Person / Time
Site:	Seabrook
Issue date:	12/31/1993
From:	Bloom E, Sjosten D, Slattery R MASSACHUSETTS MUNICIPAL WHOLESALE ELECTRIC CO.
To:
Shared Package
ML20072E546	List: ML20072E543 ML20072E548 ML20072E553 ML20072E558 ML20072E562 ML20072E566 ML20072E570
References
NUDOCS 9408220298
Download: ML20072E570 (200)

Text

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W .o.cM s if ' hh,.[.: $.'k,5,%,?q'f.M Y ,. e *: c r').;g 'W;,' ...U. @w %%pl, W& " Good business is the best art" ^ Andy Warhol, Time, July 1975. M.O ?cm. m &m% j.iM j 4Q ,.. Md.#g yy y 93 'y..a n We have tried to Provide our readers with some of the best art -both $usiniss aMErdditid. i2%.y -in this year's annual report. p@$ James Hendricks,Mario$$a ,x9 n4 We thank the following artists for their contributions to the report: Brown, Marjory Lehan, Jan Norrnan, and Janet Fredericks. []1y j yk ..s We also thank William Baczek, Gallery Director of the Hart Gallery in Northarnpton, Mass yA-achusetts for his assistance in choosing the artwork, and Stephen Petegorsky of Northarnpton,7% Massachusetts for photographing the artwork in preparation for printing. ] $- _$ ) ? 5,, ' p. g,%' p -.' y. n, ~ ,5\\ h 7jg . iig j n1 a -,., 4 j [-( I C[ s%s Dd h. - i l

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f .. p,,e4 +,, t is with great pride in the organization's accomplishments y over the past year that we present this Annual Report of the ) Massachusetts Municipal Wholesale Electric Company

j (MMWEC). With the support ofits member utili-i ties, project participant utilities, board of direc-tors and staff, MMWEC added strength and stability to its core operations through a number of finan-f cial, legal, power supply and other achievements during the year.

In recognition of these achievements, M oody's Investors Service upgraded MMWEC's credit rating from llaal to A in January 1994. It is significant to note that the upgrade came after Moody's an-nounced the application of stricter stan-dards in its reviews of electric utilities due to risks associated with increasing A ,o competition in the industry. Letter \\j Two new refunding bond issues, in April 1993 and March 1994, have for- [ppygg f/gg tified the financial positions of MMWEC MMWEC and its project participants. j Power costs for MMWEC participants y 7I gg777g7It have dropped by more than $850 mil-lion as a result of MMWEC's refund-i ing program, which was initiated in 1992. Declining power costs have en-abled participants to reduce their rates to the point where they are lower than or very competitive with the rates of Massa-chusetts' investor-owned utilities. This has given municipal utilities more flexibility and options as they work to address a number of competitive issues. i The average interest cost of MMWEC's outstand-I ing debt has dropped from about 9.8 percent to 5.9 percent as a result of the refunding program, reducing an-nual interest costs by approximately $35 million. (") Litigation of transmission access and pricing issues before the Federal Energy Regulatory Commission (FERC) resulted in sev-l eral significant victories for MMWEC and Massachusetts municipal i

t$. qq., m 4 4 A, g-Jjj g l! ,5-4; [1 utilities during 1993. The arguments of hih1WEC and others in the Northeast Utilities (NU) transmission tariff case re- } suited in a FERC order that expands ac. cess to NU's transmission system, the b largest in New England, and reduces pro-posed rates for firm transmission service e, by about 36 percent, from $22.55 to f ' #. M 4 $14.39/kW/ year. The h1 arch 1993 FERC

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\\ Q. ', J. order in the NU case, which has yet to be-s % come fmal, as well as other FERC pro- -.4, } nouncements on transmission access and pricing, reflect the success of municipal utility efforts to restrict the market power of transmission owners, Edla A.111oom, President As the FERC continues its efforts to re-solve transmission issues, every victory for MN1WEC and the municipals will enhance their competitive position because the munici-pals, w hich own very little transmission capacity, rely on access to transmission at reason-1 able rates to keep their power costs as low as possible. In other litigat on, hth1WEC has closed the books on challenges to the validity ofits i power sales cont racts, which generate the funds used by hih1WEC to pay its bondholders. With the contra :t disputes resolved in hth1WEC's favor, and related litigation also coming to a close, the co upany's legal budget is shrinking. In aidition, more stable and productive rel stionships between hthtWEC and its participants are be-ing developed, increasing the oppor-tunities for cooperative action to ad-hNy dress common needs. The existing power supply of hihlWEC's members and project y% M' participants - a diverse mix of nu-clear, oil, natural gas, hydro and oth- ) s er resources - is adequate to meet their needs through the late 1990s. k k 'f The units in hih1WEC's power sup-ply projects have proven reliability I 3 records and are scheduled for opera-tion well into the next century. T Richard E. Slattery, Chairman g help ensure successful future s sam w m.-.

V~ l l l \\ operations, MMWEC has stepped up its project oversight activities, through which unit costs and operations are closely monitored. With the effective date of new air quality regulations approaching, MMWEC has equipped its Stony llrook power plant with new combustion equipment that has dramati-l cally reduced emissions of nitrogen oxide from the plant. Installation of this equipment, completed during a plant outage late in 1993,is part of a broader plan to bring Stony 11 rook into compliance with the 1990 amendments to the federal Clean Air Act and related f Massachusetts regulations. MMWEC also has taken bids on a project to expand the natural gas generating capability of Stony llrook by building a pipeline linking the plant to the in-terstate natural gas pipeline system. Increased use of the cleaner-burning natural gas, com-pared to the No. 2 oil also used at the plant, would augment environmental compliance plans and reduce Stony 11 rook's energy costs at the same time. All of this is occurring in an improving Massachusetts economy, which helped to pro-duce a 2.3 percent increase in electricity use among MMWEC's member utilities in 1993. This compares with a 1.6 percent increase for the New England region. After several years of very little growth in electricity use, the 1993 increase has boosted member revenues and is an encoaraging sign of economic recovery. Given these many positive developments, MMWEC and its Massachusetts municipal utilities are in good position to handle the increasing competition facing electric utilities today. liut there is more to be done, and work to improve the competitive position of j municipal utilities is ongoing through the Municipal Electric Association of Massachu-setts, an organization of all 40 Massachusetts municipals, as well as through MMWEC. To foster a better understanding of the issues associated with increased competition, this year's Annual Report contains comments from a select group of people who view these issues from regulatory, financial, government, economic, and utility per-M* spectives. For their contributions to a this report, we extend our thanks to Stephen J. Remen, Massachusetts' com-missioner of energy resources; Kenneth h Gordon, chairman of the Massachusetts Department of Public Utilities; Paul L hf loskow, professor of economics at the j Massachusetts Institute of Technology; 1 conard S. liyman, first vice presi-dent at Merrill Lynch: Robert F. Wolff Jr., executive director of the New England Power Pool: and David W. Penn, director of policy analysis for David A. Sjosten, GeneralManager the American public Power Association. 1 J l 7w wa-

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i ' he electric power industry in New b England and the rest of the United States (indeed the rest of the world) is going through a process of funda-mental change. The most important + force for change and the primary arena of policy discussion involves the future role of competition f in the industry. Should we expand and improve upon changes a that have increased wholesale power market oppor-tunities? Should we introduce " retail wheeling" and related types of retail market competition? If we do, Paul L. Joskow, Professor of Economics how can we ensure that it promotes improved Afassachusetts Institute of Technology efficiency and lower prices for consumers? j On the wholesale competition front, the expan-i sion of non-utility generating (NUG) capacity and l the rapid growth of a healthy independent power sector has been impressive. Unfortunately, the po-tential benefits from wholesale market competition have not yet been fully re0ccted in electricity prices. t j The primary problem has been that utilities have d; -~ Q too often found themselves with contracts for too D N4 i much NUG capacity at too high a price. In part, j OY ~ # this problem has resulted from honest fore-casting errors regarding future load growth )QQ and natural gas prices.13ut these inevitable problems have been exacerbated by poor regulatory rules and procedures govern- ~ j l* ing generation resource procurement and the growing politicization of the l : generation procurement process. We should be working to make reforms that willimprove the performance of wholesale power markets so that they provide greater real benefits for con-sumers. A major improvement would result from reforms aimed at simplifying and depoliticizing the generation resource procurement process and introducing incentive-based regulations that pro-vide good incentives for utilities to acquire the most economical power supplies, subject of

N n n c[ l dM N ;' ..[ _,.) i course to current and expected future environ-mental regulations. M gblation, spur.re'dbyp'oliticalandlegislatile 3. i ^

eling M ' action, are incredsing cornyetition in'the electric utility indust'ry. Niw liws'and VegulationG r

](& governing transtnission' access, non utility generaiors a thirigs, are transforining the way utilities do buslriess., a K * 'y [Q 7 3 . Massachusett' tnanicipalutilities,iridividuallyand'ihiough tliiirparticipationitiMMWEC,l l SH s ae & the MunicipalElectric Association of Massachusetts, tiie Northeast Public Power Assbcistion, G '"'*I f'$ and the'Arnirican Public Power Assbciation, hds:e taken an active' role in shtiping these lasJs' < y % and regulations: At both the state andfederallevel,inuriicipal utilities have been sn~ etiitg with)

e re-e h legislators aridparticipating in regulatoryp'roceedings,to ensure that the interests and needs of Q i

.md dated g snunicipal.systemsaregivenfaircon_ sideration. jy Q;rT. Actionsplannedfdrthecomingyeartopuppprtexisting'effort i .:) ism ^ ing relationships with legislatdr$,

• regulators and key special interest grout;s. Alsoplanned is) cini Yi 2

.k .~ c.) paign intended to edu~catepolicymakers about the economic and social benefi Wh, 4 .n ur- ~As a 15 suit of these and other activities, the'collectiveforce ofinur cipbl utilities will bepre.V y

h. - (Lsent as the policies that sliape thefuture evolve. :

29 % f j f.A O h % bk k k h h hb k h h. k fhI ' N h h h kkkh N spply-mount the massive, time-consuming effort re-

ing, quired to design and create the new institutional

[ " Transition incchanisms inHst be and transition arrangements necessary to move to-ICS dCUcloped to deal with the Costs Of ward and support a fully competitive power mar-sHHk lHFCst1HCHis NHd COHirdCtHal ket. A necessary, but not sufficient, condition for creating these new institutional and transition C01HfMIt1HCHis 1HadC HHder CXisting arrangements is a shared vision for the future of the g. le TCgidatory THICs." industry, and cooperation among the nearly 100 N. a the utilities in New England and the state and federal agencies who regulate them to realize it.

o M l '..s 7 ,b f @A!; _ <4 he electric utility industry has W ! [ ,I f evolved in a steady and gradual fash-7' ion over the last century, punctuated by key events that changed the l .y course of the industry.Today,with the emergence of competition, the very core of the industry is being challenged by new ways of doing d business. Unfortunately, a lack of coordination '. I among the forces for change is making the transi-tion extremely difficult for electric utilities. In its infancy, few could envision the ultimate Robert F. Wolff Jr., Chief Executive size or importance of the utility industry, and very h{ New England Power Pool little regulation was applied. As the industry came f into adolescence, regulation was used mainly to 5 protect the public from those who would take ad-vantage of opportunities for monopolistic abuse. l [ The rapidly increasing demand for electricity con- .j stantly drove the industry to the limits of both con.

7

~ trol and production hardware. As the industry ma- .. < @./k i tured, improvements in technology carried it into N ~ and through the 1950s and '60s. With prices stable Y =, 1 l l Y and the supply of electricity keeping pace with de-j ~- mand, there was little need for regulatory involve-j "j ment m the way the business was run. Then came the oil crises of the '70s and the real-n i ~ J ity of exploding prices. Acting in their traditional .5 1 m roles, regulators and utilities were unable to con-4

]I vince the public of the need to either change its en-(

] ergy habits or accept the consequences associated ( l I with the increased cost of fuel. Both the industry [ u a and its regulators were stuck between the prover-c( f bial rock and hard place. The alternative was to be-d s P gin exploring different ways of doing business. Q ) Thus, as middle age approached, the industry en-1- II tered a state of turmoil. First welooked at working p_ p existing equipment harder to meet rising demand ') with minimal investment. Next we explored less costly, unconventional means of meeting the load. M Then came a variety of" peak shaving" efforts to ] control peak demand, followed by a proliferation of demand-management and conservation programs. (( t y w

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T g t:r @& \\ ~ MKg [ .l r.) o i 3 e .h i Now, in a movement that carries as many risks able experience and wisdom will be required to p l as potential benefits, the industry is being moved meld them into an effective and efficient system de-N toward competition with the hope that the public signed to meet the best interests of our customers' will accept the price of electricity as long as it re-Over the past century, as electric utilities grew w ]- sults from a competitive market place. maturation, an interdependency has developed that

p Growth of the non. utility industry has resulted in is renected in the thousands of pages of rules goy. h calls for increased access to the transmission system erning utility operations. Changing one operating and has increased the pressure procedure often has a ripple

,,The pressure on utilitteS to effect throughout thc cntne for retail wheeling. We are looking at dispatching power system. There are many plants based on economics CHt COSTS to NICCf C0tHpClitiOH con 0icts and priority issues and emissions rather than just can put equalprcSSure on the that need to be resolved if economics; utilities are mar-the evolution to a m"c reliability Of the electricpow-Leting emissions reduction competitive m. dustry is to credits; non-utility power er SJ' Stein. be successful. And it will 5 brokers are reaching into elec-take time. tricity markets; and there is talk of segmenting the Further complicating the issue are the efforts of utility industry into generation, transmission and several levels of regulation and legislation. In re-distribution companies. These are only a few of the sponse to these efforts, utilities, th-ir reliability W 3 M 'M F[NfS f Me $g Aw. M IIit!I,D NE D MnM.@iM Q N g g j e. i p a s %)< MMWEC's Viewb-A single municipal utility would be overcome quidly bylth' costs'. i A i e and time required to fully participate in thefar-reaching debate ovciissues as'sociated, f 4 Q 'with incriased competition'in the electric utility indu~stry.' Working togitherlhowever,'.$;& Ql h1aisachusetts municijal utilities are not mdy participating in the debati; they arE niaQ.] f &j V . ing a diffe'rente. - c With' power supply, environmental and other competitive i . m_. c 9 thsref,. i , h, % _ is a growing sense ofunity and common purpose among the state's municipalsys 4 a number bfiss'ue-oriented alliances have developed, and there has been a generalresurgence. 1 h q h ofconfidence in the straagth and effectiven'ess ofjoint action. ~ l 4 ??

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q s MMWEC, as the officialjoint action agencyfor hiassachusetts municipal utilities,Qtsn > Q ] j*g,p;lays a key role in these alliances, coordina'ing legalandfinarding activity, iesearcluing Ash k Q. sues aisd developing y sitions. At the sametime klh g. t ,f 39 G MMWEC are getting more involved, sharing in the costs and decision:makirig associatedi t 1 I 99.,.witli these iisitiatises, and expanding the base ofjoint action in Massachustts.... )i ^%,. y z h : 3a. f ? D'$ $N W O M $i& NW ?ilfkW,0??r% W?.?h Y h. V$, Tfll n 1 1 A... . f J u ll gl [ changes and issues that are shaking the traditional councils and power pools are attempting to move N j business foundation of electric utilities. into the next generation in a way that preserves tra-Many proposals for change raise extremely com-ditional economics and reliability. While willing to f plex and conflicting concepts.These concepts are accept these challenges, there is growing concern h; 9 not naturally compatible, meaning that consider-over adopting so many basic and con 0icting u N l ^f5'

I i e changes all at once, since the outcome of these creased maintenance. There are many difficult i de. changes cannot be fully understood prior to imple-choices ahead for utilities, regulators and con-mentation. In addition, the introduction of non-sumers as each search for a balance between power -ro j utility suppliers has raised a number of equity is-costs, reliability, environmental im pacts, conserva-g that sues, including the need for utilities and tion and other new components of the power sup-n n-utiliths to share the costs of conservation, ply equation. iv. clean air and an adequate transmission system. The lack of a blueprint for change - and the ing , ippi, The pressure on utilities to cut costs to meet need for one - is evidenced in the growing diver-7 tire c mpetition can put equal pressure on the reliabili-gence in the way utilities are responding to their ty of the electric power system. One example of this new challenges. pressure is the temptation to cut maintenance costs Despite this period of turmoil, one thing is ,ues

;f at generating plants in years oflean cash flow. As clear

utility leaders and regulators are both com-the inevitable impact hegins to take its toll on gener-mitted to providing a system that can meet the go ator availability, the emphasis shifts back to in-needs of our customers.

1 1 , of 1 uring the 1980s, the watchwords 1 in electricity regulation were de-mand-side management, conser-g vation and the development of a f{i wholesale electricity market based on competition among independent power pro- ,h ducers. The watchwords of the '90s appear to be Kenneth Gordon, Chairman N "open transmission." Massachusetts Department ofPublic Utilities 4'**; The avowed aim of federal policy is to foster a Ay 'g full flowering of the competitive wholesale market ) %n that was emerging during the '80s. The lesson of the $F mp $0 mid-1990s, however, is likely to be that once Pando-is - /, qin 17,, ra's competition box has been opened, unanticipat-9 y t - fff ed developments may emerge. Competitive markets ,g h; are hard to limit when customers see others making ~ [ 3/ choices, and can see no technical reason why they i W M. should not be able to join the party as well. w {({ " Joining the party" translates in electricity jar- .M. gon to " retail wheeling." Retail wheeling is nothing more than an arrangement whereby individual end 1 ve .tra. users of electricity are able to s ct their preferred g supplier, based on price. Viewed in this light, retail wheeling is simply an extension of the expanded n consumer choice that has been associated with

bh a ?h g g y{V w ,I y hj deregulation in other traditionally regulated areas. ..g j And,in fact,it is important that this perspec-3 ,b tive not be lost ir. policy discussions of retail { wheeling. The current system has been based on a 171 f presumption that the supply of electricity is a nat-ural monopoly exhibiting both economies of scale i j and economies of scope across the different cus- )4 tomer classo One of the things we will discover as options appear for particular customers, particularly large ther there are limits to economics customers, of scope and scale. We will also learn the limits reg-ula. ors face in allocating overhead costs among dif-j faent classes of customers. in New England, these trends are today compli-cated by substantial excess capacity. For short-term contracts, at least, options may appear that are very attractive mdeed, compared to the fulllong-run embedded cost options typically available to a cap-f? tive utility customer. This short-run availability of lower rates drives customers to look for alterna-tives even more vigorously than they might in a "In our econon:J', the burden A '49 long-term settmg. ofProofis upon those who y Nevertheless, these short-term exaggerated pres-sures should not be dismissed lightly to the extent would deny consumers the 2 there are long-run differences in utility costs. Cus-tomers for whom energy is an important cost will right to choosefron whon j ..? continue to look for alternatives. The same tech-

1. 7
2. NN #EN N###'

l nologies and pricing options that make wholesalc N competition possible also can afford retail cus-nM cg tomers options that they do not currently have. . Dit i Municipal electric companies occupy an inter- "gy j esting niche in this process. One the one hand, f; they have historically viewed themselves as small [ publidy owned electric companies, but otherwise ( i 0 very much like their investor-owned brethren. f k ( They can also be viewed as cooperatives of con-sumers of all sites, particularly including residen-d tial and small commercial custorners. To the extent they view themselves as agents of l r j their customers (and it certainly seems appropriate . j b s I e y s m

h 4 O ~ 7 2+ O l m O

i .~; M1 i 4 l fI a .R ~g 4 that they should), they can become the agent to make broad enough range of consumers, then it is unlik available to small subscribers the options that burden will be met. that very large customers may We will move to a new world ) soon have. If municipals where electric companies b l i think of themselves this and generators for the - I h important vehicle first time compete i l way, they may be an ,.e m3 4 broadly to retain for ensuring that ,...{ their load. This M any benefits from '. i r$ should have a l ntail wheeling salutary effect are shared wide-g on the overall ly with small as .N * ^ + levelof costs in ] j well as large ,. ip the regulated N

1. ~

] electricity in-j consumers. .{ In our econo-dustry. }I " ~ * ~ l my, the burden of The challenge, -i which the munici. I proofis upon those ~ who would deny con-Vy pals may play a cen-7* sumers the right to choose ~4 L g;- tral role in meeting,is from whom they will make E. to ensure that all customer j ] purchases. Up to now, we have gen-classes gain the advantages of ] j erally limited that right through the exclu-choice and that some are not simplyleft sive franchise if retail wheeling can be efficient for a holding the bag. &] a 9] M%MA3MMMMMMMwDMWid%%:%g 1 a y tg , DJM 'm g. l! (ins MMWEC's View - it wasn't retail wheeling, but special circumstancesfound the Holyokel l*fl S j l

• ?":

Gas & Electric Department {HG6E)in competition with the investor-owned Holyoke Wa. y' l g{ ter Power Cornpanyfor a 29-megawatt retail industrialload in Holyoke earlier this fear. The competition in Holyoke resulted in lower industrial rates and a loss of revenuefor: yf G )fll both utilities, which each serve a portion of the city's industrialload. No customers changed : ; &J k hands, but if they had, one utility would havefaced the loss ofits investment iripowerto.: $ y^ k 1 '? meet the needs of those customers, i.e. stranded investment. ~ W)' I . hj V; s !W' Loss of revenue and stranded investment are two issues facing utilities, regulators and i h';. consumers as the debate over retail wheeling evolve.s. Massachusetts municipal utilities, * -[j[ il 1 't; have identified many of the risks and opportunities associated with retail wheeling and oth. ;, y 4 er competitive issues. In anticipation ofretail wheeling, the municipais are enacting,stiate '... $ a '1( gies to participate in the regsdatoryprocess, retain existing customers andfind opportuni- .) ';2;a}, ties to expandIheircustomer base. f %w'/ R,- c / r .hSkk[k f[hb' ik' h h b hbb 1 4 + t yd .h !

,s ~ t niikely he Massachusetts Energy Plan, an-nounced by Governor William Weld a world last year, outlines steps to turn our state's disadvantaged energy system anies irthe - that lacks oil wells, gas fields, huge ipete dams and coal mines -into an efficient energy sys-etain tem not overly reliant on any one fuel. ) This The plan stresses lower energy costs, which are key to continued economic stability and growth. 4ve a f effect Maintaining low costs requires diverse and multi-cerall faceted energy systems, dominated by efficient util- 'sts in ities and competitive markets. The state's electric 'dICd utilities are particularly vital to the creation of a y in-least-cost and environmentally sound energy fu. Stephen J. Remen, ture, as misioned in the Energy lan. Commissioner of Energy Resources p Commonwealth ofMassachusetts

enge, All utilities will face significant challenges in the

'nici-years to come. Competition is increasing, and will ce - continue to do so. To respond, electric utilities must begin the difficult transition from being verti-cajj _ integrated entities offering bundled services, onTer y c5 of to more streamlined and competitive orgamzations. Y Cfl Ilecause the loyalties of customers are no longer I 7 guaranteed by geography, all utilities must also fo-yg cus on their customers' interests when moving for-N'NO3, N

• i. ".",?

ward with new programs and new capacity. In this pursuit, utilities will have to place more reliance on g$ outside nppliers, making the hest use of their own

;h,b mternal resources. Many utilities are now diversify-M ing products and services, such as electric vehicles and electrotechnologies, or are offering completely new lines of business that complement their core yy[g

.y energy business. h With these changes in the electric marketplace, ?,A the emphasis on environmental protection and Q.h enhancement will continue. The increasing pres-

T,f sure to procure " clean or green" resources will

,J a$ continue to be felt by municipals and investor- ' hi' owned utilities. 3 ,xjj. } The result of this regulatory and market pres-h sure has been a reduction in the number of options for the procurement of new resources. New facility o h l l

d } l 'M T4 siting issues arise, while cost uncertainties are in-tric systems, can and must play a maior role ig creasingly inherent in contracts for purchased pow-suring future price and supply stability of their cr. The state's energy plan outlines a diverse and systems. Increasing reliance on least-cost and envi-competitive system of energy providers that rely on ronmentally clean resources will move the state's "least-cost" resources in terms of operation and energy system toward that goal by reducing long-term environmental and socialimpacts. costs to all classes of customers. in the face of The econom-yt i' b'"i *I market changes and uElectric utilities, particularly the inn-environmental this strategy are p nicipal electric systerns, can and inust ,1,c,a y,,,,,_ y pressures converg. iny on the electric play a inajor role in ensuringfutureprice ent. Massachu-setts boasts one of utikty industry, de-g gg g j mand-side manage-the largest concen-j { ment and renewable trations of energy ij energy programs appear increasingly attractive. efficiency companies in the nation. According to I q 110th help utilities cope with the uncertainties asso-the Massachusetts Energy Efficiency Council,be-t [ ciated with the siting, approval and cost issues that tween 1,500 and 2,000 new companies, and as accompany traditional supply resources. many as 20,000 new jobs, have been created.The j Electric utilities, particularly the municipal elec-award in December of a $300 million contract to 9

1 il y

4 s 5, ? 5 h h Y{ i !' Yl J N,& M MWEC's View -- hiunicipal utilities an'd hihf WEC are implementing part of th a ;, ~ chusetts Energy Plan through their' participation on the Efficiency Partnersh>p Task Force'for g s,L, hiunicipal Utilities. , l,y jf.' ~ y p The purpose of'the taskforce, established under the ene 1 lan for expanding municipal utility demand-side management programs. The taskfor;ce iii. i. y f Q cludes representatives of municipal utilities and government agencies. as well as jublicaid,l ef private energy serviceproviders. -m' L '.. ; 4 Y:f Ef

• Nunicipal utilities also share thefundarisental energyplan goal ofcreating a least:cba ank k,

j.Y envin onm' ntally sound energyfuture that fosters econoinicgrwth. Through their member-f n e l ) ship i *r hihf WEC they are supporting Ihe Afassachusetts Alliancefor Economic Developr'nent,- ' g. an cryanization ofpublic and private utilities that assists businesses seeking to exparid oflo**? )f 3 _? lrjf care in Afassachusetts:Indi^vidually, several systems are leading by example in their.L<e'ofk electr j a nd natural gas vehicles, which diversify the state's energy system while imp ~rdring airs. l la {([ quality. ~ '.' f(p n ~ 4 m. ~ S . Achieving the goals ofthe energy plan will benefit municipal utilities and their c'onsumerL ' ; M'. as wellas the state as a whole. ' k?" h NN, UMfkfh khNkk N.h[bhNh$Nf 7 } j

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1, -9 4 Dh1C Corporation of Chelsea for demand-side man-with investor-owned electrics on regulatory and 3 agement services is a testimony to this fact. market reforms, with individual utilities on de-The growth of new companies in the energy mand side management and integrated resource j efficiency industry is only one economic benefit. plans, and with all utilities in the qualification of Reducing energy costs through efficiency and low-demand-side resources for emission reduction er rates increases the competitiveness of all hiassa-credits. DOER continues to work on initiatives set h chusetts employers. forth in the hiassachusetts Energy Plan and seeks The Division of Energy Resources (DOER)is the full partnership of all hiassachusetts electric ] [ working with municipal electric utilities on the de-utilities in these efforts. j sign of cost-effective DSh1 and efficiency programs, h i 4 I d ,n J h or decades, investors in the electric in-j L dustry based their requirements on a l f fundamental premise: the utility held a monopoly on the supply of electricity to 4l {k a particular region. The utility held that k monopoly because one utility, employing the largest j ] generating equipment, could produce and sell elec. f Leonard S. Hyman, First Vice President tricity for a lower cost than a number of smaller If MerrillLynch firms each serving a small part of the market. Im estors believed that utility securities involved w ( low risk, because of the seemingly guaranteed mar- -j Let for the utilities' output. The credit rating agen-i cies, too, understood the safety of the business. 4 They let the utilities borrow more money than ] h a y would have been acceptable in other industries. Af- / q ter all, electricity was a necessity and the utility was $h the only game in town, so why worry? t j$% 11y the 1970s, risks had increased. Utilities lost y ~ul% e billions in failed nuclear projects. When electric { ( prices rose too high, customers cut back consump-l t i p 1} tion of electricity or turned to other fuels.The mo-nopoly had limits. /4 [ g { By the late 1980s, several utilities filed for bank-4 k ruptcy. Almost one-third of the investor-owned util-ities reduced or omitted dividends, Obviously, some i utilities were safer than others, but investors did not ? f yet question the fundamental premise behind their 1 4 4 1 4 , l I ; S w

r ~f e Ov 1 investment strategy that the utility held a monop-ter the power generating business and to use the util-oly. Nor did the credit agencies, although they low-ity's transmission lines to transport the power to the cred the ratings of many utilities,in light of the de-customer. One year later, in late 1993, the credit rat. e ing agencies announced f cline in fmancial strength caused by the numerous ,N k_ h [hhhM(h that they would apply )[_ MMWEC's. View -Ifpowercosts %[$ 26 [ new, stricter standards set dif6culties. when rating bonds. . ss. The justincation for N[ ."'# "" I"E##'""'~"###""#I# "'III 7th b Could the utility !c the utility's monopoly sty s.competiturenessa MMWECa k began to erode in the made grearf keep its customers, and t p,,,fgj,,,,.hav p J trides toward iniproving their ; : p*2 '5 bring in the revenue 1960s. Power stations ' competitive position irithe past.. - l used to pay its debt, if had reached maximum levels of ef6ciency, in g twoyears. Tlie nductQn in poku - y. interlopers could h costs resultingfrom MMWEC's re: 1p h fundingprogram,in addition to; g[/ undercut the utility and 1978, Congress passed % E lowering rates for consumers,1:as 7, take away business? ~ the Public Utility Regu-g h - given participYnts another comi d With the electric utility d PetitIFe edge. Hadnglownp~own ; M@ n-latory policies Act, cre-industry facing compe-ating a new class of elec. I

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>w g, costsguves ahem more chotces when.' g ution, the rating agen- .l a tricity generators that responding to a particular threat M M[.. or opportunity. They have inore,.g cies had to adjust their y,t ' sold their output of en- " flexibility, risore optionsfor meet ' ?$ views. Competition h( ergy to industrial con-gest cerns and to utilities. - ing their customus'nuds h meant greater risk. \\Vith rights to inexpensive hy-So far, most compe-droelectricpreference power, and ' h

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lW 9 ment manufacturers he- ,,4,,,,g,,,,,,,,, gg, p,,,, y utmn largely.nnvokes gan to produce small, g ;.. from some of the region's most re-4 sales of power to elec-ved easily installed, highly pp; liableand economicgenerating? M tric companies (whole-g% units, Massachusetts municipal" i, sale wheeling). What o ~ ar-efficient, clean gas tur-utilities also have a' solid and com-6 nr power supply. M wd. l happen when pow-n- bine generators with h iti r which small indepen-N/ In addition, streamlined opern-J er suppliers attempt to dent firms could pro-p tions~and a rccovering Massachu-y:g n sell electricity directly to @9[I. setts economy have helped to im". N the customers of the lo-Af-duce electricity at a low-prove thefinancialperformance of 3.e-cal electnc utdity (retail vas er cost than that of many b Q munscavalutih..tses.. . trg utilities. N. - 'b wheeling)? That would W Competition is expected to zB 1 Remember that the = hring new challenges, hur Massa;. M destroy the local utili-utility secured its legal syi ' chusett's municipal utilities and ?j ty's monopoly, threat- 'P-monopoly because it Qf.. MMWECare contiisuing theirsuc- %}, ening the recovery of m-could produce electricity 4 255/ulwod PNParefor a mo" # M investments made over y% cmnpetitivefuture.. ld ap. 4 decades to serve the lo-at a lower cost than 2 - many of the smaller ~~ g.Q.);ygg smaller fir m s.

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cal customers. Investors have al-p 6rms could produce for less than the utility, ready learned, from experience with the airline, f m In 1992, Congress passed the National Energy transportation, natural gas and telephone indus- ) mt ir Policy Act, casing the way for additional firms to en-tries, that competition comes even to public service }

) 1 4 l d I O i i industries, and when it does,ill-prepared compa-nies suffer. j l Investors, realistically, would prefer the slow in-troduction of competition, so that the utility could 1 reduce its costs, recover as much on its investments f line with what is required in a competitie industry. as possible, and bring its financial arrangements in i Even better, they would like to think that the utility i i in which they have invested already has brought its l costs down to those of the new competitors and has } refashioned its finances for the new cra. Unfortu-i nately, few utihties have reached that point. Realistic investors will take a hard-headed ap-l proach when defming the solid electric utility, the I firm that will survive the appearance of competi-l tion, and possibly even prosper afterwards. That or- "FCW utiliticS now Ilave all ganization must produce power and provide all its tile TCquisiteS to SUCCCed in a services at the lowest possible cost. It needs an agile g management and a responsive group of employees McW HlarketpldCC. IMPCStorS Tj that understand that customers have choices. It will require a realistic cost-accounting system, because kHOWtIlat." k without such a system the utility will not know how to price the various services it will offer. Investors will examine customer mix, the types { of contracts that exist between the utility and its { customers, and they will demand that the utility price its output in a way to keep those customers. During the transition period between regulated 2 monopoly and real competition, the utility has to r have policies to maximize cash flow, depreciate as-sets of dubious value as quickly as possible, and [ ] pay down debt to a lower level appropriate for the j competitive market. And, the utility has to avoid taking on obligations that will turn into burdens [ with the onset of competition. l l Iew utilities now have all the requisites to suc-ceed in a new marketplace investors know that. l They hope that the utility will have time to evolve with the market.They want to see signs that the - l utility i, not simply keeping up with - but is instead movir g ahead of-the pace of ch.snge. { I I

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Y. 9 a 'l ] d - Q, 4 t 4 ome might think it strange to deal with the importance of customer service pro-j A grams for distribution utilities at a time when most of the attention in the U.s. has been on wholesale competition and power supply matters. Let me explain why all that j t will really count in the end is how electric utilities Dav d W. Penn i s deal with their retail customers, before coverin8 1 o Director of Poh.cy Analysis I American Public Power Ass $iation general and specik services that customers have a right to expect from their utilities. i y gy The high-voltage transmission of electricity

g

.., T-from generating sites to load centers will continue g V -- to be a natural monopoly. In contrast,it has long i [ I 'k been recogni7ed that there is room for a great deal I 9 more competition in the production of electricity. [ liowever, generation competition developed slowly in the U.S. despite congressional passage of the l R Public Utilities Regulatory Policy Act in 1978. 'I As the 1990s approached, different regions of the country, and even smaller market areas, found j themselves with wide variations in the amount and i cost of delivering generating capacity. One region 4 A might be in need of capacity and high priced, while j another nearby had extra capacity and much lower y prices. If there were fewer barriers and rnore com-1 petition in generation supply, capacity-to-load re-i lationship would equalize across regions, and so would prices. a Addressing this, Congress passed the Energy Policy Act of 1992. Its two key provisions 1) en- "...all f/laf Will C0!?til ill flic couraged the development of independent genera-C11([ iS Il0W CICCtriC titililiCS tion suppliers, and 2) gave the federal government clear authority to order the transmission-owning (Ical Wit /l t/lcir TClail CIIS-utilities to provide access to the transmission high-1 ways that allow electricity to move from areas of q 10111CrS/, surplus to areas of need. .( These are momentous changes in the industry. 3 y ] They are already causing dramatic restructuring of i ] the industry, ofits competitors, and ofits regula-tion. These changes have absorbed Congress and q I regulators and are capturing the media headlines. ? A_ 9 m

• %4pir.

I o, ,.e v ith 13ut what do they mean for distribution utilities and more convenient office hours, alternative payment their customers? Certainly, they mean more gener-plans, or cold-weather heating funds. In addition, new iro-me ation options and lower prices for wholesale power, technology is greatly expanding the number and vari-S. and, hence, lower ultimate prices. ety ofdemand-management programs, which can be nd But the genie of competition is out of the lamp tailored to meet local customer needs. at and over time these changes also mean that prices The mix of customer senice programs appropri-for wholesale power will tend to equalize for distri-ate to meet the expectations of distribution utility es 4 bution utilities. Then, all of the attention and pres-customers will provide the competitive edge neces-sure will be on utilities to supply electricity compet-sary to continue in our new world of competition. .a itively to ultimate customers. Distributors will have T.OGNN.i?.DMW49dMMT to concentrate on customer service programs that n s ue fulfdl customers' expectations. Regarding this, it is k MMWEC'sView - Consumer-owncd., - g important to remember that municipal distributors N. ' utilities,like the Afassachusetts munic-; M .al will be competing for franchises and existing and W ' ipal systems, are widely known to be'. W.,.1 v M{) more customer-and service-oriented M ~ than their investor-owned counter- $ f

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new industrial loads. Customers will decide who parts. Reing owned and operated byl M .wly will supply them on the basis of what is offered and % sonfor this. The consumer-own M: thepeople they serve is part of the rea - at what price.

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In general, a customer can expect distribution d. rect sayan e p ? .. ~ 9 W.,. unumcipal utilities hav iQ utility service that is: how the utility operates, through th*el',d ad reliable and capable of meeting variable power md and vohage requirements; y public meetings; : ~ s s i M.r h)3 ' : vidinga broadrang ' Afunicipal utilities are valuabTchs- -:g >n equally or lower priced when compared with () sets to the cornmunities they serm pro hz tiie alternatives; ver forward.lookm.g and planning in anticipation cd m b er sernces to schools, librars.es,semor :A '.,fh n-of customer needs; if : citizens and other towruiepartmenti,

• coordinated with other community needs, such

@ ' ; depending on, local needs.,They ar;c M j e-as economic development and housing programs; $! close to their customers, and can re-g J,. spond to their needs promptly. v l ~. - g. open to participation and scrutiny, making g ' 'In P anning to enhance 4heirserp g ) customers part of the decision-making process. Q m ~ vice, municipalutilities recognize that a pi in short, customers can expect electricity senice { customers' needs and expectations are that is responsive to the individual customer's q'I changing.Newservice technology,ioft2Q ra-nt needs, delivered by a utility that is a good local citi-4 age-sensitiveequipmentandenviron[,'p p1 t mentalconcerns are among the.rea. h g 7en. Massachusetts and other municipal electric f

h-utih.. ties are ideally suited to meet these general ser-

' sons municipalsystems are working to ; ;$ expand the scope and role o[ customer ? h, If there is competition to r'e . sernceprograms. Ah; vice expectations. They have a history of reliable, responsive service and lower prices over the long ~y. run. Most important, they are an integral part of p. isting customds arid obtain new ones," y tof their local communities, if : the quality ofservice provided by come h munity-based mnnicipal utilities will a& Specific customer service programs, which vary -grve thern an edge. d with kicai needs, might include such thmgs as cus- %a 8. Off

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tomer advisory panels, a customer mformation center, ,S.

wer s. e, s A f,s j .c ~ 4 l f MMWEC Directors and Officers 1 4 Other directors and officers, pictured in the management let- .l [ ter at the beginning of this re-port, include Richard E. Slattery, .w)4 Director and Chairman of the Board; Edla A. Illoom, Director i y and President; and David A. l Sjosten, Secretary and General Manager. Thomas R. losie, Director John Larch, Director t 1 1 i f l th 4y_hl 'dh j ,Y p -9 7 i, t Gilbert McCarthy, Director David I. Sweetland, Director H. Bradford White, Director h I n v _J. j 'h h 4 M l 4 W ./., - j i Nic holas I. Scobbo, General CounscI John M. Wesolowski, Treasurer James E. Fuller, Assistant Treasurer I h

~n J 0 l ) MASSACHUSETFS MUNICIPAL WHOLESALE ELECTRIC COMPANY ] l 1993 FinancialStatements I i 1 i MMWEC ret e

T%,;.c o 1 g U Table ofContents 4 Independent Auditors' Report - 2 Financial Statements Statements of Financial Position -- .3 Statements of Operations.- .4 Statements of Cash Flows 5 Notes to Financial Statements 6 Supplementary Schedules p) Independent Auditors' Report on Supplementary information 13 ,\\s Schedule 1 - Project Statements of Financial Position.. 14 Schedule 11 - Project Statements of Operations; 15 Schedule III - Project Statements of Cash Flows 16 /% l I '% )

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~. .- Independent Auditors' Report i rGl l! -1 The Board of Directors ). l. Massachusetts Municipal Wholesale Electric Company: We have audited the accompanying statements of financial position of Massachusetts Municipa Wholesale Electric Company (a Massachusetts public corporation) as of December 31,1993,19 and the related statements of operations and cash flows for the years then ended. These fmancia f Our responsibility is to express an opinion on these I are the responsibility of the Company's management. i fmancial statements based on our audits. I We conducted our audits in accordance with generally accepted auditing standards Those stan require that we plan and perform the audit to obtain reasonable assurance about whethe ? An audit includes examining, on a test basis, evidence

.ai statements are free of material misstatement.

T supporting the amounts and disclosures in the financial statements. An audit also includ j accounting principles used and significant estimates made by management, as well as eval V; fmancial statement presentation. We believe that our audits provide a reasonable basis for our op d In our opinion, the financial statements referred to above present fairly, in all material re ( 31,1993,1992 financial position of Massachusetts Municipal Wholesale Electric Company as of December f ih and 1991, and the results of its operations and its cash flows for the years then ended in conform generally accepted accounting principles. '^. ay 7 $E m>

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Q' s %t 1 March 11,1994 I.! re< + ,p, ly 'kkh. a s, Sf \\ [f )? 'i t g 3 - 'i 9 3, n A;J% ) i ( " Nyj Ud&' i ma. { w, 74Q : i '1)A i. dij l ~

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y MMWEC 'r' s -Staternents ofFinancialPosition Years Ended December 31,1993,1992 and 1991 (in Thousands) 1993 1992 1991 Assets Electric Plant in Service (Note 4) $ 1,233,845 $ 1,231,359 $ 1,231,621 Accumulated Depreciation (243,440) (201.172) (157,897) 990,405 1,030,187 1,073,724 Nuclear Fuel - net of amortization 19,553 24,626 32,226 JI Total Electric Plant 1,009,958 1,054,813 1,105,950 il e Special Funds (Notes 2,3 and 7) _ 191,099 196.259 256,187 is e Current Assets Cash and Temporary Investments (Note 7) 1,013 3,619 1,828 Accounts Receivable 9,361 6,163 5,723 3 Unbilled Revenues 7,813 8,491 8,718 inventories at Cost 14,846 15,261 19,663 e Prepaid Expenses 7,636 6,652 5,643 e TotalCurrent Assets 40,669 40,186 41,575 11 Total Special Funds and Current Assets 231,768 236,445 297,762 Deferred Charges Amounts Recoverable (Payable) Under Terrns of e ) the Power Sales Agreements (Note 2) 189,808 132,312 35,005 2g Unamortized Debt Discount and Expenses 39,340 40,272 35,322 3 Other 7,649 5,921 6,242 236,797 178,505 76,569 $ 1,478123 $ 1,469,763 $ 1,480,281 Liabilities 1.ong Term Debt 11onds Payable (Note 3) $ 1,374,605 $ 1,376,700 $ 1,380,955 Current liabilities Current Maturities of Long-Term Debt (Note 3) 33,175 28,110 19,765 Notes Payable (Note 3) 64 113 Accounts Payable 8,332 11,081 15,682 Accrued Expenses 17,561 11,167 9,376 Member and Participant Advances and Reserves 44,786 42,592 54,503 103,918 93,063 99,326 Commitments and Contingencies (Notes 4 and 6) $ 1,478,523 $ 1,469,763 $ 1,480,281 t'%.J 1he aicompanpng notes are an integralpart of thesefinanaal statements. .~ Mt y m ha y -o 'I "(. ~ MMWEC ~ ?!? - Statements of Operations ? Years Ended December 31,1993,1992 and 1991 (In Thousands) l,rg;; ,,, J W ' ; r;h I993 1992 g99y x Revenues (Note 2) $ 248,630 $ 275,041 $ 276,487 M)

4j Interest income 11,083 13,435 93

%,47 .h(; Total Revenues and Interest income $ 259,713 $ 288,476 $ 295 Operating and Service Expenses: .S Fuel Used in Electric Generation $ 20,062 23,831 5 28,917 ((), Purchased Power 74.134 78,925 73,739 Other Operating 29,451 32,533 32,147 8 Maintenance 10,470 11,873 33,39) 1 l Depreciation 44,187 44,101 44,016 ~ j Taxes Other Than income 6,076 8,225 I84,380 199,488 11 l interest Expense: 1i Interest Charges 89,742 114,459 135,445 isN S Interest Charged to Projects During } Construction (Note 2) (169) (466) (g7) 89,573 113,993 _ 134.478 M j Total Operating Costs and Interest Expense 273,953 313,481 337,052 ..N Cost of Advance Refunding (Note 3) 43,857 73,180 .l Gain on Cancelled Units - Net (Note 4) (601) (671) (1,069) - M j Gain on Retirement of Debt (207) (704) ,;.ll g l 43,256 72,302 (1,773) Q o 1 .. M}. } Decrease (Increase)in Amounts Recoverable j l Under Terms of the Power Sales fj l Agreements (Note 2) (57f_.961 (97,307) (39.862 dQ $ 259,713 $ 288,476 $ 295,412 '] 7 i .q \\ p ',M .m 4:4 u i g, .a i a 4 jf ? n.? L ' r..z e ) H S \\ \\ ' Grad v e. 1.2%. W ...s4l r a m ne aaomt anymg notes are an meegrat g, art 4 shesejmamiat statemena . g, ";g $?; _ 4,,_ h.a.

MF MMWEC Statements of Cash Flows ~ (' Years Ended December 31,1993,1992 and 1991 (In Thousands) 1993 1992 1991 yg y Cash flows from operating activities:

,437 Total Revenues and Interest Income

$ 259,713 $ 288,476 $ 295,412 g Total Costs and Expenses, net (317,209) (385,783) (335,279) i,412 Adjustments to arnve at net cash

=

provided by operating activities: Depreciation and decommissioning 45,112 44,978 44,655 . g,9 3 7 Amortiration 24,805 34,795 13,602 '8,789 Gain on land taken by eminent domain (292) 2,147 Change in current assets and liabilities: 1,393 Acc unts Receivable (3,198) (440) 13 1,016 Unbilled Revenues _ _ 678 227 347 Inventories 415 4,402 (2,481) 3"574 Prepaid Expenses (984) (1,009) 173 Accounts Payable (2,749) (4,601) 5,972 Accrued Expenses and Other 4,720 (361) (508) 5,445 Member and Participant Advances and Reserves 2,194 (l1,911) 11,518 (967) Net cash provided (used) by operating activities 13,497 (31,227) 33,132 1,478 7,052 Cash flows from investing activities: m S Construction expenditures and purchases of 3,o'69) nuclear fuel (10,312) (4,943) (5,608) (704) Interest Charged to Projects During Construction (169) (466) (967) 1,773) Net reduction in Special Funds 5,160 59,928 66 Decommissioning Trust refunds (payments), net (1,259) 1,297 (997) Proceeds from property disposal and other 620 426 729 Net cash provided (used) for investing activities (5,960) 56,242 '(6,777) 9,867) g Cash flows from financing activities: Proceeds from sale of bonds 444,290 748,295 Payrnent for bond issue costs (13,064) (27,427) Payments for principal of L<mg-Term Debt (29,165) (27,880) (26,335) Payment for defcasance of bonds (412,155) (716,325) Change in Notes Payable (49)- 113 (1) Net cash used for financing activities (10,143) (23,224) (26,336) Net increase (decrease) in cash and temporary investments (2,606) 1,791 19 Cash and temporary investments at beginning of year 3 619 1,828 1,809 Cash and temporary investments at end of year 1,013 3,619 1,828 Cash paid during the year for interest j (Net of amount capitalized as shown above) $ 86,035 5 111,464 $ 132,966 l The accompacupng notes are an integralpart of thesefinancwl statements.

i; m - ' s Q 9l N 3 QQ TN MMWEC b& -Notes to Financial Statements (1) Massachusetts Municipal Wholesale Electric Company (MMWEC) .M MMWFC is a pohtical subdivision of the Commonwealth of Massashusetts, authorired to issue revenue hond revenues denved from Power 5 ales Agreements (PSAs) isee Note 6) with its members and other electric systems to f [ construumn and ownership of electric power facihties.A Massachusetts city or town having a municipal electric de authorved by maiority vote of the uty or town, may bewme a member by applying for admission to MMWEC and a 'Q mmply with the terms and conditions of membership as the MMWEC By Liws may require.As of December 31,1993, tw n Mawashusrtis municipahties were members. MMWIC obtams power supply capacity by acquinng mterests in vanous generating units and the operation ofits own el - generaimg facilities iProtectshSee Note 4 for a discussion of MMWEC's electra generation facihties and commitments thereto in add:tmn. MMWFC mntracts for power for resale to its members and other utdities. (2) Significant Accounting Policies MMW1 C presems its finantial statements in at.cordance with generally accepted aaountmg principles as promulgated b th' Y Imanaal Acmunting Standards Board and the Governmental Accounting standards Board. interest Charged to Projens During Construction MMW1C tapitahres mterest as an element of the cost of (1) electric plant while under construction, includmg an approprise tesong pamd and R) nudear fuel m process.A correspondmg amount is reflected as a reduction of interest expense.The am mterest capitahied n based on the mst of debt, indudmg amortizanon of debt discount and expenses. related to each Proicct. n insesiment gams and losses and interest mcome derned trom unexpended Proicct funds. Nudear Fuel Nudcar fuel mdudes MMWFC's ownership interest of fuel in use, in stock and in process for Millstone Umt 3 and Seabrook Nanon]uri m use is refleded net of accumulated amortaation of 5501540.0 and 527.7 mdhon through December 31,1993,1992 and 199L respecovely.The cost of nuJear fuel is amortued to Fuel Used in Electric Generation based on the relationship of energy produied in the current penod to total expei.ted energy production for fuel m the reactor.A provismn for fuel disposal cost j mduJed m i url Used m Electne Generation based upon disposal contracts with the Department of Energy (DOE).In addition, Fuel Used m IJectric Generanon indudes the annual awessment, under the Energy Policy Act of 1992, for the costs of decontamination and detommndonmg of uranium ennchment plants operated by the DOE. Billings from the DOE will occur over the next 14 years.At MMWIC's share of Mdistone Unit 3 and Seabrook Station unbilled assessments was $481,000 and 5816,000. Dei ember 31,1993, respettnely.The amounts are mduded m other deterred charges and acsrued expenses. 5pecial Funds Proceeds from the sales of revenue bonds for Proiects are deposited with Trustees to be invested untd they are required for costs of asquiutma and wnstrucuon or debt service payments.The $pecial Funds, other than certam working funds, are restricted use by the General Bond Resolution, which also prescnbes mvestment thereof. Investments are hmited to direct obhgatio I obbganons the prmapal of and mterest on which are unmndaionaih guaranteed bv the United States, federal governmen j set unnes, new housmg authonty bonds issued by pubbc agenoes or muniapahties, direct and general obhgations of certain sta j pohncal subdivisions, bank tune deposits evidenced by certdkates of deposits issued by banks, and repurchase ag pomary de.ders secured by certam secunnes.Certain 5 pedal funds are more restricted as to which of the aforem f can be purchased Speaal i unds mdude amounts held m trust under Power Purchase Agreements, working capital ar ageon wntract,.These trusteed funds are invested in sesunties as outhned within the General Bond Resolution, a h king capital arrangement agreements sciured bs certam secunties at banks where MMWIC has established accounts, althoug the wor and agency mntrasts are not governed by the General bond Resolution.(See Note 7aThe composition of Special Fu ,j 1993 1992 1991 fund (in Thewndr Construs non l und for deposit of bond proteeds to 5 5 517 5 MM .f 4 be used for costs of asqumnon and constructmn 19,573 15.370 14,844 5' bond i und Interest Pnnapal anJ Retirement Auount to pav prinopal and interest on bonds ' $.] j ] 88.166 102,243 146 A64 I Bond f und Reserve Auount set at the maximum 4. +$ annual interest obbganon to make up any I defnienacs in the Hond I und Interest g Pnnapal and Ret.rement Account Reserse and Contingensy f und to make up 17,140 18,M4 20,078 h detiuenaes m the Bond f und and pay for A renewals and extraord nary msts e g? Revenue 1 und to reseive resenues and dnburse 47,461 47,784 58,191 them to other funds 18,759 11.981 10,517 Workmg Capital f unds to mamtam funds to mver h operatmg expeme3 M 5191,099 5 198,259 5 2 % 187 T otal $pesial f unds s ~ () -.-+ $.[Q3 4 N

m O MMWEC Notes to FinancialStatements nV (2) Significant Accounting Policies (continued) d by Cash and TemporaryInvestments ?the Certain cash and temporary investment amounts are used for power purchases and working capital requirements of

ient, MMWECfniese funds are not governed by the General Bond Resolution.In addition to the investment securities delineated in the y '"

General Bond Resolution, MMWEC purchases Canadian currency for cash and forward settlement and invests in repurchase eight agreements with banks where MMWTC has established accounts.(See Note 7.) Inventorkes

e,,;,

ating Fuel oil and spare parts inventory are recorded and accounted for by the average cost method.At December 31,1993,1992 and 1991, fuel oil inventory was valued at $4.2, $3.4 and $4.3 milhon, and spare parts inventory amounted to $10.6, $11.9 and $15.4 milbon, respectively. Revenues and Unbilled Revenues 'y the Revenues include electric sales for resale provided from MMWFC's operating units and power purchases and billings for administrative and general services provided to MMWEC's Service Participants.These and additional details of revenues are as follows: Revenues 1993 1992 1991 unbommw Electric sales f r resale $ 243,817 $ 270,455 5 271,578 mi of Service 2,813 2,586 2,617 ict of PSNH Settlement 2,000 2,000 2,000 Gain on land taken by eminent domain 292 Revenues $ 248.630 $ 275,041 $ 276.487 irunk MMWFC bills its members for costs incurred in providing services and purchased power obtained on their behalf under terms of y 9,y the Service Agreement and Power Purchase Agreements. Service revenues are recorded as the expenses are incurred. Amounts which are nerp not yet billed are included in Unbilled Revenues on the Statements of Financial Position. ,$g, ;, , l uel The difference between amounts billed currently under the terms of the PSAs and total expenses recorded in the Statement of n and Operations is charged or credited to Amounts, Recoverable Under Terms of the PSAs. 'rs;Q Amounts Recoverable Under Terms of the Power Sales Agreements [ ) Bilhngs to Project Participants are designed to recover costs in accordance with the PSAs.The billings are therefore structured on a Yj Project-by-Project basis to provide for debt service, operating funds and reserve requirements. Expenses are reflected in the Statements of Operations in accordance with generally accepted accounting principles.The timing difference between amounts billed and ists of expensed is charged or credited to Amounts Recoserable Under Terms of the PSAs. Amount will be recovered through future billings . their or an expense will be recognized to offset credit balances.The principal differences include depreciation, fuel amortizanon, costs other associated with cancelled Projects, cost of advance refunding; tertain interest, rtwives and o'her costs.The reduction of Amounts Recoverable Under Terms of the PSAs for Projects with billings in excess of cost is primarily due to the billing of interest costs for genty tes or Projects under construction through June 30,1990 An increase in Amounts Recoverable Under Terms of the PSAs is primarily caused , with by recognition of depreciation expense in excess of bond principal payments related to a Project and the cost of advanced ments refunding Individual Projects with a cumulative deferral of costs total $201.4, $164.9 and $155.4 million and Projects with cumulative is and billmgs in excess of costs total $11.6, $32.6 and $120.4 milhon at Dece nber 31,1993,1992 and 1991, respectively.These amounts have a hate been netted in the Statements of Financial Position.

ment Depretiation Elettric plant in service is depreciated using the straight-hne method.The aggregate annual provisions for depreciation for 1993, 1992 and 1991 averaged 4% of the original cost of depreciable property.

