BECO-95-117, 1994 Annual Rept to Shareholders, for Boston Edison
| ML20094L679 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/31/1994 |
| From: | Weafer R BOSTON EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| BECO-95-117, NUDOCS 9511210072 | |
| Download: ML20094L679 (63) | |
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2 BOSTONEDISON 800 Boylston Street Boston, Massachusetts 02199 Robert J. Weafer, Jr. (617)424 2463 Vice President, Controller 2
andChief AccountingOfficer November 15,1995 BECo 95-117 -
Document Control Desk
- Director of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission
. Washington, DC 20555 License DPR-35
Dear Sir:
Docket 50-293 in accordance with 10CFR140.21 and the 1975 amendments to the Price Anderson Act (Public Law 94-197), Boston Edison is submitting the following:
- 1. Boston Edison Company Annual Report for 1994.
- 2. Boston Edison Company Form 10-Q for the quarter ended September 30,1995 as filed with the Securities and Exchange Commission.
- 3. Cash Flow Forecast for the year 1996.
- 4. Narrative Statement of curtailment of capital expenditures.
Sincerely, Enclosures cc:
Mr. Ira P. Dinitz U. S. Nuclear Regulatory Commission Insurance Indemnity Specialist Region i Office of Nuclear Reactor Regulation 475 Allendale Road Mail Stop 11D23 King of Prussia, PA 19406 U. S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike Rockville, MD 20852 Mr. R. Eaton, Project Manager Senior NRC Resident inspector Division of Reactor Projects - 1/ll Pilgrim Nuclear Power Station Office of Nuclear Reactor Regulation Mail Stop: 14D1 U. S. Nuclear Regulatory Commission i 1 White Flint North 11555 Rockville Pike J Rockville, MD 20852
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FINANCIAL HIGHLIGHTS: MY 3 J9et%# .m.W;9 y* pw ~t#6,%. . years ended December 31, j y%^
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ffcome perating available forrevenues conunon stock (000) (000) $109,257 $ 102,513 + 6.6% y y y gyf[.y'sgTb K@c"p.@h gjyy%p . w Conunon s ares outstant ing - f ddM weighted aserage (000) 45,338 44,959 + 0.8% khh~ Common stock data:
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$1.775 52.28
$1.715
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Pa)out ratio 73 % 75% - 2.7% M[bh 2Y , Ikiok value per share $20.11 519.42 + 3.6% ht[ b 3.,ff{.h4 Return on average common equity 12.1 % 11.9% + 1.7% l h Th~ b ff Fixed charge coserage (SEC) 2.45 2.22 + 10.4% QTS,m $ '
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w ^2. . e,hMidgfgdgi6jf. S '" m n ,db.x @.4 . . 41 i m ggm e y%g)4' g ym < ABOUMHFCOMPANY: lkiston Edison is a public utility engaged principally in the generation, purchase, transmission, distribution and sale of electric energy. It was incorporated in 1886. We supply electricity at retail to an area of approximately 590 square miles uith. ON THE COVER: OUR NEW ENERGY in 30 miles of ik>ston, encompassing the City of Ik>ston and 39 surrounding cities MANAGEMENT CENTER opened in and towns. The population of the territory served at retail is approximately January 1995. The facility gives employees 1,500,000. the ability to control the delivery of ] We also supply electricity to other utilities and municipal electric departments at electncity from our generating stations to wholesale for resale. About 87 percent of our resenues are derised from retail our customers' homes. Members of the electric sales,1I percent from wholesale sales and 2 percent from other sources. Energy Management Center Team include (from left) Ron Poindexter, Wendy Rueger, j Bob Sullivan. Dick Zhikowski, Frank Dontan, Frank Flemming, Rick Fike and Mike Sanford. , l 1 i j i i I
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? - DEAR SHAREHOLDER: A. 88rysii>;e mst control, the use e ,
, - a of new techm>lhgies, ImprovErnents in productli-ity and changes in' work practices all contributed to
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s . anotherauccessful year in 1994 for Boston Edison.We achieved earnings growth of 5.7 percent, and continued a live ye.it, trend ofincreasing your dividend, this time by 3.4 percent to s 1.82, up from
, 'u . s 1,76.'This,five-year, }stternJf, increase places. Boston' Edison'in' the industry 's top. quartile for ,
6 y- , divideiid grofthgand reilects continued financialitrength, excellent'operatinglperformance and a
- ? 1%. ' ' a s positivsoutlook for the futurei 1 ',m'
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.M the*paciQ fndustry ' change increases, we face an exciting futuie full of opportunity.We are striiing '
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to bk leislike a monLhi>ly and[more likc[a s'uccessful service ano tahnology lirm. Our future includes - -
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P <- smaller,Iniore'cIlicientitaff operatiorisi.stiinig alliances with businesi partners and the use of new ' [ 'q ' technologies'to loiter costh im~
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p rdve servim to' customers and position'uito compete successfully.