0) Debt Power Supply Sys:em Revenue Bonds To fmance construction of ownership interests in electric generating facilities under its General Bond Resolution, MMWEC issued Power Supply System Revenue Bonds (Bonds).The Bonds are secured under the General Bond Resolution by a pledge of the revenues derived by MMWEC under the terms of the PSAs and from the ownership and operation of the Projects in its power supply system. Pursuant to the PSAs each Project Participant is obbgated to pay its share of the actual costs relatmg to the generating units planned, under construction or in operation.The Project Participants' obhgations are not contingent upon the completion or operational status of the un ts.

MMWEC financmgs, other than obligations maturing within one year, require Massachusetts Department of Public Utilities' (DPU) authoraation.in November 1993, MMWFC received authorization to issue up to $1,165.8 milhon of refunding bonds and subsequently used $334.78 milhon of said amount to issue the 1994 Series A and B bonds in February 1994. In 1993 and 1992, MMWLC issued $4443 and $748.3 milhon of refunding bonds, respectnely.The proceeds of 1993 Series bonds, when combined with $14.5 million from the Bond Fund Reserve Account and Bond Fund Principal Account were utilized to defcase ,/] $412.1 mdhon of the 1976 Series A lxmds and portions of the 1978 Senes A,1979 Series A and 1987 Series A bonds.The pmceeds of (") 1992 Series bonds, when combined with $49.1 million from the Bond Fund Reserve Acenunt, Construction Fund and Bond Fund Pnndpal Account were utilaed to defcase $716.3 milhon of high interest bonds comprised of the 1930 through 1982 5eries bcmds and portions of the 1984 Series A,19tt5 Series B and 1987 Series B bonds /fhe proceeds frorn the refund;ng bonds and the available funds have been deposited in an irrevocable esciow account and used to purchase direct obbgations of the United States Government in an _ _ - _ _ _ -. i

- @? 4.. e, s., D] 1 MMWEC - Notes to Financial Statements (3) Debt (continued) Power Supply System Revenue Bonds (continued) fh l amount sufficient to pay the debt service requirernents of the refunded bonds through the redemption dates.The ,i 1992 advame refundings equalled $43.9 and $73.2 million, net of $2.8 and $7.9 million of expenses, respecti dbi d i i reduced its aggregate debt service payments by $146.6 and $693.4 million over the next 27 and 28 years an o ta ne an e 14 fdifference between the present values of the old and new debt service payments) of $65.5 and $288.2 m f41 refundings, respectively. , 45 The fair values of MMWECs long-term debt instruments are esumated based on the quoted market prices for the 31,1993, the carrymg amount and estimated fair value of MMWEC's l issues of the same remaining matunties.As of December Dk [ long-term debt is $1,374 6 and $1,436.1 million, respectively. Fair value estimates are made at a specif NT market information and information about the financial instrument.These estimates are subjective in nature, in iudgment, and cannot be determined with predsion. Changes in assumptions could significantly affect the est d { Bonds Payable consist of Serial and Term Bonds and are comprised of the following issues, which are gene Q( dically thereafter to 1009L redemption approximately ten years after the issue date, at 103% of the principal amount, descendmg perio ] l m December 31, Inne Cmt 1993 1992 1991 Q Net In'erest un Thommiu '1' 1976 Series A 7.2% 56,005 57,140 1977 Series A 6.4% 144.240 147,815 154.430 i 74,325 75,910 77,525 1977 Series B 6.1 % 1,085 60,045 61,010 j 1978 Series A 6.8% 1979 Series A 7.0% 118,125 122.400 g 2<g 1980 Series A 10.2 % 77,835 F 98365 1981 Series B 13.4 % )i 1981 Senes A 123 % 81,415 f 1982 Senes A U.4% 61,150 1982 Series B 10.2 % [ 126,045 800 1,515 93,380 )p:' 1984 Series A 11.0 % i 525 825 52.620 gC l 1985 Series B 133 % 1987 Series A 6.9% 10,730 195,815 198,005 s i 1987 Series B 11.8 % 540 139,400 104,910 104,910 ,} i 1992 Series A 7.0% 322,665 326335 1992 Series B 7.0% 61,070 61,070 ,, y 104,690 105,805 M' 1992 Series C 6.9% 9' 1992 Series D 63% i40,050 149,040 J 1992 Series E 6.0% 1992 Series F 53 % ~ 1,055 h } 441,255 .jy 1993 Series A 53 % i 1,435 _ 1,404,810 1,400 720 1993 Senes B 5.9% f 1,407,780 f Bonds Payable 0 3,175) f 28,110) (19,765) $ 1.374 A05 $ 1376.700 $ 1380.955

[

Less: Current Maturities Total !.nng-Term Debt }[ The aggregate annual principal payments due on the Bonds in the next five years are as follows:1994 ,( ( $ 34365,000; 1996 - $35,980,000; 1997 - $37,735,000; and 1998 - $39,705,000. j Net Revenue Availablefor Debt Semce (, In accordance with the provisions of MMWEC's General Bond Resolution, MMWEC covenants that it 6 d ,5 ; collect rates, tolls, rents and other fees and charges, sufficient to produce revenues to pay all operating and mainte ld ?f '. principal of, premium, if any, and the interest on Bonds and to pay all other obligations against it f h contract year ending .3 applicable interest earnings from investments, are required to equal 1.10 times the annual debt service or ea June 30, after deduction of certain operating and maintenance expenses and exclusive of depre 7 and prior years, MMWEC met the General Bond Resolution debt service coverage requir l l{ t June 30,1993,1992,1991 applicable MMWEC Projects. Contract Year Ended June 30, B. 1993 1992 1991

• a i un ThownN

$ 168,531 $ 195.952 $ 181,887 Debt Service Coverage: %l 661 713 70 14evenues Other Billings 12.444. 14342 _ O.757 181,636 211,207 196,357 1 Reserve and Contmgency Fund Bilhngs Total (44 J47) . 151,U l) (45,024) $ 06#9_ LL9 956_ $_IlW)_ .O Less: Operatmg & Maintenance Expenses Available Revenues Net of Expenses $ 124,444_ $ 145,434 M 575,_ Coverage ()10% RequiredI ] Debt Servi (e Requirement t 10% 110 % 110% w d l n

a 4 MMWEC -Notes to Financial Statements i\\ (3) Debt (continued) Notes Payable 993 and MMWEC maintains a $7.2 million revolving hne of credit to finance temporarily certain power purchases made by MMWEC for

n effect resale under power purchase contracts.The balances outstandmg were $64,000, $113,000 and $0 as of December 31,1993,1992 and nic gain 1991, respctively, with a maximum outstanding balance of $641,000, $556,000 and $0 during 1993,1992 and 1991, respectively. Interest

,d 1992 charged on borrowings under the line of credit is at the bank's prime rate.In addition, a commitment fee of one half of 1% per annum is charged on the unused portion of the hne based on the average daily principal amount of the loan outstanding. sirmlar IWEC's (4) Electric Generation Facilities and Financing relevant MMWEC's power supply capacity includes interests in the Stony Brook Peaking and Intermediate units which it sues and operatuMMWEC is a nonoperating joint owner in the W.F. Wyman No. 4, Millstone Umt 3 and Seabrook Station units. Electric Plant in Service also indudes MMWEC's Service Operations which totalled $2.3,52.3 and $2.2 million in 1993,1992 and 1991, optional respectively. 9 100 % iscility and MMWEC Amounts as of December 31, Proiccts share of Capability atW) 1993 1992 1991 Un Thomandu Peaking PTolcCt blony Brook 170.0 56,330 56,289 5 56,247 Intermediate Proiect Stony Brook 311.3 150,322 147,973 146,529 Wyman Project W.F. Wyman No. 4 22.7 7,357 7,394 7.354 Nudcar Proiect No.3 Millstone Unit 3 36.8 128A51 128,372 128 371 Nudear Mtx No. I Millstone Unit 3 18.4 50,816 50,677 50,676 Nuclear Mix No.1 Seabrook Station 1.9 8 s7; 8.579 8,604 Nudear Project No.4 Seabnmk Station 49.8 258,545 258,665 259,346 Nudear Proicct No.3 Seabrook Station 12.6 70,764 70,794 70,966 Project No. 6 seabrook Station 69.0 500.186 500,352 501,295 5 1,231,546 5 1,229 M 5 $ 1,229381 in January 1988, Public Service of New llampshire (PSNH), then the lead owner of Seabrook Station filed for protection from its creditors under Chapter ll of the Federal Bankruptcy Code.In June 1992, in accordance with a court-approved plan of \\ reorganiotion, Northeast Utiht:es (NU) ugubed PSNH and placed Seabrook Station in a separate single asset subsidiary corporation. (] In May 1991, New Hampshire Electric Cooperative (NHFC), a 2% Seabrook Station joint owner, fded for protection from its creditors under Chapter il of the U.S. Bankruptcy Code.NHEC continues to make all of its Seabrook payments.A joint plan of reorganization has been approved by the court and NHEC expects a 6nal court decree in 1994. In February 1991, EUA Power Corporation, a 12% jotnt owner of Seabrook Station, hied for protection from its creditors under Chapter 11 of the U.S. Bankruptcy Code.Two Seabrook Station joint owners have funded in part, the FUA Power Corporation Seabrook obligations.The Bondholders Comminee fled a plan of reorganization which was approved by the Bankruptcy Court.EUA Power Corporation changed its name to Great Bay Power Corporation, has received regulatory approval of certain aspects of the plan and anticipates 6nal approval in 1994.The Bondholders Committee plan assumes the Seabrook foint Ownership Agreement (LOA). In June 1988, MMWEC's Board of Directors adopted a strategic plan of action relating to its Seabrook Station joint ownership interests.MMWEC and PSNH subsequently entered into a Memorandum of Understandmg whereby PSNH paid MMWEC's capital costs up to $30 milhon, MMWEC maintained its full ownership in Seabrook Station and agreed to a Comprehensive Settlement Agreement which was approved by the bankruptcy court.The Agreement provided for amendments to the Seabrook 10A, notices of default bemg rescinded, certain covenants not to sue, PSNH to pay MMWEC $2 milhon per year for eight years upon commercial operation of Seabrook. joint termination of the Sellback Agreement between MMWLC and PSNH and certain other considerations. MMWIC's mvestment in Seabrook Station represents a substantial portion ofits plant investment and fmandng.Seabrook Station vne and experiented persistent cost increases and schedule delays, induding the cancellation of Unit 2.The Seabrook Station joint owtwrs have nyes and authorized the sale or transfer of all salvageable cornponents and equipment from the cancelled Unit 2.MMWEC's net costs,indudmg mdude interest expenses,in Scabrook Unit 2 of $126.4,5127,0 and $127.6 million as of December 31,1993,1992 and 1991, respectivdy, have r endmg been deferred and are being recovered under the terms of the PSAs. reended , for the in 1981, the Boston Ednon Company cancelled Pilgnm Urat 2, which is induded in MMWfC's Nuclear Mix No. l.MMWEC's net costs,indudmg mterest expense associated with the Unit, with aggregates 56l.2 milhon were deferred and are being recovered under the terms of the PSAs. (5) Benefit Plans MMWEC has two non-contributory defmed bene 6t pension plans covering substantially all full-time active employees.One plan covers union emplovces (union plan) and the other plan covers non-union employees (non-union plan).The amount shown below as the l Pension Benc6t Obhgation for MMWTC is a standardacd disdosure rneasure of the present value of pension benc6ts, adjusted for the effect of proiccted salary increases, estimated to be payable in the future as a result of employee service to date.The measure is the actuarial ) present value of credited proiccted benefits and is independent of the fundmg methm! med to deterrnine contributions to the plans. ~ The Pension Benefit Obbgation was computed as part of an actuanal valuation performed as of January 1,1993.5ignificant actuarial assumptions used in the valuation mdude a weighted-average discount rate of 8.0% a year compounded annually, and pro;ccted salary increases of 3.5% a year compounded annually.The Pension Benefit Obhgation for both plans is as follows: i l 9 _._

mW u g MMWEC -Notes to Financial Statements (5) Ilenefit Plans (continued; Amounts as of January 1, 1993 1992 1991 On m mamW q Retirees currently receiving benefits and ~<' g I terminated employees not yet receiving bene 6ts $ 137 $ 123 $ 105 l Current Employees: Vested 1,423 1,172 900 q Non-vested 1,447 1,239 1,010

1. deD' Total Pension Benefit Obligation 3,007 2,534 2,015 t assets available for benefits, at market 2,395 f.859 I,260 r

Unfunded Pension Benefit Obhgation 1 612 1 675 $ 755 4 Net assets available for benefits, at market as a percentage of the Pension Benefit Obhgation were 79.6%,73.3%, and 62.5% as of January 1,1993,1992 and 1991, respectively.The unfunded Pension Benefit Obligation as a percentage of covered payroll was 11.4%, 4 12.94% and 15.67% for the years ended January 1,1993,1992 and 1991, respectively. MMWEC makes annual contributions to the pension plans equal to the amounts recorded as pension expense, which were $489 000, $467.000, and $414,000 for the years ended December 31,1993,1992 and 1991, respectively. Contributions as a percentage of U 'i MMWEC's covered payroll were 8.9%,8.3% and 7.9% for the years ended December 31,1993,1992 and 1991, respectively.The union plan uses the aggregate actuarial cost method and the non-union plan uses the froren initialliability actuarial cost method in j determimng pension expense.In addit on to the actuarial assumptions outlined above, the assumed long-term rate of return used in

U determining pension expense was 9.5EPension costs applicable to prior years' service are amortized over thirty years. Ten-year historical trend and other information which is required to be disclosed in accordance with Governmental Accounting Standards 1

Statement No. 5 is not considered material and therefore is not presented. MMWEC contributes to an employee savings plan administered by an insurance company.All full-time employees meeting the service requirements are chgible to participate in this defined contribution plan.Under the provisions of the plan, MMWEC's .)! ~ contributions sest immediately.MMWEC contnbuted $105,000, Sv4,uun and $84,000 while the employees contributed $170,000, $165,000 and $144,000 during the years ended December 31,1993,1992 and 1991, respectively. i (6) Commitments and Contingencies h, Power Purchases MMWEC entered into agreements for participation in the interconnection between New England utilities and the Hydro-Quebec -i electric system near Sherbrooke, Quebec (Phase 1), which began commercial operation in October 1986.The New England portion of 5 the interconnection was constructed at a total cost of about 5140 million, of which 3.65% or $5 million is MMWEC's share to h support.MMWEC has also entered into similar agreements for participation in the interconnection between New England utilities and ^ the Hydn>-Quebec electnc system for the expansion of the HydreQuebec interconnection (Phase 11) which went into commercial y 3 operation ir, November 1990.MMWEC's equity investment approximates 0.6% or $3.3 million of the total estimated cost MMWEC ( has corresponding agreements with its members and another utility to recover MMWEC's share of the costs associated with the interconnection. 3 p Power Sales Agreements y i M MWEC sells the Project Capability of each of its Projects to its members and other utihties (Project Participants) under PSAs. ~% a in 1985, the Vermont Department of Pubhc Service (VDPS) brought an action against MMWEC in a Vermont Superior Court challenging the vahdity of the Project No. 6 PSAs between MMWEC and the Vermont Project No. 6 Participants.In 1986, the Superior [,, i Court ruled that these Project No. 6 PSAs were valid.The plaintiffs appealed this ruling to the Vermont Supreme Court which ruled in /j -l { 1988, among other things that the Project No. 6 PSAs with the Vermont utihties were void since inception.In lanuary 1989, the j Vermont Supreme Court denied an MMWFC motion for a rehearing and MMWEC subsequently fded a writ of certiorari with the j ..? United States Supreme Court which was denied. i The Vermont Supreme Court decision, together with VDPS actions, and a Vermont Public Service Board order resuhed in all the d l Vermont Project No. 6 Partwipants ceaf.ng to make their PSA payments to MMWEC.The default by the Vermont Participants and g N i Eastern Maine Electric Cooperative (EMEC) brought about the realk> cation of the Project No. 6 Project Capability in accordance with l the step-up provhions of the PSA and precipitated various lawsuits discussed below. ,q Inasmuch as the Stony Brook Intermediate Project has approximately 8.2% of Project Capability under PSAs with Vermont 4 entities, which PSAs are virtually identical to tae Project No. 6 PSA, the Vermont Supreme Court decision on the Project No. 6 PSA could base equal apptwation to the Stony Brook Intermediate PSAs.The Vermont Legislature enacted legislation reeking to val ~ ' l Stony Brook Intermediate PSA in light of the Vermont Supreme Court decision.MMWEC sought a declaration in a Vermont Supe Court on the vahdary of the Stony Brook Intermediate PSA, as well as the legality of the curative legislation.In August 1992,the court declared the Stony Brook Intermediate PSA valid and the Vermont Supreme Court upheld that decision in February 1994. The Vermont Supreme Court decision declaring the Proget No. 6 Vermont Participants' contracts void since inceptio certam Mmachusetts Project No. 6 Participants to fue complaints in Massachusetts Superior Court relating to the valid tv of their .4 r

f i. II. '0 MMWEC Notes to Financial Statements p (6) Comrnitments and Contingencies (continued) Power Sales Agreements (continued) \\ l PsAs and the imposed step-up therein.As alleged in the complaints, a condition precedent to the validity of all the Project No. 6 PSAs is 100% participation, and if the Vermont Participants' contracts were void since inception, this condition precedent has not been met.The complaints alleged that the step-up in Proiect No. 6 billings, as a result of the default by the Vermont PSAs. failed to have 100% participation and MMWECs use of other Project No. 6 funds to cover the shortfall in receipts constituted a breach of the PSAs. ] in 1989, hiMWEC filed an onginal action in the Supreme h dicial Court for Suffolk County against two Massachusetts Project No. i 6 P.rticipants.The Supreme Judicial Court for Suffolk County combined this case with the other Project No. 6 Participant cases j pending in the Superior Court and granted two preliminary injunctions, ordering the nonpaying Participants to pay their l obligations.After the case was remanded to it in 1990, the Superior Court stayed any further proceedings and ruled that the nonpayment of the Vermont Participants constituted a default within the meaning of the governing documents and that this default triggered the step-up and other related actions required by the PSAs.On appeal, the Supreme Judicial Court for the Comraonwealth j (SIC) opmed that "the Project 6 P$As executed by the defendants are valid and that the step-up provisions therein have been properly invoked."In October 1991, judgment entered for MMWEC in the Superior Court.A writ of certiorari with the United States Supreme Court seeking to overturn the SIC opinion was rejected. % as of 11.4%, in 1992, the Superior Court amended the 1991 judgment stating that the only issue remaining in this case was the Sellback Damages Claims of three Participants against MMWEC.By stipulation of all parties to the case, all rights of appeal with respect to the 1991 judgment entered in the Superior Court and the 1992 order amendmg that judgment and allissues decided therein were itage of waived.Therefore, allissues regarding rescission of the Proicct No. 6 PSA raised in this case have been decided in favor of MMWEC.

union in 1992, the Superior Court granted MMWECs summary judgment motion on the SeUback Damages Claims.Two Participants thod in appealed this order granting Summary Judgment to the Massachusetts Appeals Court where this matter is currently under used in advisement.A successful appeal by the Participants could put the case to triai.

n-year in 1989, Washington Electric Cooperative, Inc. (WEC) filed an action seekmg restitution for amounts paid MMWEC under the

.ndards Project No. 6 PSA.MMWEC tiled a counterclaim against certain directors, managers and attorneys for misrepresentation.Morrisville subsequently sued MMWEC and Stowe, Vermont in Vermont Superior Court.All of the other Vermont entities formerly in Proiect ing the No. 6 intervened in this action and sought restitution of the total 56.2 million paid to MMWEC under the Project No. 6 PSA. (WEC's in IW1, seventeen Massachusetts municipallight departments, which are Participants in MMWECs Project No. 6, and MMWEC "[ separately filed actions against the Vermont utilities which were Project No. 6 Participants and their respective managers, consultants l Q' and lawyers.These separate actions seek damages resulting from the imposition of the step-up in Proiect No. 6 in 1992. The Federal Court denied MMWECs motion to consolidate these cases with the WEC case.In 1993, the Federal Magistrate granted au of the defendants' motions to dismiss and/or for summary judgment.MMWEC fded objections to the Magistrate's recommendation with the Federal Ihstrict Court judge which ruled that MMWEC/the Massachusetts Participants cannot recover damages from the Vermont l Quebec utibties but may be able to collect damages from the attorneys who issued opinions.Between the WEC case and the State Court actions, i rtion of the Vermont entities are seeking $6.2 million, plus interest,in restitution. Discovery in the state and federal court actions is underway. , hare to Eastern Maine Electric Cooperative (EMEC), a Participant in MMWECs Project No. 6, defaulted on its PSA payment in 1987 and ties and subsequently filed for protection under Chapter 11 of the Federal liankruptcy Code.In 1988, the bankruptcy court denied EMECs mercial attempted rejection of its PSA with MMWEC and subsequently ruled that EMEC's plan of reorganization was non MWEC confirmable. Subsequent!y, EMEC, the Massach netts Participants, the Project No. 6 Participants Committee and MMWEC entered 6th the into a settlement of all claims, wherein EMEC is to pay the Project No. 6 Participants $15 million.The consensual plan was filed in lanuary 1994 and approved by the bankruptcy court in March 1994. Ibed on bond counsels' opinions regarding the validity of the Power Sales Agreements and general counsel representations SAs. regardmg the litigation, discussions with such counsel, and other considerations, management beheves that the ultimate resolution of the actions described above will not have a material, adverse effect on the financial position of MMWEC.MMWEC continues to uperior enforce the provisions of the Power Sales Agreernents to assure that adequate revenues are collected to meet debt service payments on its bonds in accordance with the terrns of the General ikmd Resolution. ruled in >89,the with the d3" MMWEC, as a joint owner of the Millstone Unit 3 and Seabrook Station nuclear units, is required to set aside funds for i all the their eventual decommissioning.MMWECs pokcy is to fund these reserve requirements over the licensed life of the units through nts and monthly billings to MMWEC Participants in the unit.MMWEC's share of the total estimated Millstone's Unit 3 and Seabrook Station's ice with proiected reserve requirement is $18 miUion and $42 miUion, of which $2.7 and $1.9 miuion has been funded, respectively, as of December 31,1993.The amounts are included in other deferred charges and accrued expenses. ermont in August 1988, an amendment to the Price-Anderson Act was enacted, calling for a fifteen year extension of the nuclear liability u6 PSA indemmfication process.The Act now provides approximately $9.4 bilhon for pubhc liabihty claims from a single incident at a nuclear date the facihty.The $NO million primary layer of insurance for the liability has been purchased in the commercial market. Secondary coverage .upe9 N of $8.8 billion is to be provided through a $75.5 million per incident assessment of each of the currently licensed nuclear units in the ie (Q ) Umted States.The maximum assessment is $10 miUion per incident per unit in any year.lf the sum of the liabibty claims and costs from an incident exceed the maximum amount of financial protection, each reactor owner is subject to an additional $3.8 million icaused 'ucument.The maumum assessment is subject to adjustment for inflation every five years.MMWECs interest in Mdistone Unit 3 and of their Seabrook Station could result in a maximum assessment of $3.6 and $8.8 milbon, respectively..

e 4, MMWEC -Notes to Financial Statements (6) Comrnitments and Contingencies (continued) j Other issues (continued) Insurance has been purchased from Nuclear f.lectric Insurance Limited (NEIL) to cover the cost of repair, replacement, or decontamination or premature decommissioning of utihty property resulting from insured occurrences at Millstone Unit 3 and 5,cabrook Station.MMWEC is subject to a $1 million assessment, for its participation in Millstone Unit 3 and Seabrook Station fo excess property damage, decontamination and decommissioning, as well as retroactive assessments iflosses excee resources available to NEIL MMWFC is not currently covered under gradual pollution liability insurance related to MMWEC's Stony Brook power plant Management is not aware of any material claims made during 1993 or outstanding as of December 31,1993. Additional information regardmg commitments and contingencies relative to MMWEC's debt and involvement in nuclear protects is discuswd m Note 3 - Debt and Note 4 - Electric Generation Facilities and Financing. ? 4 l

7) Investrnents and Deposits All bank deposits, which amounted to $404.627 at December 31,1993, are maintained at one financial institution.The Fed l

Deposit insurance Corporation currently insures up to $100,000 per depositor.MMWEC's uninsured deposits range i $2.8 mdlion during 1993 due to seasonal cash flows, the timing of daily cash receipts and favorable earnings offered on these deposits Investments are stated at cost adjusted for accretion f amortization) of the discount (premium).MMWEC's no to hold its investments until matunty.At December 31,1993, all securities underlying repurchase agreements, and all other mvestments, were held in MMWEC's name by independent custodians consisting of the Construction Fund Trustees, Bond Fun i.i Trustee or MMWEC's depository bank. Investments, representing the Special Funds and Cash and Temporary Investments, as we 3 certain additional amounts disbursed but available for investment, and accrued interest, are presented below. P f 1992 1991 1993 Carrying Market Carrying Market Carrying Market d Amount Value Amount Value Arrount Value l Type of Investment (Thouunds) 5 2.735 2.893 2.219 2.289 $ 15,888 $ 16.308 ,I Repurchase Agreements Other investments: U.S. 'I reasury bilis 15 15 65 65 U.S. T reasury notes 97,283 101,090 84.681 87.257 37,013 38,163 U.S. Agency bonds 16,314 16,958 18,446 19,240 56,614 57,569 s U.S. Agency discount notes 76,824 76,832 96,758 96,762 149,045 149,101 Investment in Mutual I unds 42 42 l Total other l Investments 140.478 194.937 199.950 203,324 242.672 244,833 Total lnvestments $ 193.213 $ 197,830_ $ 202J69 ( 20%613 $ 258.560 $ 261,141 Temporary mvestments, made up of funds asailable from amounts for which the expense has been recogn ~ l 1993,1992 and 1991, respect vely, and are included in the totalinvestments noted above. ( j bank, approximate 5.8, $2.2 and 5.5 mdlion in 1993,1992 and 1991, MMWEC, from time to time, invested in repurchase agreements with its J Due to seasonal cash flows during 9 depository bank that were collaterahzed by secuntses in MMWEC's name held by the depository bank.MMW 'f monitor the market value of the underlying securities to ensure that the market value equals or exceeds the amount l invested. Management estimated market values of the secunties based on independent quoted market prices. i 1 1 N f $j t m ,J> q \\ c$ 7 I l 1

n o

,3 W ammmim= esam.y k,

e R } I s i AfbiWEC ndent Auditors' Report 7) on SupplementaryInformation d -In epe \\ ent,or 3 and -On for iancial Power nuclear The Itoard of Directors Federal Massachusetts Municipal Wholesale Electric Cornpany: zero to emand [f,'her We have audited and reported separately herein on the financial statements of Massachusetts Municipal i J Fund Wholesale Electric Company as of and for the years ended December 31,1993,1992 and 1991. well as Our audits were made for the purpose of forming an opinion on the basic financial statements of the Massachusetts Municipal Wholesale Electric Company taken as a whole. The supplementary information is, included in Schedules I through !!!, presented for purposes of additional analysis and is not a required part of the basic financial statements. Such supplementary information has been subjected to the auditing ,,t,, ilu' procedures applied in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole. ,g ( ? March 11.1994 !Jln i L.Jfg t by the nwe. . with its - .c is to mount + -( 1 '

. J. ?r .w3.t a 4. mi- ...- _.~-.. _ _ ~ - ~ --.-.._. ~.- -- -. AfAfWEC - Project Statements of Financial Position Schedule I l l k*t t**P:IYT 3f, I*I9.5 ((Ff [bOkWindi) Nt1 H gg NL U EM NL W AR NL*C1fAR PROffCI IMIFR-T2LlE SEC %I R\\ BE. E mil l Ptol. 3 PROI. 4 PROI. 5 Mt6 PF 4 king MFDt4T1 %YM4% PH A%f ti 10T AL A%E15 j Firsem Plane ta %em.c 2.209 49, MI 1 fle M I $ 2W %4i 5 1s.'ne $ 500.156 5 W e iu 5 1 %.122 '.t s? 5 i,2 n.n4s An tsrmeleteci l W utum ti%2 r t I. $ 29.614 til M?l

5 6166

'+ 1 2 4 ?) .' 4 R sl t 19# 4491 1%.2241 t :4 % 440) 34

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4 4H.444 14 4'9 ikL44 4.1 44 9w0 40% %frae l uri nct <it armerterate.we

1. 5M2 2,299 tien 1 40' 4.12%

f 9 553 Total t w trs Plat M7 s* I ta Mi.it? 242.s95

• sewn 4 4*..w 9 51 4'*

90, 4 ' 41s4 t ws 9ss ' gros! Funds l And Fund l 1.wcreis Pewgal enJ 8teverement Aaoum 2.191 1391 2.lel n 7.pein t /m i 5 998 123 19.P 5 Reecevr Ano+nt N.O l* 11.941 16.0'1 4 %42 44.7M 2.tS 4 6 624 5en pg. ice llenervr ar.d t ansmpems land 3.4 42 2 tan 4.2'l ou4 4 a42 Rib 1.M.* 2R2 17.140 Revenue f und f.'%

3. area 4.Cn 1.16 2 e s to R.2%

17.*UI 1 12% 4'.466 h other.g t aptal lunds 187 t 112' 11 '%9 I R. 7'l 17.469 19.ne 26.154 7.e i n hell 1 5. * *' 29.3 t % 2.120 t !21 19 t awe ('ur-ent Assets t 'adi amf lemperatv les.cernents 1,015 1 I ( 4) 1 cts t Aununts RnrivaNe 5.7'S 2M 2% 99 t 192 t 314 84 229 21 127 9, na l ( claillest Ervenues 7.A l l 7.S i l Inventam at on.t 49 1.fl0 9 4% 2.44a 1.511 8.:An 326 14 84e AJvmors ie tirom: Press 652 (%) 157! t 32) (201 (12'l 1511 4904) 171 Prevant tapeners t=9 714 t.J an i v40 set 2 MAT 4 10.' 29 ?,e6 I Toeai t 'arrene kwts 15 e!9 I.oni 140 4.* t.II* 6.526 1352 8.2mt M1 124 40.ew 9 T.wai spawi Fwid and t urwne Ainre.

14. wo in.t s4 2 t.246 30.7n a.7n e2.6 4 4 14,e29 54.029 2.441 6il 2 5 t,7aa Ikte red t bryes Annieerre+ RnnseraMe !PawsNr6 l'n.tre terms d the Pimee sales Agreements 79 A 7 BR.754 611.207) 3.121 8312 n92 2c,tos 61:

( 394 h in9.It:0 t'narrerteerd tkbt thount and i apnw s 2.80' S.28) 7.tNui 1.0 k 17.124 es4 5 3.2 % 99 49.446 t hher '5l t.i s? 2.19 t.313 3 t% H F49 8 94 45 591 ?Ag4 'O si.Re t %.2.9 4 i ' 1*ti - 6.412 lif1_ 1 545 . 3.014 93 !H7 M *lt R.RU 5 !*49.446_ $ 214 799 $ 241,4 *-' '8 ?ft ' S 5 4A le A 5 4".944 $ 6 42F0 $ *, ?! A 2M_ 5 1.4 4.524 II A BiUI'lF $ tamg from IWe B=eds Pmt=le 1 1 144 0 t5 $ !!?,42s $ 249,we 5 75 eto 3 5 t W9 5 41.0n5 3 12R nes $ tq t % 3 $,, U 9 te reg Oserent tuNinter. ( air, esse Maturmes of long 1cem th4w 4D44 3 t75 4.tos t.4no 1o.%0 2.805 6.4.'s 244 31.175 %ees Psvehle 64 64 Auousos Pavane 4.554 79 72 L.129 284 4351 17 1.022 32 2 8.132 Austeed f areneses 5.e44 a.5ct 2.811 2.371 eel 3.28* 12 1.231 57 t ?.9e1 p.tember and Pasteupene Advames and Reereves .4 955 no' 4a2 1 <.1 s 92 7.I98

2. II e 4.ns_

2e* 296 44.'80 34 857 6 411 6.4 '4 I I.I '7 3.177 22.999 4.9411 19.*59 eo! 298 10.1.419 5 44 RU 190.44n S 21 A '99 S 2e6 4 77 5 "#,'8' S M8,104 S 4 '.9M S 842.0.*6 5 e.'r e S 298 5

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ard anusee 24.ou w tII J p-* a12 ?.I*e 2.l l a ses2 2ee p eip ([ ~* h e4 po Juv s.e3: 6.44 ._u/ 4 u. ..m u4s p us ces 2., 'E 5 N '*".L s.,,J.LC*, SM, j tj];,, s,,,.L.,,i.tg s,_,17,+1L s_y43 3.5_ s_,e,3=,,, $_,,,,,jw, s,_113 3*,. n,. ~ 3 AfAfWEC 5 Project Statements of Financial Position Schedule u 3 December 31,1993 (fsf Th7s#SsMds) HYDRO NLU EAR N1.Q IAR NEGI.AR NLU RAR PROIECT INTER-Qt'E BFC M RVMY - Mill t PROF. 5 PROI. 4 PROI. 5 NO. 6 PEAKING MEDIATE WYMAN PHAMit TOTAL Revenuen S 75A37 16.3 W 5 22,849 1 28.809 5 8.246 1 56.102 5 7.3'9 5 10.896 S 1.573 6t$ $ 24A A 40 interes iseme 566 1.021 1.411 f.710 508 3.414 6t3 1382 96 133 1L083 fetal Reveseses ansl interese lritome 5 76,403 $ 17341 $ 24.2M 10.519 5 8.74 5 5*.5 16 5 ?.*91 5 32.4'8 5 1169 76A 5 259J11 (Wmg and hvke Etrenarst Fuel Uerd m fleorsc henersium 5 5 660 l.142 3,344 5 293 5 AONI 464 7.077 5 410 5 S 20.062 Purdaeed Power 73.519 615 74.144 Othee Opersteg 2,742 2.201 3.911 5_i R6 1,364 8,015 1.237 4.435 160 29,491 Mamtenence l.I81 2.277 00*5 277 1317 256 3J13 121 10.470 tiepreciatum 79 IA% 4.019 9.242 2.529 17.874 2.257 6,064 227 44.187 Tamesothr:1han tmame 8 4's 859 1.195 147 f.6% . J.L 1.D's it? 6.076 76.384 6.416 12.208 20.0 % 5..%5 35 129 4.600

22. 4 7 1.230 615 1943no Interege iapense-interes: Charges 19 9342 13Att mJ ti 4.R41 34.862 2,709 7.751 426 s9J42 lateress Charged to Progerts Durmg Geeractkm 113) t 'IO) 1441

{t2) (71) (169! 19 9.329 1.1.451 16.268 4.820 34.'9 f 2..'U9 ' 7J51 426 49 373 healOpe atmg Cnets and interese Fnpense 76.403 15J45 25.659 %,1 44 10.194 69.920 7.F'9 to.i t s 1.M6 615 273.953 (est ot' Advante Refundmg 2.196 203t6 12J41 3A37 5,667 43.957 less on Cantelled Unita - net 19) (224) f 57) , (311) 46011 2 tR? 20JI6 12.017 M80 1311) 5.667 43.256 Ihrmawtlaneese)e Amounts Rnoverahie Under Terme cd the Power 5slen Agreements f 591) (2 tJ21) ( 17.B '21 (4.820) (10.073) 682 ( 330') 13 151 157A961 1 'F.401

UQU, 90 519 5

8.79 5 59.536 1 7.991 1 32.4'8 5 1.669 5 7es 5 259J13. ...w. -- m

i. .ii . L, .m - _ a-w._ AfAfMTC - Project Statements of Financial Position Schedule 111 llr*trTn3*t*r 31. I99 (irt 7htrdMdd Ntu fAR Ntu fag Ntu FAR Ntu t.4 R PROF}CT IN113 Qt.Titf C M RVM T MIX l PROI3 PROI 4 PROI $ NO e PIMi% MI Dl %If WTM4N PH 4W il TOTAI (.ssh hws fram operoemy sitevoors i ht#1 Rc=-nues and Intews: Imonic 7k son 5 1734l S 24.2 4 5 kl.519 S 5.744 5 59 5 %

• 991 5

12.474 t.6ei9 5 762 5 2%9 711 Totai r enti ssid F spemes. nce f '* 4a l a (17932; $45.9 3 t em.ni ; (15,5'4i it 9Niei e 7.hm s ( n.7p il ( t bw; mio (317.2005 i Aeteusteirens to siteve at part cash l pn.vxterf hv operata., m emeses Imepm ur'=m ami dn ommmmmmg 79 2.045 4.299 9 4a8 2.W I A.t A7 2.240 5 'al 411!2 Amorttisivm 1.9 42 4.141 5.6 '3 f.84 7 6 P24 129 4.242 IA 24 9M ~ E hange m turies ama.:s and lwhsheart j Auuann Re.ewable 62N tM) i lh') D78: 18653 11.2913 i M9) '6 (29 1 %MI (4194 L.ntdled Rrwenoes 67n 678 inventusies ("; iS 1101 14'9) 9M (17) 415 PrepseJ F npecars (104) n 57 (1491 taAl 148); 9 4 Mar 5s [*M4) Ausmn4 Pavable (1.2nm 8 7 1352; say f6%7) t 28) (2721 (9') 05t (2J49i Aurord i spreises aml Other 2.129 int (721 955 24:1 1.284 1225) 462 tel) 4. N l Memhet and Petnspant Advames i and Resrews 4.2M in44 3 11.9 4a 5 I finn 41% . 714 ( <A l l (23M6 (*4 6 ( t 14 2,1 *4 Net <ad. g nanled by (owl for1 ( nperarma ar tiv8es 4 Mo

2. tr tl53A4 t i,42s p

1. 6A; 16.497 f.649 9349 81 (He 13A97 i

e ash h=5 from mvesemp enveirs t msenu rma caprmbrures and gaanhasrs of nuairat hsel (911 (7e21 d l.%1i ( 2.0?> n t%25i 12.87 9 (41) (2.$71) 191 (10312) 1.terest th.irged h, Penerits duems t enstnu ewm (13) I sa! i41) (121 171) (169) Net era rece idn. arse iri sproal tunds f 6.7ft21 3M4 4.911 415 2#4 0.499, 1.087 53R7 161 4 5.lfo I sr= omemisi.mmg irust perments 12ee t i tMai 1253) (641 OW (1.2591 t hhrt 166 54 106 2r 38 2R 6JQ Net c a4 penwided by hssed foet invesemp attwners e6.707) 2.289 9.2 % ( 1.92R ) ( u4) (6,757) 1.046 3.ns; 1s4 4 (s.w) (Jdi fl+nws tTom firnaria mg attivitses Pens erdi frimi sele ol licmds %nns I M.t s5 104. % 5 41.sao l l 4.0n5 444.290 Pavmeris hw imwalisauc cmas 11.7611 D.n2Ri O.06t p f l.24n ! O.1661 (15.0641 Payments kw pnag al of inas Term t'cht 12.76 % (2.2201 (4.290) (l.265) 19.740) 12.6951 (4.955 p (2.55) (29.165) i 6.00 0 ( t 12.955) (90.6601 08N5) 4 t I).570s (412.15s) 5 Pavment for detesteme of twends Change m Nuees Pevdde ( 4e 1 (44) Net tash penvided by (med forliinammg astivities ( 44) __,.14E6) 12.152 !J54 442 19.74m (2.6*M 19.am) 12.M) 110.141) Net in< rase wrece) in tee.nd iemporary

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' [s In denving Pascoag's petO)the court upheld a January Newref ndi d inue MMWEC eted the sale of $33413 mdixm in tax-ex-empt bonds on March 15. Proceeds of the bond issue, which 1993 decision of the Rhode Island Pubhc Utihties Commission. carries a true interest cost of 5.17 percent, have been used to which had denied Pascoafs earlier request for a declaratic.n that refund previously issued, higher-interest bonds. its contract w nh MMWEC was void. The contract at issue, signed The bond sale includes $115.78 milhon in 1994 Series A in 1979, in olves Pascoag's purchase from MMWEC of 1,229 bonds, whkh were used to refund $100.6 mdhon of the out-kdowatts of Seabrook power. standing 1992 Series B bonds. The 1992 Series B bonds refunded Ihe time period for appeal of the Rhode Island Supreme were selected by lot from the $144 million of 6.75 percent 1992 Court decision has expired and a related federal court case has Series B term bonds due in 2017. These bonds, whkh were ad-been terminated, ending Pawoag's challenge to the vahdity of vance refunded, wdl be called on July 1,2002 at a premium of MMWECs Pro,ect No. 6 Seabrook wntract. 102 percent. In other litigation, the U.S. Bankruptcy Court for the District In addition. $219 millnin in 1994 Series B bonds were used of Maine has confirmed a consensua* nian of reorganization for to refund all of the outstand:ng $218.5 milhon of 1977 Series A the Eastern Maine Electric Cooperative t EM EC), which filed for .First Quarter Report and B bonds, which were called on March 17 at a premium of Chapter iI bankruptcy protection in August 1987 after default. 102 percent. ing on ns Project No. 6 contract with MMWEC. The 1994 Series A and B bonds, rated AAA, are insured by Under the plan, the 21 participants in MMWECs Project No. For tht months ended March 31* 1994 the Municipal Bond Investors Assurance Corp. and the AM BAC 6 are expected to receive a total of $15.2 million from EMIC. The Indemnity Corp. effectiveness of the reorganization plan and EMECs emergence The refunded bonds were issued to finance MMWECs own-from bankruptcy are both contingent on Lil payment of the ership in the Seabrook Station, Millstone Unit No. 3 and $15.2 mdlion to the MMWEC participants. The Proint No. 6 Wy nan Umt No. 4 power plants, Lower debt servxe resulting participants assumed EMECs share of proiect capabdity and from the refundmg has reduced power costs for MMWEC par-costs followmg EMECs default. ticipants by $53 mdfion over the next 23 years, or about $2.4 The daims of MMWEC and its proint participants against million a year. E MI C were settled during the nearfy seven years of htigation and The 1994 bond issue is MMWECs fifth refunding bond is-settlement discussions that led to the court's March 4 approval of sue since April 1992, bringing the total amo,mt of refmnding the reorganization plan. bonds issued to more than $1.5 billion. The savings from the in one of the finallawsuits stemming from the 1988 decision refunding program have reached more than $850 million over vmdmg the Seabroek power contracts between MMWEC and six the hfe of the bonds, or about $35 mdlion a year. Vermont utilities, the Iamoille (Vermont) Superior Court has found MMWEC liable for payments made by four of the utihties Moody's upgrades MMWEC rating before the contracts were voided. The Aprd 15 duision also de-Moody's Investors Service, siting a number of positive de-nies MMWECs counterclaims for damages against the utdities. velopments for MMWEC and its participants. upgraded The four utilities seeking restitution in the lamodle Superior MMWECs credit rating from Baal to A on Jan.18. It is signifi-Court paid MMWFC approximately $3.4 milhon before the mn. cant to note that the upgrade came at a time when the rating tracts were voided. All six Vermont utihties paid MMWEC a total agencies were setting higher standards for electric utilities due of about $6.2 million before the contratts were voided MMWFC to risks associated with increasing competition in the industry. retains the right to appeal the Superior Court decision after the Among Moody's reasons for the upgrade were lower muni-Vermont utilities fi!c an aaounting of amounts they bdiere are cipd utihty rates, the resolution of disputes over the vahdity of due from MMWEC with the court. MMWEC power contracts, and a better relationship between in a separate federal murt case, MMWEC has filed counter-M MWEC and its municipal utihty participants. The lower rates daims and daims xding damages from the attorneys who rep. are primarily the result of MMWECs debt refunding program. resented the Vermont utihties and prm ided MMWEC with false Improvements in the regional emnomy and above-average assurances that, among other things, the utdities had the author. operation of Scabrook Station were also cited as reasons for the ity to enter into the contracts. upgrade. The Moody's report states that "substantially lower and more competitive" municipal utility rates have "added a degree 1993 energy use is up 2.3 percent of financial flexibdity to both MMWEC and its participants." Elutric energy use among M MWTC member utihties in 1993 On Jan. 20, fitch Investors Service and Standard & Poor's Corp. increased 2.3 percent over 1992. resersing a trend of relatively reaffirmed their MMWEC ratmgs of A-and BBB +, respectis ely. levd use over the past several years. The 1993 increase is being attributed to unusually hot tum-Litig tion update mer weather, as well as an imprming Massathuwtts emnomy. The final challenge to the validity of MMWECs Seabrook Baterly cold winter weather resulted in an increaw in energy Massaihusetts Municipal Wholesale E lectric Company power sales contratts was resolved on Jan. 21 when the Rhode use among M MWEC mendwrs of 9+ percent du ing lannary 199 8, Moody Street,l udlow, MA 01056 Island Supreme Lourt demed the petition of the Pascoag (IllJ wmpared to Januarv 1993. Through Mar h 1994, members en-m3) M 0HI Fire District to have its contract with MMWI C vmded. ergy use was up 3 A percent mmpared to the same perimilast year.

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Vermont 12 llampshire acanor,6%Avr Aso Aooatss g OPERATING REPORT-FINANCIAL Vermont Elecnic G & T Cooperative, Inc.

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School Street Johnson Ve r non t 05656 s INS T A UCTIO'.S. Su>rst an cig.nat and t a cop es so SEA. Rutd attamosnts to PEAO3ENoi3 nea'est d9ar. far JcWej rrs:ructys. see ly A 8a et.n 17178 3 Deccmbcr 31, 1993 ~ l M A UsE ChLY r CERTIFidATIOil We kcor ty ce % sbat sie s n: ries.'n shit repcrr.are in accor f.ance with the accos.nts and other record.s of the system au ofou Lnom.'sJ e and br1.of. S ALLINSURANCE REQUIRED BY PART 1788 OF 7 CFR CHAPTER XVil. REA, WAS 174 FORCE CURING THE REPORTING PER uhaN INob1 h b Nn N o Nrk e. I X;cz, 4 J/R,/94 OT *. AVE ' C -e W A*t Ar2204 Accou%t A 3/>d, TE~ f -2C n - e-4 smA't., At Cs wasAGE A M CA1 SEChOtlA. STATEMENT OF OPERATIONS Y E A R.T O.D AT E ITEM LAST YEAR THIS YE AR BUDGET THIS MONTH fa) (b) (c) id)

1. Efectnc Energy Resenues.

14 572 271 14 570 000 14 563 421 1 213 743

2. Income Fre n leased Proper +f (Net).

3. Omer Opera'.ng Revenue and Income -

32 131 19 384 17 700 2 608 Totat Oper Revenues & Pavonage Capitalu tw >>.. 14 604 402 14 589 384 14 581 121 1 216 351 .1

5. Opo' ann; Espense Prmction Enclud.ng Fuel.

I 117 671 1 172 844 1 010 910 151 785

6. Operating Espense Produchon Fuel.

332 224 330 442 385 049 15 517

7. Operating Espense Other Pe*er Supp'y -

3 552 325 3 614 417 3 688 208 284 435

8. Operating Esponse Transm.ssion.

658 314 620 107 571 506 40 263

9. Operating Espense Distraut:en.

10. Operabng E> pense - C,stomer Accounts.

I 103 1 014 1 200 85

11. Operanng Espense. Customer Servce a Informai;on.

12 Opera!.ng Espense Sa'es. ()

13. Operat.n; Enconse Administ'ative & General..

697 888 640 811 377 741 67 369

14. Totar Operaten Empense (5 tw /31 6 359 525 6 379 635 6 034 614 579 474

15. Maintenance Espense - Prodsction.

34 807 39 224 36 000 2 276

16. Maintenance Esponso - Trar'sm ssion,

17. Vaintenance Espenso Distnbut.cn.

13. Vaintenance Espense. Gereral P! ant.

19. TotalIAa'ntenance Espense U5 thru /s).

34 807 39 224 2t Tai 1 698 257 1 709 087 ~ 3 000 2 276 20 Depreciat4n and Amortaat.on Espense. 1 756 644 142 578 445 218 329 408 461 633 ( 13 597 )

22. Interest on Long.Terrn Dott.

3 279 837 3 024 741 3 270 734 231 706 23 Interest Charged to Constructicn Cred t.. ( ) ( ) ( ) ( 24 Other interest Espenso _2J54 021 3 142 503 3 06R R16 779 778

25. Other Deductions 52 415

26. Total Cest of Elec tric Sorvico (14 + 19 ti.ru 25)_.. _.14 724 080 14 624 598 14 628 441 1 222 2_lj

27. Operanng Margins (41,ir u).

( 119 678 ) "( 35 214 ) ( 47 320 ) ( 5 864 ) 2a tn'erest incomo.. 119 673 35 214 47 320 5 864

29. Allowanco For Funds (! sed During Construction

30. Incomo (Los s) ftom Equiy Investments -

31. Other Nonopcrating incemo (Net)..

5 32 Conora6on & Transmission CappiCredits.

33. Othr:r Capital Cred.ts and Pattenago Dividends..

34. Entraord; nary items

35. Not Patronago Capital or Margins (1/ thru 14) _.. ITEM -

36. Electric Energy nevenco per kWh Sold.

Mills AW h (Optional Use by Dorroast) l (m

37. Total Operation & Maintenanco E>penso Per kWh Sold.

38. Total Cost of Electric Sctm) p(-r kWh Sold..

\\ If J 31 Porchaso Power CosfPer kWh Sctdh >;y 8 M' REA Form 12a (Rcv.Ib9.y Poco I't% l \\

i l U50.1 AEt conno A E R CESCNAM l Vermont 12 llarnpshire OPERATING REPORT - FINANCIAL rEni00 E NDE O HEA UliEIDid ~ Deceraber 31, 1993 SECTIOllD. BALAllCE SHEET I ASSETS AND OTHER DEDITS LIABILITIES AND OTHER CREDITS

1. Total Utey Plant in Servico.

..-59 302 664

32. Memberships..

3 9_,,__

2. Constructin Work in Progress..

33. Pa tronage Cap:tal

3. Tetai uwf Plant (1 + 2).

• 59 302 664

a. Assigned and Assignable.

.( 326 47 M

4. Accum Prov;sion for Depreciation and Amort.* *11 022 04 8

b. Retired This Year.

5 Net Uicy Plant J -4).. ..***48 280 616

c. Retired Prior Years -

6 N:,n Ut.!ey Picpe tf (Net),

d. Net Patrona;o Capital..

-( 326 4] d

7. Investmeres in Subsid:ary Companies.

34. Operating Marg;ns Prior Years..

8 invest In Astoc. Org. - Patronage Cap;tal.

35. Operating Margins Current Year.

9 Invest in Assoc. Org. Other-GeneralFunds. 19 177

36. Non. Operating Marges.

10. Invest. In Assoc.Org. Other Nongeneral Funds

37. Other Margins and Equit:es..

20

11. Investmorts in Economic Development Projects.

33. Total Margins & Equities 612 + JJdsvu 37)..

-( 326 425_)_ 12 Cter invewner.ts.. 152 464

33. Long Term Dett REA (Net)..

12 790 112

13. Special Funds..

(Payments-Unapplied S ) 14 Tctal Other Proper *y and Investments (6 suu 11). 171 641 ' 40. Long Term Debt REA - Econ Devel. (Net).. 15 Cash GeneralFunds. 500

41. Long Term Debt FFB REA Gua' anteed 1.0 919 776__

16 Cash - Corstru: tan Funds Trustee.

42. Long Term Debt Other REA Guaranteed.

16 7Sj_222__

17. Special Depe sats..

43. Long. Term Debt-Other (Net).

18. Ternpora y intestments..

19. No'es Receivable (Net).

44. Total Long -Term Debt (39 bu 41)......

.40 499 160

45. ObligatOns Under Capital Leases Noncurrent..

21 A:: cunts Receivabr Sales of Energy (Net).. 44 591 449

46. Accumu'ated Operating Provis;ons.

e

21. Accounts Receivab'e Other (Net)..

50 286

47. Total Other Noncurrent Uab4t'es (45 + 46)..

p 22 Foot Stock.

43. Notes Payab!e.

5 268 174 ( 23 Materia's and Supplies Other..

49. Accounts Payable..

11 339 071

24. Prepayments.

103 360 J

50. Tares Accrued.

~ 70 853 25 Other Current and Accrued Assets..