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. COST CONTROLHwe 6 controlling our msts successfully. In May, we signed new six-year con- c
, .. tracts with our tw'o union locals providing certainty as to wage adjustments and health care benefits,
.s and gaining more 11exibifity .in work [irac'tienAs dresult dfinvestments inimproved technologies we' -
realized significant gains in reliabilit[and [jroduedvity, enabling in to reduce our work force by 371
, . positions, or 8.4%, in 1994;We accomplishhd this thbougif a ' combination of attrition and by selec-l
'{ ' tively 'cliininating, positions 1and functioni. Also, we consolidated the s , ,
Marketing and Sales organiiations, outburced certain functions, and stream-x % ' ~
,, lined operations in line organizations.
s~ Other measures will t,rini niillions of dollars from Company expenses.Two i sevice centerk will be, closed in 1995 with fimetions consolidated at remain-go hy 4j.
.ig cente'rs/ Improvements in; materials management enable us to reduce 7 - ,'
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. imentory and klose thrke warehouses.
c major work. processes, standardizing sizes ahd types of materials and employ-I y holding less inientory, streamlining g g%' # . . inj just:in-tinie imentory'technihues, b will'save 57 to $10 million annually. p y y And, wp are working ,with vendors like General Electric and Westinghouse to~ g : determine the [irice and a$aihbility of required supplies quickly and to place -
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, ", > orders ~with mini, mal human intervention and paperwo,rk.
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1 - Using new(technologies / the bill' collection process has been improved, '
, [ f [ increasing cash flod by soSie 54 million. Our fleet' of pdssenger vehicles has V
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7 y.} G been.reduded by 40 percent, oi 250 ca's. r It is noteworthy that these savings ' - [.",j;, p pare being'identitled and pealized by cross-functional teams trained in and ,.
'M 1 + charged with finding solitions.They are'doinijust that.
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y y r*= = ~ An empl.oyee, team developed a streamlined two-step, one-day process for
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' new cusi6mer installations. Cosbining new technologies with work practice changes, this new prdcess lioth reduces costs and improves service. Other employees reduced system maintenance outage times and, in doing so, lowered labor' costs, minimized customer inconvenience
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PLANNING - Our enbrts to achieve greater flexibility in resource planning pnxluced positive results, as well. In an important decision from the Massachusetts Department of Public' Utilities (MDPU), our plan to meet future demands for electricity through a Hexible resource acquisition strat egy was apprmed.The MDPU agreed that new supplies of electricity are not needed through the year -
,2000, and approved our request to issue an Options RFP (a flexible contract giving us the option to ,
buy power at a predetermined price), calling it,"an innovative approach to resource plarming"
, - In November, we eliminated a cumbersome IIEst mortgage bond indenture, providing us with gre'ater ' ._ . _.
financial flexibility. We are one of only a few electric utilities to have no lirit mortgage bonds. - 4 OPERATIONS - Our generating plants continued to perform well.The Ms'PM SMAEN
. Pilgrim plant's 1994 " report ' card from the Nuclear Regulatory Comm'ssion FR004GNMHON8iIoOE was its best ever, placing it in the top quartile of plants nationwide. Once
@MMbb wwwmae again, Pilgrim earned incentive revenues by exceeding 1994 performance tar; umgggg gets set by the MDPU. Future performance is expected to shoiv continuing .M Edh&mh improvement because of the climination of planned maintenanc.e overhauls 'I between refueling. ,
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- y c in 1994, the fossil fuel generation system achieved the second highest unit g{ ms - -
availability in the system's history, significantly improving the percentage of Q suq I6 '
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time generating units are available to produce p<mer, m _u w st.n ew , r
= - 1 Also, major emironmental modifications were completed at our power sta- .
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tion in South Boston. As a result, the Company continues to have the cleanest sus . = - i rfy generating plants in New England.We are in compliance with the Federal and - stm - - State Acid Rain regulations through the year !2000, whi_le other utilities still e ;
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- must invest to reduce emissio'ns froni their plants. sih, .
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. . I COMPETITION - success in a competitive ~ environment is measured in wins and losses, and we've b'cen winning. One of the reasons is the quality.bf the sales and marketing team, a blend of profes-sionals with extensive experience in competitive situations and seasoned Boston Edison veterans.This ,
$ year we gained more than 40 megawatts in new customer load, and had no signifkant customer losses.
- In t he wholesale market, all existing customers are under contract through at least the year 2002, and -
we added a new customer with significant growth opportunity, theTown of Braintree, in the retail
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market, we' acquired new business from.former steam customers and expanded existing customer - , ,. ; -l
. .-. . relationships through new other side-of-the meter services! - . . 4i TECHNOLOGY - With a focus on meeting the clianging needs and expectations of customers,- )
we're kmking for technological solutions that will enable us to reduce costs,imprme and expand sersice and add value to the customer relationships. = i 1
' A new energy management center and the modeling of the future distribution business, both' described later in the report, are just two examples,. Others can be Ibund throughout the Company.
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, in information, in operations, in sales, in all,a}spebs of fiehl ser,viees, technologies are being iden and deployed to' enlunce our' relationship with 'our custrimers?. >
u Our course over the past five years has been one of steady impnhement.We have successfully exe- -
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cuted our operatin'g' plans and, in' many cases, exceeded o^ur goals - Our management team is stfo'ng
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, . and creatiy, we have achieved financial strength'and flexiliilitf, and\ve have the strategies in place to - '
win'in w hat we know will be a changing, more competitive environmentMb a're confident that what.
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u . . egr changes come hur.way, we nill remain succesifuli .
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'In clo" sing one change in 1994 ihat alTected us bothidd the re'tirement of BernardW Reznicek First l'*
as prifsident and thed as chairman and chief execut'ijefollicer, Bernie brought clarity to our manage- ~ ment processes, And helped us to define excellence for our opepations, to empoweb employees to per- , . 4 ' form beyond normal'boundarie's and to enhance our reputation with' regulators and the financial ' community. He is hohkdhan of the- b.usiness school it Creighton University.in his native Om' aha, Nebraska;and serves on utir Board of Di. rectors.We wish'him well.. , , ,' e
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Thomas J. May ,
- George W. liavis Chairman and I r President and '
Chief Exec 6tive Oflicer '
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Questions are being raised about the changes in our industry and what impact they're having on Boston Edison. In this section, Company Chairman and CEO Tom May offers his views oninaustry change and what shareholders should expect in the future. What's driving the debate on how to boki prop >sals, folkmed by a period of reilection, sug-restructure the electric utility industry? gesting a somewhat shmer approach. In other cases, as here in Massachusetts, the approach has been very dehb-It,5 a combinat,on i of factors, first, the structure of vertical-crate, scry meth<xlical.The Massachusetts Department of Iv .mtegrated utilities responsible for all aspects of genera-Public utilities is asking the right questions and bringing tion, transnu. .ssmn and distribution no longer makes sense. the key stakehoklers to the table.This makes a lot of sense,
.the current system of regulation was largely created in the and I support the department's approach.