51. Interest Accrued.

4 839 093 2s. Tota 1 Current and Accrued Assets (15,uu 23)...44 750 595

52. Other Current and Accrued Usb.lzt:es..

.****36 972 639__

27. Unamortled Dobt Discount & Extraor. Prop. Lesses 2 281 446 53, Tota 1 Current & Accrued Liab tites (48 sbu!2)... 51189_B36._

23 Regutatry Assets..

54. Deferred Cred'ts.

90 7 SD_1 29 OtScr Deferred Debits. .#T269 022

55. Accumu?ated Ceferred income Taxes.

31 Accumulated DeferredIncome Tares.

56. Total Liabilit:es and Other Cred;ts

31. Total Assets and Other Debits (3 + /4 26 :Vu 30) 98 753 320

(>s +44 +47+51,9 53).. .98 753 320 SECTIOtl C. f40TES TO FINAtJCIAL STATEMENTS THIS SPACE BELOW IS PROVIDED FOR IMPORTANT NOTES REGARDING THE FINANCIAL STATEMENT C (If ADDITIONA L SPACE IS NEEDED, USE SEPARA TE SHEET) AsDortization & Net Plant in Service Installed Cost Depreciation Plant in Ser Seabrook $27 512 051 $ 3 703 564 $23 808 487 Millstone 3 14 951 022 3 898 956 11 352 056 No. Hartland 16 034 380 2 811 234 13 223 146 litghgate 785 544 608 294 177 250 other 19 667 19 657 $59 302 664* $ 11 022 048** $48 580 616**! AAAA

• • • • Includes Past-due Principal

$ 2 671 820 Interest 34 296 559

1. Other Deferred Debits -Unapplied REA Paymenta 3 257 77Q To current assets by CPA repo Q

11 252 Seabrook Funding Clettring V 3 269 022 ftEA Form 12a (Rev.12-93) Poge 2

G&T ACCOUNTS PAYABLE DETAIL DECEMBER 31, 1993 PROJECTS: NORTH HARTLAND ACRES - NOTE PAYABLE PAID-IN-FULL ~ PIZZAGALLI PAID-IN-FULL N.E.T. 10,289 10,289 MILLSTONE 3 - NORTHEAST UTILITIES JT. CONS. INV. 462,602 I JT. TRANSM 13,845 JT. SITE 8,140 INTEREST 560,703 SEABROOK 1,045,291 YAEC - PROJECT INV. 4,024,289 PROP TAXES & FEES 191,033 YAEC-INTEREST THRU 12/93 3,931,775 PSNH-TRASS SPPT 107,354 NEP SBRK-TWKBRY 75,661 TOWN OF SEABROOK -P TAX 40,933 LAWiERS 2,226 8,373,272 OPERATISG INVOICES COE & FERC 11,950 FERC 15,673 PAPPOSE (G,P&H) 13,575 LaCAPRA 9,853 BURAKLANDERSON 12,384 VEC-PR SERV &EXP 11,988 MISC. INVOICES 22,796 98,219 ACCOUNTS PAYABLE-GENERAL $9,527,071 ACCOUNTS PAYABLE-ASSOCIATED COMPANY (VEC) $544,000 ACCOUNTS PAYABLE-CASH ADVANCED (VEC) $1,268,000 TOTAL DECEMBER 93 ACCOUNTS PAYABLE $11,339,071 g

VCOCT s'.:M*.A2Y OF 2CVOCf3 CHEDULE #1 TMANCIAL STATE *IN7 *0Cf JAN 93 FE0 93 MAR 93 APR 93 MAY 93 JtN 93 JUL 93 AUG 93 SEP 93 OCT 93 NOV 93 DE: 93 Y2 ?0NN CALINDIR *0N*H DCC 92 JAN 93 FED 93 MAR 93 APR 93 MAY 93 JUN 93 JtrL 93 AUC 93 SEP 93 OCT 93 NOV 93 vtA2 TOTAL VER*0N* CLf 072:C CO-07 9,770,990 10020320 9,338,030 9,783,750 6,059,610 5,824,730 5,678,900 6,571,740 6,840,950 6,317,530 7,399,290 8,723,460 92,334,300 ret (cMivered) i M:LL: 1 3.36 107.63 118.09 114.91 177.35 167.58 183.49 15M.62 165.56 213.48 161.00 123.37 144.81 A*c NT 1,*32,059 1,079,017 1,102,727 1,124,796 1,074,667 976,103 1,042,018 1,042,430 51,132,603 51,348,640 51,191,310 11,*24,*76 $~.3,370,552 0 7!2 UTIL*** CMP GMP CMP CMP GMP CMP CNP CMP CMP CMP CMP n'd 1,394,?001,285,7701,339,260 2,224,510 4,931,590 5,570,137 5,C10,930 4,773,300 2,627,320 1,123,080 3,478,9 0 33,509,C60

• LLS 25.45 26.46 25.94 24.73 28.55 24.54 24.03 24.66 25.12 27.26 25.75 25.52 AM0;;T 535,432 534,018 534,740

$55,021 5142,221 1136,703 5120,667 1117,696 566,002 530,619 589,557 5362,735 OTwC2 UTIL; VM VM VM VM VM VM VM VM CVPs: GN 'deuvered) 1,293,900 1,407,450 1,316,280 1,407,000 463,340 1,442,080 1,412,120 1,388,350

• 123,080 11,253,600 FILLS 26.75 25.72 26.54 25.73 31.81 20.65 22.40 24.84 20.00 24,44 ASU':*

534,615 536,204 534,928 $36,198 114,737 $29,783 531,625 534,489 522,462 5275,040 0*C2 UT:C ** CMP CMP GH 1,488,530 1,019,150 2,507,680 MILLS 25.00 24.00 24.59 f AMOUNT 537,213 524,460 561,673 07-:= :- u ' CN O MILLS A*.0' NT sc J

• NUCS: ELCCTRIC SA* s i.

12459090 12713540 11993570 13420260 11504540 12836940 12,101,950 12,733,390 10,956,800 7,336,630 9,645,450 12,202 430 ~37,904,640 MILLS 96.49 90.39 97.75 90.61 107.06 89.01 93.69 93.82 112.79 187.16 129.01 d.47

• 04.14 AMO:.T 1,202,156 1,149,239 1,172,395 1,216,015 1,231,625 1,142,594 51,194,310 51,194,615 51,235,817 :1,373,099 31,244,39' 51,2*3,743 s14,570,C00 CTMC2 ELECTt:0 R!v!r.us VT..*A C.C - TRAEM. LEAS:

51,976 11,958 11,912 12,022 $1,097 1996 1%1 51,089 51,008 11,477 1987 51,997 si7,48* tvP:t - TRAN;9 CAPA ;TY 5246 5775 527* 5611 si p 3 0 2:2 Arvrv:;E 50 TOTAL 2CVCt.:ts 1,204,1321,151,1981,174,3071,218,0371,232,7221,143,590 $1,195,271 11,195,703 $1,237,07211,375,352 51,245,648 5*,2"6,35* $*4,539,334 I 9 9 e

SCHEDULE #2 VEC 7.

• SU**A2Y OF PURCNAsED POUER COSTS T!NANCAL STATE *ENT P'ONTH JAN 93 FFn 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 03 AUG 93 SEP 93 OCT 93 NOV 93 DEC 93
• 2 MON *M CA'.EM3E4 MONTH DEC 92 JAN 93 FE0 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 sEP 93 CCT 93 NOV 93 YEAR TOTAL "C22 :"A CIC CASACITY W

1,n09 1,909 1,909 1,909 1,909 1,909 1,909 1,909 1,909 1,909 1,909 1,0 22,908 UN;* Cost-5/c 7.02 4.89 5.53 6.06 5.H5 5.73 12.22 7.24 5.96 6.06 7.67 6.56 6.73 AMout:T 513,375 19,341 510,562 511,572 511,163 510,934 523,322 513.823 11,379 511,559 $14,634 512,520 5 54,214 l ENEROY nw 1,314,R90 1,162,720 1,203,6RO 1,257,760 608,430 50,340 ' 995,510 1,233,210 1,149,330 i,254,690 1,093,750 -1,*37,6'0 ~2,455,920 UN:T COST

• MILLS M.:H 17.25 17.48 17.47 17.03 17.49 29.59 18.47 17.43 17.61
• 6.83 16.49
• 8.80

~7.52 AP'0*si t??,M4 120,323 $21,032 521,478 510,643 51,490 518,391 121,496 $20,234 521,120 $13,C32 $21,274 52'3,*97 TOTAL 134,079 129,665 131,594 133,051 521,811 512,424 541,713 535,324 531,613 $32,679 $32,666 533,794 $32,411 M:R2:"ACv.-AVG Cos? - MILLS /nN 27.44 25.51 26.25 26.28 35.85 244.79 41.90 28.64 27.51 26.05 29.87 29.86 29.90 VC:*0NT wxEE CA?ACITY W 5,477 5,477 5,477 5,477 5,477 5,477 5,477 5,477 5,477 5,477 5,477 5,477 65,724 UN

• COST: 1/m 26.91 19.87 20.51 23.44 24.35 22.19 21.20 24.09 30.52 47.46 28.57

23. r.5 26.04 A*0CNT 1147,371 5103,804 1112,340 $123,356 1133,359 1121,534 5116,102 5131,943 5167,134 5259,957 5156,457 5123,4*1 11,711,767 EntaV m

4,045,020 4,049,740 3,633,130 4,034,400 2,494,180 3,964,530 3,749,900 3,757,840 2,974,650 0 638,*70 3,9'2,620 37,309,180 LN!T C0sT*

• ILLS M.H 6.00 5.79 5.84 5.80 6.06 5.80 5.83 5.83 5.95 N/A 6.67 4.99 5.86 A*0CNT S24,253 t23,460

$21,259 523,333 515,126 523,000 121,853 121,901 517,694 $2,401 54,587 $*9,525 5213,452 TOTAL 1171,629 1132,264 5133,598 1151,739 $148,485 1144,534 5137,960 5153,843 1184,828 5262,353 Si61,044 5"47,936 11,930,2*9 VT-YAW![-AV:; COST - MILL /nH 42.43 32.66 36.72 37.61 59.53 36.46 36.79 40.04 62.13 N/A 234.02 37.31 5*.74 IONCATE : CADAC!*V G 4,020 4,020 4,020 4,0?O 4,G?O 4,020 4,020 4,020 4,020 4,020 4,000 4,i] 48,240 UN: Ces - sm 5.6s 5.6s 5.14 5.69 5.50 5.69 5.50 5.68 5.68 5.c 5.59 5.c 5.55 A-1*JNT t??,843 $22,843-520,647 522,877 122,127 522,863 522,111 122,843 $22,848 521,731 522,455 52*,731 5:57,932 EXER;Y m 1,630,200 1,431,750 1,580,410 1,555,550 1,369,300 1,240,520 1,331,590 1,310,000 1,519,010 1,460,990 1,537,130 1,392,000 17,603,450 UN:? COST: F LLS/vW 16.R9 16.98 16.98 17.00 17.15 17.40 17.63 17.75 17.75 17.81 17.78 17.67 17.38 APOL*JT $27,539 127,705 $26,R35 526,444 123,483 521,535 524,357 123,251 $26,965 526,025 527,324 524,599 5306,*14 A3.*JO**ENT L VELCO CYP (14,958) (14,179) 1782 1547 12,477 5686 568 12,336 5895 59,231 5524 5752 59,120 TOTAL !45 429 144,374 543,264 149,863 543,087 145,134 146,536 548,435 550,707 556,937 550,303 $47,042 55E3,*66 H;C180 ATE 1-AVO Cesi-MILLt/nN 2t.87 23.42 30.54 32.04 35.12 36.38 33.68 36.97 33.33 39.01 32.73 33.79 33.12 s u ___m

JAN 93 FED 93 MAR 93 APR 93 MAY 93 JLH 93 JUL 93 AUG 93 SEP 93 OCT 93 NOV 93 OEC 93 12 MONN DEC 92 JAN 93 FEB 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 SEP 93 OCT 93 NOV 93 SU3*0TAL s*0T PURCWASIs GMP GMP GMP GMP GMP GMP G"P GMP GMP GMP GMP GPP e AED AED A&O A&S A50 A&8 A&B r4 5,000 5,000 5,000 4,000 4,000 3,000 3,000 4,000 4,000 3,000 4,000 3,000 47,000 LN:7 COST-5/rJ 2.75 2.75 2.75 2.75 2.75 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.62 A*0UNT $13,750 513,750 513,750 $11,000 $11,000 57,300 57,500 siO,000 510,000 $7,500 5'C,000 57,500 $123,250 10',,000 0 0 136,000 45,000 3,000 0 0 203,000 45,000 64,0 T 3,000 604,000 cv t, !! C057-M:tL;/v'.ne 30.70 ERR ERR 29.00 29.?? 23.00 28.00 28.00 29.53 29.33 29.25 23.00 29.57 N A*0LNT 53,245 10 50 53,944 51,315 534 50 50 55,994 51,320 51,872 534 s 7,353 TOTAL s16,995 513,700 513,750 514,944 512,315 57,584 57,500 110,000 515,994 ss,*'O s~i,872 57,534 si41,iO3 m -AVO COST - MILLS /CN 161.PA CER ERR 109.83 273.67 2528.00 N/A N/A 78.79 196.00 ~85.50 2523.00 233.62 SPOT PURCwASEs GMP GMP GMP GMP GMP GMP GMP CAPAC*TY DERLIN A&BCERLIN AED DERLIN ASD BERL!M ARD DERL'N AE8 PERLIN A&B BERL!N A&B CJ 2,000 2,000 2,000 2,000 2,000 2,000 2,000 ~4,000 LN 7 C007-5/rJ 0.33 0.33 0.33 0.33 0.33 0.33 0.30 0.33 A*0LN; 5667 5667 5667 5667 5667 1667 5600 54,600 ENER0v GH 946 0 9,492 13,891 6,936 17,973 15,090 64,328 LNIT C007-M*LLS/GH 74.69 74.71 71.72 69.20 71.72 74.71 83.15 74.74 A*00NT 5 71 50 5681 5961 5497 51,343 51,255 54,808 70*AL $737 5667 51,347 51,628 11,i64 52,009 si,855 59,408 AVG C007 - MILLS /cH 779.42 N/A 141.95 117.19 167.84 111.80 122.91 746.24 NOR*MEAST UTILITIE NEP CAPAC:!v BEAR sv:MP KV 8,000 8,000 8,000 3,000 8,000 GONE GONE CONE CONE GONE G0NE 1,000 4',020 UNIT Co$T-sfXU 1.22 1.35 1.35 1.35 1.35 2.C8 1.35 AMO N* 19,765 510,PJ4 510,834 510,334 510,334 $2,083 555,"87 NEP-ENERGY ENER0Y OPPORTUN!*Y PL90MAsE. nN 15,122 0 0 19,157 13,225 43,000 95,5*J. LN!T COST

• MILL /CH 66.13 ERR ERR 63.27 0.30 23.50 3

35.27 AMOLNT 51,000 512 512 51,212 14 51,i28 53,363 TOTAL 510,743 510,844 510,846 512,046 510,838 50 50 50 50 50 51,'2S 52,083 $58,555 NU 'UR3.-130 COST - MILL:/nH 712.03 ERR ERR 623.80 819.51 23.50 CAPACITY 613.12 SPO7 PURCMAs!S pc TERTIARYH3-TERT ARYWJ-TECTIARY CAPAC:TY - rd 2,000 2,000 3,500 ENERC' GN 1,452,760 1,423,000 2,543,000 5,425,760 LN!T COST: MILLS /r-H 19.50 21.00 18.00 19.19 A*0LNT 23,329 29,983 45,864 s*C4, 87 9 9 9

A T T N ( C V 5 V C O A A 5 N T K O' .C T T T / / ~ X E A A C ? T. .T ? T P P T C L L P 1 0 o T O C T t E VA - O N ? MDRC5 5 - O N 0 ON A T N O A L G U A U C.T A d' C t A U c.7 ? L AIC Y5 5 AT L TI OAUpLALmS.C

• w P N VA r
• N A P 2

t CVVP5 7 L OL 0 HGOI GL C M;CI I LO C

• N Y w A

: N IIDE.

C LT YLT P U7 YUT P 0C! - O: L - W C S: N "

• C N

W r' O U! U7 E M w iEU ) S 0 TC TC C N N U L N PN

E O

TC TC R ? TC UTC N A CEt 5 P 0 o O C S O 0 D 0 P 0 N 5 A 7 s O H T S 7 N i T A

T T

A' .Y .c O 2 O E V E P - C S C O R 2 D 2C R A C H

T H

T G O 0R S i O P' C M C A Y A P T C ) R O M O I S I E L M 5 L M s G M O L S V C I V ,T E S L I / L / M t F E L W I L I t S L W w / L L + S L / L C C C M L / S L C ?: E / I S C S 0 0 H L /' N W / n H / 0 2 E L E H T s H H W G R s L H O / f G 5 0 r. Y i a ,6 f N t 5 N 2 8 / / 1 ,1 DJ / ( 8 1 1 1 A A C A A 2 1 0 5 2 C N 4 ,3 ,3 ,4 4 ,1 52 1 0 1 2 1 3 9 6 /. ,1,1 5,51,7 ,3 1,4 99 3 0 6 5

• .1 0 8

S 4 2 5 2 2 0 1 23 52 21 7 6 0 2 0 00 5 0 0 9 39 620P 5?7 to 4 50 32MO 5?0 ,7 5 N N ) N 2 3 / / ,1 JT / 6 8 1 1 1 A A AF A !5 1 5 9 ND 3 ,1 ,9 ,4 ,4 ,1 ?4 12 1 1 6 5 4 ,2,4 ,2,81,3 1 0 3 ( 3 3 0 1 ,37.9,8 99 3 7 3 ?. 5 9 2 0 1 .4 52 7707 905 1 58 5 7.9 33 5 0 0 8 31 5 0 0 4 6 ) 0 ,6 0 80 931 0 580 1 N N N 2 5 ( ( / / f M / 5 7 15 5 1 A A t A A 1 1 1 8 7 0R 3 ,6 ,0 ,2,6 ,4 ,1 8 1 4 11 6 2 5 8 9 2 0 79 2 3 0 ,2,8 ,3,7 1,9 ,81,0 99 0 7 05 5 2 0 2 0.9 1 33 t 24 1 6 1 0 57 2 8 0 0 2 1 P 91 53 01 0 1 0 6 ) ) o 4680 1 00 ,7 3 00 1 N N N 2 4 / / ,1 MA 9 6 5 1 5 5 A A / AP 3 A 54 1 2 7 RR ,1 ,7 ,4 ,4 ,2 ,1 26 12 0 5 4 9 4 4 0 5 5 1 0 ,2,4 ,1,7 2,8 ,68.9,4 99 0 2 5 1 1 6 0 7 2 33 3 2 7 7 7 3 0 0 6 99 1 951 1 12 t 01 62 6 4 o ,6 0 40 4080 050 5 N N N 3 4 / / ,1 ,2 AM 0 4 1 5 A A P A / 4 ,2 ,3 ,4 ,4 ,1 A 59 1 6 7 RY 7 51 15 5 5 3 5 2 8 7 2 2 4 0 ,5,3 ,3,4 2,1 ,27.3,7 99 0 6 7 0 0 3 0 5 9 66 4 9.0 33 0 ? 5 8 8 9 0 0 1 84 7377 1 63 5 1 9 0 ,6 0 60 3220 990 5 C N VC 2 5 ( ( V O C M ,1 MJ 5 4 5 6 11 1 1 1 0 1 N R P 18 1 3 4 YN AU 3 ,0 ,8 ,2,6 ,4 ,1 2,0 ,7 1,7 C G 29 52 1 5 1 8 ,35.3,1 Y 6 5 6 2E 2 16,3 6 0.7 1 2 05 5 2 0 ,3,8 ,3,17 4.6,1,2 3 9 S 65 1 0 4 2 49 5 1 0 08 840 050P 82 286 0T 7 53 9931 318 5 0 , N 5 0 2 2 3 5N 6 1.5, 3 8 4 7 57 2 4 0 16 610 000U 95 591 0S 7 40 4390 360 1 5 0 ) ) R ,6 N DC C 1 V O I M JJ 2 0 ,1 UU N EP ( 4 0 1 1 5 5 1 3 Y .S 3 7 5 0 2 S 4 NL E ,8 ,5 ,4 ,4 ,1 2,7 ,4 1,9 ,33,1 S 6 2 1 5 56 15 0 1 6 99 6 0 5 5 3 0 9 7 ,1,0 ,4,7 1,7 ,06.9,8 4 6 2 0 0 4 0 82 22C 000O 1 19 0 .6 98 4782 1 90 1 1 0 0 0P 1 33 3 0 1 1 0 9 9 9 0 39 98) 000R 0 090 0 0 80 61 40 840 5 X 29 26 4 4 ,7 C ) V VG 52 5 E M JA 2 S RP ,1 UU 9 6 5 5 5 1 1 5 Y 5 5 2 59 5 4 4 38 ,2 ,2 ,4 ,4 ,1 37 G LG ,4 1,1 ,33,1 S 5,1 1 5 27 52 7 1 9 99 1 1, 0 3 5 5 8 0 9 9.9 2.9,1 1D 2 ,8,9 ,4,8 1,0 9 ,44.8,1 7 5 0 9 9 2 0 65 570 000V 33 0 0 0P .77 770 0S 9 66 1 635 299 I 8 2 3 5E 34 3 4.9 4 2 2 3 3 1 0 ?4 440 0002 02 200 0L 6 20 8550 1 90 9 4 ,8 C 5 V AS 3 1 ,1 UE 4 1 5 5 5 15 3 S 42 ,7 ,2 ,4 ,4 ,1 2,1 ,B 2,7 ,33,1 $ 3 CP Y 54 1 7 4 1 2 12 7 5 4 99 1 9 3 9 4 ( 4 7 0 1 1 1. 0 0 0P 9 ,6,6 ,3,01,3 8 1 6 2 53 2 0 84 470 000U ,67.9,6 33 93 4 2.7 1 1 1 8 20 0 0 04 480 000R 6 22 0327 105 0 7 ) 9 10 6150 700 ,5 C 5 V 4 4 ( ( SO ,1 1 3 5 2 S EC 3 15 5 5 5 5 5 Y 50 5 6 6 0 ,9 ,0 ,2,6(,4 ,1 ,1 3,7 ,4 2,0 PT 1 ,30.3,1 ,2,4 ,3,4 2,9 35 53 5 5 0 99 5 7 25s3 8 0 7 3 3 6 4 5 79i3 1 0 93 300 000V ,54.9,5 6 6 0 33 0P 1 0 4 7 6 77c0 1 0 84 450 000R 1 84 0584 700 71 75 5 4 ) ) ) 0 60 6620 640 ,7 C 53 3 V ON ,1 1 5 3 1 1 1 8 Y $1 1 8 6 CO 1 4 S 7 ,1 ,9 ,3 ,3 ,2 TV ~ 36 7, ,3 2,5 ,30.3,1 $ ,2,7 ,3,4 1,3 35 53 3 5 7 99 5 0 7 7 4 0 9 9 0 1 2 9 0 5 8 8 0 0 65 530 000V ,60.8,6 33 0P 8 0 6 3 7 7 7 0

• 8 890 0002 0

63 0408 095 40 6 9.9 4 4 6 80 0860 090 5 ,7 2 6 (( ND ,1 ,1 OE 8 S 55 5 5 5 VC 37 ,4 ,0 ,7,5 ,4 ,2 32 53 8 5 99 12 5 4 2 4 7 48 3 4 0 2 0 3 3 ,6,6 ,2,5 2,6 ,28,9 - 33 3 5 0 %6 6 6 0 ; 9 34 5 9.4 4 8 4 0 1 1. 7 )) 6 7 0 9076 845 00 1760 820 5 E ,3 ,3 S1 ( 6 4 s$ 5 s s 6 1 U 5,8 6 ~ 4 7 22 5 i i 5 3 5 1 ,8 tT B 3 ,4 ,8 ,7,5165',2 ,2 ,2 31 S 2 22 53 8 6 O ,21,7 ,83,6 ,i 4 5 83 32 8 7 5 T 1, 9.9 ~ 4 6 3 3 5 8 2 0 4 4 ,5,0 ,6,6 1,7 ,78,7 AP 0 5. 0 4 4 6 5 0 7 3 5512 7 0 00 080 000 9 9 6 0 6 85 8039 94 37 7 4.9 Lt 7557 4 0 25 560 080 6 6 1 3 0 7 20 9530 290 7 8 0 )) i l ljll! iljjji iIllll. l1,

..:.a,o w., W ; a E.4,o ~ 7a.s..a - ~'-~ - -------~- --- --~------ -'~--- ------- -- -~--- - FINAN0!AL STATEMINT *ONTH JAN 93 TED 93 M,1R 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 SEP 93 OCT 93 NOU 93 DEC 93 ~2 O~M CALENMR "O*=~M DEC 92 JAN 93 FED 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 $EP 93 OCT 93 NOV 93 SUBTOTAL N0:~:' HA1TLAN3 = rH

• 129,600 *,022,000 383,000 557,600 477,600 959,200 515,200 75,600 99,400 148,200 296,000 712,000 6,375,400 lNTERE*T LONG TE2M DEST 97,467 88,035 97,467 94,069 97,205 94,069 92,658 77,015 73,043 76,847 74,368 76,847 1,039,090 SFOR' TER't OEDL 82.596 74,197 81,795 81,5M0 84,696 86,t.92 91,921 92,468 90,351 94,041 91,597 94,705 1,046,439 PPOPERTT TAI 9,817 9,830 9,830 9,850 9,830 9,830 6,977 6,927 12,610 12,610 12,610
• 2,610
• 23,261 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746 3,202 3,979 34.,641 PROP!P*Y INSURANCE
• OEPREC!ATION TRANM:5SION 1,167 1,167 1,167 1,167 1,167 1,167 1,167 1,167 1,i67 1,16, 4,167 1,167 14,CC4 CENE2ATION 26,667 26,667 26,667 26,667 26,667 26,667 26,667 26,667 26,667 26,667 26,667 26,667 320,004 OPERA!!ON & MA!NTENANCE 9,80/

10,192 5,379 4,983 7,441 6,877 6,131 2,034 10,118 4,228 5,238 33,047 105,973 UTAL !230,267 5212,833 5225,551 5221,042 s?29,752 5227,849 f228,217 5209,024 $216,702 5218,306 52i4,84? 5249,022 52,683,413 ."NN MA2*LAN3 - MILLS /nw 203.85 208.25 588.91 396.42 481.06 237.54 442.97 2764.86 2130.10 1473.C5 725.84 349.75 420.90 MILL:70NE r.N 2,226,900 2,679,700 2,615,800 2,689,200 1,893,100 2,881,500 2,761,500 2,661,000 0 0 0 1,723,6'O 22,"32,310 INTE;EST LONG TERM CEBT 79,888 72,157 79,888 77,126 79,697 77,126 77,466 70,326 67,440 70,i34 67,920 70,"84 889,399 SMORT TEN DEUT 57,277 51,679 50,533 63,474 59,002 58,910 63,049 62,974 61,395 64,271 62,495 64,674 7 9,73 P20PER N TAI 8,5CD 8,500 8,500 8,500 8,500 8,500 8,500 8,500 8,500 8,500 8,500 (838) 92,662 PROPERN INSURANCE INCLUDED IN Of>f DEPH C:4T!ON 35,313 35,320 35,321 35,325 35,333 35,342 35,345 35,356 35,452 35,418 35,429 35,437 424,391 C$C2AT:0N 6 MAINTENANCE 42,705 42,923 30,021 33,707 34,727 40,826 41,402 39,288 60,382 95,644 74,672 58,223 ~ 594,521 T hN MIS 0:0N EXPENSE 2,315 1,739 1,898 1,646 1,502 1,809 1,718 1,461 678 1,658 1,745 i,856 20,025 A:=:NISTRATIVE 8 CENE2AL FUEL CIPENSE-RE: GENERATION T3,479 13,158 13,524 9,499 14,494 13,891 13,380 (18) (17) (3S) 7,661 14,523 i'3,536 FUEL EXPENSE-ADJ PRIO4 PERI (8,250) (M,250) (8,250) (8,250) (3,250) (8,250) (8,250) (8,250) (3,250) (8,250) (3,250) (3,250) (99,0 @ TOTAL $231,226 5217,226 5211,435 1221,027 1225,004 5228,153 5232,61* $20?,636 5225,581 5267,386 5250,172 5235,809 $2,755,265 9:L*.070* E 3 - MILL:/nw 103.83 81.06 80.83 82,19 118.85 79.18 84.23 78.78 N/A N/A VA "36.81 ~24.49 SEAOOCEUN!!" LH 3,103,7 v 2,585,300 3,196,000 3,537,900 3,418,600 3,165,i00 3,427,400 3,132,700 3,531,500 2,4*7,900 2,664,500 2,791,500 '36,97*,700 INTERE:T LONC TE:M DE3T 84,772 76,568 84,772 81,890 84,619 81,890 81,491 70,775 67,500 70,688 68,408 70,686 924,C60 9802T MRM DE07 93,968 87,470 94,479 81,386 96,266 94,222 98,783 98,931 101,165 105,262 101,125 104,654 1,*S7,740 PROPEt*Y TAI 15,680 15,680 15,680 15,680 15,680 (2,503) 12,650 12,650 12,650 12,650 12,650 (25,369)

• i3,776 P20PER N INsutANCE INCLUDED IN 01M 0:?RECIAT:cN-ine Decorr..

63,489 63,639 63,663 63,715 63,724 63,7C2 63,703 63,715 63,756 63,759 63,679 63,776 764,320 0?t2AT:0N & MA:NTENANCE 57,3 t.9 26,611 43,525 41,193 35,774 46,152 30,027 38,039 42,958 43,949 43,205 62,791 5 1,55 TAN 03:!04 EYPEN'E 624 1,303 0 0

• 927 A:=:N!072ATIVE E GENERAL TUEL EXPENSE 21,882 27,051 30,905 29,255 27,104 29,326 26,832 30,208
• 9,978 20,64?

23,452 29,263 3 5,905 TOTAL 1337,764 1298,323 5333,023 5313,118 1323,167 1312,789 1373,485 53"4,316 5308,006 5316,958 $3 2,519 5305,833 13,789,302 SEA 3:00<1-MILLO/nH 108.84 105.39 104.20 88.50 94.53 98.*2 91.46 100.33 87.22 137.09

• i7.29

~09.56 102.49 CuNO 707A; SC5'EDULE 3a $799,257 5728,382 1770,009 57;5,186 5777,923 1768,791 1776,312 5732,W6 0750,289 5802,650 5777,540 s'90,664 59,227,979 O O 9

VIO & T SU'ZARY 07 TRAN MISS:0!J, CEN :ATION, INTEREST, A S C EXPENSCS SCHEDULC #3b FINANCIAL STATCMfNT."ONTH JAN 93 FED 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUC 93 SEP 93 OCT 93 Nov 93 OEC 93

• 2 MON'N CALEN !R MONTH DEC 92 JAn 93 FED 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 sCP 93 OC7 93 NOV 93

$UBMTAL TPAN -::::0* EXPENSC M:sc 22 40 54 27 492 483 608 576 1,054 1,593 503 5,454 vrt:0 26,307 37,833 37,654 41,433 39,439 37,657 36,957 33,222 39,826 39,794 36,922 42,663 454,762 NORSEAST U'! LIT!! /P!NH (3,673) 2,387 3,753 3,773 3,769 1,407 1,379 1,403 1,418 i,336 1,460 ",133 19,900 NEV E ELAND Posita 5,750 10,100 5,750 8,650 5,750 1,450 1,450 1,733 1,409 1,409 1,409 1,409 46,267 CVP:t - N. MARTLA?3 7,217 7,217 7,217 7,217 7,217 7,217 7,217 7,217 7,217 7,21 7 7,217 (7,672) 71,772 TOTAL 535,623 557,576 551., C8 561,100 556,225 543,223 147,486 149,182 550,445 550,860 543,601 533,407 1598,*55 A*0RT::ATION: P:LGRI.* :: 2,958 2,958 2,953 2,958 2,953 2,958 2,953 2,958 2,958 2,953 2,958 2,958 35,496 OfACR00< !! 6,406 6,406 6,406 6,406 6,406 6,406 6,406 6,406 6,406 6,406 6,406 6,406 76,872 H; X ATE 6,*67 6,167 6,167 6,167 6,167 6,*67 6,167 6,167 6,167 6,167 6,167 6,167 74,000 TOTAL 515,531 $15,531 $15,531 515,531 515,531 115,531 115,531 115,531 515,531 515,531 515,531 s15,531 sis 6,368

4TrR:si Ex>t ers LCE TIR* (P II+5 II) 15,144 13,678 15,334 14,636 15,123 14,636 14,884 13,952 13,333 13,940 13,490

• 3,987 172,192 SMORT TERM 19,427 16,809 18,208 17,708 18,486 21,540 21,966 22,586 15,195 15,809 15,144 15,716 218,593 CAIN 0:4 3: ?. PROPERTY INTERECT INCOME -

(2,436) (1,316) (2,014) (1,126) (1,001) (307) 0 (853) (9,559) - AL 0 : C PHASE 1 (6,597) (6 597) (6,597) ($,864) (25,655) f 4 TOTAL 532,134 523,672 124,931 531,217 532,603 129,271 536,850 $36,538 523,533 522,294 s23,634 523,839 5355,571 CEN!RAL 1 AOMINISTRATivt DIRECTCR0 & PTCS 125 949 1,000 1,453 1,731 0 1,197 0 0 121 1,330 0 8,407 i INSURANCE 7, :! ART UP 4,2 71 4,245 4,260 4,260 4,260 4,260 4,260 4,260 9,902 4,260 Sco: Err 4,260 52,498 ' I SALARIES 6,429 6,197 5,946 8,365 5,885 6,782 6,304 4,896 7,367 6,829 6,922 7,I.* 7 79,3397 CCi;;LTANTS 5,959 33,309 5,301 11,844 7,147 2,572 2,113 1,213 3,807 4,910 8,892 8,t06

• 03,0927 LEGAL 10,092 9,814 35,894 37,005 27,571 16,920 57,855 57,104 23,376 27,430 5,643 44602 358,506/

CFFICC CIPEN E: E 000 54 322 960 524 791 1% 615 962 350 305 493

• 05 6 173 7 2:LL:4 77 29 27 110 132 43 37 90 111 116 56 86 Q,,074' NRIC4 ::Es 1,150 1,150' CROS 2CVEY,'E TAI (291)

-N TOTAL $33,.T.2 559,867 553,337 $63,532 147,547 131,631 172,432 568,524 544,913 544,47: 523,337 563,475 (1606,893) C S ER O!3; 7.- A0Mi*0Nf3 PROJ. '~ ~~ 7 70!AL (:*w:0LC : 3a 0 35) 5915,752 1390,028 5913,286 5926,616 1929,853 5393,446 1946,611 5902,752 183?,761 5935,805 5394,143 5931,976 siO,974,967 TOTAL ?;R HA C3 P;R (SCHr3. 2) 5283,330 5241,170 $256,021 1291,422 $302,86? 1250,144 $248,661 5292,952 5347,311 1439,547 1351,506 $234,435 53,614,417 nt :N TOTAL C0 T OF 5:2v:0! 1,204,132 1,151,193 1,174,307 1,218,037 1,232,722 1,it.3,590 11, 95,271 51,195,703 51,237,072 51,375,352 s*,245,643 51,2i6,351 s*4,539,334 ) y

= VE: 5 7 RIV C U!Df LINC LC :E: SCHE 00LE #4 FINANCIAL STAT!*fM* MON 7H JAN 93 FEB 93 MAR 93 APR 93 MAY 93 JUN 93 JUL 93 AUG 93 sEP 93 OCT 93 NOV 93 DEC 93 12 MONTM CALEN3I2 MONUt. DCC 92 JAN 93 ffD 93 MAR 93 APR 93 MAY 93 JLH 93 JUL 93 AUG 93 sEP 93 OCT 93 NCV 93 SUS'OTAL TOTAL CD:7 Or trav!CE r.'?' 13348742 13676030 12765500 1/.251757 12233075 13574027 12,709,120 13,431,602 11,743,861 8,016,85610,299,553 ~2,907,840148,957,963

N!T C0s?

90.?1 84.18 91.99 85.47 100,77 84.25 94.05 89.02 105.34 171.56 120.94 94.23 97.94 4* CWT 1,204,132 1,151,198 1,174,307 1,218,037 1,232,722 1,143,59l0 11,195,271 51,195,703 51,237,072 51,375,352 s*,245,648 51,2*6,351 5 4,589,384 TRAN M!::!0N L!NE LO s 889,652 962,490 771,930 831,497 728,535 737,087 607,170 698,212 737,C61 680,176 654,*C3 % 410 9,053,323 PO'.ER AV4!LAOLE FOR SALE G 124590?O 12713540 11993570 13420260 11504540 12836940 12,101,950 12,733,390 10,956,800 7,336,680 9,645,450 *2,202,430 139,904,640 W:? C:si 96.65 90.55 97.91 90.76 107.15 89.09 98.77 93.90 112.90 187.46 129.14 99.68 104.28 4?0LNT 1,204,132 1,151,198 1,174,307 1,218,037 1,232,722 1,143,590 11,195,271 51,195,703 11,237,072 51,375,352 si,245,648 51,216,351 514,589,384 OALIT v: M0'47 ELt;'t!: Co-CP. nw 9,770,990 10020320 9,338,030 9,788,750 6,059,610 5,824,730 5,678,900 6,571,740 6,840,950 6,317,530 7,399,290 8,723,460 92,334,300 LN!! C007-M!.L /nH 115.86 107.68 118.09 114.91 177.35 '67.58 183.4? '58.62 165.56 213.48 16*.03 128.87 144.81 A *1'iT s 1,132,059 1,079,017 1,102,727 1,124,796 1,074,667 5976,108 51,042,018 $1,042,430 $1,132,603 51,348,640 51,191,310 s*,*24,176 513,370,552 V~ *'ACLE LEASE CH 0 L'N!T C007-M!LL /GH 2%'NT 51,976 51,958 51,912 52,022 51,097 1996 1961 51,089 51,008 si,477 1987 51,997 517,481 CV LEASE - 72ANOM:: !0N CAPAC: 50 50 50 10 50 50 50 10 5246 5775 5271 36** 51,903 OTHER UT!L!!!ES I CN 2,68*,100 2,693,220 2,655,540 3,631,510 5,444,930 7,012,210 6,423,050 6,161,650 4,115,850 1,019, ISO 2,246,160 3,478,970 47,570,340 W!! C0!!-M!LLs/r.H 26.08 26.07 26.23 25.12 28.83 23.74 23.71 24.70 25.08 24.00 23.63 25.75 25.21 c1NT 170,096 570,222 569,668 591,219 5156,958 1166,486 1152,292 5152,185 5103,215 524,460 553,080 189,567 si,*99,448 TOTAL CALC; Mv) 12459090 12713540 11993570 13420;'60 11504540 12836940 12,101,950 12,733,390 10,956,800 7,336,680 9,645,450 *2,202,430 139,904,640 TOTAL SALES (RCVEN'ts) 1 1,204,132 1,151,198 1,174,307 1,218,037 1,232,722 1,143,590 11,195,271 51,195,703 51,237,072 51,375,352 51,245.648 51,216,351 114,589,384 TOTAL SALE: (W I CD T) 96.65 90.55 97.91 90.76 107.15 89.09 98.77 93.90 1*2.90 187.46 129.14 99.68

• 04.28 A.

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OPERATING REPORT-a tTda 3 " '2 RCA UOC ONLY SCURCES AND DISTRIBUTION OF ENERGY l Ve rm a t 12 lia pshire ,g e e 7 1NSTRUC';CNS. Smin orwal.1nd *.oo cmnes c l4FA for de'aded amyurtxwn we llt'A llutMws 17 t M t.T 1 % l-p 3. c, -d. NO. OF NAMCPLATC ANNUAL PCAK P.CT Ef4CHGY V.:LLS " t e 4' SOURCE OF ENtRGY PLANTS CAPACITY DEMAAD (kW) RECGVED BY CoGT Q) PERa n $ < 2 =', (kWh) SYSTEM sMWh) s%' Qt ~? (a) (b) (c) (J) (c) W (d 2Gi CENERATED IN OWN PLANT (Dads on farms l2J.c.f.adg) l ^ f,..<y -p

1. Fcssa S cam

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2. u: car Millstone 3 & Seabrook (ioint ownerships) 2

..8 791 59 104.01 6 544 567 1 1 10, 7'? }Qj

3. Hyd o No. Hartland 1

4 000 6 175.40 ? 6R1 4!1 !'.20. 9 0 'x, E,, -7

4. i.,:ema: ComNs:.on ar.d 0:hcr

'. ' M i 5 TOTAL in CLn Plan:Is-a c/ tans / shru 4; 3 12 791 65 479.41 9 227 980 140.93 5j$[ PURCHASED POWER (St caa suppiscr scpuraicty) '{ [ 6. Vermont E1cetric Powt r Company-Merrimack 2 1 909 12 455.9 372 411 !29.90 SE.2 i 7. - Vermont Yankee 5 477 37 309.2 1 930 219 I 51.74 M 25 8. - HQ~Te rt ia ry 3 500 5 428.8 104 181 l19.19 k.N. d,. 9. - NEPOOL Purchases 16 887.H 363 194 !21.51 Ci.y-a /~ Ni. 10. - NEPOOL Sales ( 8 657.0 ) ( 77__SJ2 ) I 8.09,N[ 11. State of Vermont-Dept. of Public Service-liighgate 1 4 020 17 608.4 583 166 1 ~

33. U,._

E5 h C 12. Northeas t Utilitics - - Cas T Ebines 8 000 47.5 55 344 I!165.14 13. Green Mountain Power Corp. - System Power 4 000 604.0 141 10B M1 69 [$w$ i ..k '; . 14. - Berlin A6B 20_0_0 64.3 9 40R b f4 M -v-o 15. - Vergennes Diesel 2 500 24_7 1 496 iAn s7 MS - a ,7 16. New England Power Co. - System Power 4H 0 1 17R I 71 sn s.~'s :- 17. Vermont Marble Co. - Spinning Reserve 17 000 5 18. Central Vt. Public Service Corp. System Power 1 000 1 657.0 I 51 405 I 'f1 O' ES 19-New Enn1nr.d Power Co. - Pu;;; ped S to rngc_Capn e i t y 1 000 ? 031 g <<7 g,. M. I ? M:

21. TOTAL Powcr Purchased (Som eflan 6 Aru 20) 83 G H _ (>

1 549 111 I (. 9 57 e.a 'r INTERCHANGED POWER g, e-

22. Received in:o Sys:em (Cicos; 3 :; F

23. Ocitvered Ou:cf Sys:cm (Crass) l M5

24. Ne: In:crchange (Lme 22 mmur 2J)

? .I TRANSHISS ON FOR OR DY OTHERS -(WHEEUNG)

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25. Recc:ved 'n:o Sys:cen

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26. Dchvered Out or Sys:cm pj (

27. Nc; Encrgy Wbecied (Gr.c 25 mmus 26)

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28. TOTAL Energy Avadable !ct Salc (Sw.ioflau 5 + 21 + 24 + 27) 138 953J1 r] U.

29. TOTAL Sa'.es (Form 125. Imc 77) 139 904.6 i ?.2

c. := -

30. Endy Furnished :o O:bcrs Without Charge Mi

31. Etw Used by 60rrowct (Escisdar Statwn Use)

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32. n Encrgy Accountcd For (Sum oftmes 29 :kru ll) 139 904.6

33. EnMy Losses - MWh (Lir.c 23 mir.ar 32) 9 0 s'l 41.__

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V; PLANT Nortli Hartland llydrO r sinucTicus th,.,w+e.or u a r<

YE AR ENDING f% r b rytrJ ast*w nw ser / E 4 Pi*rt.e lil1B 3 DeCembe r '31 1993 9 SECTION A. HYDRO GENERATING UNITS OPER ATING HOURS GROSS LINC UNIT NO. SIZE (WI) NO. G E N E R A TION (MWh) OUT OF SE R V IC E IN SE RVIC E 0 74 STANDBY Scn deed Unic Pe 3#e 3 e (c ) rll (t ) ( 1) (rl

• O

'll 1. 1 4 000 6 297 2 037 6 171 0 552 2. L 4 5 s. TOTAL 4 000 6 297 2 037 6 171 0 552 7, bat.on Serv.ce (MWh) }$7 HYDR AULIC DATA 3, Net Generation (M Wh) 6 140

1. Poot ettvATioN iFi.i 487 L 412.V 9.

sus.on Sersee

2. T A i t. A ACE ELEVATION (Ft )

358 352 % cf Greis 2.49 waTen Spitteo g ves o no Set Applicable SECTION B. LABOR REPORT Cont ractor cos ts SECTION C. FACTORS & MAXIMUM DEMANC L f h M,ggmD ITEM VALUE E g VALUE I ITEM VALUE 1 No. Err p, Fu'l T;me 5. M4:nt. P: ant Payroil {$) 1 Load Factor W) One. Super;nt endent) 6. Other Accounts 2. Plant Factor (%) 2. No. Emp. Pa't Tirre P: art Payrott ($) 3. Runn;ng Plant Capacity Factor (%) k ]l f 3. Total Emp.. Hrs. W2nd 7. TOTAL. 4 15 M;n. Gross Maximum Demand (kW) 4 Oper. Plant Pay roll (S) P!act Payrott (S) 5 Ind;cated Gross Mar. Demand (kW) SECTION D. COST OF NET ENERGY GENERATED LINE NO. PRODUCTION EXPENSE ACCOUNT AM3UNT 15) MILLS / NET kW's No. 1 Operatln, Superv>s.on and En2;reering ul m 535 2. Watcr for Po.sa r 637 $3a5 3. Hydrasi;c E=penses 27_672 4.51 537 4 Elecie;c Espenses 7 295 1.19 538 347 0.06 5. M scellaneous Hydraalic Power Generat;on Expenses 539 24 479 3.99 S. Rents 540 7 OPERATION EXPENSES (1 thru si 66 750 10.87 8. Maintenance. Seperv: sic,n and Engineering 541 6 757 9. Ma;ntenance of Structures 542 _10. Maintenance of Reservoirs. Dams and Waterways s 543 11 Maintenanc e of Fleet.c Plant 544 32 467 12. Maintenance of Maceuaneous Hydraulic Plant 545 13. MAINTENANCE EXPENSES (8 thn,12) 39 224 62 14 TOTAL PRODUCTION EXPENSES (1 + 13) 15 Depn,ciai;on 2 -- 105 974 17.26 10. Ta o s 403 3 320 004 408 123 261 17 Inteiesi 427 2 0)2 660 18. Insu ranc e 974 N 5,920 34 (341 19. TOTAL rixEo costs (is tw is) 2 510 566 _S.0jh39 20. roWEn cost ts: oi 2 616 540 426.15 REMARKSg,,N,f;n,lCt%,,,,,f,,7,3 g, bog,3 t

1. ACOF.

oot ontrol perat(On 4/I9/93 n 2 ACOF. M.d n t en ince Draw-Down kc.,I REA Form 120 (Rey,12 93)

P2.<,,,w.. s t*.r.e.' 4'e6 4. a oc4 de.t. a*J sen;k. g,J e t a cese :4 25 tru.i tit F A rwe s ita i)p e rop.rie.!r c%f.rg e 'ime for revie.;rg inirsons.nar&q< ix.r g e.. n o, l 8.+^* " r l.*=w, ;i enier a-i ga><r. gerd:r e e rg ,,1,,:s.s s',r< um e f e.fo.eseiim sed cierer c-:.: r'6"J E.',' i ed c c.,a o.r.ur, omt. Am 4oI w.wnW.tx 4 o..a is de tre i.f (xa of 6%i s o. e t i 4.rt. esm..a c e en oSes n. ,r,i.e..g is, sm.- i si n A < es... x.s,,4 :>pc.mnu.i e t.r.sc,wi ew v.vi.1.n :... =

g. san m iso.cato m M i ti 1:)..v..$ep.,.uc moi (>m ion 1.so om to 7 t:gru s 2nis t.

oscA nLA U.s.Lu o:I At uoJ re Jer=s.** y 4 eNrat. i m l.a **.I);u& om.c e Y< d rea v e u ruo**Jik U $ C G{l n e s*4 ) sd.s ve ss f.'.Le sts.'l. OPERATING REPORT. BORROWER DESIGNAilON REA USE Y Vertront 12 llampshire NUCLEAR PLANT PLANT Seabrook I - Total Plant INST RUCTIONS. L'%e n a...g.ut ed r.o re r o re l E s. YE AR ENDING fer do tsla.t ws na a. n o o E A R.'o u.n l?t.'8 3 DCCCCber 31, 1993 SECTION A. Bolt.ERS AND GENERATING UNITS UNIT TIMES GAN OPER ATING HOURS LINE NO' STARTEO SIZE (kW) G EN E R ATION ouT oF SEAv CE N O. (M M) tN $ERVICE ON ST ANOBY so.e s se s ur sc r u. e s (c) tb) it) id) (t) (f) ist t h) i. I 191 000 8 096 2 3. 4 ~ 5. 6. TOTAL 7 Station Sernce I W.'b ) 8. Net cenerat;en WVN 9 046 805 9. Sist;on Serv;ce % of Gects SECTION B. LABOR REPORT SECTION C. FACTORS & MAXIMUM DEMAND ] LINE LINE LtNE I N O. ITEM VALUE ITEM VALUE NO. NO. ITEM VALUE l i 1 No, Emp. Full Time 5. Maint. Plant Payroll (S) 1 Load Factor (%) (inc. Superintendent) 6. Other Accounts 2. Plant Factor (%) 2. No. Er p Part Time P! ant Payroll (S) 3-Running P! ant Capacity Factor (%) 3. Total E mp.. Hr s. Wed ed 7 TOTAL 4 15 Minute Gross Maximum Demand (kW 4 Oper. Plant Payroll IS) Plant Peyroit (S) 5. Ind;cated Gross Mauimum Demand (kW LECTION D. COST OF NET ENERGY GENERATED 40 PRODUCTION EXPENSE ACCOUNT ~ AMOUNT (S) MILLS / NET kWh NUMBER g 33 1 Operat;on, Superis.cn and Engineering 517 ?. Fuel 518.1 3. Less Fuel AcQu; sit;o1 Adjustment 518.2 4 NET FUEL EXPENSE (2 3; 5. Coc,lants and Water 519 s G. Steam Expenses 520 7. Steam Frorrt Other Sources 521 8. Electric Espenses 523 9. Miscellaneous Nuclear Power Espenses 524 s 10. Rents 525 11. OPERATION EXPENSES (l , 4#An,10) 12. Maintenance, Sspervis;on and Engireering 528 13. Maintenance of Structutes 529 14 Maintenance of Reacter Plant Equipment 530 15. Maintenance of Electric Plant $31 18 Maintenance of M;sce!!aneous Nuclear Plant s s 532 17 MAIN TEN ANCE EXPENSES (12 thna is) _ 18 Reactor Crediis t 19. TOTAL PRODUCTION EXPENSES fil + J r. Js) 20. Depreciation '~ ' ' 21 Taxes ~ 403 2 400 22. In teret t 427 23 Ins u ranc o

c

s. :

924.025.926 2 -1 TOT AL f IXED COSTS (20 thna 2J) ^ " ,.. w,.J 25. Less Punt Acq.rs. tion Adoniment 40G 26. POWER COST (19 e 24 25) REA Form 12g (Rev.12 93) l l

PX e rspeteg hsh.4 f.. e s ecrent.n of bbneticais suirnewJ io ni erage :4 2$ ha,rs (It MA rmr.s 12e i) pes tupese,w!de es tur.e for enie.irg exa.st car s.scarsh.r e w s t '* * ?. ' gest nt g enJ nisinie nrg t>v d.ta mAJ, e,J g.rnpl<urg and stJ** lrg de sc4'estim ofin'orrnatien. SenJgomrr. ems segardvg A s..rdca scws cs a. pedes atre.1 cf A.s t*>. O in ef. '.-r + WhJf g es t ge.asier s for rehs /s A.s bJea. '.n ikprinvas o eu.mse.Cearews On es it.Jaum Pro,so LO%t:5 sc5 72 (ci r), w,,g.go.,. DC 205fs. AD I OR \\l NO. 0572 00lY,OIR%f. It twn 4n w, w. Ar pes. D' Vo; and io de tr.94.4 5 tar garant 3J itaps. I'an... Es prea12/31,94. U%Dh REA (Mr slass,sti k n, sed re doermso yo e spreseg resaJu ud}sucsd sM.e s Year ng we se req &<dti v $ C. 9C) se seg ) ed.s r o c41.o sr.d 00RROVvEli OESIGNATION OPERATING REPORT - REA USE ONLY [V-) NUCLEAR PLANT Verm nt 12 Ilarnpshire PLANT SIMrc Seabrook I (VF 12. 412 59 norcent) i INST RUCTIONS. fiJais se ros.ulsd r.e rtr4s so A E 4. YEAR ENDING he dene'odew.s tw. ree !E4 Pd?oa lil:8 3. DCCCmber 31, 1993 SECTION A. BOILERS AND GENERATING UNITS UNIT TtMES GROM OPER ATING HOURS LINE SIZE (kW) G E N E R ATION OUT OF 5 t ravic e NO* STARTED p;o, gypy IN SERVICE ON STANOBY $ r.ne d vie d Unscr e hle 3 (a t th) fel (di (el e ft it) tM 1. 1 4 745 2. j 3. 4 5. 6. TOTAL 7 Station service WWh) 8. Net Generation WWh) 'g 9. Station Service % ef Gross N N' SECTION 8. LABOR REPORT SECTION C. FACTORS & MAXIMUM DEMANG p[ L ITEM VALUE ITEM VALUE N N, ITEM VALUE 1 No. Emp. Full Time 5. Maint. Plant Peyroll ($) 1. Load Factor t%) (inc. Superintendent) 6. Other Accounts 2. Plant Factor (%) 2. No. Emp. Part Time ant PayroH W 3, gynn;n, pg,n, c33,,;,y p,c,,,ggy 3. Tot al Emp Air s. Wcd ec 7 TOTAL 4, 15 Minute Gross Maximum DemandikW1 4 Oper. Pf ant Paysoil (S) P! ant Payroit ($) 5. Ind:cated Gross Maximum Demand (kn1

• 0&M costs in 1.1 Section D SECTION D. COST OF NET ENERGY GENERATED NE O.