1930,s when rapid expansion of the electric system was critical to the nation's economic growth.Llay, that's no our goal shouhl be to maximize the benefits of competi- I longer the case. In fact, new, more ellicient generation tech. tion to all customers, while minimizing the potential nologies and lower costs, coupled with legislation that harm to the various stakehoklers.This suggests to me an started removing barriers to market entry in the late evolutionary process. We need to sort out the complex 1970's, hase already created a competitive commodity mar. regulatory and economic obligations created under one ket for electricity. In addition, transmission systems, as a regulatory scheme as we mme to another. And I think matter of federal policy, are mming towards a common this will take a number of years. At the same time, I carrier system (like the U.S. highway system) with equal beliese choice will begin with our largest customers, access by all. For loth generation and transmission, there probably within the next the scars. / -4 are many questions that still need to be answered to assure that stakeholder -grouIw are I)rotected, but the direction has in the meantime, some of GP / @-% -
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clearly been set. el i the same technologic, eco- / y You can add customer exIicctations to the technolo87, nomic and customer factors ~M' economics and public policy drisers. Customers want drising industry restructur- Ayh4g y_6 .- d y' x,9 choice and the benefits of competition. Ours is the last of ing are already creating the regulated industries to go through this pmcess. competition. Sophisticated g Customers want, and expect to be able to make, choices customers uill look at all , in the future about their electricity supplier and the ser- options to reduce costs in a vices it will offer. highly competitise national / . and global economy. So p How long will this transition take? regardlew of how- long it p /l' There,s a lot of speculation an i uncertainty about this. takes to restructure the "4M .4w industry, we hase to be pre- Qgygg
.o W Nearly two do/en states and the federal gosernment are pared to compete su cess- k jQykI$kb!ptupq k today addressing the complex issues surrounding industry fully today to hold onto and w' - ~- '
restructuring. In some cases, there hase been relatisely expand our customer base. 4
i What's your vision of a restructured industry? What role is Boston Edison playing
" ""O' I think the excitement will be in the retail distribution business. Generation is a commodity, the competition we have a 3 ital role on behalf of all of our stakehoklers will be intense, and the margins will be small. Utilities - our sharehohlers, our customers, our employees and will continue to be players, in many cases through the communities we serve. If the interests of those stake-alliances, but the number of players will be large. holders are to be protected, the transition shouhl be Transmission will simply become the interstate highway orderly to assure that no single stakehokler benefits at the system for moving power expense of the others. We are fortunate to have already ~ hgq*, f e.y from the generators to the operated under an incentive rate structure in generation,
.- . renirNdpy{n ' retail distribution compa- and our managers are committed to freezing base rates
<;wyCM nies and to individual cus- through the year 2001We also have a seat at the table in
%M ~3Mbk . tomers who have a choice every major forum hmking at industry restructuring as it h hhh%h g N. .m JJg of WPPli er.There will be ready access to the system, could alTect Massachusetts. In fact, weie proposed a reg-ulatory transition concept that wouhl separate generation fk fM hph rates uill be published and pricing from transmission and distribution it wouhl pro- -[;f; h. @ y generators, utilities and side for generation to be market priced, allow for recov-7 .f . ;g ,. customers wdl move on cry of any generation assets currently recorded above d @ h. { p and off relatively easily. their market value through transmission and distribution p l; ;~i 4..
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most customers w dl continue buym.g electricity from us, all customers will continue to have electricity delisered by shareholders shouhl expect us to work diligently at con-us. But that's only the beginning of the relationship. We tinuing the steady pattern of financial progress we've will transform our existing distribution business into an achiesed mer the past five years. And they shouhl expect integrated client services network. Automation and stor- us to move into a more competitise environment by both age technokigies will allow us to bring new levels of eni- influencing the outcome of the debate on how to restruc-ciency and lower costs. Information technologies will ture the industry and by being aggressise in retaining and enable customers to make up-to-the-minute buying deci- attracting customers. In addition, we'll be hmking for sions and allow us to monitor and control their use based new revenue sources from expanded products and ser-on their choice of services and pnxiucts. Meters will be vices. As you'll see elsenhere in this report, we are con-replaced by computerized desices, and customers won't trolling costs, winning in competitise situations, seeking have to wait until next month to know how much they new business op[mrtunities and enhancing customer rela-have used and at uhat cost. Alliances with companies that tionships.We have a solid loundation for our participation market and move information are likely to expand the in the debate on industry restructuring and for respond-nature and scope of sersices we can offer. So the prospects ing to, and benefiting from, the competitive pressures for what this industry will look like in ten years are truly that are already emerging.We uill continue to pursue our exciting, once we work through the rules of transition. objectise of outperforming the industry. 1 5