PRODUCTION EXPENSE ACCOUNT AMOUNT (S) MILLS / NET kWh NUMBER fel m 1 Operation. Superv:sion and Engineering 517 511 573 2. Fuel Sie.1 315 905 3. Lns Fuel Acquisition Adjustment 518.2 4. NET FUEL EXPENSE (2 31 315 905 5. Coolants and Water 519 !?;h? s 6 Siesm Expenses 520 s L Steam From Other Sources 521 8. Electric Eupenses 523 9. Miscellaneous Nuclear Power Expenses s 524 10, Rents 525 11 OPERATION EXPENSES () + 4 thns 10) A?]'67A 12. Maintenance, Supervision and Engineering 528 13. Maintenance of Structures p'.s..x 520 s 14 Maintenance of Reactor Plant Equipment 530 4 15, Maintenance of Electric Plant 531 I 532 ~) gj 16. Maintenance of Miscedaneous Nuclear Plant 4 17. MAINTENANCE EXPENSES (12 thna id) A 18 11eactor Credits N-SE s M 19. TOT AL PROOUCTION EXPENSES (11 e J r. Ja) 827 478 20, Depreciation 403.2 757 164 21 Taxes s 40a 22. Internt .. I13 776 I 427 2069 304 23. Insurance s 924.025.02G _ 4 . is.,m __. 24. TOTAL FlXEO COSTS (20 tAru 23i 2940 244 s 25 Less_ Plant Acquisition Adjustment 40G 2G. POWEn COST tas. 24.ss i' 3767 722 REA FOtn112g (Rey,12 93)

p y c re p4 irg Na n f..r N o.i'a c.*f hfmances is edrwcJ to n em ss 24 25 hurs (R F.A rcema l7s i)per res;nte,irtbir g 6s 6rre for rev's e;r g ir.itrac. ions.sca rt'.;eg e nte g t..a.e us, ph ::g eaJ re.e e at t 5 'h' 6's ree.'<J. erJ tomrM;eg anJ .Opa sdh6m d ir forvsiim Ser J rcer.r sus <gerorg 1s 'en esumeis ce a *) oder s.rai *It%8 (*P" t*ht irl".'p r..o i. TH . raaf g e. ry.u. s 'e r u.'u eg e & fen. w ikp.r, rent rW.uwe. Clearance Omrer.OIR$f. Rmns 40t W. WuMervi, r250. and io de O'fus ef Wege ncis anJ lla.'ps. P vh - W & wn ito i104l *472 (nt;).%'.rre..i. DC ;0%. 0.413 FOR St NO 0512 0017.E ;vea 12/31/9a. v10A is t ^ Ta.o.Lu w,illo wed no.to:ows yw rpoor.ag ren.:u sed)kws.J ekar.c o. h w 'op ve u requ,ro.it? U $ C. 9Cl or so;) s<J a s e s t <. to es..J. 7 "" "'" 2 HansM m '5"^ OPERATING REPORT - REA USE Y e nt NUCLEAR PLANT ~~ PLANT illistone 3 - Total Plant INS 1 AUCTIONS. ?.J %e s e c a s.ulW r. a rtpas se AL4 YEAR ENDING r., a,,aa.-,...s.,,, i ro ",.. nits.: Decerber 31, 1993 { SECTION A. BOILERS AND GENERATING UNITS UNIT T6MES G R OSS OPERATING HOURS LINE N O~ STARTED SIZE (kW) GENERATION OU T O F S E R V iC F. NO. (Ms'A) W SERVICE ON ST ANDSY scr.eue s vrw e ue s (c) t b) (e) (d) (ep of) ggy qs; 1. 1 4 1 253 000 6 849 406.5 6 106.6 169.? ? 199.9 284.4 2. 3. 4. 5. 6. TOTAL 1 253 000 6 849 406.5 7. Station Serv.ce W Wh) 370 068.1 8. Net cereration W AM 6 520 454.8 9. Siation Service % of Cross 5.4 SECTION B. LABOR REPORT SECTION C. FACTORS & MAXIMUM DEMAND g$ ITEM VALUE ITEM VALUE o, ITEM VALUE 1. No. Emp Full Tir*e 5. Maint. PIsnt Payroll ($) 1 Load Factor 1%) 66.0 (ine. Superintendent) 6. Other Accounts 2, Piant Factor (%) 62.4 2. No. Emp. Part T:rre P! ant Payroll ($) 3. Running Plant Capv.ity Factor W) 89.5 3. Tc,tal Emp.. Hrs. Warn ed 7 TOTAL 4 15 Minute Gross Maximum Demand (kn1 4 Orser. Plant Pay ro'l (S) Plant Payroit ($) 5. Indicated Gross Maximum Demand (kn1 SECTION D. COST OF NET ENERGY GENERATED LINE NO. PRODUCTION EXPENSE ACCOUNY

• AMOUNT ($)

MILLS / NET kWh NUMBER (a) (6) 1 Operat.on, Supervisica and Engineering 517 2. Fuel 518.1 3. Less Fuel Acquisl tion Adjustment 518.2 4 NET FUEL EXPENSE (2. JJ 5 Coolar ts and Water 519 6. Steam Expenses 520 7. Steam From Other Sources 521 8. Electric Espenses 523 9. M;scellaneous Nucicar Power Expenses 524 10 Rents 525 d 11. OPERATION EXPENSES (1 + 4 # A ns 10) 12. Ma;ntenance. Supervision and Engineering 528 13. Ma ntenance of Structures s 529 $ntenance of Reactor Plant Equipment 14 530 15 Maintenance of Electric Plant 531 16. Maintenance of Miscellaneous Nuclear Plant .g.g j 532 17 MAINTENANCE EXPENSES (J2 IAru is) ~' 18. Reactor Credits TO'TAL PRODUCTION EXPENSES (#1 + 17 18) 19. 20. Depreciation 403.2 21 Tames 5N 400 22 Interest s 427 23 Insurance 924 S25.920 _ TOTAL. TIXED COS TS (20 rAru 2.1J ^ ' ' ~ i "fi.;; 24 25 Less Plant Acquisjtion Adjustment _,_4% 20 rO vEii COST ri, e v4 2s> "y~~ REA FOfm 12g @ v. /2 93)

p a,e s.,4 n..e.u.vt..t.. a<aa..a c o fu.,,,aP v e n.c. s t..an ..a.. w/<,. n a v.%,w,., u,,,a n,,,. g n 2 5 twri s u rmr u. i) ne runn.Nay te e ras e.*s irmw'.*u er s o w 's a a ' ' r e ne.s m.r,.rme n.,,.s na,,,,n, rom.,,g.,<, s ,,6,.... ,,,, m,.. <i er wi sc/c. m. f rei.... .y,,Oevance O%<es 01M1, Reem 4MW,WesNrpos. L J50, amt ions 6f fka or (* fans erner.e and Ildget. P v d Je g st igpuse s f.i, <<.A o/ 4 0.s '..eeen.'o lap ra e,.s. is su w e, h%<ven hr;e.s tfMtH sus 72 6017). Wee icog (X.' ;y,01 0.\\f 3 i 001.NO 05 72 001).Esps IV31/J 4. e v5o^ nE^ rau a.,u it b,,e,, a,u,,.., g, < r.....:,ui.iu t/:uv.a.w. r<,...n v, a rep.ordt1 V S C. WI os se4 ].sd.s r o so f.Jo s,..J OPERATING REPORT - oOnnOWEn DESicNatioN HEA USE ONLY 'm g NUCLEAR PLANT Verrnont 12 11ampsli t re ) w/ PLANT !!illstone 3(VT-12. 35percen t sharo) Esinuciscos. 5 i-,m <s.u adr-+ c.rma n4. YEAR ENDING r<, e,w,s.w,s.< u.,u n w,u nne s. Deccaber 31, 1993 SECTION A. BOILERS AND GENERATING UNITS UNIT TiVES GROM OPERATING HOURS LINE NO' STARTED SIZE (kN GENE R ATION CUT OF SERV cE NO. (MWh) Ird SEftVIC E OP4 $T AP4DDY so e ue s u ru r. u. s can as te r us tr > rn I T rn as u t. 4 386 23 972.9 6 106.6 169.2 2 199.8 284.4 2. 3. 4 5. 6. TOTAL 23 972.9 7. Statien SerWee (W/b) 1 295.2 a. Net Generat o, mwl 22 821.6 i 9. Stat;on Service % of Greu 5.4 SECTION B. LABOR REPORT SECTION C. FACTORS & MAXIMUM DEMAND o ITEM VALUE ITEM VALUE h4, ITEM VALUE 1. No. Emp. Full Tirne 5. Maint. Piant Payroll ($) 1 Load Factor (%) (inc. Superintendent) 6. OhAmu 2. PW Fer N 2. No. Emp. Part Time ant Payron W 3. Runnin2 Plant Ca:mity Factor (%) 3. Total Emp.. Hr s. Wod e d 7 TOTAL 4 15 Minute Gross Maximum Demand (hW1 4 Oper. Plant Payroll (5) Plant PayroH ($) O

• 06:1 costs Section 3 L1 SECTION D.

COST OF NET ENERGY GENERATED 5. Indicated Gross Maximum Demand IkW1 \\.M LINE NO. PRODUCTION EXPENSE ACCO M - MMW WSN N NUMBER gy g; 1 Operat;cn, Superv'sion and Engireering 517 593 870 2. Fuel 518.1 113 536 4.97 3. Less Fuel AcoWsitios Ad.iustrnent 518.2 (99 000 ) 4.34 4 NET FUEL EXPENSE (2 J) 5. Coolants and Water 14 536 0.63 519 6. Steam Emperses 520 7. Steam From Other Sources 521 8. Electric Empenses 523 9. Mheeif aneous Nue' ear Power Excenset 524 651 10. Rents 525 11. OPER ATION EXPENSES (f + 4 thru 10) 12. Maintenance. Supervision and Engineering 609 057 76.69 523 13. Maintenance of Structures 4 52f) 14 Maintenance of Reactor Plant Equipment 530 15. Maintenance of Electric Plant 531 16. Maintenance of M4cedaneous Nuclear Plant 1 532 17 + MAlf4 T E NANCE E XPENSES (12 thru 16) 18 neactor Cred.ts A ..s 19. TOTAL PHODUCTION EXPENSES (11 + 17 1a) ~ 20. Depreciation 10LQ57 ._4@._ 403 2 21 Taies _fj213gg 408 22. Interest g{g2 ~ 427 23. ,inyt a nc e 1605 470 24 924,925,920 l f,1 TOTAL FIXED COSTS (20 thru 23i A a'.. 4 kl Less Plant Acquaition AJjustment 2121 500 92.96 25 400 20. POWEn Cost tia 24 25, 1730 557 119.6s REA Form 120 (Rev.12 93)

P.s e.pu s Leu.f.4 #_. ce*ni.im r.nkmo i uw,4 m..u.ss :4 25 % Ot r A rone. ire o (<,surerie. k<!* a a w" fouwWes ver-5wo vanN * *W s 6' e g.hr.rg eed mawe,e. g 9e data nedeJ, r.J wmp'.4jrg and re ydo,s eHecuen sd etmatim. Stad cmrrem regs#Jirs Es b de + em sie er sq edet asE'uestih.s m n tion cf nfo.w ,.to u gsvim r,wg hu,io twp.m.u ac s am ormu.oinst. acm ax w, %sege.n. D so,.aa t. A. visu e.r. .wi u.d u.s o. r.,x t.a lie.f.gLui 1%,u1 (OstG #03 72-Col r), Weer g os. [X' 20503 v.%8 l'OR M SO. OS 72 (011. Eip.ru 12/31/14. s osan nEA 1his data milte u. ed to deterunine your orerating results andfinancial situation. Your \\ OPERATING REPORT - remove is required (7 U S C. 901 et seg ) and is not con 6dential. ANNUAL SUPPLEMENT "'U I N REA USE Vermont 12 Ilar:pshire INSirtUCTIONS.m# s. e.4%,t a*.f r-e ttp.n to AE4 r".*,s a w s.< s u,st4s a u n m i December 31,1993 SECTION A. UTILITY PLANT BALANCE A DJUS TM E N T S HEM BEGINNING ADDITIONS RETIREMENTS AND BALANCE { OF YEAR TRANSFERS END OF YEAR la) 46) (t) (d) (e)

1. Totai fnianp's Piani (Jos aw 303i.

19 667

2. Total Steer 1 Product >on Plant 4310 IAm 3 8 6).

19 667

3. Total Nuc! ear Pechtion P' ant (3:0 thru J251 4 Total Hydro ProAct;on Plant (J30 thru JJa;.

9 800 9 800

5. Total Other Prohet;on Plant (340 #Aru J46)

6. Tout Production Pfart (2 thru $)

9 800 9 S00

7. Land and Land Rights (J50) 16 440 16 440

s. Siructures and improvements rJs 1 57 565 57 565

9. Station Equipment (353) 653 811 653 811

10. Other Tranimwio, Plant (354 IAm 3591.

48 605 48 605

11. Total Transm uion Plant (7 thru J 0) 776 421

12. Land and Land Rights (J60) 776 421

13. Structures and improvements (3811 14 Station Equipment (J82)

15. Oeer DMribution Plant (363 #Aru 3 73)

16. Total Distribution Plant (12 thru 15).

17. Total General Plant (Jag thru J99) 195 195

18. Electric P: set in Serv;ce U + s + 11 + 16 + 17J 806 083

19. Electric Plant Pu chased or Sold (107).

806 0R3

20. Electric Plant leased to Others (104).

i

21. Efectric Plant Held for Future Use (105).

22. Completed Construct;on Not Classified (10s).

55 685 039 155 606

23. Acquisit on Adjustments (J J4) 55 R40 5

i

24. Other Utility Plant (1f s)

25. Nuclear Fuel Assemblies (120.1 thru J20.4) 2 399 316 256 620 2 655 936

20. Total Utility Plant in Service (18 shru 25). '

58 890 438 412 226 59 302 664

27. Construction Work in Progress (107) pt, Total Utility Plant (:s + 27; 58 MU 438 412 226 59 302 664 SECTION B.

ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION UTILITY PLANT CoM. BALANCE ITEM PostTE BEGINNING ANNUAL RETIREMENTS ADJUSTMENTS RAT 1! N OF YEAR ACCRUALS LESS AND BALANCE NET SALVAGE TRANSFERS END OF YEAR 61 to) (c) (s) (or (n

1. Depr. of Steam Prod. Plant (10#.1).

2. Depf. of Nuclear Prod. Plant (108 )

2.86 4 503 147 1 127 763_ 5 630 915 _ )

3. Depr. of Hydraulic Prod. Plant fl08.J) 2 2 373 363 320 004 4 Depr. of Other Prod. Plant (808.4) 2 693 % 7 i

5. Depr. of Tranim; uron Piani nos.3;.

663 245 96 183

6. Depr. of Distribution Plant (tod 6).

759 428

7. Depr. of General Plant (108.7)

8. Retirement Wor k in Progress (108 81 s

9. Total oept. fos Elec. riant in Servii.si 7 539 755

10. Depr. of Plant leased to Others (109) 9 083 710

11. Dept. of Plant Hefd for Future Useffle.

12. Amort. of Elec. Plant in Service (110 13, Amort of leased Plant ill2J

14. Amort. ol Plant litid for Future (113)

15. Amot t.of At r4uisition Adj. (J JJJ

16. Dept. & Amort. Othet Plant (ils;

_1_5_.63_.2g3

17. Amott. ot Nuclear fuel f f ;0.3,

10. Totai rrov. tor o,pr, s Amo,,,,s. i n 9 105 042 373_0_11_

1 938 338 1 917 006 11 022 048 REA Form 12h (Rev.12 93) ~ Pogo 1 of 5

O O l l l l VERMONT 12 HAMPSHIRE ( DECEMDER 31, 1993 RSA FORM 12 E SECTION A. LINE 22 ANALYSIS OF COMPLETED CONSTRUCTION NOT CLASSIFIED i SEABROOK MILLSTONE 3 N HARTLAND SEVERAL ACCOUNO e NCLR PLANT NCLR PLANT HYDRO PLANT TRANSM. PLANTS TOTAL 106.21 692,531 692,531 106.23 35,788 35,788 106.24 250,457 250,457 106.25 8,928 8,928 106.31 15,332,049 15,332,049 106.33 13,384,260 13,384,260 106.34 24,898,606 24,898,606 106.39 0 0 106.63 377,681 377,681 106.64 860,345 860,345 TOTALS 25,758,952 13,761,940 15,332,049 987,705 0 55,840,645 25,700,000 13,800,000 15,300,000 1,000,000 55,000,000 4 e 4

uso^ ntA ' 80HROvvE st DESIGN Ait-HEA USE ONL'i Vermont 12 llampshire OPERATING REPORT ANNUAL SUPPLEMENT YE AH ENDING December 31. 19 93 l SECTION D. ACCUMULATED PROVISION FOR DEPRECIATION ANG AMORTlZATION. UTILITY PLANT (Cent )

19. Amc.unt of Annual Accrual Charged to Espense

20. Amount of Annust Accrual Char 5 ed to Other

71. Book Cost of Propesty Hetired v

s 1 917 006 ^" """ s 207 919 $ N/A

22. Removal Colt of Property ReisreJ

23. SMvage Material from Propesty Retired

24. Renevval and Replacernent Cost s N/A s N/A s N/A

~ SECTION C. NONUTILITY PROPERTY Intentionally Blank BALANCE A D;UST M E NT S BALANCE ITEM BEGINNING OF YEAR ADDITIONS RETIREMENTS AND T R ANSF E RS END OF YE AN tal s69 tep Id) tel

1. NONUTILITY PROPERTY IJ21).

2. FROVISION FOR DErR. & AMORT. #122J.

SECTION D. DEMAND AND ENERGY AT POWER SOURCES MONTHLY PE AKS LOAD ENERGY OUTPUT MONTH PEAK OE AAND FACTOi g ras tb> tel ed) <e > to ts)

1. JANUARY.

37.2 13 348.7 48.'

2. FEBRUARY 37.2 13 676.0 4 9...

3. MARCH.

37.T 12765.5~ 49.'

4. APRIL 37.2 14 251.8 512 5.MAY.

32.7 12 233.1 45.:

6. JU N E 37.7 13 574.0 55.t 7.JutY 32.7 12 709.1 8 AUGUST J2*/

.14.J 13 431.6 55.'

9. SEPTE MBER.

JZ./ io. OCTOBER.. 31.2 11 743.8 48. 8 016.9 35.~

11. NOVEMBER 31.2,

10 299.6 44,

12. DECEMBER SU 12 907.8 9.

13. ANNUAL PEAK ANNUAL TOTAL 148 957.9 49.

REMARKS DEdAND AND ENERGY AT DELIVERY POINTS SECTION E. DELIVERED TO REA BORROWERS DEllVERED TO OTHERS TOTAL DELIVERED ponry OEMAND ENERGY LOAD DEMAND ENERGY DEMAND ENERGY LOAC (MW) (MWn) FACT. (%) (M W) (MWh) (MW) (MWh) F ACT. I" tal (b) tel (d) tel if) (I) thi

1. JANUARY.

33.2 9 771.0 39.6 4 2 688.1 37.2 12 4s9.1 45.0

2. FEBRUARY 33.2 10 020.3 40.6 4

. _2_6312 12 2 17 71, s 45.9

3. MARCH.

33 1 9 338.0 10 1

4. APRIL 32,7

_TTK8 40.9 4 2 6ss_s 17.9 11 003_6 46.3 5 3 631.5 37.2 13 432.3 ifLS

5. MAY.

27.2 6 039.6 31.0 10 5 444.9 37.2 11 504.5 43A

6. JUNE 22 1 5 824.7 34.5 10 7 012.7 32,l _ _ 12 R 36. 9 52 2

7. jut.Y aj,L 5 678.9 _ 33.3 9

6 423.1 _32.7 _11.102. n s1.A

8. AUGUST

gjg, 6 571.7 37.3 9

6 161.7 32.7 12 733 c .,_s ?. 'l b 871.0 34.4 6 4 115.9 32.7 _ _ _1Q_SM_ R 4s.0

9. SEPTEMBEH KQ 1

10. OcTOBE H.

Jg,2 6 317.5 30.1 2 1 019,2 JL 2_ 7 'L%.7 32 1 11.NOvtMatn _ 27 1 7 399.3 29.1_ 4 2 246.2 . __31.2_ 9 645J 41.A 12.DEcEMBEH 24J B 723.5 50 3 6 3 479.0 30.2 12 202.4 56.L

13. rF AK Mt TUTAI Tl 33T 3

'37.5 47 570.3 139 904.6 42_9 HEMARKS ~ h e RE A FOtm 1211 (Ret 12 93) Pogo 2 of 5

gg, gg connoA E R DESIGNATON Vermont 12 linepshire OPERATt1G REPORT-p(noo Epoc o REA USE CriLY AtJt1UAL SUPPLEMEt4T /- -( December 31,19 93 N msinucTioNs. neporting cf investenents is required by 7 crn s7:7. subperi N. Ideni'y in esiments primanfr fo, nu,ai ceve coment wah nc in cotum te) SECT 10t4 F. If4VESTfAE!4TS,l.OAti GUAllAf4 TEES AND LOANS. POWER SUPPL.Y PAliT I. It4VESTfAEt4TS DESCRIPTIOil ttJCLUDED EXCLUDEO Il4COME OR LOSS RD g (a) (b) (c) (D 4) 1 fC4 ut itl1 Y F ACPE Rif,*.E T) Intentionally Blank b c. d-I

e. To:a's

2. WvE517/E NTS W A$50CA1ED ORGANIZATONS N. R. U. C. F. C. - CTC 17 1s7 858 5 3.R.U.C.F.C. - nembership 1 non N;2tional Bank for Cooperatives - E Stock c.

1 nnn

d. N.R.E.C.A. - cembershjp In e T o:. s 10 19 167 858 3 INb E 51ME NT S 6N E CCNC'A>C DEVELOPtAENT PROJECTS Intentionally Blank a.

e. c. d (A

e. To'a's 4 OTHE R WVE 51 MENT S V.E.L.C.O. stock - Phase 1 197 464 a

~ 3. C d

e. To a's 152 464 5 LPECl/4 FLN05 a.

'ntentionally Blank b c. d,

e. Tota's 6 CA9{. CE NE RAL General Fund a

500 5. c. d e. Fot.t g i

7. SI'LCIAL DE POSilS Intentionally Blank, a

b. k O

e. Tg.>.

A ITEA Fom 12h (Rev.12 93) Po(p 3 cn

00R00M n DESiCNAllOff Ve rrron t 12 llampshiro OPERATING REPORT-

EAntucto REA USE dNLY ANNUAL SUPPLEMENT

1. q December 31.19 93 SECT 10fl F. INVESTMElJTS, LOAtt GUARANTEES AND LOANS POWER SUPPLY (Contince#)

PAR T I. lNVESTMEllTS (Continued) DESCRIPTIOtJ INCLUDED EXCLUDED INCOME OR LOSS RD ($) (5) (5) to) iH (e) (.1) (r) L T EUPORt.4 f INi E ST tAENTS Intentionally Blank. 5. C. d e To a s 1 ACCOUNTS & NOTES RECErv/ BLE (NET) .. Energy Account ( VERMONT 7) 44 59.1 449 d A/R Misc. Power 45 982 A/R_ Intercompany Se rvi_qe s 4 205 e d A/R Staf f Advance 100 . Tows 50 287 44 591 449 o cOfehTMENTS TO INVEST WITHN 1214NTHS BUT NOT ACTUALLY PUACHASED Intentionally Blank a b. C. d e To a s n TOT AL OF ;WE STUE TS ti +.. im 201 ?61 44 610 616 PART !!. LOAN GUARANTEES Intentionally Blank ORGANIZATIOP4 f.t AT U RITY ORIGINAL Af.tOUNT LOAtJ B ALANCE RD DATE (S) (S) (4) (b) (c) (d) (c) 1 2. TOT /5 5 S T OT AL S olu.%k is:.e C ar.au a Cr! ) PART 111. RATIO RATIO OF if tie STMENTS AND LCAN GUARANTE E S TO UTILITY PL ANT ITotal c/IntI=fr.1/cestmts (Part l. //bj oe lled* Gwa ve r s. lsan Datant n Part II. !.1) ta foul 1:aulity Plant rFoorn 1:a. Susic o D. lke 1)] 0*ON eg PARTIV. LOANS Intentionally Blank ORGAN 12ATIOPJ fAATURITY ORIGINAL AfdOUNT LOAtl D ALANCE RD 1 DATE (S) (S) (J) It) (c) (.1) (t) hlf.Ph Of'.cers. D +ec tge_s lhe'gy Resource Co6servy oilo.vs 3 ~ d {'

7. TOTALS

} REA Fern 12h (Rev.12-93) Pogo 4 of I

UsDA Ra acancn n ot scwm nEA USE OttLY 12 liar:pshire OPERATING REPORT-ANNUAL SUPPLEMENT $rfgo

NSTRUCTioNS Fr< RFA U If, tin 17);# 3 December 31,19 93 SECTIOt1 G. MATERIALS AND SUPPLIESINVENTORY Intentionally Blank 11EIA DALANCE BEGiNNIND PURCHASED USED & SOLD BALANCE "

OF YE AR & S ALVACED END OF YE AR fa) (b) (c) (J)

1. Coal.

~

2. Oter Fuel.

3 Prodxton Pla-1 Par.s and Suppfes. 4 S'aion Transfomers and Egipment.

5. Lrie Materia's and Suppi;cs..

6. Oter Matena's and SuppEes..

7. TOT AL (Sam of tir.es I sh 6)

SECT 10t1 H. LONG TERM DEBT AND DEBT SERVICE REQUIREMENTS BALANCE BILLED THIS YEAR REA USE ITElA END OF YEAR INTEREST PRINCIPAL TOTAL ONLY (a) (b) (c) (d) I) t 1 R.ra E nt*am 4an smon(Eui4 AE4 Ecn Dev L=vi 14 446 119 722 306 _.122 904 945 'M O 2 Natona! Real Utltes Coope ata Fina a Corpo aton

3. e.as far Cmpe anas LO 911776 1 72 2 72 8 224 921 2 007 649

4. FeSat rinareng eank 10 919 776 1 782 728 224 921 2 007 649

'S REA - Emnomic Deve:opment loans s CterNational Bank for Cooperatives 16 789 272 519 707 62 882 582 589 7. 9.

3. TOTAL (Sw,onsh 8) 42 155 167 3 024 741 510 707 3 535 448 SECTION 1. ANNUAL MEETING AND BOARD DATA

1. Date of last Annual Meet n;

2. Total Number of Elqb:e Voters

3. Was Osorum Present?

4. Number of Members Vot.ng May 5, 1993 6

2t Yes O No 0

5. N.smber of Members Present at

6. Total Number of Beard Members

7. Annual Cost of Directors' Fees and

8. Does Manager Have Wntien Meeting Esper ses Contract?

3 6 7,406 3 Yes O No SECBott J. MAti HOUR At4D PAYROLL STATIST 1CS Intentionally Blank

1. Numberof Fu:1 Tme Ernployees

4. Pa)rollEspensed

2. MatHours Worked Reg.Ar Tmo 5 PayrollCapEalded 3 fAttHours Worked Curtmo 6 Payrol10ther SECT 10N K. LONG TERM LEASES tifadditionalspaceis needed, use separate shcel) Intentiona11y Blank LIST BEL 0 tV ALL RESTRICIED PROPERTY

• liELD UNDER LONG TERhi ' LEASEllfNONE. tare NObE)

RENTAL NAME OF LESSOR TYPE OF PROPERTY THIS YEAR 1. 2. 3.

4. TOTitL

• U $lkTCli6~fM6i'TiaW maan att prepars,as other than a.:or,wb,ter. sructs. traa<rs. tracsor1. onner vehictos (inclains who s timaa aM mau house space aM cff:ta eqaipment (aM withos,s li,.vtasion computers).

L0 G R At* mem leases hav ng suspired terms of mcra chan i2 months (rat ng into account serons cf rentalat she option of the lessor. mkusher or not such e SECTION L. f40TES lF ADDlil0NAL 5 PACE /S NELDED. USE !EPARAT E $llEET O REA Form 12h (Rev.12 93) Pogo 5 of 5

1 m...-..n,.m.,_......,.2.,,,_.-_.,2.....,_...~._.,-.....,_........5,..._. g.e reg ar d e,:renirarg oe teis nretrJ.and segna'enrg e.d re Nirpe csdecde clinforvratim Sard cowrma regsads g tts '= lea e.tsme on a3 Ju arpet of tMs ce ados ciirl.ne en.n. S ernt. g s.ppews foe se#Mr a kJen,io dram e,4 e 'c me, Ce.sance OLer Olk M. Rwirvt 4%W. % 4 *xg.r.3 f 750 anJ io.h4 LP.he c.f Manager cr i and lla/get.P.pr=.srli R c J.u w I'e,ut (OMll sv5 72-1 T). *'a A r g on. IX' 20$f,. MU IORM SO C572 003. I'spres12/31/94. t25 0 A.REA & ha mill N krf.$ 10 diturSed }Od (rding rth?ll Gn.$fnd*K'50$ Ji/Ml@!1 l'Od OPERATING REPORT - reyow is requiredi7 U S C 9t'l er uq ) an.$ is nat umfidcMial. O OCRROWER DESIGNATION IINES AND STATIONS REA USE ONLY Q Vermont 12 llan:pshire SHSTRUCTIONS. Sutat an onginst ard two ccSes to REA. For detals. TEAR EM% see nEA ue:.n ema J. December 31 1993 SECTION A. EXPENSE AND COSTS ITEMS ACCOUNT LINES STATIONS NUMBER g,3 m TR ANSMIS$10N OPERATION 3. w;PERvlSION AND ENGINEE R 6NG. 560 21 952 2. LOAD OiSPATCHING 56] 3. STAfsON EXPENSES 562 4 OVERHC AO LINE EXPEre5ES 563 5. UNDERGROUNO LINE EXPENSES. e 564 6. Ms5C E L '.ANEOUS E X PENSES 566 216 7 S.iBTOTAL (I thm 6). 22 168 o 8. TR ANSMs55 TON OF ELECTRICITY BY OTHERS 565 597 939 a-9. RENTS 567 10. TOTAL TRANSMISSION OPERATION (7 thru 9) 620 107 TR ANSMISSION MAINTENANCE 13. $UI'E R VI$ TON AND ENGINEERING 568 32. ST RUCTU R ES. 569 13. ST AT TON E QU IPM EN T. 570 14 OVERHE AD LINES 573 e' 15. UNOCRGROUNO LINES < {#!; 572 16. MISCELLANEOUS T R ANSMIS$10N PLANT... 173 17. TOTAL TRANSMIS$10N MAINTENANCE (1J ram 16) 18. TOTAL TR ANSMISSION EXPENSE (Jo + 17) W 19. DISTRIBUTION EXPENSE ~ OPER ATION 580 thru $89 \\ 20. OI$7RIBUTION EXPENSE - MAINTENANCE 590 thru 598 21 TOTAL OISTRIBUTION EXPENSE (19 + 20). 4 22. TOTAL OPERATION AND MAINTENANCE (18 + 21). FIXED COSTS 23. CEPR ECI ATION - T R ANSMISSION. 403.5 96 183 24 OEPRECIATION - DIST RIBUTION. 403.6 25. T Ax ES ~ T R ANSMISSION. ACS 26. T As E S - DIST PIBUTION. 408 27, IN1 E REST ~ TRANSMi$$40N. 427 129 878 26 INTEREST ~ OtSTRIBUTION 427 29. INSUR ANCE ~ TR ANSMISSION 924.925.976 30. INSUR ANCE - DIST RIBUTION 924.925.926 31 TOTAL TRANSMISSION (Je + 23 + 25 + 27 + 29J 846 168 32. TOTAL DISTRIBUTION (2J + 2d + 28 + 28 + 30) 33. TOTAL LINES AND STATIONS (31 + J2) 846 168 SECTION D. FACILITIES IN SERVICE SECTION C. LABOR AND MATERIAL

SUMMARY

TR ANSMISSIOrd LINES SUBSTATIONSN/A

1. NUMBER OF EMPLOYEES g/g VOLTAGE (W)

MILES TYPE CAPACITY (ItVA) ITEM LINES STATIONS

1. 7.2/12 5 1.0

9. S T E PUP AT G E N.

2.OPrn.LADOR 1 2._115 2.68% 7.5 .2 ERATIM2 PLANTS

3. M AINT. LADO R 3-

10. T R AN5 MIS $10N

~". OPE R. M AT E R IAL 5. ~5. MAIN T. MAf r nl A t p*

31. O:,Tniou tlON SECTION D. OUTAGES N/A r.. TOTAL (i A,u s) 1.2

1. TOTAL

\\.

7. 0lS T n. LINE s

12. TOTAL

2. AVO. NO. DIS T R. CONS. SE RVE D i

8. TOTAL (6 + 7; 1,2 (9 thm Jfl

3. AVO. NO. 6 tOU RS OUT PE R CONS.

HEA Form 125 (Rev.12 93)

h th - ! - 0 The Commonwealth of Massachusetts O RETURN OF THE ) TOWN OF HUDSON, LIGHT AND POWER DEPARTMENT TO THE O DEPARTMENT OF PUBLIC UTILITIES OF MASSACHUSETTS For the Year Ended December 31,1993 1993 Name of officer to whom correpondence should Herst Huehmer be addressed regarding this report. Official title Manager Official Address 49 Forest Avenue Hudson, MA 01749 Form AC-19

=. TABLE OF CONTENTS Page ~ General Information 3 Schedule of Estimates 4 Customers in each City or Town 4 Appropriations Since Beginning of Year 5 Changes in the Property 5 Bonds 6 Town Notes 7 Cost of Plant 8-9 Comparative Balance Sheet 10-11 Income Statement 12-13 Earned Surplus 12 Cash Balances 14 Materials and Supplies 14 Depreciation Fund Account 14 Utility Plant - Electric 15-17 Production Fuel and Oil Stocks 18 Miscellaneous Nonoperating income 21 Other Income Deductions 21 Miscellaneous Credits to Surplus 21 Miscellaneous Debits to Surplus 21 Appropriations of Surplus 21 Municipal Revenues 22 Purchased Power 22 Sales for Resale 22 Electric Operating Revenues 37 Sales of Electricity to Ultimate Consumers 38 Electric Operation an Maintenance Expenses 39-42 Taxes Charged During Year 49 Other Utility Operating Income 50 income from Merchandising, Jobbing and Contract Wc,rk 51 1 Electric Energy Account 57 Monthly Peaks and Output 57 Generating Station Statistics 58-59 Steam Generating Stations 60-61 Hydroelectric Generating Stations 62-63 Combustion Engine and Other Generating Stations 64-65 Generating Statistics (Small Stations) 66 Transmission Line Statistics 67 Substations 68 Overhnd Distribution Lines Operated 69 Electric Distribution Services, Meters and Line Transformers 69 Conduit, Underground Cable and Submarine Cable 70 Street Lamps 71 Rate Schedule Information 79 Signature Page 81 FOR GAS PLANTS ONLY: Page Utility Plant - Gas 19-20 Gas Generating Plant 74 Gas Operating Revenues 43 Boilers 75 Sales of Gas to Ultimate Consumers 44 Scrubbers, Condensers and Exhausters 75 Gas Operation & Maint. Expenses 45-47 Purifiers 76 Purchased Gas 48 Holders 76 Sales for Resale 48 Transmission and Distribution Mains 77 Sales of Residuals 48 Gas Distribution Services, House Governors Record of Sendout for the YEAR in MCF 72-73 and Meters 78

• l PAGES INTENTIONALLY OMITTED: 23 TO 36 AND 53 TO 56

\\ 3 Annual Report of TOWN OF IIUDSON LIGIIT AND POWER DEPARTMENT Year ended December 31.1993 GENERAL INFORMATION 1 Name of town (or city) maldng this report. Iludson,Ma 01749 2 If the town (or city) has acquired a plant, Kind of plant,whether gas or electric. Electric Owner from whom purchased,1f so scuired. Iludson Electric Co. 7/11/1891 Date of votes to acquire a plant in accordance with the provisions of chapter 164 of the General Laws. 9/11/1891 Record of votes: First vote: yes,30; No,7 Second vote: Yes,69; No,11 Date w ben town (or city) began to sell gas and electricity January 15,1897 3 Name and address of manager of municipallighting: j llorst llueluner 23 Plant Avenue liudson,MA 01749 4 Name and address of mayor or selectmen. Richard O. lleauregard Joseph J. Durant Joarm P. Forance Carl J. Leeber Robert J. Steere ] 40 Green Street 22 Ilarriman Road 7 Kathleen Road 4 Lark Drive 35 Old Bolton Road Iludson,MA 01749 Iludson, MA 01749 Iludson,MA 01749 Iludson,MA 01749 Iludson,MA 01749 5 Name and address of town (or city) treasurer: Virginia Cahill 5 Rockport Road Southboro, MA 01772 6 Name and address of town (or city) clerk: Dorothy A. Risser { 3 Lincoln Street i Ifudson,MA 01749 7 Name and addresses of members of municipallight board: j Rohmd L. Phmte Peter R. Keane Weedon G. Parris, Jr. 136 Murphy Street 15 ichn Robinson Road 9 Champlain Drive Iludson,MA 01749 liudsoi Ma01749 Iludson,MA 01749 t i N Total valuation of estates in ton n (or city) according to the last State valuation $944,454,497.00 l 9 Tax rate for all purposes during the year: $15.04 Res $26.39 Com 10 Amount of manager's salary: 93,800.79 11 Amount of manager's hond: $1,000.00 k 12 Amount of salary paid to members of municipallight board (each): $500.00

4 Annual Report of TOWN OF iHJDSON LIGHT AND POWER DEPARTMENT Year ended December 31.1993 FURNISH SCHEDULE OF ESTIMATES REQUIRED BY GENERAL LAWS, CIIAPTER 164, SECTION 57 FOR GAS AND ELECTRIC LIGIIT PLANTS FOR THE FISCAL YEAR, ENDING DE'CEMBER 31, NEXT. Amount INCOME FROM PRIVATE CONSUMERS: 1 From sales of gas 2 From sales of electricity $27,658,009.00 3 4 TOTAL $27,658,009.00 5 EXPENSES: 6 For operation, maintenance and repairs $26,873,452.00 7 For interest on bonds, notes of scrip $0.00 8 For depreciation fund ( 3 per cent. on $18669168.74 as per page 9) $560,075.06 ) ) 9 For sinking fund requirements $0.00 10 For note payments $0.00 1I For bond payments $0.00 12 For loss in preceding year $0.00 13 l TOTAL $27,433,527.06 14 15 COST: 16 Of gas to be used for municipal buildings $0.00 17 Of gas to be used for street lights $0.00 18 Of electricity to be used for municipal buildings $612,700.00 19 Of electricity to be used for street lights $118,700.00 20 Total of the above items to be included in the tax levy $731,400.00 21 22 New construction to be included in the tax levy 0 23 Total amounts to be included in the tax levv $731.400.00 CUSTOMER ( Names of the cities or towns in w hich the plant supplies Names of the cities or towns in which the plant supplies i GAS, with the number of customers' meters in each. E'.ECTRICITY, with the number of customers' meters in each l Number of Customers Number of Customers l City or Town Meters Dec.31 Citv or Town Meters, Dec. 31 l Hudson 7,621 Stow 2,315 Berlin, Bolton, Boxboro l Harvard, Maynard l Merlboro 110 O TOTAL TOTAL 10.046

e 5 Annual Report of TOWN OF IIUDSON LIGIIT AND POWER DEPARTMENT Year ended December 31,1993 APPROPRIATIONS SINCE BEGINNING OF YEAR (includes also all items charge direct to tax levy, even where no appropriation is made or required.) FOR CONSTRUCTION OR PURCIIASE OF PLANT: 'At rnecting 19 , to be paid from ~

• At meeting 19

, to be paid from ~ TOTAL None FOR 11IF ES1 ti4ATL:D COST OF TlIE IIAS OR ELECTRICITY TO DE USED BY TIIE CITY OR TOWN FOR: 1 Street lig'2ts $137,132.00 2 Municipal buildings (Amounts are included in overall appropriations for each Department) 3 TOTAL $137.132,00

• Date of rnectine and whether recular or mecial

~Here insert bonde notes or tax levv. CIIANGES IN PROPERTY l Describe briefly all the important physical changes in the property during the last fiscal period including additions, alterations or improvements to the works or physical property retired. In electric property: Expanded 115KV Substation at Forest Ave. In gas property: k NOT APPLICAULE \\ o e

m N" BONDS n c, (Issued on Account of Gas or Electric Lighting.) Amount of Period of Paymends Interest Amount Outstanding E, When Authorized

• Date of issue Original Issues" Amounts When Payable Rate When Payable at End of Year j

Apr. 7,1913 Spec. Jun.1,1913 $9,000.00 g hfar. 4,1918 Reg. Apr.1,1918 550,000.00 Jun.14,1920 Spec. Feb. I,1921 $25,000.00 O

• n Mar. 5,1923 Reg. Nov.1,1928

$40,000.00 Nov. 29,1954 Spec. Mar.1,1955 $250,000.00 8 en Mar. 7,1955 Spx. May 1,1955 S100,000.00 0 Mar. 7,1955 Reg. Nov.1,1955 $150,000.00 t Jun. 8,1959 Spec. Aug,1,1959 $300,000.00 k l Nov. 7,1961 Spec. Jul. 15,1962 $450,000.00 5 3 il

c s

=

Y$ k l l Eo. 8.o 8 TOTAL $ 1,374,000.00 TOTAL 8 1 Ir The 'xnds and notes outstanding at the end ofyear should agree with the Balance Sheet. When bonds and notes are repaid report the first three columns only.

• Date of meeting and whether regular or special.

" List original issue ofbonds and nores including those that have been retired. 3 a s

• w

I TOWN NOTES e = (Issued on Account of Gas or Electric Lighting.) 8 Amount of Period of Payments Interest Amount Outstanding k When Authorized

• Date of Issue Original Issues *
• Amounts When Payable Rate When Payable at End of Year Dec.18,1896. Spec.

Jan.1.1897 $18,000.00 June 20,1897. Spec. Jan.1,1898 $17,000.00 l ' June 10,1898. Spec. Jul.1,1898 $5,000.00 Nov. 5,1903. Spec. Nov. 2,1903 $13,000.00 1 Mar. 7,1904. Reg. Jan.1,1905 $5,000.00 Apr. 2,1912. Spec. May 1,1912 $2,000.00 en Q Aug. 4,1941. Spec. Oct.15,1941 $100,000.00 Sep.14,1942. Spec. Oct.15,1942 $100,000.00 C l g Feb.8,1943. Spec. Feb.15,1943 $50,000.00 4 Mar. 6,1950. Reg. Sep.15,1950 $241,000.00 3 Ri

c h

7c i 0 0a.8.' o k TOTAL $551.000.00 TOTAL The bonds and notes outstanding at the end ofyear should agree with the Balance Sheet. w When bonds and notes are repaid report the first three columns only. ~

• Date of meeting and whether regular or special.
  • List original issues ofbonds and notes including those that have been retired.

TOTAL COST OF PLANT - ELECTRIC E L

1. Report below the cost ofutility plant in service cedin g year.Suchitems should be included in column effect of such am ounts.

E accordin g to prescribed ac coun ts. (c) or (dj es appropriate.

4. Reclassification s or transfers within utdity plant 3

2. D o n ot in c lu de a s adju stm en ts. c orrec tion s of

3. Credit adjustm ents ofplant accounts should a ccounts should be shown in colum n (f).

h addition s an d retirements for the current or the pre-be enclosed in parentheses toindicate the negativ- -1 O Balance l Beginning Balance Account of Year Additions Retirements , Adjustments Transfers End of Year (a) (b) (c) (d) (e) (f) (g) 'o

1. INTANGIBLE PLANT

$3,879.76 $0.00 $0.00 $0.00 $0.00 $3,879.76 Z C $3,879.76 $0.00 $0.00 $0.00 $0.00 $3,879.76 9

1

2. PRODUCTION PLANT k

A. Steam Production U 310 Land and Land Rights $0.00 $0.00 $0.00 $0.00 $0.00 50.00 3 311 Structures and Improvements $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 312 Boiler Plant Equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 W 313 Engines and Engine Driven g Generators $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 'o 314 Turbogenerator Unites $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 313 Accessory Electric equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 316 Miscellaneous Power Plant Equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Total Steam Production Plant $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 B. Nuclear Production Plant 320 Land and Land rights $1,252.93 $0.00 $0.00 $0.00 $0.00 $1,252.93 321 Structures and Improvements $847,640.09 $116.54 $0.00 $0.00 $0.00 $847,756.63 M 322 Reactor Plant equipment $1,252,311.84 $3,542.72 $0.00 $0.00 $0.00 $1,255,854.56 k 323 Turbogenerator Units $203,948.74 ($676.30) $0.00 $0.00 $0.00 $203,272.44 k 324 Accessory electric equipment $304,207.65 $190.61 $0.00 $0.00 $0.00 $304,398.26 8. 325 Miscellaneous Power Plant { $0.00 Equipment $96,711.21 ($1,305.70) $0.00 $0.00 $0.00 $95,405.51 g Total Nuc! car Production Plant $2,706,072.46 $1,867.87 $0.00 $0.00 $0.00 $2,707,940.33 T G 't 4 e G ~

v i TOTAL COST OF PLANT - ELECTRIC (Continued) E Balance f Beginning Balance 2 Line Account of Year Additions Retirements Adjustments Transfers End of Year No. (a) (b) (c) (d) (c) (f) (g) o 1 C. Ilydraulie Production Plant f 2 330 Land and Land Rights $0 00 $0.00 $0.'00 $0.00 $0.00 $0.00 3 331 Structures and Improvements $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 m0 4 332 Reservoirs, Dams and Waterways $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 5 333 Water Wheels, Turbines and Generators $0.00 $0.00 $0.00 $0.00 50.00 $0.00 0 6 334 Accessory Electric Equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 7 335 Miscellaneous Power Plant g Equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 8 336 Roads, Railroads and Bndges $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 9 D. Other Production Plant y Z 10 340 Land and Land Rights $5,500.00 $0.00 $0.00 $0.00 $0.00 $5,500.00 ( 11 341 Structures and Improvements $332,767.70 $1,503.06 $0.00 $0.00 $0.00 $334,270.76 O 12 342 Fuel Holders, Producers and h Accessories $123,S89.32 $0.00 $0.00 $0.00 $0.00 $123,989.32 N 13 343 Prime Mowers $2,455,596.22 $0.00 $0.00 $0.00 $0.00 $2,455,596.22 14 344 Generators $296,559.88 $0.00 $0.00 $0.00 $0.00 $296,559.88 5 15 345 Accessory Electric Equipment $332,470.28 $0.00 $0.00 $0.00 $0.00 $832,470.28 16 346 Miscellaneous Power Plant g Equipment $43.463.17 $76.117.53 $0.00 $0.00 $0.00 $119,580.70 3 17 Total Other Production Plant $4,090,346.57 577,620.59 $0.00 $0.00 $0.00 $4,167,967.16 IS Total Production Plant $6.796,419.03 $79,488.46 $0.00 $0.00 $0.00 $6,875,907.49 19

3. TRANSMISSION PLANT 20 350 Land and Land Rights

$53,804.14 $0.00 $0.00 $0.00 50.00 $53,804.14 21 351 Clearing Land and Rights of Way $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 22 352 Structures and Improvements $168,166.08 $0.00 $0.00 $0.00 $0.00 $168,166.08 23 353 Station Equipment $385,601.70 $11,061.35 $0.00, $0.00 $0.00 $396,663.05 24 354 Towers and Fixtures $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $ 25 355 Poles and Fixtures $796,839.02 $0.00 $0.00 $0.00 $0.00 $796,839.02 0 26 356 Overhead Conductors and Devices $227,329.01 $0.00 50.00 $0.00 $0.00 $227,329.01 0 27 357 Underground Conduit $258.07 $0.00 $0.00 $0.00 $0.00 $258.07 h 28 358 Underground Conductors and

• Devices

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 29 359 Roads and Trails $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 30 Total Transmission Plant $ 1,631,998.02 $11,061.35 $0.00 $0.00 $0.00 $1,643,059.37

TOTAL COST OF PLANT (Concluded) S'* a 5. 13alance j Beginning Balance 2 Line Account of Year Additions Retirements Adjustments Transfer s End of Year No. (a) (h) (c) (d) (c) (f) (g) 1

4. DISTRIBUTION PLANT 4

2 360 Land and Land Rights 50.00 50.00 50.00 50.00 $0.00 $0.00 3 361 Structures and Improvements $9,286.53 $0.00 50.00 $0.00 $0.00 59,286.53 k 4 362 Station Equipment $474,378.93 $1,366,997.14 $0.0p 50.00 $0.00 51,841,376.07 5 363 Storage Battery Equipment 50.00 S0.00 50.00 50.00 S0.00 $0.00 6 364 Poles, Towers and Fixtures $734,309.75 531,049.76 $0.00 $0.00 $0.00 $765,359.51 y 7 365 Overhead Conductors and Devices $2,175,334.51 ($125,315.57) 50.00 ($330,382.64) $0.00 $ 1,719,636.30 2; l 8 366 Underground Conduit $286,774.90 $117,572.98 $0.00 $0.00 $0.00 $404,347.88 t i 9 367 Underground Conductors & Devices $675,195.61 5131,962.81 $0.00 ($328,364.61) $0.00 $478,793.81 9 10 368 Line Transformers $ 1,863,977.53 $126,617.20 $2,728.63 $0.00 $0.00 $1,987,866.10 9 11. 369 Services $479,242.37 $33,563.94 $0.00 ($93,721.6I) $0.00 $419,084.70 12* 370 Meters $652,790.55 $16,750.46 $4,009.01 $0.00 $0.00 $665,532.00 y 13 - 371 Installations on Cust's Premises $0.00 $0.00 50.00 $0.00 50.00 $0.00 14 372 Leased Prop. on Cust's Premises $0.00 $0.00 $0.00 50.00 $0.00 $0.00 O y 15 373 Street Lighting and Signal Sys: ems $345,031.88 $26,571.80 $0.00 ($42,578.02) $0.00 $329,025.66 h 16 Total Distribution Plant.... $7,696.322.56 $ 1.725,770.52 $6,737.64 ($795,046.88) $0.00 $8,620,308.56 N 17

5. GENERAL PLANT h

18 389 Land and Land Rights $0.00 $0.00 S0.00 $0.00 $0.00 $0.00 3 19 390 Structures and Improvements $474,165.26 $17.00 $0.00 $0.00 $0.00 $474,182.26 l 20 391 OfIice Furniture and Equipment $464,211.79 $26,341.46 $0.00 $0.00 $0.00 $490,553.25 21 392 Transportation Equipment $513,104.70 $0.00 $10,700.00 $0.00 $0.00 $502,404.70 g 22 393 Stores Equipment S12,045.77 $0.00 $0.00 $0.00 S0.00 $12,045.77 23 394 Tools, Shop and Garage Equipment $16,224.04 $0.00 $0.00 $0.00 $0.00 $16,224.04 24 395 Laboratory Equipment $20,609.03 S11,190.19 $0.00 $0.00 $0.00 $31,799.22 25 396 Power Operated Equipment $3,497.53 $0.00 50.00 $0.00 $0.00 $3,497.53 26 397 Communication Equipment $45,198.76 $55.68 $0.00 $0.00 $0.00 $45,254.44 27 398 Miscellaneous Equipment S14,411.60 S43.86 $0.00 $0.00 $0.00 $14,455.46 [ 28 399 Other Tangible Property $33.72 S0.00 50.00 $0.00 $0.00 $33.72 29 Total General Plant........ 51,563,502.20 $37,648.19 $10,700.00 $0.00 $0.00 $ 1,590,450.39 E. 30 Total Electric Plant in Service $17,692.121.57 $1.853,968.52 $17,437.64 ($795,046.88) $0.00 $18,733,605.57 h 31 Total Cost of Electric Plant..... $18,733,605.57 8 32 0 33 Less Cost of Land, I,and Rights, Rights of Way.. $64,436.83 k 34 Total Cost upon which Depreciation is based... $18,669,168.74 $ Ihe above figures should show the original cost of the existing property. In case any part ofproperty is sold or retired, the cost of such property should be deducted from the } Ihe act cost pf the property, less the land values, shouM be taken as a basis for figuring depreciation. e e 9~

10 Annual report of TOWN OF ifMDSOM I.IGHT AND POWFR DFPARTMENT Year ended December 31.1993 - COMPARATIVE BALANCE SIIEET Assets and Other Debits O Balance Title of Account Beginning of Balance Increase Line Year End of Year or (Decrease) No. (a) 0>) (c) (d) j 1 UTILITY PLANT 2 101 Utility Plant - Electric (P.17) 6,169,625.74 6,696,026.84 526,401.10 3 10i Utility l>lant - Gas (P.20) 0.00 0.00 0.00 4 120 Nuclear Fuel 74,984.43 69,399.38 (5,585.05) i 5 Total Utility Phmt 6,244_.610.17 6,765,426.22 520.816.05 l l 6 OTilER PROPERTY & INVESTMENTS 7 123 Invest in Assoc. Companies 146,418.33 146,418.33 0.00 l 8 124 Other investments 0.00 0.00 9 Total Other Prop. & Investment 146,418.33 146,418.33 0.00 I l 10 0.00 1 11 FUND ACCOUNTS 0.00 12 125 Sinking Funds 0.00 0.00 0.00 13 126 Depreciation Fund (P.14) 3,004,137.73 1,866,445.86 (1,137,691.87; 14 128 other Special Funds 3,177,903.74 5.671,310.49 2,493,406.75 15 Total Funds 6,182,041.47 7,537,756.35 1,355,714.88 16 CURRENT AND ACCHUED ASSETS i 17 131 Ca.sh (P.14) 2,405,039.77 2,749,139.97 344,100.20 18 132 Special Deposits 335,620.30 358,871.67 23,251.37 l 19 135 Working Funds 500.00 500.00 0.00 j 20 142 Customer Accounts Receivable 2,840,111.20 2,964,220.40 124,109.20 l l 21 143 Other Accounts Receivabic 112,207.61 39,235.88 (72,971.73) l 22 146 Receivables from Municipality 2,286.36 2,286.36 0.00 l 23 151 Materials and Supplies (P.14) 563,699.03 1,091,409.09 527,710.06 l 24 165 Prepayments 424,584.79 419,012.69 (5,572.10J l 25 171 Dividend & Int. Receivable 31,278.09 45,771.61 14,493.52 l 26 173 Accrued Utility Revenues 0.00 0.00 0.00 27 174 Miscellaneous Current Assets 0.00 971.14 971.14 28 Total Current and Accrued Assets 6,715,327.15 7,671,418 81 956,091.66 29 DEFERRED DEBITS 30 181 thuunortized Debt Discount d.00 0.00 0.00 31 182 Extraordinary l'roperty Losses 0.00 0.00 0.00 t 32 185 Other Deferred Debits 368,668,72 368,668.72 0.00 33 Total Defened Debits 368,668.72 368.668.72 0.00 34 35 Total Awet< nnd Other Debits 4 19 657 065.84 22 489.688 43 2.812 622 59 O l 1 1 i

11 Annual report of TOWN OF litID5 ION I IGHT AND POWFR DFPARTMENT Vear ended December 31.1993 COMPARATIVE BALANCE SHEET Liabilities and Other Credits Balance Line Title of Account Beginning of Balance increase j No. Year End of Year or (Decrease) (a) (b) (c) (d) 1 APPROPRIATIONS 2 201 Appropriations for Construction 50.00 $0.00 $0.00 3 SURPLUS 4 205 Sinking Fund Reserves $0.00 $0.00 $0.00 5 206 Loans Repayments $1,925,000.00 $ 1,925,000.00 $0.00 6 207 Appropriations for Construction Repayments $20,093.39 $20,093.39 $0.00 7 208 Unappropriated Earned Surplus (P.12) $14,903,714.42 $ 17,307,278.89 $2,403,564.47 8 Total Surplus $ 16.848.807.81 $ 19,252,372.28 $2,403,564.47 9 LONG TERM DEBT 10 221 Bonds (P.6) $0.00 $0.00 $0.00 11 231 Notes Payable (P.7) $0.00 $0.00 $0.00 12 Total Bonds and Notes $0.00 $0.00 $0.00 13 CURRENT & ACCRUED LIABILITIES 14 232 Accounts Payable $601,101.11 $641,992.96 $40,891.85 15 234 Payables to Munbipality $0.00 $0.00 $0.00 16 235 Customer' Deposits $335,620.30 $358,871.67 $23,251.37 17 236 Taxes . Collection Payable $20,002.80 $18,903.78 ($1,099.02) 18 237 Interest Accrued $0.00 $0.00 $0.00 19 242 Miscellaneous Current and Accrued Liabilities $85,728.31 $116.03 ($85,612.28) O 20 Total Current and Accrued Liabilities $ 1,042,452.52 $1,019.884.44 ($22,568.08)l 21 DEFERRED CREDITS 22 251 Unamortized Premium on Debt $0.00 $0.00 $0.00 23 252 Customer Advances for Construction $3,210.00 $2,100.00 ($1,110.00) 24 253 Other Deferred Credits $748,541.78 $1,201,277.98 $452,736.20 25 Total Deferred Credits $751,751.78 $ 1,203,377.98 $451,626.20 26 RESERVES 27 260 Reserves for Uncellectible Accounts $0.00 $0.00 $0.00 28 26i Property Insurance Reserve $0.00 $0.00 $0.00 29 262 Injuries and Damages Reserves $605,394.41 $605,394.41 $0.00 30 263 Pensions and Benefits $0.00 $0.00 $0.00 31 265 Miscellaneous Operating Reserves $0.00 $0.00 $0 00 32 Total Reserves $605,394.41 $605,394.41 $0.00 33 CONTRIBUTIONS IN AID OF CONSTRUCTION 34 271 Contributions in Aid of Construction $408,659.32 $408,659.32 $0.00 35 Total I iabilities and Other Credits $19 657 065 84 $22 489 688 43 $2.832.622 59 State below if any earnings of the municipallighting plant have been used for any purpose other than discharging indebtedness of the plant, the purpose for which used and the amount thereof. Transferred $200,000.00 to town O i

1 12 l Annual report of TOWN OF 111 TDSON i IOfiT AND POWER DEPARTMFNT Year ended December 31 1993 STATEMENT OF INCOME FOR THE YEAR Total Increase or (Decrease) from Lin: Account Current Year Preceding Year No, (a) (h) (c) i OPERATING INCOME 2 400 Operating Revenues (P. 37 and 43) $27,262,741.68 ($ 1,185,423.83) 3 Operating Expenses 4 401 Operating Expenses (P. 42 and 47) $25,062,763.61 ($ 1,601,328.73) 5 402 Maintenance Expenses (P. 42 and 47) $524,498.50 ($30,331.15) 6 403 Depreciation Expenses $528,830.54 $7,365.13 7 407 Amortization of Property Losses $0.00 $0.00 8 9 408 Taxes (P. 49) $24,336.43 ($ 14,008.61) 10 Total Operating Expenses $26,140,429.08 ($1,638,303.36) 1I Operating income $ 1,122,312.60 $452,879.53 12 414 Other Utility Operating income (P. 50) $0.00 $0.00 13 14 Total Operatmg Income $1,122,312.60 $452,879.53 15 OTIIER INCOME 16 415 Income from Merchandising, Jobbing and Contract Work (P. 51) $0.00 $0.00 17 419 Interest Income $201,064.51 ($30,574.35) 18 421 Miscellaneous Nonoperating income $ 1,433.34 ($191,635.37) 19 Total Other Income $202.497.85 ($222,209.72) 20 Total Income $1,324,810.45 $230,669.81 21 MISCELLANEOUS INCOME DEDUCTIONS 22 425 Miscelbmeous Amortization $0.00 $0.00 23 426 Other Income Deductions $ 140.45 ($35.57) 24 Total Income Deductions $ 140.45 ($35.57) 25 Income Hefore Interest Charges $1,324,670.00 $230,705.38 26 INTEREST CIIARGES 27 427 Interest on Bonds and Notes $0.00 $0.00 28 428 Amortization of Debt Discount and Expenses $0.00 $0.00 29 429 Amortization of Premium on Debt - Credit $0.00 $0.00 30 431 Other Interest Expenses $701.95 $258.33 31 432 Interest Charged to Construction Credit $0 00 $0.00 32 Total Interest Charges $701.95 $258.33 33 NET INCOME $ 1.323.968 05 $230.447.05 EARNED SURPLUS line Debits Credits No, (a) fb) (c) 34 208 Unappropriated Earned Surplus (at beginning of period) $14,903,714.42 35 36 37 433 Balance Transferred from Income $ 1,323,968.05 38 434 Miscellaneous Credits to Surplus (P. 21) $1,279,596.42 39 435 Miscellaneous Debits to Surplus (P. 21) 40 436 Appropriations of Surplus (P. 21) $200,000.00 41 437 Surplus Applied to Depreciation 42 208 Unappropriated Earned Surplus (at end of period) $17,307,278.89 43 44 TOTALS $ 17.507.278.89 $17.507,278.89

14 Annual report of TOWN OF iTUDSON I.IOHT AND POWER DEPARTMENT Year ended December 31.1993 CASil BALANCES AT END OF YEAR (Account 131) Une items Amount No. (a) (b) 1 Operation Ftmd $2,749,139.97 2 Interest Fund $0.00 3 Bond Fund $0.00 4 Construction Fund (128) $0.00 5 Miscellaneous Cash (128) $1,408,080.92 6 Insurance Escrow Reserve (128) $726,214.32 7 Insurance Escrow - Project #6 (128) $3 537,015.25 8 9 10 11 12 $8.420.450.46 MATERIALS AND SUPPLIES (Accounts 151 159,163) Summary Per Balance Sheet Amount End of Year Line Account Electric Gas No. (a) (b) (c) 13 Fuel (Account 151)(See Schedule, Page 25) $236,498.87 14 Fuels Stock Expenses (Account 152) 15 Residuals (Accotmt 153) 16 Plant Materials and Operating Supplies (Accoimt 154) $854,910.22 NOT APPLICABLE 17 Merchandise (Account 155) IN Other Materials and Supplies (Account 156) 19 Nuclear Fuels Assemblies and Components - In Reactor (Account 157) 30 Nuclear Fuels Assemblies and Components - Stock Account (Account 158) 21 Nuclear Hyproduct Materials (Account 159) 22 Stores Expense (Account 163) 23 Total Per Italance Sheet $ 1.091.409.09 DEPRECIATION FUND ACCOUNT (Account 136) Line Amount No. (a) (b) 24 DEHITS 25 llalance of account at beginning of year $3,004,137.73 26 income during year from balance cr. deposit $73,999.78 27 Amount transferred from income $528,830.54 38 Reimbursement from sales of plant and damages property, etc. $0.00 29 TOTAL $3,606,968.05 30 CREDITS 31 Amount expended for construction purposes (Sec.57,C164 of G L.) $1,740,522.19 32 Amounts expended for renewals, viz: 33 34 35 38 39 Italance on hand at end of year $1,866,445.86 j 40 TOTAL $3.606.968.05

N UTILITY PLANT-ELECTRIC g

1. Report belowthe items of utility plantin service ce ding y e ar. Such ite ms should be include d in column e ffect of such amounts.

b according to prescribed accounts. (c ).