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i 5 l 4 { THE EMPLOYEE OF THE FUTURE win possess j multiple skills, be flexible and be expected to j undertake more tasks. Specialized jobs and j narrowly defined job classifications are being { replaced, and employees are being asked and ! Utilitits used to have empowered to take more personal responsibility real life situations. For example, the malule pre-4
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- ng lzad times to plan for improsing customer sersice. For example, sents a supersisor nith 50 homes without power l for the future. Stability Company and union leadership worked together at the end of a shift.The supervisor answers a was the norm, and the with 70 substation operators and mechanics to series of questions and makes decisions.The mod-j premium on speed was create one new job combining both sets of skills, ule takes the" answer", evaluates it, and presents a j smIll. But the rules are The new classification provides employees with number of other scenarios that might have been
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! flexibility are required Company through more etlicient use of employec thinking, enhances decision-making and increases attributes in a competi' f resources. and benefits customers by quicker confidence. ! tive mirket. We are response at lower cost. ! achirving flexibility and MMNMbh%MM l spied through our focus in this example, as in so many others, the key to
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i on cross-functional success is Mutual Gains llargaining, a technique Q% " tsams for meeting for understanding what's at stake before negoti- jhQ ' hk customers
- needs, the ating an agreement that most closely meets the MM h use of technologies and a needs of all imolved. It sounds simple enough, but the effects base been very dramatic, pgw
! cost consciousness - j shared by all employees. In May 1994, our labor unions signed six-year S< j < contracts.They include a number of productisity s /f and benefits improvements, along with fair wage 1/[1 e ' increases, that would not base been possible l without Mutual Gains Bargaining.The contracts
- provide both flexibility and stability as a result of j a shared view of emerging competition. From left John Prior, Warren Farnsworth and Steve
- Prosper, a self directed work team given the in addition to well-trained and llexible employ. autonomy to act on behalf of the customer.
i ces, we will continue to focus on technology to ] ! help employees meet competitise challenges. In 1994, we initiated an interactive television simu-
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i OUR APPROACH TO Resources Authon.ty goes well beyond supphing SERVING eienricitv. one ispen of the partner; hip CUSTOMERS is changing. involved the installation of a 115 kv submarine We are becoming a husiness partner, not just an cable and the construction of backup generators l electricity provider to our commercial and to serve a new Waste treatment facility for i mdustrial customers. We are working to under. Greater ik>ston. In addition, the Company and stand their businesses so that we can be a more MWRA h.ne entered into a three-year operation effective partner in meeting their needs.We are and maintenance training agreement which using technology to improve service, lower costs alone is valued at more than s2.5 million. Ik>ston Customers want quality and enhance our customers' internal operations. Edison personnel are using their expertise to and value. Providing the in doing so, we will add value to the relationship, train MWRA personnel. Other aspects of the right mix of both will win w hich will help us retain and attract customers. relationship include energy efficiency upgrades customer loyalty. That is l The elTects of changes in the industry are evi- and environmental technologies. why we are working dent, and we are responding well. In 1994 we closely with our In another example of alliance building, the gained over 40 megawatts of new load and had . customers to understand, C,ompany worked with city and state govern-no significant customer losses. ' not only their energy ments to put together a comprehensn.e proposal . needs, but also their in anticipation of a tougher, more competitive which led to the restart of a large paper compa-business needs. This way, future, we structured sales and marketing func. ny in Ikaton.The company' will create 120 jobs we can offer operating tions to ensure the most effective response to the and add 9 megawatts ofload to our system, efficiencies. { varying needs of customers. We recruited sea-
.The Imttom line is that business customers want environmental solutions soned sales and marketinb> I3rofessionals from and new technolog ies to help in meeting their business needs. So, we must 1 competitive industries.The combining of highly -
be more creative, act more quicklv, become a part suit individual situations- '
' i skilled long term Boston Edison employees and in other words: A total sales professionals from competitive industries of our customers, total business solutions, and stay
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focused on the basics of customer service. ener9Y solution based on i has produced an exceptionally strong team. We innovation and expertise.
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- products and services. For example, a multi.
Part ol the team responsible for planning, faceted efliirt uith the Massachusetts Water constructing and delivering service to the new MWRA wastewater treatment plant. Pictured from ; left: Jerry LaFond, Bill Polin, Rob Billet, Dan l Charbonnet, Charlene Greene. Tim Crowell, and Tony Gervasi. 1 I i 8
Pictured below is the MWRA wattewater treatment facility located on Deer Island.