4. Reclassifications of transfers within utdity plant

{

2. Do not include as adjustments. corrections of

3. Credit adjustme nts of plant accounts should accounts should be shown m colunrt (f).

'8 additions and retirements for the current or the pre-be e nelose d in pare nthe se s to indicate the ne gstiv e

a P,

b IIalance g Beginning Adjustments Balance Line Account of Year Additions Depreciation Other Credits Transfers End of Year "1O No. (a) (b) (c) (d) (c) (f) (g) g 1 3 2

1. INTANGIBLE PLANT S3,879.76

$3,879.76 O 3 4 Total Intangible Plant $3,879.76 r- $3,879.76 5 5

2. PRODUCTION PLAST 5

6 A. Steam Production 7 310 Land and Land rights h c5 8 - 311 Simctures and improvements u 9 312 Boiler Plant equipment 10 313 Engine and Engine Driven 11 Generators

c o

12 314 Turbogenerator Units 13 315 Miscellaneous Power Plant 14 Equipment k 15 Total Steam Production Plant M 16 B. Nuclear Production Plant 17 320 Land and Land Rights $1,252.93 $0.00 $0.00 $0.00 $0.00 $1,252.93 18 321 Stmctures and improvements $802.247.54 $116.54 $56,033.67 $0.00 $0.00 $746,330.41 19 322 Reactor Plant Equipment $1,194,684.26 $3,542.72 $68,441.51 $0.00 S0.00 $ 1,129,785.47 20 323 Turbogenerator Units S172,829.17 ($676.30) 511,559.10 $0.00 S0.00 $160,593.77 s. 21 324 Accessory Electric Equipment $273,069.44 $190.61 521,578.00 S0.00 S0.00 $251,682.05 0 22 325 Miscellaneous Power Plant E Equipment $87,832.77 (S t.305.70) $9,003.84 $0.00 S0.00 $77,523.23 &~ 23 Total Nucicar Production Plant $2,531,916. I 1 S1,867.87 5166,616.12 $0.00 $0.00 $2,367,167.86 2 RaXb 3$G

UTILITY PLANT - ELECTRIC (Continued) E 5 Italance .35 Ileginning Adjustments Balance 2 l t 1,ine Account of Year Additions Depreciation Other Credits Transfers End of Year E No. (a) (b) (c) (d) (c) (O (g) O -4 I C. II draulic Production Plant 3 2 330 Land and Land Rights $0.00 $0.00 $0.00 .ed.00 $0.00 $0.00 O 3 331 Structures and impros ements $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 m = 4 332 Rescrsoirs, Dams and Waterna3s $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 5 333 Water Whects, turbines and Generators $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 8 6 334 Accessory Electric equipment $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 2 7 335 Misceilaneous Power Plant Equipment 50.00 $0.00 $0.00 $0.00 $0.00 $0.00 h 8 336 iloads, Railroads and Bridges $0.00 $0.00 $0.00 50.00 $0.00 $0.00 9 Total llydraulic Production Plant $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 10 D. Other Production Plant b 11 340 Land and Land Rights $5,500.00 $0.00 $0.00 $0.00 $0.00 $5,500.00 g 12 341 Structurcs and improvements $7,466.59 $ 1,503.06 $996.89 $0 00 $0.00 $7,972.76 y 13 342 Fuel Holders, Producers and Accessories $14,044.13 $0.00 $3,772.22 $0.00 $0.00 $10,271.91

c 14 343 Prime Movers

$90,696.42 $0.00 $9,708.37 $0.00 $0.00 $80,988.05 15 344 Generators $4,867.07 $0.00 $486 70 $0.00 $0.00 $4,380.37 3 16 345 Accesscry Electric Equipment $27,316.57 $0.00 $3,016.12 $0.00 50.00 $24,300.45 h 17 346 Miscellaneous Power Plant Equipment $15,418.07 $76,117.53 $ 19,858.08 $0.00 $0.00 $53,697.22 R 18 Total Other Production Plant $ 165,308.85 $77,620.59 $37,838.38 $0.00 $0.00 $205.091.06 k 19 Total Production Plant $2,697,224.96 $79,488.46 $204,454.50 $0.00 $0.00 $2,572,258.92 20

3. TRANSMISSION PLANT 21 350 Land and Land Rights

$53,804.14 $0.00 50.00 $0.00 $0.00 $53,804.14 22 351 Clearing Land and Rights of Way $6,812.85 $0.00 $0.00 $0.00 $0.00 $6,812.85 g 23 352 Structures and Improvements $22,445.20 $0.00 $2,529.13 $0.00 $0.00 $19,916 07 8 24 353 Station Equipment $97,504.48 $11,061.35 $ 10,838.88 $0.00 $0.00 $97,726.95 [ 25 354 Towers and Fixtures $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 8. 26 355 Poles and Fixtures $61,815.76 $0.00 $6,965.43 $0.00 $0.00 $54,850.33 ( 27 356 Overhead Conductors and Devices $44,396.59 $0.00 $5,002.63 $0.00 $0.00 $39,393.96 3 28 357 Underground Conduit $84.95 $0.00 $9.57 $0.00 $0.00 $75.38 d 21 358 Underground Conduit and Devices $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $ 30 359 Roads and Trails $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 ~ 31 Total Transmission Plant $286,863.97 $11,061.35 $25.345.64 $0.00 $0.00 $272,579.68 0 e e 9-

UTILITY PLANT - ELECTRIC (Continued) E Balance j Beginning Adjustments Balance Line Account of Year Additions Depreciation Other Credits Transfers End of Year E, No. (a) (h) (c) (d) (c) (I) (g) g 1

4. DISTRIllUTION PLANT 2

360 Land and Land Rights S03)0 SD 00 $0.00' $0.00 $0.00 $0.00 Z 3 361 Structures and Improvements $5,710.36 $0.00 $643.45 $0.00 $0.00 $5,066.91 4

362 Station Equipment

$157,410.95 $1,372,032.14 S72,531.06 55,035.00 $0.00 $ 1,451,877.03 = 5 363 Storage Battt y Equipment SO 00 50.00 $0.00 $0.00 50.00 $0.00 E 6 364 Poles Towers and Fixtures $132,893.01 558,913.50 $29,863.01 527,863.74 $0.00 $ 134,079.76 o 7 365 Overhead Conductors and Devices $564,651.62 545,193.60 $51,113.16 $170,509 C (S330,382.64) $57,840.25 Z 8 366 Underground Condmt $144,128.65 $127,165.73 $26,228.96 59,592 15 S0.00 $235,472.67 { 9 367 Underground Conductors & Devices S439,282.69 $167,192.95 $11,598.78 $35,230. s ($328,364.61) 5231,282.11 y 10 368 Line Transformers $682,364.91 $130,646.25 $29,391.54 $4,029.05 $0.00 $779,590.57 11 369 5crvices-S157,056.28 551,845.50 $6,957.52 $18,281.56 (593,721.61) SE9,941.09 g y 12 370 Meters $320,163.54 $24,331.20 $12,565.38 $7,580.74 $0.00 $324,348.62 13 371 Installations on Cust's Premises $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 b 14 372 Leased Prop. on Cust's Premiscs $0.00 $0.00 $0.00 50.00 50.00 S0.00 tk 15 373 Street Lighting and Signal Systems $82,294.31 $26,571.80 S4,311.36 $0.00 ($42,578.02) $61,976.73 16 Total Distribution Plant $2.685,956.32 $2,003,892.67 $245,204.22 S278,122.15 ($795,046.88) $3,371,475.77 b 17

5. GENERAL PLANT f

IS 389 Land and Land Rights S0.00 S0.00 $0.00 50.00 $0.00 50.00 y 19 390 Structures and Improvements e $82,645.87 S37.00 $9,315.49 $20.00 $0.00 573,347.38 20 391 Office Furniture and Equipment k,[ $191,351.11 S26,391.46 521,025.30 550.00 $0.00 $196,667.27 21 392 Transportation Equipment JM $176,685.25 $0.00 $19,908.97 $3,690.00 $0.00 $153,086.28 22 393 Stores Equipment $3,429.80 $0.00 $386.47 $0.00 $0.00 $3,043.33 23 394 Tools, Shop and Garage Equipment $7,666.53 $0.00 S493.59 $0.00 50.00 $7,172.94 24 395 Laboratory Equipment $6,824.54 S11,190,19 S627.00 $0.00 $0.00 $17,387.73 25 396 Power Operated Equipment $2,031.40 50.00 $116.55 $0.00 $0.00 $1,914.85 8 26 397 Communication Equipment S17,167.17 $55.68 SI,375.11 $0.00 50.00 515,847.74 { j 27 398 Miscellaneous equipment $7,868.71 $43.86 $577.70 $0.00 $0.00 $7,334.87 g 28 399 Other Tangible Property $30.35 S0.00 S0.00 50.00 $0.00 $30.35 a 29 Total General Plant $495,700.73 537,718.19 $53,826.18 $3,760.00 $0.00 5475,832.74 l 30 Total Electric Plant in Service 56,169,625.74 $2,132,160.67 $528,830.54 5281,882.15 ($795,046.88) $6,696.026.84 {. 31 104 Utility Plant Leased to Others $0.00 S0.00 30.00 $0.00 $0.00 50.00 1 32 101 Property I!cid for Future Use 50.00 $0.00 $0.00 S0.00 50.00 50.00 .U 33 107 Construction Work in Progress $0.00 50.00 S0.00 S0.00 $0.00 50.00 G 34 Total Utility Plant Electric $6,169,625.74 $2.132,160.67 S528,830.54 $281,882.15 (S795,046.88) $6,696,026.84 00 i

NE PRODUCTION FUEL AND OIL STOCKS (Included in Account 151) _= (Except Nuclear Materials) E 3

1. Report below the inforrnation called for concerning production fuel and oil stocks.

6

2. Show quantities in tons of 2,000 lbs., gal., or M cf., whichever unit of quantity is applicable.

3. Each kind of coal or oil should be shown separately.

]

4. Show gas and electric fueled separately by specific use.

O h Kind of Fuel and Oil O Total GAS MCF Line Item Cost Quantity ' Cost Quantity Cost 5 No. (a) (h) (c) (d) (c) (f) 3 i On Hand beginning of Year 1271,058.27 450,693 5271,055.27 o 50.00 2 Received During Year $38.723.72 0 $0.00 14,122 S38,723.72 7 3 TOTAL 5309,781.99 450,693 5271,058.27 14.122 538,723.72 3 4 Used During Year (Note A) 571,600 09 56,385 532,876.97 14,122 538,723.72 y 6 >Z 7 o 8 v 9 O5 10 d 11 Sold or Transferred $1,682.43 2.786 $ 1,682.43 0 50.00 12 TOTAL DISPOSED OF $73,283.12 59,171 $34.559.40 14.122 S38.723.72 y 13 BALANCE END OF YEAR $236,498.87 391,522 $236,498.87 0 $0.00 Kinds of Fuel and Oil-Continued 9R Line Item Quantity Cost Quantity Cost k No. (g)) (h) (i) (j) (k) 14 On Hand Beginning of Year 15 Received During Year [ 16 TOTAL 17 Used During Year (Note A) iS = 19 8, 20 0 21 0 22 3 23 k l 24 Sold or Transferred O l 25 TOTAL DISPOSED OF kg 26 BALANCE END OF YEAR 0 Notg A - Indicate specific purpose for which t <ed, e.g. Boiler Oil, Make Oil, Generator Fuel, Etc. e e e3

21 Annual report of TOWN OF 111TDSON i IGIIT AND POWER Di'PA RTMENT Year ended December il 1991 i MISCELLANEOUS NONOPERATING INCOME (ACCOUNT 421) j IJne Item Amount /'s No. (a) (b) w] 1 2 3 4 i 5 6 TOTAL OTIIER INCOME DEDUCTIONS (ACCOUNT 426) Line Item Amount No. (a) (b) 7 8 9 10 11 12 13 14 TOTAL MISCELLANEOUS CREDITS TO SURPLUd (ACCOUNT 434) line Item Amount No. (a) (b) 15 Partial Pilgrim 1 Settlement with Boston Edison 21,875.00 16 True Up of prior years transmission expenses 99,858.66 7 Flush Back of 1992 Project payments 1,157,862.76 19 20 21 22 23 TOTAL $ 1.279.596.42 MISCELLANEOUS DEhlTS TO SURPLilS (ACCOUNT 435) Line Item Amount No. (a) (' ) 24 25 l 26 27 28 29 32 TOTAL APPROPRIATIONS OF SURPLUS (ACCOUNT 436) I Line Item Amount No. (a) (b) 33 Transfer to Town Treasury $200.000.00 34 3r 37 38 39 ~ l 40 l TOTAL $200.000.00

22 Annual report of TOWN OF IIIIDSON I.IGliT AND POWER DEPARTMENT Year ended December 31.1993 MUNICIPAL REVENUES (ACCOUNTS 482,444) (K.W.II. sold under the provisions of Chapter 269. Actions of 1927) Averal,e Revenue Line A cct., Gas Schedule Cubic Feet Revenue Received per M.C.F. No. No. (a) (b) (c) (50.0000) (d) 1 482 NOT APPLICABLE 2 3 4 Average Revenue Electric Schedule KW.II. Revenue Received perk.W.II (a) (b) (c) (cents) (0.0000) l (d) 5 444 Municipal (Other than Street Lightmg) 6 7 All Electric 6,542,400 $600,146.91 9.1732 8 Power 4,977,059 $592,617.86 11.9070 9 Commercial 10 Yard Lighting 577,040 $78,487.73 13.6018 24,874 53.378.43 13.5822 11 TOTALS 12.121,373 $ 1,274,630.93 10.5156 12 13 Street Lighting 14 15 Town ofIIudson 1,166,141 5130,737.00 11.2111 16 Town of Stow 27,595 $4,216.80 15.2810 17 Town of Berlin 388 $75.13 19.3634 18 TOTALS ~,194,124 $135,028.93 11.3078 1 19 TO TALS 13.315.497 $ 1.409.659.86 10.5866 FURCilASED POWER (ACCOUNT 555) Names of Utilities Where and at What I Lost per K W.IL from Which Electric Voltage Received KW.II. Amount (cents) Line Energy is Purchased (0.0000) No. (a) (b) (c) (d) (e) 20 See Pages 54,55,50 f or Detait 21 22 23 24 23 26 27 28 29 TOTALS 271.242.185 $22.189.110.10 8.1806 SALES FOR RESALE (ACCOUNT 447) Revenues per Names of Utilities Where and at What KW.II. to Which EIcetric Voltage Received KW.lt Amount (cents) Line Energy is Purchased (0.0000) No. (a) (b) (c) (d) (c) Ju 32 33 34 NONE 35 36 37 38 39 40 TOTA LS

m /m U U Cm ELECTRIC OPERATING REVENUES (Account 400) g

1. Report below the amount of operating revenue for added for biiling purposes, one customer shall be counted

4. Unmetered sales should be included below. The

{ the year for cath prescribed account and the amount of for each group or meter = to added. The average number of d e t ait, nr much sale. Should be given m. focinote. increne or decresse over the precedmg year. customers means the averace of 12 ficures at the close

5. Clas sification of Commercial and Industrial sales,

} 2 If mercases and decreases are not derived from of each month. If the custemer count in the residential A ccount 4 42, accordin g to Small(or Commercial) and ~ n previously reported firures, explain any inconsistencies. ,ervice claasification includes customers cotinted more Large (or industrial) may he according to the basis of o L Number of cuetomers shou!d be reported on the , * * '" 9" " ' than once tiecause of special services, such as water "E hasis of number of meters, plus number of flat rate heating, etc., indicate in a footnote the number of such I

• I"'

"'8'" H nctounts, except that w here sep arate meter rendings are 9 dup cate customers included in the classification li r A ccou n ts. F.xp lain been or clas sification. O Average Number of 2 Operating Herenues Kilowatt-hours Sold Customers per month g increase of Increase or increase or tn O Amount for (Decrease) from Amount for (Decrease) from Number for (Decrease) from z Line Account Year Preceding Year Year Preceding Year Year Preceding Year C No. (a) (h) (c) (d) (c) (f) (g) l SALES OF ELECTRICITY H 2 440 Residential Sales $7,391,178.23 ($431,631.77) 67,393,087 2,403,747 8,666 179 3 442 Commercial and Industrial Sales: C 4 Small (or Commercial) see instr. 5 $ 1,704,001.18 ($92,567.77) 11,747,838 699,782 1,102 (3) 3 5 Large (or Industrial) see instr. 5 $ 17,097,789.02 ($'778,291.18) 163,787,225 6,177,701 189 0 h 6 444 < Municipal Sales; (P. 22) $ 1,409,659.86 ($ 146,009.89) 13,315,497 (71,805) 88 (3) 7 445 Other Sales to Public Authoritics $0.00 50.00 0 0 0 0 0 8 446 Sales to Railroads and Railways $0.00 $0.00 0 0 0 0 f 9 449 Fuel Charge Adjustment ($452,199.16) $281,139.67 0 0 0 0

j 10 449 Miscellaneous Electric Sales

$72.251.79 ($21.165.09) 529,775 (15.530) 162 7 fB i1 Total Sales to Ilitimate Consumers $27,222.680.92 ($ 1,188.526.03) 256,973.422 9,193.895 10.207 180 M 12 447 Sales for Resaic $0.00 $0.00 0 0 0 0 13 Total Sales of Electricity * $27.222.680.92 ($1,188.526 03) 256,973,422 9,193,895 10.207 180 14 OTIIER OPERATING REVENUES 15 450 Forfeited Discounts 16 451 Miscellaneous Sen-ice Revenues $0.00 -<g 17 453 Sales of Water and Water Power 50.00

• Includes revenues from application of fuel clauses S

$3,329,230.10 y 18 454 Rent fro Electric Property $27,484.00 o-19 455 Interdepartmental Rents $0.00 0 20 456 Other Electric Revenues $12,576.76 Total KWH to which applied 255,807,281 Q 21 3 22 f" 24 a 7 25 Total Other Operating Rcrenues $40.060.76 g 26 Total Electric Operating Revenues $27,262,741.68

o. 38 Annual report of TOWN OF filIDSON I IGIIT AND POWER DFPARTMENT Year ended December 31.1993, SALES OF ELECTRICITY TO ULTIMATE CONSUMERS Repon by account, the K.W.II. sold, the amount derived and the total number of customers under each fided schedule or contract. Contract sales and unbilled sales may be reported separately in total. Average Number of Customers s Revenue (Per Bills Rendered) perIGVII (cents) Line Acct. Schedule K.W.li. Revenue (0.0000) July 31, Dee. 31, No. No. (a) (b) (c) (d) (e) (f) ~ 1 440 "A" Domestic Rate 40,185,279 $4,645,473.68 11.5601 6,572 6,620 2 442 "C" Conunercial Rate 11,697,920 $1,697,237.07 14.5089 1,077 1,099 3 442 "D" Power Rate 163,787,225 $17,097,789.02 10.4390 187 189 ) 4 440 "E" Water licater Residential 11,026,512 $1,160,408.49 10.5238 1,139 1,148 ) 5 440 "F" Rate All Electric 16,381,296 $1,585,296.06 9.6775 895 898 6 442 "G" Rate commercial lleat 49,918 $6,764.11 13.5504 3 3 7 444 Street Lighting 1,194,124 $135,028.93 11.3078 3 3 8 444 Municipal Sales 12,121,373 $1,274,630.93 10.5156 90 86 9 449 Yard Lighting 529,775 $72,251.79 13.6382 159 161 10 449 Power Adjustment Charge 0 ($452,199.16) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 TOTAL SALES TO ULTIMATE l CONSUMERS (Pace 37 line 1 D ! 756 9714?? $27 ??? 6R0 97 10 5936 10.125 10,707

.a 39 Annual report of TOWN OF liUDSON i IGliT AND POWER DFPARTMFNT Year ended December 31.1993 ELECTRIC OPERATING AND MALNTENANCE EXPENSES

1. Enter in the pace provided the operation and maintenance expenses for the year.

{ 2 If the increases and decreases are not derived from previousiv reported ficures explain in footnote Increase or (I)ecrease) from Line Account Amount for Year Preceding Year No. (a) (b) (c) 1 POWER PRODUCTION EXPENSES 2 STEAM POWER GENERATION 3 Operation: 4 500 Operation supervision and engineering 5 501 Fuel 6 502 Steam expenses 7 503 Steam from other sources 8 504 Steam transferred - Cr. 9 505 Electric expenses 10 506 Miscellaneous steam power expenses 11 507 Rents 12 Total Operation 50.00 $0.00 13 Maintenance: 14 510 Maintenance supervision and engineering 15 511 Maintenance of structures 16 512 Maintenance of boiler plant 17 513 Maintenance of electric plant 18 514 Maintenance of miscellaneous steam plant 19 Total Maintenance $0.00 $0.00 20 Total power production expenses - steam power 50.00 $0.00 21 NUCLEAR POWER GENERATION 22 Operation: 23 517 Operation supervision and engineering $15,903.58 $823.03 24 518 Fuel .$41,987.43 ($1,938.02) 25 519 Coolants and water $471.97 $59.57 26 520 Steam expenses $9,962.62 ($1,677.17) 27 521 Steam from other courses $0.00 $0.00 28 522 Steam transferred - Cr. $0.00 $0.00 29 523 Electric expenses $332.74 $34.04 30 524 Miscellaneous nuclear power expenses $22,786.67 ($8,177.40) 31 525 Rents $0.00 $0.00 32 Total operation $91,445.01 ($10,875.95) 33 Maintenance 34 528 Maintenance supervision and engineering $4,938.02 ($603.74) 35 529 Maintenance of structures $3,293.26 ($588.41) 36 530 Maintenance of reactor plant equipment $2,327.92 ($5,239.60) 37 531 Maintenance of electric plant $3,015.04 ($2,608.92) 38 532 Maintenance of miscelhmcous nuclear plant $5,924.12 ($1,131.38) 39 Total maintenance $19.498 36 ($10,172.05) 40 Total power production expenses-nuclear power $110,943.37 ($21,048.00) 41 IIYDRAULIC POWER GENERATION 42 Operation 43 535 Operation supervision and engineering 44 536 Water for power 45 537 Ilydraulic expenses 46 538 Elect ic expenses 47 539 Miscelhmeous hydraulic power generation expenses 48 540 Rents 49 Total ooeration

De 40 Annual report of TOWN OF HUDSON I IGHT AND POWFR DEPARTMINT Year ended December 31 1993 ELECTRIC OPERATING AND MAINTENANCE EXPENSES - Continued increase or (Deercase) from Line Account Amount for Year Preceding Year No. (a) (b) (c) 1 IIYDRAULIC POWER GENERATION - Continued 2 Maintenance 3 541 Maintenance supervision and engineering 4 542 Maintenance of structure 9 543 Maintenance of reservoirs, dams and waterways 6 544 Maintenance of electric plant 7 545 Maintenance of miscellaneous hydraulic plant 8 Total maintenance 9 Total power production expenses - hydraulic power 10 OTIIER POWER GENERATION 11 Operation 12 546 Operation supervisiorrand engineering $24,956.25 $1,961.25 13 547 Fuel $71,600.69 $19,984.28 14 548 Generation expenses $200,333.68 $ 14,358.81 15 549 Miscellaneous other power generation expenses $59,019.91 ($1,953.24) 16 550 Rent $0.00 $0.00 j 17 Total operation 5355,910.53 $34,351.10 l 18 Maintenance 19 551 Maintenance supervision and engineering $24,490.38 $1,688.35 20 552 Maintenance of structures $118,662.76 $13,614.75 21 553 Maintenance of generating and electric plant S49,104.97 ($13,999.96) 22 554 Maintenance of miscellaneous other power generation plant $4,155.48 $2,928.83 23 Total maintenance $196,413.59 54,231.97 24 Total power production expenses $552,324.12 $38,583.07 25 OTIIER POWER SUPPLY EXPENSES 26 555 Purchased power $22,189,110.10 ($1,580,809.01) 27 556 System control and load dispatching $25,540.84 $1,075.55 28 557 Other expenses $28,625.67 ($5,046.08) 29 Total other power supply expenses $22.243,276.61 ($1,584,779.54) 30 Total power production expenses $22.906,544.10 ($1,567,244.47) 31 TRANSMISSION EXPENSES 32 Operation 33 560 Operation supervision and engineering $0.00 $0.00 34 561 Load dispatching $0.00 50.00 35 562 Station Expenses $3,908.45 $2,312.62 36 563 Overhead line expenses $37.32 $37.32 37 564 Underground line expenses $0.00 50.00 38 565 Transmission of electricity by others $915,681.92 ($61,459.14) 39 566 Miscellaneous transmission expenses $0.00 $0.00 40 567 Rents $50.00 $0.00 41 Total operation $919,677.69 ($59,109.20) 42 Maintenance 43 568 Maintemmcc supervision and engineering $0.00 S0.00 44 569 Maintemmcc of structures $328.72 $254.88 45 570 Maintenance of station equipment $3,166.28 $413.75 46 571 Maintenance of overhead lines S114.86 578.46 47 572 Maintenance of underground lines $0.00 10.00

• 48 573 Maintenance of miscellaneous transmission plant

$0.00 $0.00 49 Total maintenance S3,609.86 $747.09 Total transmission expenses $923.287.55 (S58.362.11)

41 Annual report of TOWN OF lillDSON 1.lGIIT AND POWER DEPARTMFNT Year ended December 31,1993 ELECTRIC OPERATING AND MAINTENANCE EXPENSES inercase or (Decrease) from A Line Account Amount for Year Preceding Year No. (a) (b) (c) I DISTRIBUTION EXPENSES l 2 Operation: l 3 580 Operation supervision and engineering $22,678.60 $1,067.30 4 581 Load dispatching $0.00 $0.00 5 582 Station expenses $287.56 $212.58 6 583 Overhead line expenses $7,081.11 $1,319.80 7 584 Underground line expenses $1,919.48 $1,251.80 8 585 Street lighting and signal system expenses $8,410.21 ($237.45) 9 586 Meter expenses $45,038.35 $5,489.97 } 10 587 Customer installations expenses $1,269.14 $377.02 / 11 588 Miscellaneous distribution expenses $5,774.69 $2,034.66 12 589 Rents $0.00 $0.00 13 Total operation $92,459.14 $11,515.68 14 Maintenance: 15 590 Maintenance iTupervision and engineering $22,729.33 $1,182.56 16 $91 Maintenance of structures $0.00 $0.00 17 592 Maintenance of station equipment $181.84 ($221.40) 18 593 Maintenance of overhead lines $189,281.54 ($9,976.09) 19 594 Maintenance of underground lines $21,243.88 ($21,217.11) 20 595 Maintenance ofline transformers $8,593.71 ($2,432.28) i 21 596 Maintenance of street lighting and signal systems $7,145.07 $1,808.61 22 597 Maintenance of meters $7,014.33 $430.82 A 23 598 Maintenance of sniscellaneous distribution plant $0.00 $0.00 () 24 Total maintenance $256,189.70 ($30,424.89) 25 Total distribution expenses $348,648.84 ($18,909.21) 26 CUSTOMERS ACCOUNTS EXPENSES 27 Operation: 28 901 Supervision $10,632.71 $2,744.05 29 902 Meter reading expenses $47,055.81 $1,810.10 30 903 Customer records and collection expenses $169,149.61 $5,925.15 31 904 Uncollectible accounts $43,957.02 $20,669.97 32 905 Miscellaneous customer accounts expenses $0.00 $0.00 33 Total customer accounts expenses $270,795.15 $31,149.27 34 SALES EXPENSES 35 Operation: 36 911 Supenision $0.00 $0.00 37 912 Demonstrating and selling expenses $0.00 $0.00 38 913 Advertising expenses $25.00 $0.00 39 916 Miscellaneous sales expenses $11,782.88 ($417.51) 40 Total sales expenses $11,807.88 ($417.51) 41 ADMINISTRATIVE AND GENERAL EXPENSES 42 Operation: 43 920 Administrative and general salaries $319,579.16 $24,259.28 44 921 OITice supplies and expenses $9,768.45 ($5,257.20) 45 922 Administrative expenses transferred Cr. ($28.56) ($53.07) 46 923 Outside services employees $190,962.07 $37,962.68 47 924 Property insurance $26,748.32 ($1,511.42) 48 925 Injuries and damages $47,214.48 ($92,322.42) 49 926 Employee pensions and benefits $393,320.43 $21,707.75 50 928 Regulatory commission expenses $3,514.72 ($156.85) 51 933 Transportation expenses $39,840.68 ($11,712.34) 52 930 Miscellaneous pencral expenses $46,471.85 $3,921.01 53 931 Rents $0.00 $0.00 54 Total operation $ 1.077.39L60 ($23.162.5K)

i 42 Annual report of TOWN OF ITUDSON I.IGHT AND POWER DEPA RTMENT Year ended Decernher 31.1993 ELECTRIC OPERATION AND MAINTENANCE EXPENSES - Continued Ol Increase or (Decrease) from Line Account Amount for Year Preceding Year No. (a) (b) (c) 1 ADMINISTRATIVE AND GENERAL EXPENSES - Cont. 2 Maintenance 3 932 Maintenance of generalplant $48,786.99 $5,286.73 4 Total administrative and general expenses $ 1,126.178.59 ($17,875.85) 5 Total Electric Operation and Maintenance Expenses $25.587.262.11 ($1.631.659.88) SUMMdRY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES Line Functional Classification Operation Maintenance Total No. (a) (b) (c) (d) 6 Power Production Expenses 7 Electri: Generation: 8 Steam power 9 Nuelear power $91,445.01 $19,498.36 $110,943.37 10 Hydraulic power 1I Other power $355,910.53 $196,413.59 $552,324.12 12 Other power supply expenses $22,243,276.61 $0.00 $22,243.276.61 13 Total power production expenses $22,690,632.15 $215,911.95 $22,906,544.10 14 Transmission Expenses $919,677.69 $3,609.86 $923,287.55 15 Distribution Expenses $92,459.14 $256,189.70 $348,648.84 16 Customer Accounts Expenses $270,795.15 $0.00 $270,795.15 17 Sales Expenses $11,807.88 $0.00 $11,807.88 18 Administrative and General Expenses $1,077.391.60 $48,786.99 $1,126,178.59 19 Total Electric Operation and 20 Maintenance Expenses $25.062.763.61 $524.498 50 $25.587.262.11 21 Ratio operating expenses to operating revenues (carry out decimal two places, e g.: 0.00%) 95.88 % Complete by dividmg Revenues (acci. 430) mio the sum of Operation and Mamtenance Expenses 0'agt 42, Ime 2?(3).1)cpreciation (Acct 403) and Amortization ( Acct. 407) 22 Total salaries and wages of electric depanment for year, including amounts charged to oper- $1,407,972.58 j atmg expenses, construction and other accounts. 23 Total number of employees of electric department at end of year including administrative, 34 j operatmg, mamtenance, constructwn and other employees (including part time employees) l

\\ TAXES CIIARGED DURING YEAR !3 ( This sc hedule is intende d to give the accennt elb 1The aggregate cre ach k'ul of ta x shouk! he Lsted numberof the apprornate balance sheetplant accounts ~ e w tribution of tetalta xe s charged to operatens and other underthe appropriate heading of

• Federal,"' State,* and or sub ac c ount.

O finalaccounts during the year. local"in such mannerthat the totaltsx for each State

5. For any tax which it was necessary to apportion

2. Do not inchide gasoline and othersales taxes which and for allsubdivisions can teadily be ascertained.

to more than one utdty department or account state o have been charged to accounts to which the material in a footnote the basis of apportioning such tax. on which the tax was levied was charged.If the actual 4.The accounts to whic h the taxes charged were ids-6.Do not ' clude in this sche dule entne s with respect h o orestimated amounts oIsuch taxes are known.they tributed shouh! be shown in columns (c)to (h). Show to de ferred income taxes ortaxes collected through pay-should he shown as a footnote and designated uhether both the utility department and number of account rqG deductions orotherwise pending transmittalof such estim ated or actuat amounts. c h ange d. For taxe s charge d to utility plant show the ta xes to the taxing authority. O' e. r Total Tales Distribution of Taxes Charged (omit cents) h Charged (Show utility department where applicable and account charged) to During Year Electric Gas Line Kind of Tax (omit cents) (Acet. 408,409) (Acct. 408,409) e No. (a) (h) (c) (d) (e) (f) (g) (h) (j) (k) 5 i Real Estate Taxes $21,230.29 $21,230.29 2 Payroll Taxes $3,106.14 $3,106.14 3 4 5 mO 6 h 7 N 8 a 9 rn m 10 N' 11 d 12 N 13 h 14 15 16 17 18 8 19 20 E g-l 21 22 C o 23 8 g 24 T, 25 w 26 ~ ~ 27

• ea 28 TOTALS 524,336.43 524,336.43

50 Annual report of TOWN OF IIUDSON LIG1IT AND POWER DEPARTMENT Year ended December 31.1993 OTIIER UTILITY OPERATION INCOME (Account 414) Report below the particulars called for in each column. Amount Gain or Amount of Amount of of Operating (less) from Line Property Investment Revenue Expenses Operation No. (a) (b) (c) (d) (e) I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 o NONE 22 23 24 25 26 27 28 29 30 3I 32 33 34 35 36 37 38 39 40 41 42 43 44: e 47 48 j f 49 50 51 TOTALS

51 i Annual report of TOWN OF IIUDSON LIGIIT AND POWER DEPARTMENT Year ended December 31.1993 INCOME FROM MERCilANDISING, JOBBING, AND CONTRACT WORK (Account 415) Report by utility departments the revenues, costs, expenses and net income from merchandising, jobbing and contract work during year. Other Electric Gas Utility Line item Department Department Department Total No. (a) (b) (c) (d) (e) 1 Revenues: 2 Merchandise sales, less discounts, S' allowances and returns 4 Contract work 5 Commissions 6 Other (list according to major classes) ) 7 l 8 9 to Total Revenues NONE 11 12 13 Cost and Expenses: 14 Cost of sales (list according to major 15 classes of cost) 16 17 18 19 h[D 20 21 22 23 24 25 26 Sales expenses 27 Customer accounts expenses 28 Administrative and general expenses 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 o 47 48 49 50 TOTAL COSTS AND EXPENSES 51 Net Profit (or less)

52 Annual report of TOWN OF HUDSON LIGiff AND POWER DEPARTMENT Year ended December 31.1993 SALES FOR RESALE (Account 447)

1. Report sales during year to other electric utilities and and place and "x" in column (c) if sale involves export acro to cities or other public authorities for distribution to line.

ultimate consumers.

3. Report separately firm, dump, and other power sold t

2. Provide subheadings and classify sales s to (1) Associ.

utility, Describe the nature of any sales classified as Other ated Utilities, (2) Nonassociated Utiolities, (3) Municipalitic column (b). (4) R.E.A. Cooperatives, and (5) Other Public Authonties.

4. If delivery is made at a substation indicate ownersidp For each sale designate statistical classification in column (b in column (e), thus: Respondent owned or leased, RD; cust thus: firm power, FP, or surplus power, DP; other, G, owned ofleased, CS.

Kw or Kva of Demand (Specify Which) Average Monthly Annual Sales to Point of Contract Maximum Maximum Line Delivery Demand Demand Demand No. (a) (b) (c) (d) (e) (f) (g) (h) 1. 2 3 4 5 6 7 8 1 11 12 13 14 15 16 17 18 19 20 NONE 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 3 38 39 40 41 42

53 Annual Report of TOWN OF HUDSON LIGHT AND POWER DEPARTMENT Year ended December 31.1993 SALES FOR RESALE (Account 447)- Continued

5. If a fixed number ofkilowatts of maximum demand

6. The number of kilowatt-hours sold should be the is specified in the power contract as a basis of billings to the customer this number should be shown in column (f).

quantities shown by the bills rendered to the purchasers. The number of kilowatts of maximum demand to be shown

7. Explain any amounts entered in column (n) such as l

in column (g) and (h) should be actual based on monthly fuel or other adjustments. readings and should be fumished whether or not used in the determination of demand charges, Show in column (i) type S. If a contract covers several points of delivery and of demand reading (instantaneous,15,30, to 60 minutes small amounts of electric energy are delivered at each point, integrated.) such sales may be grouped. Voltage Revenue Type of at per IGVil Demand Which Kilowatt-Demand Other (Cents) Reading Delivered hours Charges Energy Charges Total (0.0000) Line i (i) 0) (k) (1) (m) (n) (o) (p) No. 1 1 2 I 3 4 5, 6 1 l 7 8 9 10 11 12 13 14 15 16 17 18 19 NONE 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 p) 36 q 37 38 39 40 41 TOTAIS 42

4 54 l Annual report of TOWN OF HUDSON LIGHT AND POWER DEPARTMENT Year ended December 31,1993 i PURCIIASED POWER (Account 555) (except interchange power) 1.Reportpower purchased for tesale during the year Exclude fromthis schedule and reporton page 56 Authorities. For each purchase designate statistical classi-parnc ulars fication in column (b), thus: firm power, FP; dump or concerning interchange power transactions during the year. surplus power, DP; other, O, and place and "x" in colunm (c) {

2. Provide subhe adings anJ classify purc hase s as to if purchase involves import across a state line.

(1) Associate d Utilitie s,(2) No nassoc iate d Utihtie s. (3)

3. Report separately firm, dump, and other power pur-Associated Nonut:lities,(4)Nonassociated Utilitie s,(5)Muni-chased fromthe same company. Describe the nature of any cipahties,(6)R E.A. Cooperative s, and (7)Other Pubhc g

p g Kw or Kva of Demand c}{ [ojj; j Average g (Specify Which)

e j3 ga j

Contract Monthly Annual Line Purchsed from -[E Demand Maximum Maximum Point of Receipt Demand Demand No.. (a) (b) (c) (d) (c) (f) (g) (h) 1 Pilgrim 1 - Boston Edison O Marlboro-Hudson Line 2500 N/A N/A 2 Vermont Yankee O X 578 N/A N/A 3 hiaine Yankee O X 1310 N/A N/A 4 Wyman - Yarmouth - CM O X 2102 N/A N/A 5 Point Lepreau O X 5000 N/A N/A 6 MMWEC - Canal O 3141 N/A N/A 7 MMWEC - Mix No.1 0 X 691 N/A N/A 8 MMWEC - Project (!3 - Mi O X 591 N/A N/A 9 MMWEC - Project #4 0 X 2109 N/A N/A 10 MMWEC-Project #5 0 X 235 N/A N/A 11 MMWEC - Project #6 O X 15972 N/A N/A 12 Taunton - Cleary Station O 5000 N/A N/A 13 Pasny O X 2521 N/A N/A 14 RFA - Lawrence O 928 N/A N/A 15 N E. Power CO. F 3000 N/A N/A 16 17 18 19 20 21 22 Purchased Power Used at Power Plant 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 41 42

Annual report of TOWN OF IIITDSON l.IGHT A ND POWFR DEPARTMFNT Year ended December 31.1991 55 PURCliASED POWER (Account 555) Continued (except interchange power) ~

4. lf recei ofpower is at a substation indicate owner should be furnished whether or not used in the determianti in colum (e), us: resondent owned or leased, RS; seller owned or leased, SS.

of demand charges Show in column (i) type of demand

5. If a fixed number of kilowatts of maimum demand reading (instantaneous,15, 30, or 60 minutes integrated).

6. 7he number of kilowatt hours is specified in the power contract as a basis of billing, thi quantities shown by the power bills. purchased should be t number should be shown in colunm (f) The number of

7. Explain any amount entered in column (n) such as fu kilowatts of maximum demand to be shown in columns (

or other adjustments. and (h) should be actual based on monthly readings and Cost per Typeof Voltage KWil Demand at Which Kilowatt-Energy Other (Cents) Reading Delivered hours Charges Charges Charges Total (0.0000) IJne (i) 0) (k) (1) (m) (n) (o) (p) No. NA 115 kv 16,196,746 $1,253,409 $82,050 $37,596 $1,373,055 8.4774 1 NA 115 kr 3,749,827 $166,038 $21,714 $12,569 $200,321 5.3421 2 NA 115 kv 8,514,537 $235,238 $38,416 $13,493 $287,147 3.3724 3 NA 115 kv-1,286,957 $105,887 $37,939 $0 $143,826 11.1757 4 NA 115 kv 38,194,800 $1,413,639 $60,741 $0 $1,474,380 3.8602 5 NA 115 kv 9,881,852 $142,138 $212,188 $0 $354,326 3.5856 6 NA 115 kv 4,052,543 $549,283 $13,954 $0 $563,237 13.8984 7 NA i15 kv 3,333,672 $346,975 $10,328 $0 $357,303 10.7180 8 NA II5 ky 16,581,203 $1,255,380 $97,713 $0 $1,353,093 8.1604 9 NA 115 kv 1,846,773 $158,369 $10,883 $0 $169,252 9.1647 10 NA ll5 ky 125,560,139 $13,588,497 $739,929, $0 $14,328,426 11.4116 11 [ NA 115 kv 2,619,344 $305,091 $88,668 $0 $393,759 15.0327 12 NA 115 kv 19,114,961 $109,817 $0 $0 $109,817 0.5745 13 NA 115 kr 2,837,376 $0 $232,665 $0 $232,665 8.2000 14 NA i15 kr 45,000 $0 $1,215 $0 $1,215 2.7000 15 16 17 18 CllARGED TOACCOUNT 549 (1,595,868); ($34,046) ($34,046) 19 20 21 22 23 24 25 26 27 28 ) 29 30 31 32 33 34 35 36 37 38 39 40 41 TOTAIS 252 219 862 I $19.629 761 S t.648 A03 529 612 521 307.776 R 44R1 42

i I INTERCIIANGE POWER (Included in Account 555) > m* g!. t

1. Report kclow the kilowa tt-heurs re c eive i a nd s h a ll b e fu rn ish e d m P a rt B, D e t a ils o f S e ttle m e n t fo r de liv ere d dunng the y e a r a n d the ne t c ha rg e or c re dit In te re h a n g e P o we r. If se ttle m e n t fo r a ny tra n s e e tio n c oordina tion. or othe r s uc h a rra ng e m e n t, s ubm it a 3

unde r inte rc ha nge powe r a g re e m e nts. n ts o m e lu d e s e re d et o r d e b it a m o a n t s o t h e r t h a n fo r c opy of the a nnuals um m a ry of tra ns a c tions a nd ball- ] 2, Provide subhe a ding s a nd cla s sify inte rc ha ng e s in c re m e n t g e n e rs tm n e x p e n ses.sh o w su e h oth e r ings a m ong the pa rtie s to the a gree m e nt.If the g e o m p o n e n t a m o u n t s s e p a r a t e ly, m a d d it io n t o d e b it a m ount of se ttle m e nt re porte d in this s c he dule for a ny a s en (1) A s e ncia te d Utiinic a,(2) Nona ssocia te d Utih-o ties (3) A s mocia te d Nonatalitie s,(4)Other Non-o r e re d it fo r tn e re m e n t g e n e r a tm n e x p e n s e s, a n d g iv e transa ction fors not represent allef the c harges and 9 u ti?itie s,(5 ) M u nic ip a litie s,(6) R I.A. Coop e ra tive s, a b rie f e x p la n s tio n o f th e fa c to rs a n d p rm e sp le s u n d e r c re dits covere d by the a gre em ent. furnish in a footnote H a n d (7) Othe r P ublic A uth oritie s, F or e a c h inte r-w hic h su e h oth e r e om p o n e n t a m o u n ts we re de te r-a de sc ription of the othe r de bits a nd c re dits a nd sta te O j c ha nge a c ros s a sta te line pla c e a n *x

• in c olum n (b) m mie d. lf su c h s e ttle m e nt re p re se n ts the n e t o r d e b its the a m ount a nd ac c ounts in whic h suc h other

3. Pa rtic ala rs of s e ttle m e nts for inte rc h a ng e powe r a n d c re d its u n d e r a n in te re o n n e c tio n. F o w e r p o o lm g,

am ounts are include d for the y e a r. 1 O m l A. Summary ofInterchange According to Companics and Points of Interchange Interchange Voltage Kilowatt-llours cn i o Across at Which Net Amount of Z Line Name of Company state unes Point of Interchange Interchanged Received Delivered Difference Settlement C No, (a) (b) (c) (d) (c) (f) (g) (h) O l 1 NEPEX Hudson-Marlboro Town Lin 115 KV 38,120,155 18,965,620 19,154,535 $887,037.49 I USED AS STATION POWER AND CHARGED TO (549) (132,212) (132,212) ($5,703.52) 2 3 4 T 5 OI 6 m 7 i 8 O 9 10 11 12 'l O l'A LS 37,987,943 18,965,620 19,022,323] $881,333.9 7 II. Details of Settlement for Interchange Power Line Name of Company Explanation Amount N o. (i) (.j) (k) [ 13 NEPEX Energy Received by H.L.& P. -Economy S1,087,012.87 14 -Scheduled Outage $48,353.42 E. 15 -Unscheduled Outage $63,132.32 E 16 -Deficiency $0.00 17 Energy Dollars from NEPOOL ($210,189.26) g 18 Quebec Net Savings Fund ($63,352.87) T 19 NEPOOL Savings ($125,444.67) 5 20 NEPOOL Expenses $65,653.21 L 21 Other $21,872.47 3 TOTAL 5887,037.49 e e 9-

.^ 57 Annual ref>ori of TOWN OF HUDSON I IGHT AND POWER OFPARTMENT Year ended December 31.1993 ELECTRIC ENERGY ACCOUNT Report below the information called for concerning the disposition of electric energy generated, purchased, and interchanged d IJne item IGlowatt-hours No. (a) (b) 1 SOURCES OF ENERGY 2 Generation (excluding station use): 3 Steam 0 4 Nuclear 6,999,514 5 Ilydro 0 6 Other (DIESEL) 1,792,704 7 Total Generation 8 Purchases 8,792,218 252,219,862 9 In (gross) 37,987,943 10 Interchanges Out (gross) 18,965,620 11 Net (kwh) 19,022,323 12 Received 13 Transmission for/by others (wheeling) Delivered 14 Net (kwh) 15 TOTAL 280,034,403 16 DISPOSITION OF ENERGY 17 Sales to ultimate consumers (including interdepartmental sales) 256,973,422 18 Sales for resale 0 19 Energy fumished without charge 0 20 Energy used by the company (excluding station use): 329,019 21 Electric department only 22 Energy losses: [ 23 Transmission and conversion losses 11,044,879 24 Distribution losses 8,004,959 25 Unaccounted for losses 3,682,124 26 Total energy losses 27 Energy losses as percent of total on line 15 8.1176 % 22,731,962 28 TOTAI. 280.034.403 MONTIILY PEAKS AND OUTPUT

1. Report hereunder the informabon called for pertaining to sunul.

3. State type of monthly peak readmg (Instantaneous, I $. 30, or 60 taneously peaks estabbshed monthly (m kdowatts) and monthly output 6n minutes miegrated )

kilowatt-hours)for the combmed sources of electnc energy of respondent.

4. Monthly output should be the sum of respondent's net generation

2. Monthly peak col (b) should be respondent's matsmum kw load as and purchases plus or mmus net interchange and plus or mmus net trans-measured by the sum of its comcidental net generation and purchase plus missmn of wheelmg. Total for the year should agree with Ame 15 above.

or mmus net mterchange, mmus temporary dehvenes (not mterchange)

5. If the respondent has two or more power systems not physicatty of ernergency power to another system. Monthly peak mcludmg such connected, the mformataan called for below should be fumished for each emergency dchvenes should be shuan in a footnote with a bnef explanation system as to the nature of the emergency.

l Day orl Monthly Output Type (kwh) Line Month Kilowatts Day of Week Mont flour of Reading (See Instr. 4) No. (a) (h) (c) (d) (c) (f) (st) 29 January 41,700 TUESDAY 19 9:00 60 Min. 24,441,255 30 February 41,300 TUESDAY 2 9:00 60 Min. 22,904,722 31 March 40,000 FRIDAY 19 8:00 60 Min. 23,955,702 32 April 37,700 FRIDAY 2 10:00 60 Mm. 21,323,590 33 May 36,600 TUESDAY 11 15:00 60 Min. 20,831,556 34 June 41,300 MONDAY 28 14:00 60 Min. 21,950,380 35 July 44,700 WEDNESDAY 7 15:00 60 Min. 24,119,558 0 36 August 45,600 THURSDAY 26 16:00 60 Min. 24,725,556 37 September 44,800 FRIDAY 3 14:00 60 Min. 21J)26,127 38 October 37,800 WEDNESDAY 27 12:00 60 Min. 23.220,072 39 November 40,000 TUESDAY 30 19:00 60 Min. 22,389,894 40 December 42.800 MONDAY 27 18:00 60 Min. 29,145,991 41 TOTAL 280 034.401

I 58 Annualreport of TOWN OF IIUDSON 1.lGIIT AND POWER DEPARTMENT Year ended December 31.1993 l GENERATING STATION STATISTIC (Large Stations)

• Limited to 15,200 by Diesel (Except Nuclear. See Instruction 10)

1. Large stations for this purpose of this schedule are steam and

4. If peak demand for 60 minutes is not available, give that stations of 2,699 Kw' or more of installed capacity and other statio which is available, specifying penod 500 Kw' of more of installed capacity (name plate ratings). (*10,0

5. If a group of employees attends more than one generating, and 2,600 Kw, respectively, if annual electric operating revenue of station, report on line 11 the approximate average number of spondent are $25,000,000 or more.)

employees assignable to each station.