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ustomers want the ability to
- make 's choice. Tomorrow they willhave that choice in one form or another. For some of the largest customers, the choice will be over their energy provider, but for all customers they willbe able to exercise some choice over an array of products and services delivered over an integrated customer services network.
Faced with these choices, customers willmake electricitypurchase decisions based on the t value they're receiving. 4 L. L Carl Gustin, Senior Vice President [ Marketing and Corporate Relations
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AS THE UTILITY INDUSTRY CHANGES,excitingnew business opportunities will result. We are well positioned to grow with the changes and benent from the results in our own service territory, and possibly beyond. As the industry changes, in the past tuo years, we realigned our tradition- and advanced control and telecommunications we will play a critical al electricity distribution functions to address the technology to monitor electrical system perfor-rote in furthering the concerns of customers and communities more mance, and proside new services at customer interests of all our effectisely. Now, commitments to customers and facilities. A new substation in South Iloston and stakeholders. We want to communities are made by employees who have other system improvements in 1993 will retire take a leadership role in the resources, the authority and the accountabil- aging distribution circuits, resulting in reduced shaping the future of the ity to make commitments and carry them out. operating cost and imprmed customer serdce. elsctric utility industry. Whether a routine sersice call or a response to We will attempt to an emergency, customer concerns and commit- ykNENlhyM $ MEkMf maximize the benefits of industry restructuring to ments to customers are matters of greatest N5N !* importance to all emplovees. ; all stakeholders. We d ' 1 have a solid foundation Our strategy is to make im estments in new tech-for our participation in nologies that address customer concerns, reduce the key debates on operating costs, increase the utilintion of our industry change. assets, and create new sources of resenue. We will invest approximately 54 million over the next two years to demonstrate technologies and service options for the distribution business of tomorrow. We intend to lescrage lloston Boston Edison representatives leading the discussions on forming a Regional Transmission Edison's signincant imestment in right of-way - Agreement and restructunng the New England and distribution circuits to proht from the bur- Power Pool. Pictured from left Joyce Wood, geoning"information highnay.* Phil Legrow, Ed O'Brien and Joel Kamya. In January of this year, we inaugurated our new state-of the art energy management control center, pictured on the cover. The 525 million center features interactise o mputer mapping, 11
IT IS IMPORTANT TO UNDERSTAND the cost ofour we wiii simuitaneousiv product and to act based on reliable information. strive for cost savings Managers are analyzing their own business units and for smart in new way s. Managers throughout the organiza. investments in new tion will now be responsible for resenues, technologies. The wires expenses and contribution for their individual into our customers' business units. homes and businesses will one day carry more liased on a competitive business analysis, lising technology to access information is also than just electricity. They managers will determine, for instance, if their important to our success. In 1994, we structured w ll also carry services deci.; ions will increase resenues, reduce costs or our information systems group to focus informa- and information; another imprme operations. In understanding the tion systems (IS) personnel on helping their link to the information
..nplications of their decisions, managers will be internal customers, managers and employees, highway. The right armed with timely, action-oriented information. with any IS issue. The reorganization marks a technologies improve signincant shift to a more 11exible client-server reliability, add value for Our emplovces' are challenged and time after (personal computer based) emironment, the customer and provide time find creative approaches to streamline potential new revenue processes and improve prontability. The supply management 9 stem was also sources. It's an assessed to identify etliciency improvements and
.mvestment in our N improve ways of doing business.The results have
-N competit.ive future.