2. If any plant is leased, operated under a license from the Feder

6. If gas is used and purchased on a thenn basis, the B t.u.

Power Commission, or operated as ajoint facility, indicate such fa content of the gas should be given and the quantity of fuel converted to cy, ft. Line Item Plant Plant Plant No. (a) Cherry St. Sta. IILP Peaking (d) 1 Kind of plant (steam, hydro, int. comb., gas turbine) Int. Comb. Int. Comb. 2 Type of plant construction (conventional, out-door, boiler, full outdoor, etc ) Conventional Conventional 3 Year originally constructed 1897 1962 4 Year last unit was installed 1972 1962 5 Total installed capacity (maximum generator name plate ratings in kn) 16,150* 4,400 6 Net peak demand on plant-kilowatts (60 min.) 15.2 2.8 7 Plant hours connected to load 221 137 8 Net continuous plant capability, kilowatts: 9 (a) When not limited by condensed water 15.200 4,400 10 (b) When limited by condensed water 15,200 4,400 11 Average number of employees 12 12 Net generation, exclusive of station use 1,455,744 336,960 13 Cost of plan (omit cents) 14 Land and land rights $5,500 15 Structures and improvements $332,768 16 Reservoirs, dams and waterways 17 Equipment costs $3,117,645 712,054 18 Roads, railroads and bridges 19 Total Cost $3,455,913 712.054 20 Cost per kw ofinstalled capacity 227 162 21 Production expenses: 22 Operation supervision and engineering $24,956.25 23 Station labor $196,638.68 24 Fuel $71,600.69 25 Supplies and expenses, including water $62,714.91 26 Maintenance $ 196,413.59 27 Rents $0.00 28 Steam from other sources $0.00 29 Steam transferred - Credit $0.00 30 Total production expenses $552 324.12 31 Expenses per net KWII(5 places) $0.30810 32 Fuel: Lind

1. 2 Dieset Natural Gas 33 Unit: (Coal-tons of 2,000 in.)(Oil barrels of 42 l

gals.) (Gas-M cu. ft.) (Nuclear, indicate) 42 Gal M Cu Ft 34 Quantity (units) of fuel consumed 1,342 14,122 35 Average heat content of fuel (111 u. per lb. of coal, per gal. of oil, or per cu. f t. of pas) 140,000 Bru, 910 BTU 36 Average cost of fuel per unit, del. f.o b plant $2.74208 MCF 37 Average cost of fuel per unit consumed 24.4985 BBL $2.74208 MCF 38 Average cost of fuel consumed per million B.t.u $4.16485 $3.01320 39 Average cost of fuel constmed per kwh net gen. $0.03994 40 Average B.t.u. per kwh net generation 11,571 41 42

e 58A Annualreport of TOWN OF IRJDSON LIGHT AND POWER DEPARTMENT Year ended December 31.1993 l GENERATING STATION STATISTIC (Large Stations) L:q) The liudson Light & Power Department is a.07737% owner of Seabrook Unit #1 located at Seabrook, N.H. The 1993 generation statistics are as follows: Line item Plant No. (a) (b) I Kind of Plant l. Nuclear 2 Type of Plant Construction Fully Contained 3 Year Originally Constructed 1,990 4 Year Last Unit Was Installed 1,990 5 TotalInstalled Capacity 1197 M W 6 Net Peak Demancf'On Plant i157 M Wii 7 Plant flours Connected To Load 8,096 8 Net Continuous Plant Capability 9 (a) When not limited by condenser water 1,150 10 (b) When limited by condenser water 1,150 11 Average number of employees 960 12 Net generation, exclusive of station use 9,046,805,000 KWH 13 Fuel: Kind Nuclear 14 Unit Grams 15 Quantity of Fuel Burned 1,478,164 16 Average Heat Content of Fuellhirned 62.1 MMBTU/Gr 17 Average BTU Per KWH Net Generation 10,151.6 BlU 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 39 i 40 41 42

59 Annualreport of 70WN OF IIUDSON I.lGHT AND POWER DFPARTMEN Year ended Decernher 31.1991 G ENERATING STATION STATISTICS (Large Stations) - Continued .g (Except Nuclear, See Instruction 10) 547 as shown on hne 24.

8. %e items under cost of plant and production expenses repres operation with a conventional steam unit, the gas turbine should be inc

10. If the respondent operates a nuclearpower generating station accounts or combinations of accounts prescribed by the Uniform S of Accounts. Production expenses, however, do not include Purch submrt (a) a bnef explanatory statement conceming accounting for th Power, System Control aid Load Dispatching, and Other Expense cost of power generated including any attnbubon of excess costs to res and development expenses;(b) a brief explanation of the fuel accounti classified as "Other Power Supply Expenses."

spectfying the accounting methods and types of cost units used with

9. If any plant is equipped with combinations of stearn, hydro, combustion engine or gas turbine equipment, each should be repo(r respect to the various components of the fuel cost, and (c) such additio mformation as may be mformathe concerning the type of plant, Lind o separate plant. However,if a gas turbine unit functions in a combi fuel used, and other physical and operating charactenstics of the plant Plant Plant Plant Plant Plant Plant Line (e)

(O (R) (h) (i) (i) No. I 2 3 4 5 6 7 8 9 10 11 O u 14 15 16 l 17 I 18 19 I 20 i i 21 i 22 23 24 25 26 l 27 i i 28 I 29 I 30 I 31 32 33 i 34 35 36 ( 37 N i 38 i i e i 39 l 40 j 41 l 42

60 Annuai reriort of TOWN OF IUIDSON I IGIIT AND POWER DFPARTMENT Year ended December 31.1993 STEAM GENERATING STATIONS

1. Report the infonnation called for concerning g lessor, date and terms oflease, and annual rent. For any ating stations and equipment at end of year.

generating station, other than a leased station or portion

2. Exclude from this schedule, plant, the book co thereof for which the respondent is not the sole owner but which is included in Account 121, Nonutility Proper which the respondent operates or shares in the operation o

3. Designate any generating station or portion the fumish a succinct statement explaining the arrangement a for which the respondent is not the sole owner. If s give particulars as to such matters as percent owmership property is leased from another company, give nam by respondent, name and co-owner, basis of sharing outp i

BOILERS Rated Max. Name of Station location of Station Number Kind of Fuel Rated Rated Continuous and Year and Method Pressure Steam M lbs Steam Installed of Firing in Ibs. Temperature

• per hour line No.

(a) (b) (c) (d) (c) (f) (t) 1 2 3 4 5 6 7 8 1 11 12 13 14 15 16 17 18 19 20 NO T A P P LI CABLE 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 I i Olndicate reheat boilers thusly, 1050/1000

61 ^ Annuaireport of TOWN OF I1UDSON I.iGIIT AND POWER DEPARTMENT Year ended December 31.1993 STEAM GENERATING STATIONS - Continued /" expenses or revenues, and how expenses and/or revenues S. Designate any plant or equipment owned, not oper-accounts for an accounts affected. Specify iflesser, ated, and not leased to another company. If such plant er co-owner, or other party is an associate company. equipment was not operated within the past year explain

4. Designate any generstmg station or portion thereof whether it has been retired in the books of account or what leased to another company and give name oflessee, date disposition of the plant or equipment and its book cost are terms oflease and annual rent and how determined. Spe contemplated.

whether lessee is an associated company. Turbine-Generators

• Name Plate Rating Steam in Kilowatts I!ydrogen Station Pressure At at Pressure-~

Capacity Year at Minimum Maximum Power Voltage Maximum Installed Type ~ Throttle R.P.M. Ilydrugen flydrogen Factor K.v.- Name Plate p.s.Lg Pressure Pressure Min. Max. Rating-Line _pq (i) (i) (k) (1) (m) (n) (o) (p) (p) (r) No. I 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 i NOT-APPL ICA BLE 18 20 21 22 23 24 26 27 28 29 30 l 31 l 32 33 34 35 36 TOTALS 37 Note

References:

• Report cross-compound turbine-generator units on two lines - II.P. section and L.P. section

-indicate tandem-compount (T.C.); cross compound (C.C.); all single casing (S.C.); topping unit (T), and noncondensing (N.C.). Show back pressures. -Designate air cooled enerators F -~-If other than 3 phase,60 cycle, indicate other characteristic. ShonId acree with column (m)

62 Annual report of TOWN OF iTUDSON I IGFIT AND POWER DEPARTMENT Year ended December 3 L 1991 HYDROELECTRIC GENERATING STATIONS O

1. Report the information called for conceming gener-lessor, date and terms oflease, and annual rent. For any ating stations and equipment at end of year.

generating station, other than a leased station or portion

2. Exclude from tlus schedule, plant, the book cost of thereof for which the respondent is not the sole owmer but which is included in Account 121, Nonutility Property.

which the respondent operates or shares in the operation of,

3. Designate any generating station or portion thereof for which the respondent is not the sole owner. If such furnish a succinct statement explaining Ole arrangement and give particulars as to such matters as percent ownership property is leased from another company, give name of by respondent, name and co-owner, basis of sharing output, Water Wheels Name of Station Location Name of Gross Static Stream Attended or Type of Year llead With Line Unattended Unit Installed Pond Full No.

(a) (b) (c) (d) (e) (f) (g) 1 2 3 4 5 6 7 8 9 10 11 14 15 16 17 18 19 20 NOTAPP LIC A BLE 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 'llorizontal or vertical. Also indicate type of runner - Francis (F), fixed propeller (FP), automatically adjustable propeller (AP). Impulse (1).

63 Annua 1 report of TOWN OF IUTDSON 1 IG11T AND POWFR DFPARTMENT Year ended December 31.1993 IIYDROELECTRIC GENERATING STATIONS (Continued) percent of ownership by respondent, name of co-owne basis of sharing output, expenses, or revenues, and ho Specify whether lessee is an associated company. 1 expenses and/or revenues are accounted for and accou

5. Designate any plant or equipment owned. not oper-afTected. Specify iflessor, co-owner, or other part is a ated and not leased to another company. If such plant associated company.

or equ:pment was not operated within the past year explain

4. Designate any generating station or portion there whether it has been retired in the books of account or what leased to another company and give name oflessee, da disposition of the plant or equipment and its book cost are and term oflease and annual rent and how determined.

contemplated. Water-Whecis - Continued Generators TotalInstalled Maximum hp. Name Plate Number Generating Capacity of Fre-Rating of of Capacity in Kil-Design Unit at Year quency Unit in Units in owatts (name Line IIcad R.P.M. Design IIead Installed Voltage Phase or d.c. Kilowatts Station plate ratings.) No. (h) (i) (i) (k) (I) (m) (n) (o) (p) (q) 1 2 3 4 5 6 7 8 } 9 / 10 11 12 13 14 15 16 17 18 19 NOT APPL ICABLE 20 21 22 23 24 25 26 27 28 29 30 31 32 33 1 34 35 36 37 TOTAIS 39

64 Annualrepon of TOWN OF IIUDSON I IGIIT AND POWER DEPARTMENT Year ended December 31.1993 COMilUSTION ENGINE AND OTIIER GENERATING STATIONS (except nuclear stations)

1. Repon the information called for concerning gen-erating stations and equipment at end of year. Show ass propeny is leased from another company, give name of lessor, date and terms oflease, and annual rent. For any ciated prime movers and generators on the same line.

generating station, other than a leased station, or portion

2. Exclude from this schedule, plant, the book cost of thereof, for which the respondent is not the sole owner but i

which is included in Account 121, Nonutility Propeny. which the respondent operates or shares in the operation

3. Designate any generating station or ponion thereof of, furnish a succinct statement explaining the arrangement for which the respondent is not the sole owner.

and giving particulars as to such matters as percentage owner Prime Movers { Diesel or llelted j Name of lecation of Station Other Type Year 2 or 4 or Direct Line Station Engine Name of Maker Installed Cycle Connected No. (a) (b) (c) (d) (e) (f) (g) l I Cherry St Cherry Street, IIndson Diesel Norderg-MFG Co. 1951 2 Direct 2 Cherry St Cherry Street, iludson Diesel Norderg-MFG Co 1955 2 Direct 3 Cherty St Cherry Street, Iludson Diesel Norderg-MFG Co. 1960 2 Direct 4 Cherry St Cherry Street,Iludson Diesel Cooper-Dessemer 1972 4 Direct 5 6 7 8 9 10 lludson Light Cherry Street, Hud. son Diesel Fairbanks-Morse 1962 2 Direct j 11 Peaking Plt. Cherry Street, Hudson Diesel Fairbanks-Morse 1962 2 Direct 3 14 15 16 17 18 19 j 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 l

4 65 'Annualreport of TOWN OF IIUDSON LIGHT AND POWER DEPARTMENT Year ended December 31.1993 COMBUSTION ENGINE AND OTilER GENERATING STATIONS - Continued (except nuclear stations) ship by respondent, name of co-owner, basis of sharing Specify whether lessee is an associated member. output, expenses, or revenues, and how expenses and/or

5. Designate any plant or equipment owned, not oper.

revenues are accounted for and accounts affected. Specify if ated and not leased to another company. If such plant lessor, co-owner, or other party is an associated company. or equipment was not operated within the past year, explain

4. Designate any generatmg station or portion thereof whether it has been retired in the books of account or what leased to another company and give name oflessee, date disposition of the plant or equipment and its book cost are and terms oflease and annual rent and how determined.

contemplated. Prime Movers _ Continued Generators TotalInstalled Total Rated hp. Name Plate Numbers Generating Capacity ) Rated hp. of Station Year Frequency Rating of Unit of Units in Kilowatts of Unit Prime Movers Installed Voltage Phase or d.e. In Kilowatts in Station (name plate rating) Line (h) (i) 0) (k) (I) (m) (n) (o) (p) No. 4,250 4,250 1951 4,160 3 ph 60 cyl. 3,300 1 3,000 1 5,100 9,350 1955 4,160 3 ph 60 cyl. 4,000 1 3,600 2 4,250 13,600 1943 4,160 3 ph 60 cyl. 3,250 1 3,000 3 7,760 21,360 1972 4,160 3 ph 60 cyl. 5,600 1 5,600 4 5 6 7 8 9 3,168 3,168 1962 4,160 3 ph 60 cyl. 2,200 1 2,200 10 3,168 6,336 1962 4,160 3 ph 60 cyl. 2,200 1 2,200 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 k 35 36 37 38 38 TOTALS 20.550 6 19,600 39

GENERATING STATION STATISTICS (Small Stations) DE 5_ E. l. S m all g e n e r a tin g s ta tio n s, fo r th e p u rp o s e o f th is or op e rate d as a joint f acility, an d giv e a c oncise

5. If pe ak d e mand fo r 60 min ute s is not av ail-E sc h e d ule a re s te a m an d h y d r o s ta tie n s o f te ss th a n sta te me nt o f th e f a cts in a fo o m o te.

2,50t1 K W

• a n d o th e r s ta tio n s o f le a s th a n 4 n0 K W
• able, give that which is av ailable. specifying pe riod.

in s talle d e s p a c ity (n a m e p la te ra tin g s ). (* 10,00 0 K W

3. List pla n ts ap p ro priate ly u n d e r su bh e adin g s for

6. If any plant is e quipp e d with combinations o f ste am, hy drn, n u cle ar in te rn al c omb u stio n e n g in e an d a n d 2,5 00 K W, r e sp e c riv e ly, if an n u al e le c tric o p e ra t-g a s tu r b in e s ta tio n s. ro r n u cle a r. s e e in s tr u c tio n 10 ste am, hy dro, intern al c o mbustion e ngine or g as tur-

"'s in g r e v e n u e s o f r e s p o n d e n t a r e s 2 5,0 00,000 o r mo r e.) pag e 59. bine e quipment, e ach abould be re porte d as a se parate H

2. D e sig n ate any plan t le a se d fro m o th e rs, op e rate d

4. Sp e cify, if to tal plant c a p acity is re po rte d in k v a plan t. llow e ve r, if the e t h eust he at from the g as h

u n de r a lice n se from th e Fe d e ral P ow e r C o mmissio n, in s te a d o f k ilo w a tts. turbin e is u tiliz e d in a ste am tu rbin e re g e ne rativ e fe e d ,,g, ,g,,,, ,,,, g, p, Z g o m Fuel Cost E Installed Plant Production Expenses Per KWII 8 Capacity Peak Generation Cost \\ Exclusive of Depreciation Net Name Demand Excluding Per KW and Taxes Kind Generation Name of Plant Year Plate KW Station Cost of Plant Ins. (Omit Cents) of (Cents) gr Line Const. Rating-KW (60 Min.) Use (Omit cents) Capacity Labori Fuel Other Fuel (0.0000) y No. (a) (b) (c) (d) (c) (f) (g) (h) (i) (j) (k) (1) 1 2 3 m 4 o 3 i% 6 7 O rn m N 1 11 a 12 g 13 14 NOT A P P LIC A B LE 15 16 17 g 18 9, 19 n:s 20 21 22 O p, 23 8 24 I 25 m 26 ~ 27 G e 28l TOTALS O O O-

m-67 i Annualreport of TOWN OF TR1DSON I,IGifT AND POWER DEPARTMENT Year ended December 31.1993 TRANSMISSION LINE STATISTICS Q Report information concerning transmission lines as indicated below. Nj Designation Type of length (Pole miles) Size of Operating Supporting On Structures of On Structures of Number of Conductor Line From To Voltage Structure Line Designated Another Line Circuits and Material No. (a) (b) (c) (d) (e) (f) (g) (h) 1 Marlboro-Ifudson Forest Avenue 336.4 MCM 2 Town lines Substation, 115 KV Steel poles 3.2 2 ACSR 3 at River Street fludson " Linnet" 4 5 6 } 7 ) 8 9 10 11 12 13 14 15 16 17 18 19 r] 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 1 37 38 39 40 41 42 43 44 45 i 46 i b TOTAI,5 3.2 None 2 47 'Where other than 60 cycle,3 phase, so indicate.

SUBSTATIONS i E a a Report below the mform ation e nDed for concerning substations 4.Indiente in column (b)the functiowic he rec ter of esch s ab-fessen of sole ownership by the respondent. For any substetie t or k of the respondent es of the end of the year. statien designstmg whether transmission or destnbution a nd whether eq lease and annust rent. For any substation or equipra ent operste*ipm ent ope 2 Subs'ations which serve but one industria tor street railwey attended orunattended. of y eustom e r should riot be be te d he reunder

5. show in c olum ns fi). rj), a nd (k) spe cial e quipm e n t suc h as other than by reasons of sole ownership or lesse, giee nem e of ee-e wner

3. Substations eth especiry of Sss than 5.000 ke s.excep those retary conv erters.rectiners.conde nsers,etc..ond suntiary equipment or other party, esplein basis of sharing expenses of other eccevntirts serv s g custom ers eth energy for resak.n.ny be g rmaped a ccordmg from meressmg espacity.

betw een the parties, and state em ounts and secounts affected ar'or. O g to fianctmnalc haracter,but the nism ber et such s ubstations m mt

6. Designate substations cr m ajoritem s of ertiespm ent leesed from re ondent s book of eccount S pec fy in esch se whether less

• e s hown.

ethers.rintly owned with others.or ope rated othermse than by ]O Capacity of Number Number Conversion Apparatus and Character Voltage Substation of Trans-of Sparc Special Equipment Name and Location of Second-In kva formers Trans-Type of Number Total Line of Substation Substation Primary ary Tertiary (In Service) In 5ervice formers Equipment of Units Capacity h No. (a) (b) (c) (d) (c) (f) (g) (h) (i) (j) (k) r.n 1 Cherry Street, llodson, MA Unattended 80001 24001 Not Brought 19,200 2 None None None None O 2 Distribution 13800 4160 Out 3 t~ 4 O 5 Forest Avenue, Hudson, MA Unattended 4 6 13.8 Distribution >g 7 & Dicsci Tic 115 KV 80001 NA 80,000 2 None None None None 8 Tic with NEPCO 13800 o b 10 y 11 0 12 13 I4 15 p 16 17 18 19 20 21 22 4 23 8 ~ n 24 g, 25 g, 26 0 27 0 '8 3 er 29 4 30 w 31 -e 32 TOTALS 99,200 4 None None None None w

69 Annualreportof TOWN OF IIITDSON LIGliT AND POWER DEPARTMENT Year ended December 31.1991 OVER!!EAD DISTRIBUTION LINES OPERATED Line length (Pole Miles) No. Wood Poles Steel Towers Total 1 Miles - Deginning of Year 181.5 181.5 2 Added During Year 0.3 0.3 j 3 Retired During Year None None 4 Miles - End of Year 181.8 181.8 5 6 7 Distribution System Characteristics - A.C. or D.C., phase, gcles and operating voltages for Light and Power. 8 9 10 Primary distribution at 2400/4160Y,4800/8300Y,800'J/13800Y volts,60 cycle, 11 3 phase secondary power at 600 volts,60 cycle,3 phase 3 wire; 480 volts 3 ) 12 phase,3 wire; 277/480 volts,3 phase 4 wire; 220 volts,3 phase 3 or 4 wire; 13 120/208 volts, 3 phase, 4 wire lighting, heating and air conditioning 14 120/240 colts,120/208 volts,60 cycle single or three phase. 15 \\ ELECTRIC DISTRIBUTION SERVICES, METERS AND LINE TRANSFORMERS Line Transformers Number of Total Line Electric Watt-Ilour Capacity No. Item Services Meters Number (kva) 16 Ntuuber at begirming of year 7,758 10,637 3,163 91,531.5 17 Added during year: 1 l 18 Purchased 201 131 5,145.0 19 Installed 84 20 Associated with utility plant acquired None None None 21 Total additions 84 201 131 5,145.0 22 Reductions during year: 23 Retirements 38 150 12 170.0 24 Associated with utility plant sold None None None None 25 Total reductions 38 150 12 170.0 26 Ntunber at End of Year 7,804 10.688 3,282 96,506.5 4 27 la stock 617 425 17,363.0 28 Locked meters on customers' premises None None None 29 Inactive transformers on system None None None 30 In customers' use 10,046 2,849 79,009.5 31 In company's use 25 8 134.0 32 Number at End of Year 19 633 3 792 96.506 5 1 \\

CONDUlT, UNDERGROUND CABLE AND SUBMARINE CABLE -(Distribution System) fS Report below the information called for concerning conduit, underground cable, and submarine cable at end of year. Miles of Conduit Underground Cable Submarine Cable Bank ( All Sizes Operating I Line Designation of Underground Distribution System and Types) Miles

• Operating voltage Feet
• Voltage

[ No. (a) (b) (c) (d) (e) (f) 0 1 Route 495 Underpass 0.10 0.10 13,800 f 2 Harvard Acres Estates, Stow 6.50 6.50 13,800 3 Meadowbrook Mobile Home Park, Hudson 1.80 1.90 13,800 0 's 4 Colbum and Margaret Circle, Hudson 0.00 0.20, 4,800 5 Main, Felton and Central Street, Hudson 0.70 0.70 13,800 E 6 Seven Star Lane, Stow 0.00 0.09 4,800 o 7 Forest Avenue, Hudson 1.50 1.50 13,800 Z 8 Juniper Estates, Stow 0.50 0.50 13,800 C 9 Carriage Lane, Stow 0.19 0.33 4,800 9 10 Brigham Circle,Iludson 0.90 0.90 13,800 5 11 Rustic Lane, Hudson 0.00 0.20 4,800 12 Wildwood Subdivision, Stow 0.00 0.60 13,800 C 13 Birch Hill Estates, Stow 3.60 3.60 13,800 g 14 Appleton Drive, Hudson 0.10 0.10 13,800 g 15 Cedar Strect, Hudson 0.03 0.03 4,800 16 Country Estates, Hudson 0.00 0.34 4,800 x a 17 Deacon Benham Drive, Stow 0.00 0.07 8,320 Ig 18 Forest Road, Stow 0.00 0.22 8,320 g 19 Francis Circle, Stow 0.00 0.10 4,800

j 20 Karen Circle, Hudson 0.00 0.07 8,320 F;j 21 Main Street, Hudson OVhispering Pines) 0.11 0.11 13,800 22 Glen Road, Hudson 0.24 0.24 13,800 23 Brigham Street, Hudson (Valley Park) 0.14 0.14 13,800 24 Brigham Street, Hudson (Assabet Village) 0.23 0.23 13,800 25 Chapin Road, Hudson 0.07 0.07 13,800 26 Cahill Raylor Road, Stow 0.25 0.25 13,800 27 Great Road, Stow 0.07 0.07 13,800 Q

28 Kane Industrial Drive, Hudson (Digital) 0.05 0.05 13,800 g 29 Peter's Grove, Hudson 0.05 0.05 13,800 g 30 Johnston Way, Stow 0.20 0.20 13,800 a 31 Hudson Town Hall, Hudson 0.08 0.08 13,800 Q 32 Sudbmy Road, Stow (OIT Pole 121) 0.23 0.23 13,800 9 33 Parmenter Road, Hudson (Off Pole 16-1) 0.10 0.10 13,800 ( 34 TOTALS 17.74 19.87 None None s

• Indicate number of conductors per cable.

h

c~ Z CONDUIT, UNDERGROUND CABLE AND SUBMARINE CABLE -(Distribution System) d Report below the ir: formation called for concerning conduit, underground cable, and subn.arine cable at end of year. Miles of Conduit Underground Cable Submarine Cable h Bank ( All Sizes Operating Line Designation of Underground Distribution System and Types) Miles

• Operating Voltage Feeta Voltage

~' No. (a) (b) (c) (d) (e) (f) o 1 Icchnology Dnve, Iludson 0.28 0.28 1.3,800 2 Reed Road, Hudson

0. I 1

0. I 1 13,800 Z

3 Central St. Hudson 0.06 0.06 13,800 4 Washington St., Hudson 0.10 0.10 13,800 5 Barton Road, Stow 0.26 0.26 13,800 6 Causeway St. Hudson 0.12 0.12 13,800 g 7 Off Harvard Rd., Stow 0.07 0.07 13,800 z 8 Off River Rd. Hudson 0.05 0.05 13,800 t 9 Hazelwood Drive, Hudson 0.24 0.24 4,160 9 10 Maura Drive, Stow 0.19 0.19 13,800 4 11 Shay Rd. Hudson 0.07 0.07 13,800 2;; 12 Ashford Meadows, Hudson 0.99 0.99 13,800 6 13 Indian Ridge Estates, Hudson 1.31 1.31 13,800 u 14 Boxmill Rd., Stow 0.13 0.13 13,800 O 15 Brigham Estates, Hudson 0.61 0.61 13,800 b 16 October Lane, Stow 0.24 0.24 13,800 17 Santos Drive, Hudson 0.12 0.12 8,320 E 18 Kerrington Way, Stow 0.07 0.07 13,800 g 19 Bennett St., Hudson 0.39 0.39 13,800 g 20 Solo Rd., Hudson 0.28 0.28 13,800 g 21 Cabot Rd., Hudson 0.22 0.22 13,800 g 22 Beechnut Rd., Hudson 0.14 0.14 13,800 23 Bocazzoli Ave.,Iludson 0.16 0.16 13,800 24 Red Acre Estates, Stow 1.08 1.08 13,800 25 Merritt Drive, Iludson 0.09 0.09 13,800 26 Orchard Drive, Hudson 0.50 0.50 13,800 27 Annie Terrace Drive, Hudsor. 0.20 0.20 13,800 g 28 Heath Hen Trail, Stow 0.26 0.26 13,800 29 Appleblossom Lane, Stow 0.34 0.34 13,800 1 30 Walmart, Hudson. 0.97 0.97 13,800 31 Blueberry Lane, Hudson 0.58 0.58 13,800 0 32 Stow Farms, Stow 0.86 0.86 13,800 0 33 Forance Woods, Hudson 0.21 0.21 13,800 h 34 TOTALS 11.30 11.30 None None }

• Indicate number of conductors per cable, jy

71 ~ Annualreport of TOWN OF IIITDSON I.IGiiT AND POWER DEPARTMENT ' Year ended December 31 1991 STREET LAMPS CONNECTED TO SYSTEM City Type or Total Incasdescent Mercury Vapor Fluorescent II. P. Sodium Line Town Municipal Other Municipal Other Municipal Other Municipal Other No. (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) 1 Iludson 1,912 389 15 909 233 242 124 2 Stow 77 4 2 7 35 19 10 3 13erlin 1 1 4 Marlboro 4 1 3 5 floiton 1 I 6 7 ) 8 9 10 11 12 13 14 15 16 17 18 19 20 O 21 V 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 i 41 42 43 44 45 48 49 50 51 52 TOTAI. 1995 39.1 17 916 270 261 137

5 79 Annuaireport of TOWN OF HIIDSON f IGIIT AND POWER DFPARTMENT Year ended December 31 1993 RATE SCHEDULE INFORMATION

1. Attach copies of all Field Rates for General Consumers.

2. Show below the changes in rate schedule during year and the estimated increase or decrease in annual revenue predicted on the previous year's operations.

Estimated Date M.D.P.U. Rate Effect on Effective Number Schedule Annual Revenues increases Decreases 09/01/92 140 Domestic Rate "A" f i 09/01/92 141 Commercial All Electric Rate "G" 09/01/92 142 Commercial and Industrial Rate "D" 09/01/92 143 Residential Water Heater Rate "E" 09/01/92 144 Residential All Electric Rate "F" 09/01/92 145 General or Commercial Rate "C" 09/01/92 146 Street Lighting Schedule 09/01/92 147 Power Adjustment Charge N/C O l (s \\ i w

P W. Annuaireportof TOWN OF HUDSON LIGifT AND POWER DEPARTMENT Year ended December 31,1993 s THIS RETURN IS SIGNED UNDER THE PENALTIES OF PER Mayor M HORST HUEHMER Manager ofElectric Light 1 .I-~P IE' ~ ) Selectmen or sy-Members PF ER R. KEANE ofthe A Mmicipal Light Board [ / 3 O SIGNATURES OF ABOVE PARTIES AFFIXED OUTSIDE THE C MASSACHUSETTS MUST BE PROPERLY SWORN TO 1 ss 19 Then personally appeared and severally made oath to the truth of the foregoing statement by them subscri and belief C Notary Public or v Justice ofthe Peacc. u .m

h. c. INDEX Prge y Appropriations of Surplus 21 Appropriations Since Beginning of Year 5 Bonds 6 y Cash Balances 14 / Changes in the Property 5 Combustion Engine and Other Generating Stations 64 65 Comparative Balance Sheet 10 11 Conduit, Underground Cable and Submarine Cable 70 Cost of Plant 89 Customers in Each City or Town 4 Depreciation Fund Account 14 Earned Surplus 12 Electric Distribution Services, Meters and Line Transformers 69 Electric Energy Accotm,ts 57 Electric Energy Purchased 22 ) Electric Operating Revenues 37 1 Electric Operation and Maintenance Expenses 39-42 GeneralInformation 3 Generating Station Statistics $8-59 Generating Station Statistics (Small Stations) 66 Ilydroelectric Generatirig Stations 62-63 lacome from Merchandising, Jobbing and Contract Work 51 lacome Statement 12-13 Materials and Supplies 14 Miscellaneous credits to Surplus 21 Miscellaneous Debits to Surplus 21 Miscellaneous Nonoperating Income 21 Monthly Peaks and Output 57 Municipal Revenues 22 Other Income Deductions 21 Other Utility Operating income 50 Overhead Distribution Lines Operated 69 Production Fuel and Oil Stocks 18 Rate Schedule information 79 Sales of Electricity to Ultimate Constuners 38 Sales for Resale - Electric 22 Schedule of Estimates 4 Steam Generating Station 60-61 Street Lamps 7i Substations 68 Taxes Charges During Year 49 Town Notes 7 Transmission Line Statistics 67 Utility Plant - Electric 15-17 1 FOR GAS PLANTS ONLY: Page Boilers 75 Gas Distribution Services and IIouse Governors and Meters 78 I Gas Generating Plant 74 Gas Operating Revenues 43 Gas Operation and Maintenance Expenses 45-47 lloiders 76 Purchased Gas 48 Purifiers 76 -{+ Record of Sendout for the Year in MCF 72-73 Sales for resale 48 Sales of Gas to Ultimate Consumers 44 a Sales of residuals 48 scrubbers, Condensers and Exhausters ' 75 Transmission and Distribution Mains 77 l

/1 F ~ ' O SECURITIES AND EXCHANGE COMMISSION WASIIINGTON, D.C. 20549 oV Form 10-K (Mark One) j [X] ANNUAL REPORT PURSUANT TO SECT 10N 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31.1993 OR [] TRANSITION REPORT PURSUANT TO SECHON 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACTOF 1934 (NO FEE REQUIRED) Commission File Number 33-10978 j GREAT BAY POWER CORPORATION (f.k.a. EUA Power Corporation) (Exact name ofregistrant as specified in its charter) Debtor and Debtor-in-Possession under Chapter 11 of the Bankruptcy Code New Hampshire 02 - 0396811 (State or otherjurisdiction of (1.R.S Employeridentification No.) imnrporation or organization) Forty Stark Street, P.O. Box 326 Manchester, N.H. 03105 (Addicss ofprincipal exewtise ollices) (Zip Code) Registrant's telephone number, including area code: (617)357-9590 v Securities registered pursuant to Section 12(b) of the Act: litle ofeach Cass Name ofeach Erchange on whkh registered None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes _/_ No Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is j not contained herein, and will not be contained to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K. M State the aggregate market value of the voting stock held by non-affiliates of the registrant. As of March 1,1994: None Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. ) Common Shares Outstanding at March 1,1994 4 None O Documents Incorporated by Reference None I

GREAT BAY POWER CORPORATION, Debtor and Debtor-in-Possession rN ('--) 1993 Annual Report on Form 10-K Table of Contents i PART I \\ Page Table of Contents. (i) Glossary of Defined Terms. (iii) Item 1. BUSINESS 1 ( General 1 Bankruptcy Proceeding. 2 Marketing. 7 Power Purchase Agreement and Power Purchase Option. 7 Competition. 9 Construction Program. 9 Nuclear Power Issues. 10 Public Utility Regulation. 12 Environmental Regulation. 12 Energy Policy. 13 (} Item 2. PROPERTIES. 13 Item 3. LEGAL PROCEEDINGS. 13 Bankruptcy Proceeding. 13 SEC Review. 14 Other Proceedings. 14 l Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. 15 i l PART II l Item 5. MARKET FOR REGISTRANTS' COMMON STOCK AND RELATED SHAREHOLDER MATTERS. 15 Item 6. SELECTED CONSOLIDATED FINANCIAL DATA............... 16 i 4

1. ~

9 (,_-) (i)

PART II (Cont'd) Page Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF 3 FINANCIAL CONDITION AND RESULTS OF OPERATIONS. \\16 Overview. 16 Power Purchase Agreement and Power Purchase Option. 19 Comparison of Financial Results. '20 Operating Revenues. 20 Expenses. 21 Financial Condition and Liquidity.... 22-Nucicar Fuel Disposal and Nuclear Plant Decommissioning Costs. 24 Changes in Accounting Standards. 25 Other. 25 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 26 Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 26 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS. 26 Item 11. EXECUTIVE COMPENSATION. 28 ,-sg Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. 28 (a) Security Ownership of Certain Beneficial Owners. 28 (b) Security Ownership of Management. 28 Item 13. Certain Relationships and Related Transactions. 28 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDOLES REPORTS ON FORM 8-K. 28 Exhibits. 29 Reports on Form 8-K. 32 Signatures. 33 Financial Statements. 35 Notes to Financial Statements. 40 Supplementary Schedules... 54 Report of Independent Accountants.. 58 M.- f"% t (ii) s

GLOSSARY OF DEFINED TERMS iv 1 The following is a glossary of frequently used abbreviations or acronyms found throughout this report: ) The EUA System Companies EUA Eastern Utilities Associates EUA Power EUA Power Corporation, now known as Great Bay Power Corporation EUA Service EUA Service Corporation EUA System EUA and Subsidiary Companies Montaup Montaup Electric Company l Companies Company Great Bay Power Corporation Great Bay Great Bay Power Corporation Registrant Great Bay Power Corporation CL&P Connecticut Light & Power Company UI United Illuminating l UNITIL UNITIL Corporation Regulators /ReRulations (j\\ 1935 Act Public Utility Holding Company Act of 1935 Bankruptcy Court United States Bankruptcy Court for the Di;trict of New Hampshire' DOE Department of Energy Energy Act Energy Policy Act of 1992 EPA Federal Environmental Protection Agency FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission NHIDA Industrial Development Authority of the State of New Hampshire NHPUC New Hampshire Public Utility Commission NRC Nuclear Regulatory Commission NWPA Nuclear Waste Policy Act Price Anderson Act The Price-Anderson Act, as amended by the Price-Anderson Act amendments of 1980 PURPA Public Utility Regulatory Policies Act of 1978 SEC Securities and Exchange Commission (iii) f*'% (_-)

GLOSSARY OF DEFINED TERMS (Cont'd) OU The following is a glossary of frequently used abbrevigtions or acronyms that are found throughout this report: Other + AFUDC Allowance for Funds Used During Construction Bondholders Committee Officially Appointed Bondholders' Committee or Committee Representing Holders of EUA Power's ~ Series B and Series C Secured Notes s CICs Contingent Interest Certificates Confirmation Date The date of Confirmation of the Fif th Amended Plan of Reorganization as modified by the First Modification thereto DIP Financing Debtor-in-Possession Financing Effective Date Effective Date of the Fifth Amended Plan of Reorganization as modified by the First Modification thereto as filed by the l Bondholders Committee EWG Exempt Wholesale Generator FAS96 FASB Statement No. 96 " Accounting for Income Taxes" A FAS109 FASB Statement'Nc. 109 " Accounting for U Income Taxes" IPPs Independent Power Producers, JOA Joint Owner Agreement Among Owners of the 1 Seabrook Project l MW Megawatt NEP00L New England Power Pool Participating Joint Owners U1 and CL&P, pursuant to the DIP financing j Plan The Fifth Amended Plan of Reorganization i as modified by the First Modification j thereto QFs Qualifying cogeneration and small power production facilities Seabrook Interest The Company's right, title and interest in and to its 12.1324% interest in the t Seabrook Project i Seabrook Project Seabrook Nuclear Power Project Seabrook Unit 1 Seabrook Nuclear Generating Station Unit 1 Seabrook Unit 2 Seabrook Nuclear Generating Station Unit 2 Secured Notebolders Holders of the Secured Notes j Secured Notes EUA Power's 17.50% Series B and Series C Secured Notes due May 15, 1993 and November 15, 1992, respectively. Settlement Agreement Settlement Agreement dated November 18, 1992, Among EUA Power, EUA and the Bondholders Committee p (iv)

PART I b(% Item 1. BUSINESS s General \\ The Registrant, Great Bay Power Corporation (formerly known as EUA Power Corporation), is a New Hampshire corporation, incorporated in 1986, authorized by the NHPUC to engage in business as a public utility for the purposes of participating as a joint owner in the Seabrook Project, acquiring its 12.1% interest in the Seabrook Proj ect and selling its share of the output of Seabrook Unit 1 for resale. The Company, organized as a wholly-owned subsidiary of EUA, became fully independent of EUA on February 5, 1993 in connection with the bankruptcy proceeding described below. The Company became a wholesale generating company when Seabrook Unit 1 commenced commercial operation on August 19, 1990. On February 28, 1991, the Company filed a voluntary petition in the Bankruptcy Court for the District of New Hampshire for protection under Chapter 11 of the Bankruptcy Code. The Bankruptcy Court confirmed the Bondholders Committees' Fifth Amended Plan of Reorganization on March 5, 1993. After confirmation, the Company was unable to obtain the $45 million of debt financing contemplated by the Fifth Amended Plan of Reorganization. In February 1994, however, the Bondholders Committee obtained a commitment from Omega Advisers, Inc. (" Omega") or its designees to provide $35 million of equity financing for the Company (the " Omega Financing"). The Bondholders Committee prepared a First Modification to Fif th Amended Plan of Reorganization to reflect this change in financing and submitted a Supplemental Disclosure v Statement describing that First Modification to the Bankruptcy Court for its approval. The Fifth Amended Plan of Reorganization, as modif,ied by the First Modification is hereinaf ter referred to as the " Plan." The Bankruptcy Court approved the Supplemental Disclosure Statement at a hearing on March 11, 1994. The Plan is scheduled to be mailed to the Company's creditors for their approval on or before April 7, 1994. If the Creditors approve the Plan, the Company expects the Bankruptcy Court to confirm the plan in a hearing currently scheduled for May 13, 1994, although such confirmation cannot be assured. The Omega Financing and the Plan are subj ect to approval by certain regulatory authorities. On February 15, 1994 the Nuclear Regulatory Commission issued an order approving a transfer of control of the Company as contemplated by the Omega Financing and extending the deadline for completion of such transfer to June 30, 1994. There can be no assurance that other such approvals will be obtained. Moreover, the Omega Financing is not yet reduced to a definitive agreement. The Plan will not be circulated to creditors unless and until such a definitive agreement has been signed. The Omega Financing provides for the Company to sell its common stock representing a 60% ownership interest in the Company to Omega or its designees for an aggregate purchase price of $35 million. The 40% balance of the Company's common stock will be issued 34% to the Company's Bondholders in full payment and satisfaction of their secured c ims and 6% to the Company's unsecured creditors with claims in excess cf $25,000 in full payment and satisfaction of their claims. These unsecured claims consist primc.rily of the unsecured deficiency claims of-the Bondholders under the Bonds. (See qV 1 i

Bank ruptcy Proceedinn below for a discussion of the Company's bankruptcy proceeding and the Omega Financing.) Seabrook Unit 1 is a 1,150 MW nuclear generating plant located in Seabrook, New Hampshire. The Company acquired its joint ownership interest in the Seabrook Project for approximately $174,000,000 in November 1986 fro'm five New England electric utilities in independently negotiated transactions. At I that time, construction of Seabrook Unit I was substantially completed. Because Seabrook Unit 2 had _ been cancelled, the Company assigned no value to it. On March 29, 1991, the Company announced that it had provided an ) impairment reserve in 1990 against its investment in Seabrook Unit 1. At i December 31, 1993, the Company's net investment in Seabrook Unit 1 including nuclear fuel, was approximately $312 million. The Company has no employees. John R. Stevens, president of EUA, serves as president and sole director of the Company at the request and subject to the direction of the Bondholders Committee. Mr. Stevens expects to resign both positions on the Effective Date. Since the Company's organization, EUA Service, a wholly owned subsidiary of EUA, has provided, or arranged for, various management and professional services. Pursuant to various Bankruptcy Court orders, EUA Service continues to provide similar services to the Company. Under the terms of the Settlement Agreement (as discussed below), EUA Service will continue to provide, at cost, certain services to the Company at the request of the Bondholders Committee for a period of not more than two years from the effective date of the Settlement Agreement. However, such services specifically exclude the marketing of the Company's entitlement in Seabrook Unit 1 on a long-term basis. The Company has agreed with UNITIL that an affiliate of UNITIL will replace EUA Service in providing various services - O on the Effective Date. In addition, the Company has entered into a contract with an affiliate of UNITIL pursuant to which that affiliate is marketing the Company's share of electricity from Seabrook Unit 1. Bankruptcy Proceedinn

Background:

On February 28, 1991, the Company filed a voluntary petition in the Bankruptcy Court for the District of New Hampshire for protection under Chapter 11 of the federal Bankruptcy Code and has been conducting its business as a Debtor and Debtor-in-Possession under the provisions of the Bankruptcy Code. The Company filed such petition because the cash generated by short-term sales i of electricity from its entitlement in Seabrook Unit 1 would have been insufficient to pay interest on its outstanding Secured Notes when interest became due on May 15, 1991 and the prospects for signing long-term power sales contracts prior to that date were minimal. The Co' pany continues its efforts m to market its entitlement to Seabrook Unit 1 under the direction of the i Bondholders Committee. Settlement Agreement: On November 18, 1992, the Company, the Bondholders Committee and EUA entered ' 'into a ' Settlement Agreement which' resolved certain adversary proceedings against EUA.

brought, or threatened to be brought, by the Bondholders Committee including, (i) a claim for recovery of certain alleged preferential transfers in the aggregate amount of $38.5 million, plus interest; 2

1

(ii) a threatened claim for the recovery of $100 million plus treble damages arising from, among other things, certain alleged breaches of fiduciary duties (- by EUA, EUA Service and the officers and directors of the Company; and, (iii) certain matters arising out of tax sharing agreements between EUA. its subsidiaries, and the Company. The Settlement Agreement also provided.for the payment of $20 million to the Company by EUA. The Settlement Agreement 'further provided for the relinquishment by EUA of its equity interest in the Company and all claims filed in Bankruptcy Court by EUA and its affiliates against the Company. These claims related primarily to obligations of the Company guaranteed and paid by EUA. including $21 million of Solid Waste Disposal Facility Revenue Bonds, issued by the New Hampshire Industrial Development Authority on behalf of the Company and other notes payable. The settlement of these claims was recorded as a deferred credit on the Company's 1992 Balance

Sheet, pending the ultimate outcome of the Bankruptcy Proceeding.

The Settlement Agreement became effective on December 30, 1992 at which time EUA paid $20 million to the Company. The Company used a substantial portion of the proceeds from the Settlement Agreement to repay amounts outstanding under the First Stipulation (as described below) and to pay reorganization expenses and other operating expenses. The Company redeemed all of its outstanding equity securities which were held by EUA, at no cost, on February 5, 1993. The redeemed shares have been classified as treasury stock on the Company's financial statements as of December 31, 1993 and 1992. As a result of the redemption, the Company is no longer part of the EUA System. Under the Settlement Agreement, EUA reaffirmed its guarantee of up to $10 million of the Company's share of future decommissioning costs of Seabrook Unit 1 and any costs of cancellation of Seabrook Unit 1 or Unit 2. EUA had guaranteed this obligation in 1990 in order to secure the release to the Company of a $10 million fund established by the Company for the same purpose at the time the Company acquired its Seabrook Interest. Further, under the Settlement Agreement, all of the officers and directors of th,e Company (except Mr. Stevens) resigned and the Company changed its name to Great Bay Power Corporation. EUA now has no ownership interest in the Company. Reorganization Plan: The Bankruptcy Court confirmed the Bondholders Committees Fifth Amended Plan of Reorganization on March 5, 1993. After confirmation, the Company was unable to obtain the $45 million of debt financing contemplated by the Fif th Amended Plan of Reorganization. In February 1994, however, the Bondholders Committee obtained a commitment from Omega or its designees to provide $35 million of equity financing for the Company. The Bondholders Committee prepared a First Modification to Fifth Amended Plan of Reorganization to reflect this change in financing and submitted a Supplemental Disclosure Statement describing that First Modification to the Bankruptcy Court for its approval. The Bankruptcy Court approved the Supplemental Disclosure Statement at a hearing en March 11, 1994. The Plan is scheduled to be mailed to the Company's creditors for their approval on or before April 7, 1994. .lf the Creditors approve the Plan, the Company expects the Bankruptcy Court to confirm the Plan in a hearing currently scheduled for May 13, 1994, although such confirmation cannot be assured. The Omega Financing and the Plan are subject to approval by certain regulatory authorities. On February 15, 1994 the Nuclear Regulatory Commission issued an order approving a transfer of control of the Company as contemplated by the Omega Financing and extending the n I deadline for completion of such transfer to June 30, 1994. There can be no 3 l

-4+ Du -i--J S-rLi+- -s-- 2 5 s assurance that other such approvals will be obtained. Moreover, the Omega Financing is not yet reduced to a definitive agreement. The Plan will not be O circulated to creditors unless and until such a definitive agreement has been signed. g The Omega Financing provides for the Company to sell its comrpos stock representing a 60% ownership interest in the Company to Omega or its designees j for an aggregate purchase price of $35 million. The 40% balance of the Company's common stock will be issued 34% to the Company's Bondholders in full payment and satisfaction of their secured-claims pursuant to the Bonds zand 6% to the Company's unsecured creditors with claims in excess of $25,000 in full payment and satisfaction of their claims. These unsecured claims consist primarily of the unsecured deficiency claims of the Bondholders under the Bonds. The holders of unsecured claims of less than $25,000, other than those unsecured claims resulting from the ownership of the Secured Notes, will be paid 50% of the amounts of their claims allowed by the Bankruptcy Court in cash on the Effective Date. The Plan requires that prior to the Effective Date the Bondholders Committee obtain the Omega Financing. Although a bar date for all claims has been entered and passed, claims arising from the rejection of contracts or claims which the Bankruptcy Court permits to be filed notwithstanding the bar date may dilute the percentage of s the unsecured claims held by the Secured Bondholders. All of the previously issued and outstanding equity securities of the Company have been redeemed by the Company. The CICs issued in connection with the Series B Notes or. otherwise will be extinguished on the Effective Date. After the Effective Date, the equity of the Company will be represented by a singic class of. common stock. The Company will use good faith efforts to list its shares of common stock so that they will be tradeable on the American Stock Exchange or the NASDAQ National Market System. The Bondholders Committee has appointed or will appoint ' agents to. manage the Company's business and to market the Company's share of Seabrook electricity. During the period between the Confirmation of the Plan and the Effective Date, those agents are to report to the Bondholders Committee and, to the extent-actions are to be taken outside of the ordinary course of business, such actions shall be subject to the approval of the Bankruptcy Court and regulatory bodies with jurisdiction under applicable law. John R.

Stevens, president of EUA, expects to resign as president and director of the Company on the Effective Date. The Bondholders Committee has disclosed the names of two individuals proposed to serve on the Board of Directors (the New Board) of the Company after the Effective Date.

The proposed two members of the New Board are John A. Tillinghast and Walter H. Goodenough. The Bondholders Committee is also considering other candidates to serve as members of the New Board. The persons who will serve on the New Board will be finally determined before the Effective Date. The New Board will take' office upon the Effective Date. The New Board will serve until its members resign or are, replaced in accordance with New Hampshire corporate law and the requirements of the Company's charter and.by-laws. The effectiveness of the Plan is conditioned upon obtaining plan of reorganization-financing and approvalo. from various regulatory agencies [ including the NRC. The% Company has obtained the approval of the NEC, provided the Company obtains plan. of reorganization financing. The Company cannot predict whether it will be able to obtain plan of reorganization financing or 4 -v - = - - - -

whether the plan, or any other plan if filled, will be approved by the various regulatory agencies having jurisdiction. (~N DIP Financing:

s The Company is required under the JOA to pay its share of SeabropkiUnit 1 and Seabrook Unit 2 expenses including, without limitation, operations and maintenance

expenses, construction and nuclear fuel expenditures and decommissioning costs, regardless of Seabrook Unit l's operations.

Under certain circumstances, a failure by the. Company to make its monthly payments under the JOA could adversely affect its entitlement in Unit 1. At current market prices, the cash generated by such electricity sales continues to be less than the Company's on going cash requirements. On August 29, 1991, the Bankruptcy Court approved a Stipulation and Consent order (the First Stipulation) with respect to DIP Financing to be provided by certain joint owners of Seabrook for the benefit of the Company. The First Stipulation was entered into by the Company and CL&P and UI (the Participating Joint Owners), two of the other eleven joint owners of the Seabrook Project, as well as the Bondholders Committee. The "irst Stipulation was also approved by the NHPUC and the SEC under the 1935 Act. On July 21,

1992, the Bankruptcy Court issued a procedural order permitting an extension of the First Stipulation.

For the period after September 30, 1992 until March 5,

1993, the procedural order permitted continued debtor-in-possession financing on a month-to-month basis at the sole discretion of the Participating Joint Owners terminable on 30 days notice.

The Bankruptcy Court issued a second procedural order on September 8, 1992 increasing to $22 million from $15 million the amount of advances outstanding ( at any one time permitted under the First Stipulation. The Participating Joint owners continued to advance funds under the First Stipulat,lon, as amended, until the amounts advanced thereunder were repaid with the proceeds of the Company's Settlement Agreement with EUA. The First Stipulation expired on March 5, 1993. A second stipulation was entered into by the Company and the Participating Joint Owners and was approved by the Bankruptcy Court and various regulatory authorities. However, that stipuletion did not become effective, and en March 5, 1993, the Company and the Participating Joint Owners entered into a third stipulation (the Third Stipulation) which was approved by the Bankruptcy Court. The Third Stipulation provides that the Participating Joint owners shall provide up to a maximum of $20 million in advances to the Company to enable the Company to pay its nro rata share of the Seabrook Project's operating expenses, expenses of the Company in connection with its Chapter 11 proceedings and certain other costs of operation of the Company. Pursuant to the Third Stipulation, the advances made by the Participating Joint Owners bear an interest rate equal to the prime rate of The First National Bank of Boston plus 7% per annum. The Third Stipulation provides the. Participating Joint Owners with a priority lien on all the Company's assets, which lien has priority over the Bondholders' mortgage. The Third Stipulation further provides that in the event of a default thereunder, the Participating Joint owners are entitled to purchase the Company's,Seabrook Interest for 75% of the lesser of fair market value er book value and t.o apply all or part of the amounts ewing under the Third Stipulation against the purchase price. The Third Stipulation terminates v 5

7 on the earliest to occur of (a) July 1, 1994 (b) the Effective Date or the closing of a sale of all or substantially all of the Company's assets or .Q

business, and (c) an event of default under the terms of the Third V

Stipula' tion. The Company is in default of the Third Stipulation for, among other reasons, failure to obtain financing for the Plan by the date required in the Third Stipulation. Although the Company has been in default since, November 1, 1993, the Participating Joint Owners have continued to provide financing pursuant to the Third Stipulation. There is, however, no assurance that they will continue to do so. As of March 25, 1994, outstanding advances under the Third Stipulation were approximately $2.2 million in the aggregate. 7 If the Plan is confirmed by the Bankruptcy Court and the Omega Financing is obtained, the Company will repay amounts owing under the Third Stipulation out of the proceeds of the Omega Financing. The Company cannot predict whether the Plan will be confirmed or the Omega Financing obtained. s s Other Matters: The Company's reorganization expenses are subj ect to approval by the Bankruptcy Court. For the period March 1, 1991 through August 31,

1993, professionals have submitted fees and expenses in the amount of approximately

$5.9 million to the Bankruptcy Court for its approval, and the Bankruptcy Court has provisionally authorized, subject to its review at the conclusion of the 3 Chapter 11 proceeding, payments of approximately $4.5 million. The Company has paid amounts provisionally authorized by the Bankruptcy Court, and those are reflected on the Company's Statement of Loss during the period in which they have been paid. O Since August 31, 1993, no hearings on approval of reorganization expenses have been held and no requests for allowance for such expenses have been made. According to the Supplemental Disclosure Statement, the Bondholders Committee has budgeted reorganization expenses payable on closing of ths Omega Financing and subject to Bankruptcy Court approval of $4.5 million. Under Chapter 11, certain claims against the Company in existence prior to the filing of the petition for relief under the Bankruptcy Code are stayed while the Company continues business operations as debtor-in-possession. These claims are reflected in the Company's Balance Sheet as of December 31, 1993 and December 31, 1992 as " Liabilities Subject to Compromise." Additional claims (Liabilities Subject to Compromise) may arise subsequent to the filing date resulting from rejection of executory contracts and from the determination by the Bankruptcy Court (or agreed to by parties in -interest) of allowed contingent and disputed claims. Enforcement of claims secured by certain of the Company's assets (secured claims) also are stayed, although the holders of such claims have the right to move the court for relief f rom the stay. Secured claims, principally the Secured Notes, are secured by an interest in certain Seabrook Project assets of the Company, principally realty and personalty. EUA Power Debt: The current face amount of principal and accrued interest to February 28, 1991 on the Company's Secured Notes is $279,597,200 and $14.126,174, respectively. The Secured Notes are collateralized by a security interest in j the Company's 12.1% ownership interest in the realty and personalty of the Seabrook Project. Early in the Chapter 11 proceeding, the Company raised the j 6 l

issue of whether the Secured Noteholders are also secured by the Company's " entitlement" to electricity from Seabrook Unit 1. In light of the Plan, this . O issue did not need to be resolved in the Chapter 11 case. As a result. of the bankruptcy filing, the Company is in default under the indenture pursuant to which the Secured Notes were issued. All of the Secured Notes w(11 be converted into common stock of the Company on the Effective Date. i The Company also has outstanding 180,000 CICs evidencing the right to receive additional payments contingent upon, and measured by, the Company's income in certain years following the commercial operation of Seabrook Unit.1. Under the Plan, the CICs will be extinguished on ti e Effective Date. Such Secured Notes and CICs are solely the obligation of the Company and are not guaranteed by EUA or any other person (see Reorganization Plan above). Marketinn The Company, under the direction of the Bondholders Committee, is currently seeking to enter into long-term power contracts to realize the long-term value of its interest in the Seabrook Project. The Company intends to continue its marketing efforts which have consisted of both direct negotiations with utilities and participation in utility sponsored supply bidding processes. The Company's marketing efforts are being provided by an affiliate of Unitil under the supervision of the Bondholders Committee. The Company has entered into a contract for the sale of approximately 10MW of its entitlement in Seabrook Unit 1 (See Power Purchase Acreement and Power Purchase Option below). However, economic conditions in the Northeast, the availability of competing long-term power supplies and the bidding requirements for power contracts being implemented by various state utility commissions continue to adversely affect the Company's ability to enter into long-term sales contracts. Consequently, the Company is unable to predict when, if ever, the Company will be able to enter into. additional long-term purchased power contracts. Power Purchase Agreement and Power Purchase Option The Company has entered into an agreement (the Power Purchase Agreement) with UNITIL Power Corporation (UNITIL Power), a wholly owned subsidiary of UNITIL, which provides for the Company to sell to UNITIL Power approximately 0.9% of the power generated by Seabrook Unit 1 (approximately 10 MW) and allocable to the Company at prices significantly above those. currently available.In the spot-market, where the Company is otherwise selling its electricity. The Power Purchase Agreement has an initial term which commenced on May 1, 1993 and extends through October 31, 2010. From the commencement date of sales through October 31, 1993, the price of power ' under the Power Purchase Agreement was 5.0 cents per kilowatthour (kWh), with formulauincreases at less than inflation thereafter. The Power Purchase Agreement also provides UNITIL Power with the option to extend the Power Purchase Agreement for an additional 12 years. To provide the Company with needed near-term revenue and cash flow while spot-market prices are low, the Power ' Purchase Agreement is front-end loaded whereby UNITIL Power will pay more in real terms in the early years of the I Agreement and lesser amounts in later years. This structure is not unusual for power purchase contracts, and will result in an increase in the Company's 7

~. -- l 7 revenues above the existing spot-market price. The amount of this " overpayment" by UNITIL Power in the early years of the Power Purchase Agreement is quantified in a " Balance Account", which increases annually to ) $4.1 million in 1998, then decreases annually, reaching zero in 2001. If the Power Purchase Agreement terminates when there is a positive amount cin the 3 Balance Account, the Company is obligated to pay that amount to UNITIL, Power. To secure the obligation of the Company under the Power Purchase Agreement to repay to UNITIL Power the amounts in the Balance Account, the Power Purchase Agreement grants UNITIL Power a mortgage on the Company's Seabrook Interest. This mortgage granted to UNITIL Power ir. junior only to the existing m#rtgage on the Seabrook Interest granted pursuant to the Third Stipulation and any successor first mortgage financing up to a maximum amount of $80,000,000. The-Power. Purchase Agreement further provides that UNITIL's second mortgage will rank pari passu with other mortgages that may hereafter be granted to other purchasers of power from the Company to secure similar obligations, provided / that the maximum amount of indebtedness secured by the first mortgage on the Seabrook Interest does not exceed $80,000,000 and provided that the combined total of all second mortgages on the Seabrook Interest does not exceed the sum of (a) $80,000,000 less the total amount of the Company's debt then outstanding which is secured by a first mortgage plus (b) $57,000,000. The Power Purchase Agreement will also provide that the Company must pay UNITIL Power " benefit of the bargain" damages in the event that the Power Purchase Agreement is terminated due to a default by the Company. To secure. the Company's obligations under this provision, the Power Purchase Agreement grants UNITIL Power a third mortgage on the Seabrook Interest junior to the first mortgage and the second mortgages described above, but senior to the Bondholders' Mortgage. The Power Purchase Agreement provides that such third mortgage may be pari passu with mortgages securing similar obligations to other purchasers of power from the Company for the reasons set forth above. In addition to the Power Purchase Agreement, the Company also has entered into an agreement (the Power Purchase Option Agreement) with UNITIL Power under which the Company will grant UNITIL Power the option to purchase, in addition j to the purchases by UNITIL Power under the Power Purchase Agreement, approximately 1.3% of the power generated by Seabrook Unit 1 (approximately 15 MW) and allocable to the Company at prices significantly above those currently available in the spot market. If UNITIL Power exercises this option, the Power Purchase Option Agreement would serve as an additional power purchase agreement with sales taking place under it from November 1, 1998 through October 31, l 2018. The purchase price under the Power Purchase Option Agreement will be 6.5 cents per kWh, adjusted to reflect inflation from May 1, 1993 to November 1, 1998, with annual increases thereafter in accordance with inflation to the extent inflation exceeds 1% during the applicable year. UNITIL Power will be required to exercise its option under the Power Purchase Option Agreement on or before the earlier of (a) October 31, 1996, and (b) 30 days af ter the first date on.which the Company is prepared to commit to sell, for a minimum of 10 years, all or any part of the last remaining 15 MW of electricity from Seabrook Unit I to which the Company is entitled. The Power Purchase Option Agreement also requires UNITIL Power to purchase up to 1$ MW of electricity from the Company, at the discretion of the Company, - on a i month-to-month basis, 'during the interim period between the date on which UNITIL Power exercises its option (if it does so) and November 1, 1998, when i 8 1 l 1

i purchases begin under the terms of the Power Purchase Option Agreement. The purchase price for electricity during this option period will 'be determined on O a monthly basis at $3.00 less than UNITIL Power's actual marginal cost per megawatthour in the applicable month. i In contrast to the Power Purchase Agreement, the Power Purchase ;0ption Agreement does not provide for a Balance Account. Competition The Company is facing new sources of competition primarily as a result of PURPA, the Energy Act, and other policies being implemented by state regulators relating to the solicitation of competitive proposals for new generation sources. Non-utility wholesale generators, ger.erally hown as independent power producers or IPPs, are subject to FERC regulations under the Federal Power Act as well as various other federal, s ta te,, anti local regulators. However, PURPA was intended, among other things, to promote national energy independence and diversification of energy supply and to improve the overall efficiency of energy usage. PURPA created a new class of non-utility power generation facilities called QFs. PURPA allows QFs to sell power generated by the QFs to local utilities at specified rates based on each utility's avoided cost. In order to further promote completion in energy supply, the Energy Act established a new class of non-utility generators, generally referred to as EWGs, which are exempt from the 1935 Act. The Company is an EWG.

Also, various states have implemented regulations which require utilities 'to integrate least-cost planning with competitive proposals to meet requirements for new generation.

The Company is competing with New England and New York utilities and with QFs, EWGs and IPPs as it markets its wholesale power to other electric utilities. The Company may face increased competition, primarily based on price, from such sources in the future. The Company is a party to the NEP00L Agreement and is a inember of NEPOOL. ) NEP00L is open to all investor-owned, municipal and cooperative electric utilities in New England that are connected to the New England power grid under an agreement which provides for coordinated planning of future facilities as I well as the operation of nearly 100% of existing generating capacity in New England and of related transmission facilities as if they were one system. The NEPOOL agreement imposes obligations concerning generating capacity reserves and the right to use maj or transmission lines, and provides for central dispatch of the generating capacity of the pool's members with the objective of achieving economical use of the region's facilities. Pursuant to the NEPOOL agreement, interchange sales to NEP00L are made at a price approximately equal to the fuel cost for generation without contribution to the support of fixed - charges. Because of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of other members. i Construction Program i i The Company's cash construction expenditures for 1994, 1995 and 1996, as set forth below, are estimated to total $18.5 million (including nuclear fuel j-expenditures). ,!O ~ 9 i

J GREAT BAY POWER CONSTRUCTION PROGRAM (Thousands of Dollars) 1994 1995 1996 3-Yr Total i Seabrook Unit 1 ,\\ Construction j,g33go j,g3gog ),g3160 {18 45g, 3 Cash construction and nuclear fuel expenditures for the' year

• ended December 31, 1993 were approximately $6.9 million.

1 Nuclear Power Issues ) Like other nuclear generating facilities, the Seabrook Project is subject i to extensive regulation by the NRC. The NRC is empowered to authorize the siting, construction and operation of nuclear reactors after consideration of public health, safety, environmental and anti-trust matters. The. NRC has promulgated numerous requirements ' affecting safety systems, fire protection, emergency response planning and notification systems, and. other aspects of nuclear plant construction, equipment and operation.. The Company has been, and may be, affected to the extent of its proportionate share-by the cost of any such modifications to Seabrook Unit 1. Nuclear units in the United States have been subj ect to widespread. criticism and opposition. Some nuclear projects have been cancelled following substantial construction delays and cost overruns as the result of licensing problems, unanticipated construction defects and other difficulties. Various -groups have by litigation, legislation and participation in administrative proceedings sought to prohibit the completion and operation of nuclear units and the disposal of nuclear waste. In the event of a shutdown of any unit, NRC regulations require that it be completely decontaminated of any residual radioactivity. The cost of such decommissioning, depending on the circumstances, could substantially exceed the owners' investment at the time of cancellation. 1 Public controversy concerning nuclear power could adversely affect the operating license of Seabrook Unit 1. While the Company cannot-predict the ultimate effect of such controversy, it is possible that -it could result in a j premature shutdown of the unit. The Price-Anderson Act provides, among other t.hings, that ~ the liability for_ damages resulting from a nuclear incident would not exceed an amount which at present is about $9.2 billion. Under the. Price-Anderson Act, prior. to 1 operation of a nuclear reactor, the licensee is required to insure against this - exposure by purchasing the maximum amount of insurance available from ' private j sources (currently $200 million) and to maintain the insurance available under a mandatory - industry-wide - retrospective. rating program. Should an individual-licensee's liability for an incident exceed- $200 million, the difference j between such liability and the overall maximum liability, currently about $9.2 billion, will be made up by the retrospective rating program. Under such a program, each owner of an operating nuclear facility may be assessed a retrospective premium - of up to a limit - of $79.3 million (which shall be adjusted for inflation at least every five years) for each reactor owned in the 10

event of any one nuclear incident occurring at any reactor in the United States, with provision for payment of such assessment to be made over time as O necessary to limit the payment in any one year to no more than $10 million per V reactor owned. The Company would be obligated to pay its proportionate share of any such assessment. 3 \\ ~ Joint owners of nuclear projects are also subject to the risk that one of their number may be unable or unwilling to finance its share of the project's costs, thus jeopardizing continuation of the proj ect. On May 6, 1991, New Hampshire Electric Cooperative, Inc.,

a. 2.2% owner of the Seabrook Proj ect, announced that it had filed for Chapter 11 bankruptcy protection.

A reorganization plan, filed by the New Hampshire Electric Cooperative with the Bankruptcy Court in September, 1991 and revised in January, 1992 was. approved by the Bankruptcy Court in March 1992 and approved by the NHPUC on October 5, 1992. All appeals of the NHPUC order approving the reorganization have been resolved in NHEC's favor and the effective date of the plan occurred on December 1, 1993. Nuclear Fuel and Nuclear Plant Decommissioning: The Seabrook Proj ect joint owners have made, or expect to make, various arrangements for the acquisition of uranium concentrate, the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of that fuel after use. The owners and lead participants of United States nuclear units have entered into contracts with the DOE for disposal of spent nuclear fuel in accordance with the NWPA. The NVPA requires (subj ect to various contingencies) that the federal government design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel and establish prescribed fees for the disposal of such wastes and fuel. The NVPA specifies that the DOE provide for the disposal of such wastes and spent nuclear fuel starting in 1998. Objections on enviroilmental and other grounds have been asserted against proposals for storage as well as disposal of spent fuel. The DOE anticipates that a permanent disposal site for spent fuel will be ready to accept fuel for storage on or before 2010. However, the NRC, which must license the site, stated only that a permanent repository will become available by the year 2025. At the Seabrook Project there is on-site storage capacity which, with minimal capital expenditures, should be sufficient for twenty years or until the year 2010. No near-term capital expenditures are anticipated to deal with any increase in storage requirements after 2010. The estimated cost to decommission Seabrook Unit 1, based on a study performed for the lead owner of the Plant is approximately $351 million in 1993 dollars. The Company's share of that amount is approximately $42.6 million, or 12.1%. In 1993, the Company paid approximately $895,000 in decommissioning expenses. The agreements of purchase and sale under which the Company purchased its Seabrook Interest required the Company to establish a fund of $10 million to secure payment of part of its share of the decommissioning costs of Seabrook Unit 3 and any costs of cancellation of Seabrook Unit 1 or Unit 2.. In May 1990 EUA guaranteed this obligation and the entire fund was released to the Company. Under the Se,ttlement Agreement EUA reaffirmed this guaranty. (See Bankruptev Proceedinn - Settlement Agreement above.) 11

9 Seabrook Unit 2: p The Company also has a 12.1% ownership interest in Seabrook Unit 2 to V which it has assigned no value. On November 6, 1986, the joint owners of the Seabrook Project, recognizing that Seabrook Unit 2 had been cancelled 19 1984, voted to dispose of the Unit. Certain assets of Seabrook Unit 2 have,been and are being sold from time to time to third parties. Plans regarding disposition of Seabrook Unit 2 are now under consideration, but have not been finalized and approved. The Company is unable, therefore, to estimate the costs for which it would be responsible in connection with the disposition of Seabrook Unit 2. Monthly charges are required to be paid by the Company with respect to Seabrook Unit 2 in order to preserve and protect its components and various warranties. Public Utility Renulation The Company is subj ect to regulation by the NHPUC in many respects including the issuance of securities, contracts with affiliates, forms of r accounts, transfers of utility properties and other matters but excluding the rates charged for sales of electricity at wholesale. The Company is no longer subject to the jurisdiction of the SEC under the 1935 Act as a result of the redemption by the Company of its outstanding equity securities held by EUA and as a result of its status as an EWG. The Company is also subject to the jurisdiction of FERC under Parts II and III of the Federal Power Act. That jurisdiction includes, among other things, rates for sales for resale, interconnection of certain facilities, accounts, service and property records. y) (See Nuclear Power Issues with respect to regulation of nuclear facilities by the NRC and see Nuclear Fuel and Nuclear Plant Decommissioninn with respect to the disposal of spent nuclear fuel. See also Environmental Regulation and Enercy Policy, below.) Environmental Regulation The Company, like other electric utilities, is subject to standards administered by federal, state and local authorities with respect to the siting of facilities and associated environmental factors. The EPA, and certain state and local authorities, have jurisdiction over releases of pollutants, contaminants and hazardous substances into the environment and have broad authority in connection therewith including the ability to require installation of pollution control devices and remedial actions. The NRC has promulgated a variety of standards to protect the public from radiological pollution caused by the normal operation of nuclear generating facilities. In some environmental areas the NRC and the EPA have overlapping jurisdiction. Thus, NRC regulations are subject to all conditions imposed by the EPA and a variety of federal environmental statutes, including obtaining permits for the discharge of pollutants (including heat) into the nation's navigable waters. In addition, the EPA has established standards, and is in the process of reviewing existing standards, for certain toxic air pollutants, including radionuclides, under the Clean Air Act which apply to NRC-licensed facilities. The effecIive date for the new radionuclide standards has been p& stayed as to nuclear generating units. The EPA has also promulgated 12

' environmental radiation protection standards for nuclear power plants which PA provides for development b the federal gove ment of facilities for the disposal or permanent storage of civilian nuclear waste. (See Nuclear Fuel and Nuclear Plant Decommissionint.) The NRC has also prom 41 gated regulations regarding the disposal of nuclear waste materials designed ,t o protect the public from radiological dangers. Environmental regulation of nuclear facilities may result in significant increases in capital and operating costs, in delays or cancellation of construction of planned improvements, or in modification or termination of existing facilities. Enerny Pollev The Energy Act deals with many aspects of national energy policy and includes important changes for electric utilities and registered holding companies. It is not possible to predict the impact which the Energy Act and the rules and regulations which will be promulgated by various regulatory agencies pursuant to the Energy Act will have on the Company. Certain provisions of the Energy Act will increase competition in the generation of electricity. One of the more significant provisions of the Energy Act creates a new class of generation companies exempt from the 1935 Act, which sell exclusively at wholesale. called EWGs. The Company is an EWG. The Energy Act also grants FERC new authority to mandate transmission access for QFs, EWGs and traditional utilities. p It is also not possible to predict the timing or content of future energy (' policy legislation and the significance of such legislation to the Company. Various issues not addressed by the Energy Act, including regional planning and transmission arrangements, could be addressed in future legislation. Item 2. PROPERTIES The Company's principal asset is its 12.1324% joint ownership interest in the Seabrook P;oject. The Seabrook Proj ect is a nuclear-fueled, steam electricity, generating plant located in Seabrook, New Hampshire, which was planned to have two Westinghouse pressurized water reactors, Seabrook Unit 1 and Seabrook Unit 2 (each with a rated capacity of 1,150 megawatts), utilizing ocean water for condenser cooling purposes. Seabrook Unit 1 entered commercial services on August 19, 1990. Seabrook Unit 2 has been cancelled. The Company la required to pay its share (i.e., the same percentage as the percentage of its ownership and its entitlement to the output) of all of the costs of the Seabrook Proj ect including fixed costs (whether or not Seabrook Unit 1 is operating), operating costs, costs of additional construction or modification, costs associated with condemnation, shutdown, retirement, or decommissioning of the Seabrook Project, and certain transmission charges. Item 3. LEGAL PROCEEDINGS Bankruptev Proceedine On February 28, '199,1, the Company. filed a voluntary petition for p protection under Chapter 11 of the federal Bankruptcy Code. A plan of V 13 l

\\ ) reorganization filed by the Bondholders Committee was confirmed on March 5, 1993. That Plan has been modified and will be resubmitted to the creditors of O the Company for their approval. For a general discussion See Item 1. BUSINESS V - Bankruntev Proceedinc. 4 SEC Review \\ In January of 1991, the SEC's Division of Corporation Finance commenced a review of the Company's Annual Report on Form 10-K for the year ended December 31, 1989 and subsequent Quarterly Reports on Form 10-Q. The Company submitted written responses to all of the inquiries made by the Division of Corporate Finance. In May of 1991, the Company was informed by the SEC's Division of Enforcement that it would conduct an informal review with respect to certain issues addressed by the Division of Corporate Finance principally relating to the accounting for the capitalized financing costs related to the Company's investment in Seabrook Unit 1 and the effect which recording such amounts had on reported earnings for the three year period ended December 31, 1990. The Company informed the Division of Enforcement that it would cooperate with the informal inquiry and in July of 1991 the Company completed its responses to the Division of Enforcement's initial inquiries. The Company has received no communications from the Division of Enforcement since the Company completed its responses in July, 1991. The Company restated its financial statements with respect to the amount of AFUDC recorded in 1988, 1989 and the first three quarters of 1990 which it. believes addresses several issues raised by the SEC. The Company cannot predict the outcome of the SEC's review. The SEC could require that the Company further restate its financial statements for 1990, 1989 or 1988, or for O any quarterly period during such years. The ultimate outcome of this matter cannot presently be determined and, accordingly, no provision for any adjustment that may result from its outcome has been made in the 1990 financial statements of the Company. The Company continues to believe that its financial statements (as previously restated) were prepared in accordance with generally accepted accounting principles and presented fairly the financial position and results of operations of the Company. Other Proceedines On January 8,

1992, the Massachusetts Municipal Wholesale Electric Cooperative and its member municipalities, all of which are members of NEP00L, filed a suit in Massachusetts Superior Court against the investor-owned i

utilities that are also members of NEPOOL. The suit alleges damages by NEP00L's establishment of minimum size requirements for generating units designated as pool-planned generating units. The suit names as defendants members of NEPOOL, including the Company. Management cannot predict the ultimate outcome of this proceeding at this time. Discovery has not begun, pending resolution of certain procedural matters. The FERC initiated an action when the EUA subsidiaries and other participants filed an amendment - to the NEP00L Agreement with the FERC that concerns many of the issues raised in the Massachusetts litigation. The plaintiffs in the Massachusetts litigation and one other participant have obj ected to the amendment, and have sought to prevent or delay its effectiveness. The FERC has not yet determined whether or I when it will hold heqings on this matter. Management cannot predict the ultimate outcome of this pr.oceeding at this time. 14

In June 1991, the State of New Hampshire imposed a Nuclear Station Property Tax applicable only to the Seabrook Project. The Company paid its O share of the tax, aggregating $4.2 million through December 31, 1992. In V October 1991 the Attorneys General of Connecticut, Massachusetts and Rhode Island petitioned the United States Supreme Court in an original jurisc}iction case for a determination of the legality of the tax, and in January,1992 the Supreme Court agreed to take the case. The parties to the litigation and other Joint Owners of Seabrook entered into a Settlement Agreement on April 13, 1993. In general, the terms of the Settlement Agreement significantly reduced nuclear station property taxes payable by the Company. In addition, under the terms of the Settlement Agreement, certain of the prior payments of the tax by the Company will be permitted to be credited against future taxes due. The Bankruptcy Court has approved the Settlement Agreement with respect to the Company. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS On February 5, 1993, the Company redeemed all of its outstanding equity securities previously held by EUA pursuant to the terms of the Settlement Agreement. The Company reflects this balance as Treasury Stock on the Statement of Capitalization since December 31, 1992. No dividends have ever been paid or declared on the Company's equity securities. ~ Y 15

T Item 6. SELECTED FINANCIAL DATA The selected financial data for the year ended December 31, Iq89 has been restated from amounts previously reported. For the year Ended (Dollars In December 31, Thousands) 1993 1992 1991 1990 1989 Operating Revenues $ 24,620 $ 23,027 $ 20,919 $ 10,499 Net (Loss) Income (18,478) (47,468) (19,792) (74,505) (2,983) Total Assets 337,616 346,137 359,058 365,920 413,195 Capitalization: 1 Long-Term Debt (excluding current maturities) 180,000 300,597 279,597 Common Equity (148,828)* (130,350)* (82,882) (63,090) 11.417 Cumulative Convertible Preferred Stock 63.090* 63.090* 63.090 63.090 60.790 Total Capitalization gfgggggg) ((g333g0) g}gggggg g3gggggZ gg5}380g

• Balances include Paid-In Capital - Treasury Stock of $10,000 and $63,090,000 for Common Equity and Cumulative Convertible Preferred Stock, respectively.

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND I"D RESULTS OF OPERATIONS overview: Great Bay operates as a public utility in the state of New Hampshire. The Company was organized for the purpose of acquiring a 12.1% ownership interest in the Seabrook Project and selling, in the wholesale market its share of the electricity generated by Seabrook Unit 1. On Feb ruary 28, 1991, the Company filed a voluntary petition in the federal Bankruptcy Court for protection under Chapter 11 of the federal Bank ruptcy Code and has been conducting its business as a Debtor and a Debtor-In-Possession under the provisions of the Bankruptcy Code. Settlement Agreement: On November 18, 1992, the Company, the Bondholders Committee and EUA entered into a Settlement Agreement which resolved certain adversary proceedings against EUA,

brought, or threatened to be brought, by the Bondholders Committee including, (i) a claim for recovery of certain alleged preferential transfers in the aggregate amount of $38.5 million, plus interest; (ii) a threatened claim for the recovery of $100 million plus treble damages-arising from, among other things, certain alleged breaches of fiduciary duties by EUA, EUA Service and the officers and directors of the Company; and, (iii) certain matters arising out of tax sharing agreements between EUA.

its subsidiaries, and the Company. The Settlement Agreement also provided for the ( ) payment of $20 million to the Company by EUA. The Settlement Agreement further i v e 16 l

i provided for the relinquishment by EUA of its equity interest in the Company i and all claims filed in Bankruptcy Court by EUA and its affiliates against the l O Company. These claims related primarily to obligations of the Company l Suaranteed and paid by EUA, including $21 million of Solid Waste Disposal i Facility Revenue Bonds, issued by the New Hampshire Industrial ' Development l Authority on behalf of the Company and other notes payable. The settlement of l these claims was recorded as a deferred credit on the Company's 1992 Balance l

Sheet, pending the vitimate outcome of the Bankruptcy Proceeding.

The Settlement Agreement became effective on December 30, 1992 at which time EUA paid $20 million to the Company. The Company used a substantial portion 'of the proceeds from the Settlement Agreement to repay amounts outstanding under the First Stipulation (as described below) and to pay reorganization expenses and other operating expenses. The Company redeemed all of its outstanding equity l securities which were held by EUA, at no cost, on February 5, 1993. The ( redeemed shares have been classified as treasury stock on the Company's financial statements as of December 31, 1992. As a result of the redemption, the Company no longer part of the EUA System. l ( Under the Settlement Agreement, EUA reaffirmed its guarantee of up to $10 million of the Company's share of future decommissioning costs of Seabrook Unit l 1 and any costs of cancellation of Seabrook Unit 1 or Unit 2. EUA had guaranteed this obligation in 1990 in order to secure the release to the Company of a $10 million fund established by the Company for the same purpose at the time the Company acquired its Seabrook Interest. Further, under the Settlement Agreement, all of the officers and directors of the Company (except Mr. Stevens) resigned and the Company changed its name to Great Bay Power Corporation. EUA now has no ownership interest in the Company. Reorganization Plan: The Bankruptcy Court confirmed the Bondholders Committees Fifth Amended Plan of Reorganization on March 5, 1993. After confirmation," the Company was unable to obtain the $45 million of debt financing contemplated by the Fifth Amended Plan of Reorganization. In February 1994, however, the Bondholders Committee obtained a commitment from Omega or its designees to provide $35 million of equity financing for the Company. The Bondholders Committee prepared a First Modification to Fifth Amended Plan of Reorganization to reflect this change in financing and submitted a Supplemental Disclosure Statement describing that First Modification to the Bankruptcy Court for its approval. The Bankruptcy Court approved the Supplemental Disclosure Statement at a hearing on March 11, 1994. The Plan is scheduled to be mailed to the Company's creditors for their approval on or before April 7, 1994. If the Creditors approve the Plan, the Company expects the Bankruptcy Court to confirm the Plan in a hearing currently scheduled for May 13, 1994, although such confirmation cannot be assured. The Omega Financing and the Plan are subject to approval by certain regulatory authorities. On February 15, 1994 the Nuclear Regulatory Commission issued an order approving a transfer of control of the Company as contemplated by the Omega Financing and extending the deadline for completion of such transfer to June 30, 1994. There can be no assurance that other such approvals will be obtained. Moreover, the Omega Financing is not yet reduced to a definitive agreement. The Plan will not be circulated to creditors unless and until such a definitive agreement has been signed. 17 i.,

The Omega Financing provides for the Company to sell its common stock representing a 60% ownership interest in the Company to Omega or its designees O-for an aggregate purchase price of $35 million. The 40% balance of the Compan'y's common stock will be issued 34% to the Company's Bondholders in full payment - and satisfaction of their secured claims pursuant to the Bonds:,and 6% to the Company's unsecured creditors with claims in excess of $25,000 in full payment and satisfaction of their claims. These unsecured claims consist primarily of the unsecured deficiency claims of the Bondholders under the Bonds. The holders of unsecured claims of less than $25,000, other than those unsecured claims resulting from the ownership of the Secured Notes, will be paid 50% of the amounts of their claims allowed by the Bankruptcy Court in cash on the Effective'Date. The Plan requires that prior to the Effective Date the Bondholders Committee obtain the Omega Financing. Although a bar date for all claims has been entered and passed, claims ) arising from the rejection of contracts or claims which the Bankruptcy Court / permits to be filed notwithstanding the bar date may dilute the percentage of the unsecured claims held by the Secured Noteholders. All of the previously issued and outstanding equity securities of the Company have been redaemed by the Company. The CICs issued in connection with the Series B Notes or otherwise will be extinguished on the Effective Date. After the Effective Date, the equity of the Company will be represented by a single class of common stock. The Company will use good faith efforts to list its shares of common stock so that they will be tradeable on the American Stock Exchange or the NASDAQ National Market System. The Bondholders Committee has appointed or will appoint agents to manage the Company's business and to market the Company's share of Seabrook ( electricity. During the period between the Confirmation of the Plan and the Effective Date, those agents are to report to the Bondholders Committee and, to the extent actions are to be taken outside of the ordinary course of business, such actions shall be subj ect to the approval of the Bank'ruptcy Court and regulatory bodies with jurisdiction under applicable law. John R.

Stevens, president of EUA, expects to resign as president and director of the Company on the Effective Date.

The Bondholders Committee has disclosed the names of two individuals proposed to serve on the Board of Directors (the New Board) of the Company after the Effective Date. The proposed two members of the New Board are John A. Tillinghast and Walter H. Goodenough. The Bondholders Committee is also considering other candidates to serve as members of the New Board. The persons who will serve on the New Board will be finally determined before the Effective Date. The New Board will take office upon the Effective Date. The New Board will serve until its members resign or are replaced in accordance with New Hampshire corporate law and the requirements of the Company's charter and by-laws. The effectiveness of the Plan is conditioned upon obtaining plan of reorganization financing and approvals from various regulatory agencies including the NRC. The Company has obtained the approval of the NRC, provided the Company obtains plan of reorganization financing. The Company cannot predict whether it will be able to obtain plan of reorganization financing or whether the plan, or any other plan if filled, will be approved by the various regulatory agencies having jurisdiction. ~. ~ O 18 7 -n ---e.

l Power Purchase Agreement and Power Purchase Option C\\ V The Company has entered into an agreement (the Power Purchase Agreement) I with UNITIL Power Corporation (UNITIL Power), a wholly owned subsidiary of UNITIL, which provides for the Company to sell to UNITIL Power apprpximately 0.9% of the power generated by Seabrook Unit 1 (approximately 10 MW) and allocable to the Company at prices significantly above those currently i available in the spot-market, where the Company is othe rwise selling its electricity. The Power Purchase Agreement has an initial term which commenced on May 1, 1993 and extends through October 31, 2010. From the commencement date of sales through October 31, 1993, the price of power under the Power Purchase Agreement was 5.0 cents per kilowatthour (kWh), with formula increces at less than inflation thereafter. The Power Purchase Agreement also provides i UNITIL Power with the option to extend the Power Purchase Agreement for an additional 12 years. i To provide the Company with needed near-term revenue and cash flow while spot-market prices are low, the Power Purchase Agreement is front-end loaded whereby UNITIL Power will pay more in real terms in the early years of the Agreement and lesser amounts in later years. This structure is not unusual for power purchase contracts, and will result in an increase in the Company's revenues above the existing spot-market price. The amount of this " overpayment" by UNITIL Power in the early years of the Power Purchase Agreement is quantified in a " Balance Account", which increases annually to $4.1 million in 1998, then decreases annually, reaching zero in 2001. If the Power Purchase Agreement terminates when there is a positive amount in the Balance Account, the Company is obligated to pay that amount to UNITIL Power. Q To secure the obligation of the Company under the Power Purchase Agreement to repay to UNITIL Power the amounts in the Balance Account, the Power Purchase Agreement grants UNITIL Power a mortgage on the Company's Se'abrook Interest. This mortgage granted to UNITIL Power is junior only to the existing mortgage on the Seabrook Interest granted pursuant to the Third Stipulation and any successor first mortgage financing up to a maximum amount of $80,000,000. The Power Purchase Agreement further provides that UNITIL's second mortgage will rank pari passu with other mortgages that may hereaf ter be granted to other purchasers of power from the Company to secure similar obligations, provided that the maximum amount of indebtedness secured by the first mortgage on the Seabrook Interest does not exceed $80,000,000 and provided that the combined total of all second mortgages on the Seabrook Interest does not exceed the sum of (a) $80,000,000 less the total amount of the Company's debt then outstanding which is secured by a first mortgage plus (b) $57,000,000. The Power Purchase Agreement will also provide that the Company must pay UNITIL Power " benefit of the bargain" damages in the event that the Power 1 Purchase Agreement is terminated due to a default by the Company. To secure the Company's obligations under this provision, the Power Purchase Agreement grants UNITIL Power a third mortgage on the Seabrook Interest junior to the first mortgage and the second mortgages described above, but senior to the Bondholders ' Mortgage. The Power Purchase Agreement provides that such third mortgage may be pari passu with mortgages securing similar obligations to other purchasers of poweg from the Company for the reasons set forth above. v 4 19

4 In addition to the Power Purchase Agreement, the Company also has entered into an agreement (the Power Purchase Option Agreement) with UNITIL Power under ] which the Company will grant UNITIL Power the option to purchase, in addition to the purchases by UNITIL Power under the Power Purchase Agreement, approximately 1.3% of the power generated by Seabrook Unit 1 (approximately 15 t MW) and allocable to the Company at prices significantly above those,, currently available in the spot market. If UNITIL Power exercises this option, the Power Purchase Option Agreement would serve as an additional power purchase agreement with sales taking place under it from November 1, 1998 through October 31, 2018. The purchase price under the Power Purchase Option Agreement will be 6.5 cents per kWh, adjusted to reflect inflation from May 1, 1993 to November 1, 1998, with annual increases thereafter in accordance with inflation to the extent inflation exceeds 1% during the applicable year. UNITIL Power will be required to exercise its option under the Power Purchase Option Agreement on or before the earlier of (a) October 31, 1996, and (b) 30 days after the first date on which the Company is prepared to commit to sell, for a minimum of 10 years, all or any part of the last remaining 15 MW of electricity from Seabrook Unit 1 to which the Company is entitled. The Power Purchase option Agreement also requires UNITIL Power to purchase up to 15 MW of electricity from the Company, at the discretion of the Company, on a month-to-month basis, during the interim period between the date on which UNITIL Power exercises its option (if it does so) and November 1, 1998, when purchases begin under the terms of the Power Purchase Option Agreement. The purchase price for electricity during this option period will be determined on a monthly basis at $3.00 less than UNITIL Power's actual marginal cost per megawatthour in the applicable month. p In contrast to the Power Purchase Agreement, the Power Purchase Option h Agreement does not provide for a Balance Account. ~ Comparison of Financial Results The Company reported a net loss in each of the last three years as follows: $9.4 million in 1993, $47.5 million in 1992 and $19.8 million in 1991. These losses are primarily due to short-term power sales of the Company's entitlement from Seabrook Unit 1 at prices substantially below actual operations, maintenance and capital related costs. The 1993 net loss was $38.1 million less than the 1992 net loss primarily l due to the 1992 reversal of certain tax assets because of the uncertainty of the availability of those assets to the Company. This reversal significantly increased 1992's provision for deferred taxes contributing to the larger net loss reported by the Company in 1992. Also, the Company began recognizing deferred tax assets relating to net operating losses subsequent to the change in ownership of the Company which occurred on February 5, 1993. Operatine Revenues Since commercial operation, the Company has been selling its share of Seabrook Unit l's output on a short-term basis at prices substantially below its actual operations, maintenance and capital related costs. The level of operating revenues of _the Company depends upon the price per kWh of its short-term sales and Unit l's capacity factor. V(3 20 i

u Due to minimal outages in 1993, there was a slight increase in operating revenue of 6.9%. Consequently, there was a higher average capacity factor over . [] 12 months in 1993 as compared to 1992; 89.9% vs 77.9%, respectively. The (/ average kWh sales price was 2.24 cents in 1993 as compared to 2.39 cents in 1992. Scheduled refueling outages of Seabrook Unit 1 in both 1992 and 1991 had a negative impact on the Unit's capacity factor. However, a higher capacity factor averaged over twelve months in 1992 as compared to 1991, 78% vs. 68% respectively, contributed to the 15.5% growth in kWh sales and the $2.1 million, or 10.1%, improvement in revenues despite a 5.2% decline in the average per kWh sales price. The average kWh sales price was 2.39 cents in 1992 as compared to 2.52 cents in 1991. Expenses 1993 vs 1992 Other Operation & Maintenance expense decreased $4.0 million from 1992 primarily due to (i) operational efficiencies throughout 1993 as compared to 1992 and (ii) fewer repair outages resulting in lower maintenance expenses. Income & Deferred taxes decreased by $29.3 million due primarily to the reversal of accumulated deferred tax benefits in 1992 relating to net operating losses and alternate minimum tax credit carryforwards which are limited due to the effect of changes in ownership of the Company. Also, the Company began recognizing deferred tax assets relating to net operating losses subsquent to the change in ownership of the Company which occurred on February 5,1993. Total Interest changes for 1993 decreased $1.3 million due to the Company's higher debtor-in-possession financing in 1992 and a lower prime rate in 1993. ~ 1992 vs 1991 Fuc1 Expense represents the Company's amortization of fuel costs associated with Seabrook Unit 1 generation during each respective period. In 1992, Fuel Expense associated with the Company's 12.1% interest in Unit 1 decreased approximately $400,000, or 5.6% as compared to 1991. This decrease is due primarily to a reduction in the average price of fuel offset somewhat by greater generation in 1992. Other Operation and Maintenance expenses for 1992 compared to 1991 decreased approximately $700,000 due primarily to a shorter refueling outage in 1992 than in 1991. Reorganization Expenses increased by approximately $630,000 in 1992 as a result of increased activity relating to the Company's bankruptcy proceeding. Income and Deferred taxes increased by $35.4 million due primarily to the reversal of accumulated deferred tax benefits relating to net operating loss and alternate minimum tax credit carryforwards which are limited due to the effect of changes in the ownership of the Company which will result in the deconsolidation of the Compiany from the EUA tax group. 21

~ Net Interest charges for 1992 decreased by $8.7 million to $1.4 million due primarily to interest expense accrued in 1991 prior to February 28, 1991. O Total Interest Expense for 1992 relates to the Company's debtor-in-possession V financing. Total Contractual Interest Expense for 1992 was approximately $51.0 million. Of this amount, interest in connection with the debtor-in-possession financing for 1992 was $1.3 million. i Financial Condition and Liouldity Liquidity: The cash resources of the Company are primarily dependent upon the price at which it sells its share of electricity generated by Seabrook Unit 1 and the operating capacity of Seabrook Unit 1. At current market prices, the cash L generated by such electricity sales is less than the Company's on-going cash requirements. While operating in Chapter 11. the Company intends, with the approval of the Bankruptcy Court, to continue making payments of its on-going obligations under the JOA to the extent its cash flow permits. The Company is required under the JOA to pay its share of Seabrook Unit 1 and Seabrook Unit 2 expenses including, without limitation, operations and maintenance

expenses, construction and nuclear fuel expenditures and decommissioning costs, regardless of Seabrook Unit l's operations.

Under certain circumstances, a failure by the Company to make its monthly payments under the JOA could adversely affect its entitlement in Unit 1. Pursuant to the Settlement Agreement of December 30, 1992, EUA paid $20 million to EUA Power, $14.7 million of which was used to repay the DIP O financing (as discussed below). (See Item 1 for bankruptcy proceeding V discussion). The Company has filed consolidated income tax returns t'ogether with EUA and other EUA affiliates. As a result of such consolidated filings, certain federal income tax benefits available to the Company have reduced the federal income tax obligations of EUA and such other EUA affiliates. Under a tax allocation agreement between EUA and its subsidiaries. EUA and its subsidiaries compensate each other for the use of the tax benefits. As a result of the redemption of the Company's outstanding common stock, the Company was deconsolidated from the EUA tax group effective February 5, 1993. Under the terms of the Settlement Agreement, EUA is entitled to utilize the Company's tax credits to reduce EUA's 1993 consolidated tax liability without compensation. The Company will be included in EUA's consolidated tax returns for the years 1992 and 1993. To the extent that the Company's carryforwards of nec operating losses, investment tax credits, alternative minimum tax credits, and deductions attributable to built in losses are available after the Company is no longer part of the consolidated return, the Company expects that these carryforwards will be significantly limited due to the impact of provisions of the tax law relating to the treatment of debt forgiveness in bankruptcy and the effect of changes in the ownership of the Company. R ( e 22 i

n DIP Financing: i O The Company is required under the JOA to pay its share of Seabrook Unit 1 and Seabrook Unit 2 expenses including, without limitation, operations and maintenance

expenses, construction and nuclear fuel expenditures and decommissioning costs, regardless of Seabrook Unit l's operations., (Under

[ certain circumstances, a failure by the Company to make its monthly payments under the JOA could adversely affect its entitlement in Unit 1. At current market prices, the cash generated by such electricity sales continues to be less than the Company's on-going cash requirements. On August 29, 1991, the Bankruptcy Court approved a Stipulation and Consent Order (the First Stipulation) with respect to DIP Financing to be provided by certain joint owners of Seabrook for the benefit of the Company. The First Stipulation was entered into by the Company and CL&P and UI (the ) Participating Joint Owners), two of the other eleven joint owners of the / Seabrook Project, as well as the Bondholders Committee. The First Stipulation was also approved by the NHPUC and the SEC under the 1935 Act. On July 21,

1992, the Bankruptcy Court issued a procedural order permitting an extension of the First Stipulation.

For the period after September 30, 1992 until March 5,

1993, the procedural order permitted i

continued debtor-in-possession financing on a month-to-month basis at the sole discretion of the Participating Joint Owners terminable on 30 days notice. The Bankruptcy Court issued a second procedural order on September 8, 1992 increasing to $22 million from $15 million the amount of advances outstanding at any one time permitted under the First Stipulation. The Participating Joint Owners continued to advance funds under the First Stipulation, as amended, until the amounts advanced thereunder were repaid with the proceeds of the Company's Settlement Agreement with EUA. The First Stipulation expired on March 5, 1993. A second stipulation was entered into by the Company and the Participating Joint Owners and was approved by the Bankruptcy Court and various regulatory authorities. However, 'that stipulation did not become effective, and on March 5, 1993, the Company and the Participating Joint Owners entered into a third l stipulation (the Third Stipulation) which was approved by the Bankruptcy Court. The Third Stipulation provides that the Participating Joint Owners shall provide up to a maximum'of $20 million in advances to the Company to enable the Company to pay its pro rata share of the Seabrook Project's operating expenses, expenses of the Company in connection with its Chapter 11 proceedings and certain other costs of operation of the Company. Pursuant to the Third Stipulation, the advances made by the Participating Joint owners bear an interest rate equal to the prime rate of The First National Bank of Boston plus 7% per annum. The Third Stipulation provides the Participating Joint Owners with. a priority lien on all the Company's assets, which lien has priority over the Bondholders' mortgage. The Third Stipulation further provides that in the-I event of a default thereunder, the Participating Joint Owners are entitled to purchase the Company's Seabrook Interest for 75% of the lesser of fair market value or book value and to apply all or part of the amounts owing under the Third Stipulation against the purchase price. The Third Stipulation terminates j on the earliest to occur of (a) July 1, 1994 (b) the Effective Date or the i j . closing of a sale of 'all, or substantially all of the Company's assets or

business, and (c) an event of default under the terms of the Third 23

( i

4 n Stipulation. The Company is in default of the Third Stipulation for, among other reasons, failure to obtain financing for the Plan by the date required in p the Third Stipulation. Although the Company has been in default since November -U' 1, 1993, the Participating Joint Owners have continued to provide financing pursuant to the Third Stipulation. There is, however, no assurance that they will continue to do so. As of March 25, 1994, outstanding advances un(er the Third Stipulation were approximately $2.2 million in the aggregate. If the Plan is confirmed by the Bankruptcy Court and the Omega Financing is obtained, the Company will repay amounts owing under the Third Stipulation out of the proceeds of the Omega Financing. The Company cannot predict whether the Plan will be confirmed or the Omega Financing obtained. The Company cannot predict whether it will be able to enter into contracts for the sale of its share of the Seabrook Project capacity or energy prior to the termination of the Third Stipulation, if at all, at prices sufficient to cover its costs and provide for repayment of advances which may be outstanding 4' under the Third Stipulation, or whether alternative debtor-in-possession financing can be arranged to repay advances. Company Debt: The current face amount of principal and accrued interest to February 28, 1991 on the Company's Secured Notes is $279,597,200 and $14,126,174, respectively. The Secured Notes are collateralized by a security interest in the Company's 12.1% ownership interest in the realty and personalty of the Seabrook Project. Early in the Chapter 11 proceeding, the Company raised the issue of whether the Secured Noteholders are also secured by the Company's Q " entitlement" to electricity from Seabrook Unit 1. In light of the Plan, this (/ issue did not need to be resolved in the Chapter 11 case. As a result of the bankruptcy filing, the Company is in default under the indenture pursuant to - which the Secured Notes were issued. All of the Secured Notes will be converted into common stock of the Company on the Effective Date. The Company also has outstanding 180,000 CICs evidencing the right to receive additional. payments contingent upon and measured-by the Company's income in certain years following the commercial operation of Seabrook Unit 1. Under the Plan, the CICs will be extinguished on the Effective Date. Such Secured Notes and CICs are solely the obligation of the Company and are not guaranteed by EUA or any other person (see Reorganization Plan above). Construction: Cash construction and nuclear fuel expenditures for the year ended December 31, 1993 were approximately $6.9 million. The Company's cash construction program is estimated to be approximately $4.3 million in 1994 and aggregate approximately $23.4 million for the years 1995 through 1998. Nuclear Fuel Disposal and Nuclear Plant Decommissioninn Costs The Seabrook Proj ect joint owners have made, or expect to make, various arrangements for the acquisition of uranium concentrate, the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of 24

fuel in accordance with the NWPA. The NWPA requires (subj ect to various contingencies) that the federal government design, license, construct and p operate a permanent repository for high level radioactive wastes and spent V nuclear fuel and establish prescribei fees for the disposal of such wastes and fuel. The NWPA specifies that the DOE provide for the disposal of suchqwastes and spent nuclear fuel starting in 1998. Objections on environmental,and other grounds have been asserted against proposals for storage as well as disposal of spent fuel. The DOE anticipates that a permanent disposal site for spent fuel will be ready to accept fuel for storage on or before 2010. However, the NRC, which must license the site, stated only that a permanent repository will become available by the year 2025. At the Seabrook Project there is on-site storage capacity which, with minimal capital expenditures, should be sufficient for twenty years or until the year 2010. No near-term capital expenditures are anticipated to deal with any increase in storage requirements after 2010. The estimated cost to decommission Seabrook Unit 1, based on a study performed for the lead owner of the Plant is approximately $351 million in 1993 dollars. The Company's share of that amount is approximately $42.6 million, or 12.1::. In 1993, the Company paid approximately $895,000 in decommissioning expenses. The agreements of purchase and sale under which the Company purchased its Seabrook Interest required the Company to establish a fund of $10 million to secure payment of part of its share of the decommissioning costs of Seabrook Unit 1 and any costs of cancellation of Seabrook Unit 1 or Unit 2. In May 1990, EUA guaranteed this obligation and the entire fund was released to the Company. Under the Settlement Agreement EUA reaffirmed this guaranty. (See Bankrupt cy Proceedinn - Settlement Agreement above.) !U Channes in Accountine Standards In February 1992, FASB issued statement No. 109, "Accou'nting for Income Taxes" (FAS109) which essentially supersedes FASB Statement No. 96 (FAS96) (see Note D of Notes to Financial Statements - Income Taxes). The Company adopted FAS109 in the first quarter of 1993. The Company adopted FAS96 in 1990 and as a result was not significantly impacted by FAS109. In December

1990, FASB issued Statement No.

106,

" Accounting for Post-Retirement Benefits other than Pensions and in November 1992 issued Statement No. 112 " Accounting for Post-Employment Benefits" which were adopted by the Company on January 1, 1993 and January 1, 1994, respectively. Since the Company presently has no employees, the adoption of such statements had no significant impact. Other On January 8,

1992, the Massachusetts Municipal Wholesale Electric Cooperative and its member municipalities, all of which are members of NEPOOL, filed a suit in Massachusetts Superior Court against the investor-owned utilities that are also members of NEP00L.

The suit alleges damages by NEP00L's establishment of minimum size requirements for generating units designated as pool-planned generating units. The suit names as defendants members of NEPOOL, including the Company. Management cannot predict the ultimate outcome of this proceeding at this time. Discovery has not begun, p pending resolution of certain procedural matters. The FERC initiated an action V 25

ultimate outcome of this proceeding at this time. Discovery has not begun, pending resolution of certain procedural matters. The FERC initiated an action A when the EUA subsidiaries and other participants filed an amendment to the h NEP00L Agreement with the FERC that concerns many of the issues raised in the Massachusetts litigation. The plaintiffs in the Massachusetts litigat4on and one other participant have obj ected to the amendment, and have sought to prevent or delay its effectiveness. The FERC has not yet determined whether or when it will hold hearings on this matter. Management cannot predict the ultimate outcome of this proceeding at this time. In June 1991, the State of New Hampshire imposed a Nuclear Station Property Tax applicable only to the Seabrook Project. The Company paid its share of the tax, aggregating $4.2 million through December 31, 1992. In October 1991 the Attorneys General of Connecticut, Massachusetts and Rhode Island petitioned the United States Supreme Court in an original jurisdiction case for a determination of the legality of the tax, and in January 1992 the Supreme Court agreed to take the case. The parties to the litigation and other Joint owners of Seabrook entered into a Settlement Agreement on April 13, 1993. In general, the terms of the Settlement Agreement are expected to result in a significant reduction in annual state taxes paid by the Company. In addition, under the terms of the Settlement Agreement, certain of the prior payments of the tax by the Company will be permitted to be credited against future taxes due. The Bankruptcy Court has approved the Settlement Agreement with respect to the Company. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ( The response to this item is submitted in the response found under Item ( 14(a)(1) in this report. Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES ~ None. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT (a), (b), (c), (d) and (e) The name, age and position of the sole director and executive officer of the Company as of March 21, 1994, are listed below with his business experience during the past five years. ~ O 26

Name, Age Business Experience _/\\ and Position Durinn Past 5 Years h i John R. Stevens, 52 Director since July 1987; President. since Director and President August 1990;ExecutiveVicePresident(from October 1987 to July 1990; Preside 6t of.EUA since July 1990; Senior Executive Vice President of EUA from January 1990 to June 1990; Chief Operating Officer of EUA. since January 1990; Executive Vice President of EUA from June 1987 to December 1989. Mr. Stevens is also President, Trustee and Chief Operating Officer of EUA; Vice Chairman and Director of Bit.ckstone Valley Electric Company, Eastern Edi-son Company, Newport Electric Corporation and EUA Cogenex Corporation; Presi-dent and Director of EUA Energy Investment Corporation, EUA Ocean State Corpora-tion, EUA Service Corporation and Montaup Electric Company. Messrs. Richard M. Burns, Arthur A. Hatch, Clifford J. Hebert, J r., William F. O'Connor, Donald G. Pardus and John R. Stevens, who have been officers or direc-tors of the Company since its formation in 1986, resigned their positions effec-tive December 30, 1992, with the exception of Mr. Stevens who remains the sole officer and director of the Company. Mr. Stevens serves at the request, and subject to direction of the Bondholders Committee. The Bondholders Committee has disclosed the names of two individuals proposed to serve on the Board of Directors of the Company (the New Board) after the O(/ Effective Date. The proposed two members of the New Board are John A. Tillinghast and Walter H. Goodenough. The Bondholders Committee is also consid-ering other candidates to serve as members of the New Board. The persons who will serve on the New Board will be finally determined befo're the Effective Date. The New Board will take office upon the Effective Date. The New Board will serve until its members resign or are replaced in accordance with New Hampshire corporate law and the requirements of the Company's charter and by-laws. Name, Age Business Experience and Position Durinn Past 5 Years John A. Tillinghast, 66 Chairman of the Energy Board of the National Director upon Effective Academy of Sciences and President of Date Tillinghast Technology Interests, a Consul-tant to the US utility industry. Walter H. Goodenough, 54 Consultant to the U.S. utility industry Vice Director upon Effective President - Public Affairs, Texas Utilities Date Se rvices. Vice President - Finance, Texas Utilities Services. Treasurer, Texas Utilities Company. A 27

l Mr. Tillinghast has more than 30 years of experience in the utility industry in various functions. In his current employment, Mr. Tillinghast O serves as consultant to various corporations relative to cogeneration, L' alternative energy p roj ects, third party power generation and general restructuring of the US utility industry. Mr. Tillinghast holds a K.S. in Mechanical Engineering from Columbia University. i Mr. Goodenough has more than 30 years of utility experience with the Texas Utilities System. Before joining Texas Utilities Services in 1983, he worked for twenty years at Texas Power & Light Co. where he became Vice President and CFO. Mr. Goodenough has been involved in all executive management aspects of the utility business including direct responsibility in financial management resource

planning, investor relations, rates and regulation, governmental affairs and field operations.

Currently, he is retired from the Texas Utilities System and serves as a consultant to the U.S. utility industry. Mr. Goodenough is a Certified Public Accountant and holds a B.A. in accounting from Texas A&M University. (f) Except for the Registrant's Chapter 11 filing, there have been no events under any bankruptcy

act, no criminal proceedings-and no judgments or injunctions material to the evaluation of the ability and integrity of any director or executive officer during the past five years.

Item 11. EXECUTIVE COMPENSATION The executive officer of the Company receives no compensation from the Company. O Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT .) (a) Security ownership of certain beneficial owners. Pursuant to the terms of the Settlement Agreement, the Company redeemed all of its outstanding common aad preferred stock on February 5, 1993 (See Item 1, Bankruptcy Proceeding). (b) Security ownership of Management as of March 21, 1994. None (c) Except as described under Bankruptcy Proceeding (See Item 1) the Company knows of no contractual arrangements which may at a subsequent date result in a change in control of the Company. Icem 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None PART IV Item 14. EXHIBITS, FININCI,AL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. U 28

I 9 (a)(1) Financial Statements: O The following financial statements and supplementary data are filed herewith as required by Item 8. for the three years in the period ended Dkeember Statements of Loss 31, 1993. Statements of Retained (Deficit) Earnings for the three years in the. . period ended December 31, 1993. Statements of Cash Flows for the three years in the period ended December 31, 1993. Balance Sheets at December 31, 1993 and 1992. Statements of Capitalization at December 31, 1993 and 1992. Notes to Financial Statements at December 31, 1993, 1992 and 1991. Report of Independent Accountants dated April 7, 1994. (a)(2) Financial Statement Schedules: The following additional financial statement schedules are filed herewith. 1. Financial Statement Schedules: Schedule V - Property, Plant and Equipment for the three years ended December 31, 1993. Schedule VI - Accumulated. Depreciation. Depletion and Amortization of Property, Plant, and Equipment for the three years ended December 31, 1993. Schedule IX - Short-term Borrowings for the three years ended December 31, 1993. Schedule X - Supplementary Income Statement Information for the three years ended December 31, 1993. All other schedules have been omitted since the required information is not-present or not sufficiently material' to require submission of the schedule, or because the information required is included in the financial statements or the notes thereto. . (a)'(3) Exhibits (* denotes filed ' herewith) 3-1 Articles of. Incorporation of EUA Power Corporation, as amended (Exhibit 3-1, Registration No. 33-10978; Exhibit 3-3, Form 10-K of EUA Power for 1988 File No. 33-10978). 3-2 By-Laws of EUA Power Corporation as amended (Exhibit 3-2 Form 10-K of EUA Power for 1988 File No. 33-10978). 29 ~

1 .I ) 3-3 Articles of Amendment to the Articles of Incorporation of EUA Power 1 Corporation changing corporate name from EUA Power Corporation to Great Bay Power Corporation. 4-1 Indenture of EUA Power Corporation to State Street Bank and Trust (Exhibft 4-1 {

Company, Trustee, dated as of November 15, 1986 Registration No. 33-10978).

4-2 First' Supplemental Indenture dated as of February 24, 1987. of EUA Power Corporation (Exhibit 4-35, Form 10-K of EUA for 1986, File No. 1-5366). 4 Second Supplemental Indenture dated as of May 1, 1988 of EUA Power Corporation. (Exhibit 4-40, Form 10-K of EUA for 1988 File No. 1-5366). 4-4 Third Supplemental Indenture dated as of November 1, 1988 - of EUA Power Corporation (Exhibit 4-41, Form 10-K of EUA for 1988 File No. 1-5366). 4-5 Form of Note Purchase Agreement (Exhibit 1, Certificate of Notifi-cation Pursuant to Rule 24 File No. 70-7161). 4-6 Form of Note Exchange Inducement Agreement (Exhibit 4-6, Registration No. 33-23127). 4-7 Form of Registration Rights Agreement relating to Exhibit 4-6 (Exhibit 4-7, Registration No. 33-231270). 10-1 Agreement of Purchase and Sale between Bangor Hydro-Electric Company ("BHCE") and Eastern Utilities Associates ("EUA") dated February 19, 1986 (Exhibit B-6, File No. 70-7161). 10-2 Addendum to Agreement of Purchase - and Sale between BHEC and EUA (Exhibit B-6(a). File No. 70-7161). 10-3 Agreement of Purchase and Sale between Central Maine Power Company ) ("CMPC") and EUA dated February 19, 1986 - (Exhibit - B-7,~ File No. 70-7161). 10-4 Addendum to Agreement of Purchase and Sale between CMPC. and' EUA (Exhibit B-7(a), File No. 70-7161)'. { 10-5 Agreement of Purchase and Sale between Central Vermont Public Service Corporation _ ("CVPSC") and EUA dated as of February 19, 1986 (Exhibit B-8, File No. 70-7161). 10-6 Addendum to Agreement of Purchase and Sale between CVPSC and EUA (Exhibit B-8(a), File No. 70-7161). 10-7 Agreement of Purchase and Sale between Maine Public Service Company ("MPSC") and EUA dated April 7, 1986 (Exhibit B-9, File No. 70-7161).- 10-8 Addendum to Igreement of Purchase ' and Sale between MPSC and EUA (Exhibit.B-9(a), File No. 70-7161). 30

10-9 Agreement of Purchase and Sale between Fitchburg Gas and Electric Company ("FG&E") and EUA dated April 8, 1986 (Exhibit B-1, File No. 70-7251). LJ 10-10 Addendum to Agreement of Purchase and Sale between FG&E gnd EUA (Exhibit B-1(a), File No. 70-7251). i 10-11 Agreement dated as of May 1, 1973 for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities including Montaup, ' as amended as of May 24, 1974, June 21, 1974, September 25,

1974, October 25, 1974 January 31,

1975, as supplemented by Letter Agreement dated April 27, 1978 and amended as of April 18, 1979 (two amendments), April 25, 1979, June 8, 1979, October 11, 1979, December 15, 1979, June 16, 1980 December 31, 1980, June 1, 1982, April 27, 1984, June 15, 1984, March 8,

1985, March 14, 1986 May 1, 1986 March 14, 1986, May 1, 1986. September 1, 1986, November 1987, January 13, 1989 and November, 1990. (Exhibit 13-57, Registration No. 2-48966; Exhibit B-6, Form U5S of EUA for year 1974; Exhibit 5-130, Registration No. 2-62862; Exhibit 5-70 Registration No. 2-65785; Exhibit 2, Form 10-K of EUA for 1979, File No. 1-5366; Exhibit 5-34, Registration No. 2-69052; Exhibit 10-36, Form 10-K of EUA for 1980, File No. 1-5366; Exhibit 10-69 Registration No. 2-80205; Exhibit 2 Form 10-Q of EUA for the Quarter Ended March 31, 1984, File No. 1-5366; Exhibit 3, Form 10-Q of EUA for the Quarter i Ended June 30, 1984, File No. 1-5366; Exhibit 10-70, Form 10-K of EUA for 1985, File No. 1-5366; Exhibits 10-80 and 10-81 Form 10-K of EUA I for 1986, File No. 1-5366; Exhibits 10-95 and 10-96, Form 10-K of EUA q for 1987 File No. 1-5366; Exhibit 10-101 Form 10-K of EUA for 1988, j Q File No. 1-5366; Exhibit 10-110, Form 10-K of EUA for 1990 File No. I 1-5366). 1 10-12 Decommissioning Costs Security Agreement of November 25, 1986 (Exhibit A-7, File No. 70-7161). 10-13 Agreement dated as of October 20, 1986 among BHCE, CMPC, CVPSC, MPSC and EUA Power Corporation relating to the use of certain transmission facilities (Exhibit 10-13, Registration No. 32-10978). 10-14 Settlement Agreement dated November 18, 1992 among EUA Power Corporation. Eastern Utilities Associates and the Official Bondholders' Committee of EUA Power Corporation (Exhibit 10-69 Form 10-K of EUA for 1992, File 1-5366).

• 10-15 Power furchase Agreement between UNITIL Power Corporation and the Company dated May 1, 1993.
• 10-16 Power Purchase option Agreement between UNITIL Power Corporation and the Company dated May 1, 1993.

10-17 Marketing Agent Agreement between UNITIL Corporation and the Company dated April 1, 1993. (Exhibit 10-17, Form 10-K of the Company for 1992, File No. 33-10978) /"N \\ ) v 31

10-18 Stipulation and Consent Order for 1993-1994 Financing by Participating Joint Owners. (Exhibit 10-18 Form 10-K of the Company for 1992. File No. 33-10978) 10-19 Bondholders' Committee Fifth Amende/. Plan of Reorganization (Exbibit 10-19, Form 10-K of the Company fo 1992 File No. 33-10978), i

• 10-20 Bondholders' Committee First Modiliication to Fifth Amended Plan of Reorganization.
• 10-21 Second Mortgage granted to UNITIL Power Corporation by the Company dated December 22, 1993.

l l

• 10-22 Mortgage granted to UNITIL Power Corporation by the Company dated December 22, 1993.

(b) Reports on Form 8-K. None. l l- ) i l I l ~

1. NN

) t..~' 1 32

SIGNATURES /^ Pursuant to the requirements of Section 13 or 15(d) of the Securities ( Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. i Signature Title Date i GREAT BAY POWER CORPORATION ~ By /s/ John R. Stevens President and Director John R. Stevens (Principal Executive. April 7, 1994 Financial and Accounting Officer) ^. M

O \\ '} / 1 t ] (This page left blank intentionally) l l O e m. O ~ 34

GREAT BAY POWER CORPORATION Item 8 and Item 14(a)(1) Financial Statements and i s Supplementary Data l Item 14(a)(2) j Financial Statement Schedules O 35

1 GREAT BAY POWER CORPORATION (f.k.a. EUA Power Corporation) ~ STATEMENTS OF LOSS Demmber 31, g~g (Debtor-in-Possession)(In Thousands) 4 V 1993 1992 1991 Operating Revenues 24,620 $ 23,027 $ 20,919 Operating Expenses: Fuel 6,869 6,735 7,133 Other Operation 13,052 15,411 15,494 Maintenance 3,070 4,677 5,269 Reorganization - nses 1,867 1,699 1,069 Depreciation and ortization 9,020 8,816 8,737 Taxes Other Than Income (Schedule X) 3,878 6,077 3,948 income Tax (Credit) (630) (17,497) (3,444) i Deferred Taxes (Credit) (3,421) 42,245 (7.237) Total Operating Expenses 33,705 68,163 30,% 9 Operating (Loss) (9,085) (45,136) (10,050) Deferred Income Taxes (459) (919) Other Income - Net 226 (47j 287 Ir.come Before Interest Charges (9.318) (46,102) (9,763) Interest Charges: Interest on Long-Term Debt (ContractualInterest Expense for 1993 and 1992 was $48,929,510, respectively, and for 1991 was $50,071,437) 8,204 Other Interest Expense (Contractual Interest Expense for 1993,1992 and 1991 was $114,763, $2,099,954, aod $2,744,427, respectively) 115 1,366 1,825 b Net Interest Charges 115 1,366 10,029 Net Loss (9.433) $ (47,468) $ - (19.792j 8 STATEMENTS OF RETAINED (DEFICIT) EARNINGS Years Ended December 31, (Debtor-in-Possession)(In nousands) 1993 1992 1991 Retained (Deficit) Earnings - Beginning of Year : (130,360) $ (82,892) $ (63,100) Net Loss (9,433) (47,468) (19,792) Retained (Deficit) Earnings - End of Year 5 (139.793) $ (110,1@) $ (82 192) C BWamb DOlCS RM 3D blepipd Ohbc finan&l5UlemeDU. 36

GREAT BAY POWER CORPORATION (f.k.a. EUA Power Corporation) STATEMENTS OF CASH FLOWS [] December 31, 's ) (Debtor-in-Possession)(In Thousands)

s i

1993 1992 1991 CASII FLOW FROM OPERATING ACTIVITIES: Net Loss (9,433) $ (47,468) $ (19,792) Adjustments to Reconcile Netloss to Net Cash Provided by Operating Activities: Depreciation and Amortization 8,124 8,002 8,472 Amortization of Nuclear Fuel 5,818 5,853 6,453 4 Deferred Taxes (2,962) 37,155 (7,114) r Investment Tax Credit, Net (630) (268) (269) Other - Net 1,026 (2,169) (1,855) Net Changes of Working Capital: Accounts Receivable (97) 3,793 145 Accounts Payable (122) (910) 1,030 Accrued Taxes 139 (12,017) 2,583 Other - Net (1,401) 4.245 5,382 Net Cash (Used In) Provided from Operating Acthities 462 (3,784) (4,%5) CASli FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (6,885) (2,464) (4,614) m Net Cash (Used In) Provided From Investing Activities (6,885) (2,464) (4,614) ) CASII FLOW FROM FINANCING ACTIVITIES. Issuances: Financing Expenses (542) Debtor-in-Possession Financing 1,744 (9,068) 9,068 Settlement Proceeds 20,000 Net Increase in Short-Term Debt 1,170 Net Cash Provided from Financing Activities 1,744 10,932 9,6% Net Increase (Decrease)in Cash (4,679) 4,684 117 Cash and Temporary Cash Investments at Beginning of Year 4,817 133 16 Cash and Temporary Cash Investments at End of Period 138 $ 4.8A $

133, Cash paid during the year for:

Interest 1,619 $ 316 Income Taxes (Benefits) (2,200) 4 e 37

GREAT BAY POWER CORPORATION (f.k.a. EUA Power Corporation) BALANCE SHEETS p December 31, 'Q (Debtor-in-Possession)(In Thousands) i ASSEIS \\ 1993 1992 Utility Plant and Other Investments: Utility Plant and Nuclear Fuel (Schedule V) 542,180 $ 536,620 Less: Accumulated Provision for Depreciation (Schedule VI) and Amortization 56,556 38,145 Provision for Estimated Loss on Seabrook Investment 51,459 52,903 Deferred Allowance for Funds Used During Construction 122 233_ 126,583 2 f Total Net Utility Plant 311,932 318,989 Current Assets: Cash and Temporary Cash Investments 138 4,817 Accounts Receivable: Customers 2,470 2,373 Prepaid Scabrook Funding 4,044 2,342 Other Current Assets 43 168 Total Current Assets 6,695 9.700 Deferred Debits: Unamortized Debt Expense 5,069 5,069 Other Deferred Debits 894 Total Deferred Debits 5,%3 5,069 Total Assets 324.590 $ 333.758 O CAPITALIZA110N AND LIABILITIES Capitalization: Common Equity (139,783) $ (130,350) Redcemable Preferred Stock 63,090 63,090 TotalCapitalization (76,693) (67,260) Liabilities Subject to Compromise : Long-Term Debt due within One Year 279,597 279,597 Accounts Payable 141 141 Interest Accrued 14,126 14,126 Total Liabilities Subject to Compromise 293,864 293,864 Liabilities Not Subject to Compromise : Accounts Payable 91 213 Taxes Accrued 581 442 Debtor-in-Possession Financing 1,744 UnamortizedInvestment Tax Credits 6,778 7,412 Accumulated Deferred Taxes 51,484 54,444 Other Liabilities and Deferred Credits 46,741 44,643 Total Liabilties Not Subject to Compromise 107,419 107.154 Commitments and Contingencies (B,G) Total Liabilities and Capitalization 324.590 $ 333.758 () Denotes Contra ~. (v The acrumpanying notes are an integralpart of the financialstatements. 38

9 GREAT BAY POWER CORPORATION (f.k.a. EUA Power Corporation) STATEMENTS OF CAPITALIZATION December 31, (Debior-in-Possession)(In nousands) 1993 1992 Common Eq Common and related AdditionalPaid-In Capital, $.01 par value, authorized, issued and outstanding 10,000 shares 10 $ 10 Less: Treasury Stock,10,000 Shares (10) (10) Paid-In Capital-Treasury Stock 10 10 Retained earnings (139,793) (130,360) Total Common Equity (139.783) __(130,MQ) Redeemable Preferred Stock. Class A 25% Cumulative Convertible Preferred Stock, $100 par value authorized 750,000 shares, issued and outstanding 630,900 shares 63,090 63,090 Less: Treasury Preferred Stock,630,900 Shares (63,090) (63,090) Paid-In Capital-Treasury Stock 63,090 63,090 Total Preferred Stock 63.093 _ 63.090 Long-term Debt Subject to Compromise 17-1/2% Series B Secured Notes due 1993 180,000 180,000 17-1/2% Series C Secured Notes due 1992 99,597 99,597 Total 279,597 279,597 less Portion due within One Year 279.597 279.597 Total Long-Term Debt 0 0 Total Capitalization (76.693) $ (612@) f% NC ANDmpan)$D$ DOlCS BrC 3D $DiegTalpBT! OflbC [IDBDCialStalCments. 39

.~ h GREAT BAY POWER CORPORATION b NOTES TO FINANCIAL STATEMENTS December 31, 1993, 1992 and 1991 3 Note A - Business: The Registrant, Great Bay Power Corporation (formerly known as EUA Power Corporation), is a New Hampshire corporation, incorporated in 1986, authorized by the NHPUC to engage in business as a public utility for the purposes of participating as a joint owner in the Seabrook Proj ect, acquiring its 12.1% interest in the Seabrook Proj ect and selling its share of the output of Seabrook Unit 1 for resale. The Company, organized as wholly-owned subsidiary of EUA, became fully independent of EUA on February 5, 1993 in connection with s the bankruptcy proceeding described in Note B Bankruptcy Proceeding. The Company became a wholesale generating company when Seabrook Unit 1 commenced commercial operation on August 19, 1990. On February 28, 1991, the Company filed a voluntary petition in the Bankruptcy Court for the District of New Hampshire for protection under Chapter 11 of the Bankruptcy Code. The Bankruptcy Court confirmed the Bondholders Committees' Fifth Amended Plan of Reorganization on March 5, 1993. After confirmation, the Company was unable to obtain the $45 million of debt financing contemplated by the Fifth Amended Plan of Reorganization. In February 1994, however, the Bondholders Committee obtained a commitment from Omega Advisers, Inc. (" Omega") or its designees to provide $35 million of equity financing for the Company (the " Omega Financing"). The Bondholders C; Committee prepared a First Modification to Fifth Amended Plan of Reorganization I to reflect this change in financing and submitted a Supplemental Disclosure Statement describing that First Modification to the Bankruptcy Court for its approval. The Fifth Amended Plan of Reorganization, as modified by the First Modification is hereinafter referred to as the " Plan." The Bankruptcy Court approved the Supplemental Disclosure Statement at a hearing on March 11, 1994. The Plan is scheduled to be mailed to the Company's creditors for their approval on or before April 7, 1994. If the Creditors approve the Plan, the Company expects the Bankruptcy Court to confirm the plan in a hearing currently scheduled for May 13, 1994, although such confirmation cannot be assured. The Omega Financing and the Plan are subj ect to approval by certain regulatory authorities. On February 15, 1994 the Nuclear Regulatory Commission issued an order approving a transfer of control of the Company as contemplated by the Omega Financing and extending the deadline for completion of such transfer to June 30, 1994 There can be no assurance that other Ev.h approvals will be obtained. Moreover, the Omega Financing is not yet reduced to a definitive agreement. the Plan will not be circulated to creditors unless and until such a definitive agreement has been signed. The Omega Financing provides for the Company to sell its common stock representing a 60% ownership interest in the Company to Omega or its designees for an aggregate purchase price of $35 million. The 40% balance of the Company's common stock will be issued 34% to the Company's Bondholders in full payment and satisfaction of their secured claims and 6% to the Company's unsecured creditors wi3h claims in excess of $25,000 in full payment and satisfaction of their claims. These unsecured claims consist primarily of the ( } unsecured deficiency claims of the Bondholders under the Bonds. (See wJ 40 1 A

I Bankruotev Proceedinn below for a discussion of the Company's bankruptcy proceeding and the Omega Financing.) O V Seabrook Unit 1 is a 1,150 MW nuclear generating plant located in Seabrook, New Hampshire. The Company acquired its joint ownership 11nte{est in the Seabrook Project for approximately $174,000,000 in November 1986,f rom five New England electric utilities in indapendently negotiated transactions. At that time, construction of Seabrook Unit 1 was substantially completed. Because Seabrook Unit 2 had been cancelled, the Company assigned no value to it. On March 29, 1991, the Company announced that it had provided an impairment reserve in 1990 against its investment in Seabrook Unit 1. At December 31, 1993, the Company's net investment in Seabrook Unit 1, including nuclear fuel, was approximately $312 million. The Company has no employees. John R. Stevens, president of EUA serves as president and sole director of the Company at the request and subject to the direction of the Bondholders Committee. Mr. Stevens expects to resign both positions on the Effective Date. Since the Company's organization, EUA Service, a wholly owned subsidiary of EUA, has provided, or arranged for, various management and professional services. Pursuant to various Bankruptcy Court orders, EUA Service continues to provide similar services to the Company. Under the terms of the Settlement Agreement (as discussed below). EUA Service will continue to provide, at cost, certain services to the Company at the request of the Bondholders Committee for a period of not more than two years from the effective date of the Settlement Agreement. However, such services specifically exclude the marketing of the Company's entitlement in Seabrook Unit 1 on a long-term basis. The Company has agreed with UNITIL that an affiliate of UNITIL will replace EUA Service in providing various services n on the Effective Date. In addition, the Company has entered into a contract v with an affiliate of UNITIL pursuant to which that affiliate is marketing the Company's share of electricity from Seabrook Unit 1. Note B - Bankruptcy Proceeding:

Background:

On February 28, 1991, the Company filed a voluntary petition in the Bankruptcy Court for the District of New Hampshire for protection under Chapter 11 of the federal Bankruptcy Code and has been conducting its business as a Debtor and Debtor-in-Possession under the provisions of the Bankruptcy Code. The Company filed such petition because the cash generated by short-term sales of electricity from its entitlement in Seabrook Unit 1 would have been insufficient to pay interest on its outstanding Secured Notes when interest became due on May 15, 1991 and the prospects for signing long-term power sales contracts prior to that date were minimal. The Company continues its efforts to market its entitlement to Seabrook Unit i under the direction of the Bondholders Committee. Settlement Agreement: On November 18, 1992, the Company, the Bondholders Committee and EUA entered into a Settlement Agreement which resolved certain adversary proceedings against EUA,

brought, or threatened to be brought, by the Bondholders Committee incl.uding, (i) a claim for recovery of certain alleged

[] preferential transfers in the aggregate amount of $38.5 million, plus interest; V 41 I

(ii) a threatened claim for the recovery of $100 million plus treble damages arising from, among other things, certain alleged breaches of fiduciary duties N by EUA, (Q ~ EUA Service and the officers and directors of the Company; and, (iii) certain matters arising out of tax sharing agreements between EUA, its subsidiaries, and the Company. The Settlement Agreement also provided (or the } payment of $20 million to the Company by EUA. The Settlement Agreemen,t further l provided for the relinquishment by EUA of its equity interest in the Company and all claims filed in Bankruptcy Court by EUA and its affiliates against the Company. These claims related primarily to obligations of the Company guaranteed and paid by EUA, including $21 million of Solid Waste Disposal Facility Revenue Bonds, issued by the New Hampshire Industrial Development Authority.n behalf of the Company and other notes payable. The settlement of these claims was recorded as a deferred credit on the Company's 1992 Balance i

Sheet, pending the ultimate outcome of the Bankruptcy Proceeding.

The Settlement Agreement became effective on December 30, 1992 at which time EUA paid $20 million to the Company. The Company used a substantial portion of the / proceeds from the Settlement Agreement to repay amounts outstanding under the First Stipulation (as described below) and to pay reorganization expenses and other operating expenses. The Company redeemed all of its outstanding equity securities which were held by EUA, at no cost, on February 5, 1993. The redeemed shares have been classified as treasury stock on the Company's financial statements as of December 31, 1993 and 1992. As a result of the redemption, the Company is no longer part of the EUA System. Under the Settlement Agreement, EUA reaffirmed its guarantee of up to $10 million of the Company's share of future decommissioning costs of Seabrook Unit 1 and any costs of cancellation of Seabrook Unit 1 or Unit 2. EUA had i guaranteed this obligation in 1990 in order to secure the release to the Company of a $10 million fund established by the Company for the same purpose i at the time the Company acquired its Seabrook Interest. Further, under the l Settlement Agreement, all of the officers and directors of the Company (except Mr. Stevens) resigned and the Company changed its name to ' Great Bay Power Corporation. EUA now has no ownership interest in the Company. Reorganization Plan: The Bankruptcy Court confirmed the Bondholders Committees Fifth Amended Plan of Reorganization on March 5, 1993. After confirmation, the Company was unable to obtain the $45 million of debt financing contemplated by the Fifth ) Amended Plan of Reorganization. In February 1994, however, the Bondholders l Committee obtained a commitment from Omega or its designees to provide $35 million of equity financing for the Ccmpany. The Bondholders Committee i prepared a First Modification to Fifth Amended Plan of Reorganization to reflect this change in financing and submitted a Supplemental Disclosure Statement describing that First Modification to the Bankruptcy Court for its approval. The Bankruptcy Court approved the Supplemental Disclosure Statement at a hearing on March 11, 1994. The Plan is scheduled to be mailed to the Company's creditors for their approval on or before April 7, 1994. If the Creditors approve the Plan, the Company expects the Bankruptcy Court to confirm the Plan in a hearing currently scheduled for May 13, 1994, although such confirmation cannot be assured. The Omega Financing and the Plan are subject to approval by certain regulatory authorities. On February 15, 1994 the Nuclear Regulatory Commission issued an order approving a transfer of control of the Company as contemplated by the Omega Financing and extending the deadline for completion of such transfer to June 30, 1994. There can be no v 42

assurance that other such approvals will be obtained. Moreover, the Omega Financing is not yet reduced to a definitive agreement. The Plan will not be A circulated to creditors unless and until such a definitive agreement has been h signed. The Omega Financing provides for the Company to sell its commgn \\ stock representing a 60% ownership interest in the Company to Omega or its designees for an aggregate purchase price of $35 million. The 40% balance of the Company's common stock will be issued 34% to the Company's Bondholders in full payment and satisfaction of their secured claims pursuant to the Bonds and 6% to the Company's unsecured creditors with claims in excess of $25,000 in full payment and satisfaction of their claims. These unsecured claims consist primarily of the unsecured deficiency claims of the Bon,dholders under the Bonds. The holders of unsecured claims of less than $25,000, other than those unsecured claims resulting from the ownership of the Secured Notes, will be s paid 50% of the amounts of their claims allowed by the Bankruptcy Court in cash on the Effective Date. The Plan requires that prior to the Effective Date the e Bondholders Committee obtain the Omega Financing. Although a bar date for all claims has been entered and passed, claims arising from the rejection of contracts or claims which the Bankruptcy Court permits to be filed notwithstanding the bar date may dilute the percentage of the unsecured claims held by the Secured Bondholders. All of the previously issued and outstanding equity securities of the Company have been redeemed by the Company. The CICs issued in connection with the Series B Notes or otherwise will be extinguished on the Effective Date. After the Effective Date, the equity of the Company will be represented by a single class of common stock. The Company will use good faith efforts to list its shares of common N stock so that they will be tradeable on the American Stock Exchange or the (h NASDAQ National Market System. The Bondholders Committee has appointed or will appoint a' gents to manage the Company's business and to market the Company's share of Seabrook electricity. During the period between the Confirmation of the Plan and the Effective Date, those agents are to report to the Bondholders Committee and, to the extent actions are to be taken outside of the ordinary course of business, such actions shall be subject to the approval of the Bankruptcy Court and regulatory bodies with jurisdiction under applicable law. John R.

Stevens, president of EUA, expects to resign as president and director of the Company on the Ef fective Date. The Bondholders Committee has disclosed the names of two individuals proposed to serve on the Board of Directors (the New Board) of the Company af ter the Effective Date.

The proposed two members of the New Board are John A. Tillinghast and Walter H. Goodenough. The Bondholders Committee is also considering other candidates to serve as members of the New Board. The persons who will serve on the New Board will be finally determined before the Ef fective Date. The New Board will take office upon the Effective Date. The New Board will serve until its members resign or are replaced in accordance with New Hampshire corporate law and the requirements of the Company's charter and by-laws. The effectiveness of the Plan is conditioned upon obtaining plan of reorganization financing and approvals from various regulatory agencies including the NRC. The _ Company has obtained the approval of the NRC, provided the Company obtains plan of reorganization financing. The Company cannot predict whether it will be able to obtain plan of reorganization financing or 43

whether the plan, or any other plan if filled, will be approved by the various regulatory agencies having jurisdiction. DIP Financing: 1 j The Company is required under the JOA to pay its share of Seabrook Unit 1 and Seabrook Unit 2 expenses including, without limitation, operations and maintenance

expenses, construction and nuclear fuel expenditures and decommissioning costs, regardless of Seabrook Unit l's operations.

Under certain circumstances, a failure by the Company to make its monthly payments under the JOA could adversely affect its entitlement in Unit 1. At current market prices, the cash generated by such electricity sales continues to be less than the Company's on-going cash requirements. On August 29, 1991, the Bankruptcy Court approved a Stipulation and ~ Consent Order (the First Stipulation) with respect to DIP Financing to be provided by certain joint owners of Seabrook for the benefit of the Company. e The First Stipulation was entered into by the Company and CL&P and UI (the Participating Joint Owners), two of the other eleven joint owners of the Seabrook Project, as well as the Bondholders Committee. The First Stipulation was also approved by the NHPUC and the SEC under the 1935 Act. On July 21,

1992, the Bankruptcy Court issued a procedural order permitting an extension of the First Stipulation.

For the period after September 30, 1992 until March 5,

1993, the procedural order permitted continued debtor-in-possession financing on a month-to-month basis at the sole discretion of the Participating Joint Owners terminable on 30 days notice.

The Bankruptcy Court issued a second procedural order on September 8, 1992 { increasing to $22 million from $15 million the amount of advances outstanding ( at any one time permitted under the First Stipulation. The Participating Joint owners continued to advance funds under the First Stipulation, as amended, until the amounts advanced thereunder were repaid with the " proceeds of the Company's Settlement Agreement with EUA. The First Stipulation expired on March 5, 1993. A second stipulation was entered into by the Company and the Participating Joint Owners and was approved by the Bankruptcy Court. and various regulatory l authorities. However, that stipulation did not become effective, and on March 5, 1993, the Company and the Participating Joint Owners entered into a third stipulation (the Third Stipulation) which was approved by the Bankruptcy Court. The Third Stipulation provides that the Participating Joint Owners shall provide up to a maximum of $20 million in advances to the Company to enable the Company to pay its p_to rata share of the Seabrook Project's operating expenses, expenses of the Company in connection with its Chapter 11 proceedings and t certain other costs of operation of the Company. Pursuant to the Third Stipulation, the advances made by the Participating Joint. Owners bear an interest rate equal to the prime rate of The First National Bank of Boston plus 7% per annum. The Third Stipulation provides the Participating Joint Owners with a priority lien on all the Company's assets, which lien has priority over the Bondholders ' mortgagt The Third Stipulation further provides that in the event of a default thereunder, the Participating Joint Owners are entitled to purchase the Company's Seabrook Interest for 75% of the lesser of fair market value or book value and to apply all or part of the amounts owing under the l {J Third Stipulation against the purchase price. The Third Stipulation terminates 44

on the earliest to occur of (a) July 1, 1994 (b) the Effective Date or the closing of a sale of all or substantially all of the Company's assets or ['

business, and (c) an event of default under the terms of the Third Stipulation.

The Company is in default of the Thied Stipulation for, among other reasons, failure to obtain financing for the rian by the date required in the Third Stipulation. /,1thoughtheCompanyhasbeenindefaultsinceNkvember 1, 1993, the Participating Joint Owners have continued to provide Tinancing pursuant to the Third Stipulation. There is, however, no assurance that they will continue to do so. As of March 25, 1994, outstanding advances under the Third Stipulation were approximately $2.2 million in the aggregate. J If the Plan is confirmed by the Bankruptcy Court and the Omega Financing is obtained, the Company will repay amounts owing under the Third Stipulation out of the proceeds of the Omega Financing. The Company cannot predict whether the Plan will be confirmed or the Omega Financing obtained. Other Matters: The Company's reorganization expenses are subject to approval by the Bankruptcy Court. For the period March 1, 1991 through August 31,

1993, professionals have submitted fees and expenses in the amount of approximately

$5.9 million to the Bankruptcy Court for its approval, and the Bankruptcy Court has provisionally authorized, subject to its review at the conclusion of the Chapter 11 proceeding, payments of approximately $4.5 million. The Company has paid amounts provisionally authorized by the Bankruptcy Court, and those are reflected on the Company's Statement of Loss during the period in which they have been paid. 0 Since August 31, 1993, no hearings on approval of reorganization expenses have been held and no requests for allowance for such expenses have been made. According to the Supplemental Disclosure Statement, the Bondholders Committee has budgeted reorganization expenses payable on closing of thd Omega Financing and subject te Bankruptcy Court approval of $4.5 million. Under Chapter 11, certain claims against the Company in existence prior to the filing of the petition for relief under the Bankruptcy Code are stayed while the Company continues business operations as debtor-in-possession. These claims are reflected in the Company's Balance Sheet as of December 31, 1993 and December 31, 1992 as " Liabilities Subject to Compromise. " Additional claims (Liabilities Subject to Compromise) may arise subsequent to the filing date 1 resulting from rejection of executory contracts and from the determination by the Bankruptcy Court (or agreed to by parties in interest) of allowed i contingent and disputed claims. Enforcement of claims secured by certain of the Company's assets (secured claims) also are stayed, although the holders of such claims have the right to move the court for relief from the stay. Secured claims, principally the Secured Notes, are secured by an interest in certain ) Seabrook Project assets of the Company, principally realty and personalty. Note C - Summary of Significant Accounting Policies: System of Accounts: The accounting policies and practices of the Company are subj ect to regulation by FERC with respect to its rates and accounting. The accounts of the Company are maintained in accordance with the uniform system of accounts presEribed by FERC. O ~ 45

Utility Plant and Depreciation: Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct .O_ labor and material, allocated overhead, allowance for funds used during construction and indirect charges for engineering and supervision. For financial statement purposes, depreciation is computed on the straight-line method based on the estimated useful life of Seabrook Unit 1. Sin'ce the l. commencement of commercial operation, the provision for depreciation for the Company has been calculated at 2.5%. I Operatinn Revenues: Revenues are based on billing rates authorized by l FERC and are recognized when billed. 1 Income Taxes: The general policy of the Company with respect to accounting for federal income taxes is to reflect in income the estimated amount of taxes currently payable and to provide for deferred taxes on certain 8 items subject to temporary differences to the extent permitted by the various regulatory commissions. It is the policy of the Company to defer the investment tax credits and to amortize these credits over the productive lives of the related assets. Transactions with Affiliates: Prior to February 5, 1993, the Company was a wholly-owned subsidiary of EUA. EUA has interests in other retail and wholesale utility companies, a service corporation, and other non-utility companies. Transactions between the Company and EUA affiliated companies include the following: accounting, engineering and other services rendered by EUA Service of approximately $209,000, $420,000 and $647,000, in 1993, 1992 and 1991 respectively. Transactions with other affiliated companies are subject to \\ review by applicable regulatory commissions (See Note D - Income Taxes). Cash and Temporary Cash Investments: The Company considers all highly liquid investments with a maturity of three months or less when acquired to be cash equivalents. l l l f l l O ~ 46 l 1

1 i 9 ~ \\ Note D - Income Taxes: fV Components of income tax expense for the years 1993, 1992, and 1991 are as follows: 'l (In Thousands) 1993 1992 1991 t Federal: Current S $ (22.453) $ _(3,175) Deferred (3,421) 42,246 (7.237) Investment Tax Credit. Net (630) 4.955 (269) Total Charge to Operations (4.051) 24.748 (10.681) l Charged to other Income: Current 25 Deferred 459 919 123 Total Charged to Other Income 459 919 148 Total j,[g3g93}, g,,ggg gg, j,{}g3g3}} 6 Total income tax expense (credit) was different from the amounts computed by applying federal income tax at statutory rates to book income subject to tax for the following reasons: O V (In Thousands) 1993 1992 ~ 1991 Federal Income Tax (FIT) Computed at Statutory Rates (4,559) $ (7,412) $ (10,311) Increases (Decreases) in Tax from: Depreciation of Equity AFUDC 548 819 260 i Amortization of ITC (630) (269) (269) FIT Net Operating Loss Carryforward 926 Reversal of carryforwards due to uncertainties of realization after reorganization 32,527 Nuclear Decommissioning Costs 313 277 269 Other (190) (275) (482) Total Income Tax Expense (Credit) j,fg3gg3} j,,35gg{, j,f3ggggg} 3 ~ 47

\\ i The provision for deferred taxes resulting from temporary differences is comprised of the following:

q (In Thousands) 1993 1992 1991 i Debt Component of AFUDC (1,458)

(1,829) (1,815) Capitalized Overheads (59) (505) 184 Excess Tax Depreciation 7,181 8,069 9,817 Deferred Charges Net Operating Loss Carryforward (8,724) 26,907 (14,911) Provision for Estimated Loss on Seabrook Investment 459 919 Alternative Minimum Tax 9,985 Other (361) (382) (389) Total j,gg g}, {,,gg}64, g,gg}}g 9 The Company adopted FAS96 in 1990 which requires the use of the liability method to record deferred income taxes for temporary differences that are reported in different years for financial reporting and tax purposes. Under the liability method adopted by FAS96, deferred tax liabilities or assets are computed using the tax rates that will be in effect when the temporary differences reverse. Generally, for regulated companies, the changes in tax rates applied to accumulated deferred income taxes may not be immediately recognized in operating results because of ratemaking treatment and provisions in the Tax Reform Act of 1986. O V In February 1992 FASB issued Statement No. 109, " Accounting for Income Taxes," which essentially supersedes FAS96. As a result of,the adoption of FAS96 in 1990, FAS109, adopted in the first quarter of 1993, had no significant impact. At December 31, 1993 total deferred tax assets for which no valuation allowance was deemed necessary were $26.1 million and total deferred tax liabilities were $77.6 million. Total deferred tax assets and liabilities are comprised as follows: Deferred Tax Deferred Tax Assets Liabilities (000) (000) Plant Related Plant Related Differences $ 16,999 Differences $ 77,444 Other 9,073 Other 112 Total $ 26,072 Total $ 77,556

=

=

The Company has filed consolidated income tax returns together with EUA and other EUA affiliates. As a result of such consolidated filings, certain federal income tax benefits available to the Company have reduced the federal income tax obligations of EUA and such other EUA affiliates. Under a tax allocation agreement between EUA and its subsidiaries, EUA and its subsidiaries compensate each other fqr the use of the tax benefits. 1 O 48 ) 4

As a result of the redemption of the Company's outstanding common stock, the Company was deconsolidated from the EUA tax group effective February 5, 1993. Under the terms of the Settlement Agreement, EUA is entitled to utilize the Company's tax credits to reduce EUA's 1993 consolidated tax liability I without compensation (see Note B - Bankruptcy Proceeding). The Company wfl1 be i included in EUA's consolidated tax return for the years 1992 and 1993. i To the extent that the Company's carryforwards of net operating losses, ) investment tax credits, alternative minimum tax credits, and deductions attributable to built in losses are available after the Company is no longer part of the consolidated ietu e., the Company expects that these carryforwards will be significantly limited due to the impact of provisions of the tax law relating to the trett: ment of debt forgiveness in bankruptcy and the effect of [ changes in the ownership of the Company. As a result, the Company reversed accumulated tax benefits relating to carryforwards of net operating losses and s alternative minimum tax credits. The Company has $8.7 million of net operating r loss deduction carryforwards which expire in 2008. i Note E - Capital Stock: Common Stock: On December 31,

1993, the Company had issued and

[ outstanding, no shares of its Common Stock, par value $.01. Preferred Stock: At December 31, 1993, the Company had outstanding no shares of preferred stock. i Pursuant to the terms. of the Settlement Agreements, on February 5, 1993 the Company redeemed all of its outstanding common and preferred stock, which i were held by EUA, at no cost to the Company (See Note B - Bankruptcy Proceeding). The redemption has been classified as treasury stock on the Company's financial statements as of December 31, 1993 and 1992. f Note F - Long-Term Debt: 1 As a result of the Bankruptcy filing, the Company is in default under the indenture pursuant to which the Secured Notes were issued. The current face amount of principal, and accrued interest to February 28, 1991, on the Company's Secured Notes is $279,597,200 and $14.126,174 respectively. The Secured Notes are collateralized in part principally with a security interest j in the Company's 12.1% ownership interest in the realty and personalty of the Seabrook Proj ect. As a result of the bankruptcy filing, the Company is in default under the indenture pursuant to which the Secured Notes were issued and ceased accruing interest expense as of February 28, 1991. I i The contractual interest expense on the Secured Notes in-both 1993 and 1992 was approximately $49 million and in 1991 was approximately $50 million. In 1993, 1992 and 1991, no interest was paid. The Company also had outstanding i 180,000 CICs evidencing the right to receive additional payments contingent upon and measured by the Company's income in certain years following the commercial operation of Seabrook Unit 1. Under the Plan, the CICs - have been extinguished. (See Note B - Bankruptcy Proceeding) The Secured Notes and CICs are solely the obligation of the Company and are not guaranteed by EUX og any other person. O 49 i i i ~, - = -

7-The Series B Secured Notes, which have a stated maturity date of May 15, 1993, are redeemable at 100.125% of principal amount. The Series C Secured Notes have a stated maturity date of November 15, 1992. Note G - Fair Value of Financial Instruments: 3 i ~ The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate: Cash and Temporary Cash Investments: The carrying amount approximates fair value because of the short-term maturity of those instruments. Long-Term Debt: The fair value of the Company's long-term debt can not be determined at this time. See Note B - Bankruptcy Proceeding for a discussion of the Company's Bankruptcy Proceeding and Reorganization Plan. Note H - Commitments and Contingencies: Nuclear Power Issues Like other nuclear generating facilities, the Seabrook Project is subject. to extensive regulation by the NRC. The NRC is empowered to authorize the siting, construction and operation of nuclear reactors after consideration of public health, safety, environmental and anti-trust matters. The NRC has promulgated numerous requirements affecting safety systems, fire protection, emergency response planning and notification systems, and other aspects of nuclear plant construction, equipment and operation. The Company has been, and may be, affected to the extent of its proportionate share by the cost of any such modifications to Seabrook Unit 1. Nuclear units in the United States have been subj ect to widespread criticism and opposition. Some nuclear projects have been cancelled following substantial construction delays and cost overruns as the result of licensing problems, unanticipated construction defects and other difficulties. Various groups have by litigation, legislation and participation in administrative proceedings sought to prohibit the completion and operation of nuclear units and the disposal of nuclear waste. In the event of shutdown of any unit, NRC regulations require that it be completely decontaminated of any residual radioactivity. The cost of such decommissioning, depending on the circumstances, could substantially exceed the owners' investment at the time of cancellation. ) Public controversy concerning nuclear power could adversely affect the operating license of Seabrook Unit 1. While the Company cannot predict the ultimate effect of such controversy, it is possible that it could result in a premature shutdown of the unit. The Price-Anderson, Act provides, among other things, that the liability for damages resulting from.a nuclear incident would not exceed an amount which p at present is about 39.2 billion. Under the Price-Anderson Act, prior to v 50

operation of a nuclear reactor, the licensee is required to insure against this liability by purchasing the maximum amount of insurance available from private /N sources (currently $200 million) and to maintain the insurance available under h a mandatory industry-wide retrospective rating program. Should an individual licensee's liability for an incident exceed $200 million, the difference between such liability and the overall maximum liability, currently abotik $9.2 billion, will be made up by the retrospective rating program. Under such a program, each owner of an operating nuclear facility may be assessed a retrospective premium of up to a limit of $79.3 million (which shall be adjusted for inflation at least every five years) for each reactor owned.in the event of any one nuclear incident occurring at any reactor in the United States, with provision for payment of such assessment to be made over time as necessary to limit the payment in any one year to ne more than $10 million per reactor owned. The Company would be obligated to pay its proportionate share of any such assessment. Joint owners of nuclear projects are also subject to the risk that one of their number may be unable or unwilling to finance its share of the project's costs, thus jeopardizing continuation of the project. On May 6, 1991, New Hampshire Electric Cooperative, Inc., a 2.2% owner of the Seabrook Proj ect, announced that it had filed for Chapter 11 bankruptcy protection. A reorganization plan, flied by the New Hampshire Electric Cooperative with the Bankruptcy Court in September, 1991 and revised in January, 1992 was approved by the Bankruptcy Court in March 1992 and approved by the NHPUC on October 5, 1992. All appeals of the NHPUC order approving the reorganization have been resolved in NHEC's favor and the effective date of the plan occurred on December 1, 1993. /3 Nuclear Fuel and Nuclear Plant Decommissioning: b The Seabrook Project joint owners have made, or expect to make, various arrangements for the acquisition of uranium concentrate. the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of that fuel after use. The owners and lead participants of United States nuclear units have entered into contracts with the DOE for disposal of spent nuclear fuel in accordance with the NWPA. The NWPA requires (subject to various contingencies) that the federal government design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel and establish prescribed fees for the disposal of such wastes and fuel. The NWPA specifies that the DOE provide for the disposal of such wastes and spent nuclear fuel starting in 1998. Objections on environmental and other grounds have been asserted against proposals for storage as well as disposal of spent fuel. The DOE anticipates that a permanent disposal site for spent fuel will be ready to accept fuel for storage on or before 2010. However, the NRC, which must license _ the site, stated only that a permanent repository will become available by the year 2025. At the Seabrook Project there is on-site storage capacity which, with minimal capital expenditures, should be sufficient for twenty years or until the year 2010. No near-term capital expenditures are anticipated to deal with any increase in storage requirements after 2010. I l The estimated cost to decommission Seabrook Unit 1, based on a study by the New Hampshire Yankee Division of the Public Service Company of New { Hampshire, is approximately $351 million in 1993 dollars: The Company's share 1 of that amount is approYimately $42.5 million, or 12.1%. In 1993, the Company i O paid approximately $895,000 in decommissioning expenses. V 51

The agreements of purchase and sale under which the Company purchased its Seabrook interest required the Company to este olish a fund of $10 million to /9 secure payment of part of its share of decommissioning costs of Seabrook Unit 1 O and any costs of cancellation of Seabrook Unit 1 or Unit 2. In May 1990 EUA guaranteed this obligation and the entire fund was released to EUA Power. q Under the Settlement Agreement, EUA reaffirmed this guaranty. i Seabrook Unit 2: The Company also has a 12.1% ownership interest in Seabrook Unit 2 in which it has assigned no value. On November 6, 1986, the joint owners of the Seabrook Project, recognizing that Seabrook Unit 2 had been cancelled, voted to dispose of the Unit. Certain assets of Seabrook Unit 2 have been and are being sold from time to time to third parties. Plans regarding disposition of Seabrook Unit 2 are now under consideration, but have not been finalized and approved. The Company is unable, therefore, to estimate the costs for which it would be responsible in connection with the disposition of Seabrook Unit 2. Monthly charges are required to be paid by the Company with respect to Seabrook Unit 2 in order to preserve and protect its components and various warranties. Construction Expenditures Great Bay Power's cash construction expenditures, including nuclear fuel, are estimated to be approximately $4.3 million in 1994 and aggregate approximately $23.4 million for the years 1995 through 1998. SEC Review In January of 1991, the SEC's Division of Corporation Finance commenced a d review of the Company's Annual Report on Form 10-K for the year ended December 31, 1989 and subsequent Quarterly Reports on Form 10-Q. The Company submitted written responses to all of the inquiries made by the Division of Corporate Finance. In May of 1991, the Company was informed by the SEC's Division of Enforcement that it would conduct an informal review with respect to certain issues addressed by the Division of Corporate Finance principally relating to the accounting for the capitalized financing costs related to the Company's investment in Seabrook Unit 1 and the effect which recording such amounts had on reported earnings for the three year period ended December 31, 1990. The Company informed the Division of Enforcement that it would cooperate with the informal inquiry and in July of 1991 the Company completed its responses to the Division of Enforcement's initial inquiries. The Company has received no communications from the Division of Enforcement since the Company completed its responses in July, 1991. The Company restated its financial statements with respect to the amount of AFUDC recorded in 1988, 1989 and the first three quarters of 1990 which it believes addresses several issues raised by the SEC. The Company cannot predict the outcome of the SEC's review. The SEC could require that the Company further restate its financial statements for 1990, 1989 or 1988, or for any quarterly period during such years. The ultimate outcome of this matter cannot presently be determined and, accordingly, no provision for any adjustment that may result from its outcome has been made in the 1990 financial statements of the Company. The Company continues to believe that its financial statements (as previously. restated) were prepared in accordance with generally C 52 l )

1 J accepted accounting principles and presented fairly the financial position and results of operations of the Company. Other Proceedines. In June 1991, the State of New Hampshire imposed a Nuclear S,tation Property Tax applicable only to the Seabrook Project. The Company " paid its share of the tax, aggregating $4.2 million through December 31, 1992. In October 1991 the.Atto rneys General of Connecticut, Massachusetts and Rhode Island petitioned the United States Supreme Court in an original jurisdiction case for a determination of the legality of the tax, and in January 1992 the Supreme Court agreed to take the case. The parties to the litigation and other Joint Owners of Seabrook entered into a Settlement Agreement on April 13, 1993. In general, the terms of the Settlement Agreement are expected to result in a significant reduction in annual state taxes paid by the Company. In ~~. - additibh7 under7he~termarof the*SettT# ment-WgreementFcertain"'of r the' prior:i. payments of the tax by the Company will be permitted to be credited against future taxes due. The Bankruptcy Court has approved the Settlement Agreement with respect to the Company. n 1 l i ~ M $U 53

. Schedule V Great Bay Power Corporation (f.k.a. EUA Pour Corporation) PROPERTY PLANT AND EQUIPMENT ~, (In Thousands) ) 5%./ COL A COLB COL C COL D COL E I COL F Balance at OtherCharges

• Balance at i

Beginning Additions Add (Deduct) - End of Classification ofPeriod at Cost Retirements Describe Period + For the Year Ended Decernber 31.1993: l j Production Nuclear $497.726 $1.174 $1.263 $497.637 Transmission and Distribution 7,183 7.183 l General Plant _._ 5,981 75 31 6.025 { Intangible P1an' 926 926 Nuclear Fuelin Service ._ _ _22,479...-_ _ ~~..__ _,__ M 479 ^um ~ Construction Work in Progress _ ' ~ IS76 ~ 944 2.920'" Nuclear Fuelin Process 349 2,156 2.505 Nuclear Fuel in Stocl-2.505 2.505 Total Utility PlanL. SD6420_ $6254_ SL294 19_ $542.18Q. For the Year Ended December 31,1992: Production Nuclear $499.597 $1,282 $130 ($3.023) (a) $497.726 Transmission and Distribution 7.243 4 (64)(a.b) 7.183 Genetal Plant. 5.885 132 (36)(a) 5 S81 Intangible Plant 929 (3)(a) 926 Nuc! car Fuct in Servi ~ 22.493 7,708 7,722 22.479 Construction Work in Progress.. 996 980 IS76 Nuclear Fuelin Process. 4.524 (4.175) 349 b] / Total Utility P1an' $141M7_ $5ML $2,812. ($A126) . $536.620 For the Year Ended December 31,1991: Production Nuclear $498.760 $1.862 $482 ($543) (c) $499,597 ~ Transmission and Distribution 6,915 336 (8) (d) 7,243 GeneralPlant 5.891 (6) (d) 5.885 Intangible Plant 930 (1) (d) 929 Nucleat Fuelin Service 19.230 7.272 4,009 22.493 Construction Work in Progress 1.039 (43) 996 Nuclear Fuelin Procca 9At6 (4.522) 4.524 Total Utility Plan' $14L61L $4.901. $4 43. ($153) .314LG61. 2 (a) UE&C Settlement agreement ($557,949). Pre Operational Decommissioning ($1.558.158). Property Tax Abatement ($1.287,300). and Settiement Proceeds Fees $300.000. (b) includes ($22314) transferred to cost of removal. (c) Transfer pre-operational deccrnmissioning trust funds from Plant in Service to Accounts Receivable. (d) Transfer between accounts. ) y/ $4

4 i Schedulo VI Great Bay Power Corporation (f.k.a. EUA Power Corporation) ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF e PROPERTY. PIANT AND EQUIPMENT (In Thousands) } Column A Column B Column C Column D Column E Column F Other Additions Charges Balance at Charged to Add Balance at

---

~_._.-

. Beginnin g~"' ~ " ~ Costs siid ~ ~~

• ~~~(Deduct) ~

' End of~ '"1 Description of Period Expenses Retirements Describe Period For the Year Ended December 31,1993: Accumulated Depreciation. Depletian and Amortization $38.145 $19,684 $1,273 $0 $56.556 For the Year Ended December 31.1992: Accumulateu Depreciation. Depletion and ( Amortization $25.751 $20.205 $7.811 $0 $38,145 For the Year Ended Decemtwr 31,1991: Accumulated Depreciation, Depletion and Amortization $9,161 $21,108 $4,518 0 $25,751 i e v 55

9 Great Bay Pcwsr Ccrpsration schedule Ix (f.k.a. EUA Power Croporation) Short-Term Borrowmgs (In Thousands) p. iG I 8 COLUMN A COLUMNB COLUMN C COLUMN D COLUMN E COLUMNF Maximum Average Weighted Category of amount amount average aggregate Balance Weighted outstanding outstanding Interest rate ~ short-term at end Average during during the during the borrowines of period Interest Rate the period period (a) period (b) a.-,__

==- ~z:;;=,g er=:r%.i=='^~ ^ M-m n= - -f - a 2~ x==.- Notes Payable to Banks: December 31, 1993 (c) $1 0.0% 31 $(L 0.0% 1992 (c) $0 0.0% $0 $0 0.0% J 1991 $0_ 0.0% $ 16.28. 0_ $2d17_. 7.4% (a) The average amount outstanding during the period was computva by Juviding the summation of the daily principal balances outstanding by 365. (b) The weighted average interest rate during the period was computed by dividLng the actual interest expense by the daily average short-term debt outstanding. (c) Excludes amounts outstanding under the Debtor-in-Possession fm' ancing facility. i 1 4 J 56 i i

Great Bay Power Corporation Schedule X Supplementary Income Statement Infonnation Ob '.) COLUMN A COLUMNB i For the Years Ended December 31, 1993 1992 1991 ) Charged to Costs and Expense ___..__. g I. (In Thousands) Taxes -- Other than Income: PAYROLL TAXES. $487 $498 $55 LOCAL PROPERTY TAXES...~... 3,391 5,579 3,505 STATE CORPORA *ITON TAXES. 0 0 0 Charged to Operating Expenses- $3,878 $6,077 $3)_60_ O \\ i l l Amounts of rents, advertising costs and research and development costs did not exceed 1% of gross revenues. 1 Amounts of maintenance and repairs and depreciation expense were as shown in the income statement and notes thereto. O 57

m l l REPORT OF INDEPENDENT ACCOUNTANTS ('\\ U c3 To the Director of Great Bay Power Corporations \\ s We have audited the financial statements and financial statement schedules of i Great Bay Power Corporation (forTnerly EUA Power Corporation; the " Company") l listed in item 14(a)(1) and (2) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express our opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. ~ Those standards "' require that~ we' plan ~ ~Hrid"psrform ~ the - audit ~~to' obtain reasonable assurance about whether the financial statements are free of t material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles - used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein. As discussed in Note H of " Notes to Financial Statements" under the heading "SEC Review", the Staff of the Securities and Exchange Commission (SEC) has reviewed certain reports previously filed with the SEC and has raised questions principally regarding the accounting for capitalized financing costs and could require that the Company further restate its financial statements. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note B of " Notes to Financial' Statements," the Company filed a voluntary petition for protection under Chapter 11 of the Bankruptcy Code because it is currently selling power below its costs and has been unable to pay the debt service related to its Series B and Series C Secured Notes when due, all of which raise substantial doubt about its ability to continue as a going concern. The Company's plans in regard to these matters are also described in Note B. The financial statements do not include all of the adjustments that might result from the outcome of this uncertainty. COOPERS & LYBRAND Boston, Massachusetts April 7, 1994 ~ 58}}