( + been excellent: working with sendors and thinking about our business ditTerently, we have been able to improve operations, reduce imen-tory lesels, reduce paperwork and procedures, and eliminate three warehouses. Creatise sendor partnerships with suppliers like General Electric and Westinghouse base led to an integrated Members of the cross-functional team working on system that determines availability and price of the two-year Distribution Circuit Business Pilot supplies and places timely orders with minimal Project. From left Ben Tucker, Mike Cooper, Virginia Walker, Frank Gaffney, Frank Silvia, human m. tenention or paperwork. Rob Becker and Annmarie Svingen. We will continue our commitment to new tech-nology, imprmed information and creative thinking to help control costs, improve senice and assure future success. 12
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Gone are the days when we could
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, .s Charles Peters, Senior Vice President ~
Finance
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-0 Senior Vice President ; ~ i cE[ y
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; E. Thomas Boulette, , r,
.' Senior Vice President "N uclear ~
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l A COMPETITIVE POWER GENERATION MARKET emphasizes sare, reliable and low cost power. Every employee i I knows that our reputation among regulators, State Clean Air Act requirements are expected to customers and the communities in which we be minimal.We also installed a new, state-of-the-operate is also important. art environmental management system across the company. - The Pilgrim Nuclear Power Station's 1994 ;
" report card" from the Nuclear Regulatory We base taken a leadership role in working with 1
Commission was its best es er, placing it in the top public and municipal utilities, non-utility gen-in every community quartile of plants nationwide. Also, at the Pilgrim erators, power marketers and regulators to build wh re we operate a plant, we are decreasing costs by improving main- a consensus on what a " regional transmission" i plint, we must remember tenance planning and reducing down time for agreement should hmk like, and how the inter-that we are neighbors maintenance work. Ileginning in 1995, we will ests of our customers and shareholders can best and guests. Making low- refuel the plant every two yeais and eliminate be served. c st p:wer has to be planned maintenance outages between refueling. balanced with many . . . . As more players try to fight for a piece of the gen-Th.is performance combined with a reduction in eration market, we'll continue to focus on man-other things, including . the length of each outage will increase our aver-t:p-nitch reliability, agii.g ourselves emciently and effectively,
- remain age capacity factor to 8W,, placing us in the top safety and environmental . .
an active player in community alTa. irs and ensure group of plants nationwide and resulting in an practices. Additionally, our customers and shareholders are actively rep-annual cost savings of $4.5 million, our r:lationship with our resented at tlie table of regulatory change. c:mmunities is a priority. On the fossil-fuel generation system, we've also ,n%-
- f. w w;g imprmed operations and reduced costs. We . -
%g streamlined work practices and consolidated [j maintenance activities into one group resulting in reduced staffing lesels and cost savings ( ',
totalling s2 million. Our unit overhauls were completed ahead of schedule and 9% under bud- c;
# ~
get. We've also negotiated lise-year contracts which cut natural gas transportation prices in Members of the Pilgrim Station cutage review half, and will continue to look for every oppor. team preparing for this year's planned refueling tunity to decrease the cost of our product and outage. From left: Bruce VanFleet, Nancy Desmond, ensure our success. Stuart Minahan, Tom Trepanier, Mark Potkin and Steve Geary. We completed important emironmental modifi-cations at our plant in South lloston in 1994. As a result, future expenditures to meet Federal and 15
a RIagefnent's Disc:ssion cnd Analysis - Retail cIcctric res 1,es increased 561 million.The Nmemtwr 1993 and 1994 hase rate increaws resulted in 528.6 million of the Regulatory Proceedings - '"""' *d """""" ^"d "PP'" *"Il ' 6 * *"" " *"""o the 2% increase in retail sales. f uel and purchased pmer rnenues increased 528.5 million primarily due to the recmcry of certain new pur-fletail settlement agreements chased power expenses. In accordance with the 1992 settlement in 1992 our state regulators, the Massachusetts Department of agreement spxific resenues related to the purchawd pmer contract Public Utilities, approved a three. year settlement agreement effec. that expired in Odober 1993 were not affected. tise November 1992.This agreement provided us with retail rate The decrease in wholesale and other resenues is primarily due to increases, allowed for the recovery of demand side management an estimated prmision for refunds to w holesale customers due to c ntract issues. (DSM) conservation program costs, specified certain accounting adjustments and clarified the timing and recognition of certain Operating espe.-ses expenses.Tho agreement also set a h. .mit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any Total fuel and purchased pnver expenses decreased 527 million. penalties or rewards from performance incentives. Fuel expense decreased partly due to lower fossil fuel prices and a The retail rate increases consisted of a new annual performance 12% decrease in nuclear output. Purchased pmcr experse reflects adjustment charge ofTectise Nmember 1992 and two annual base rate lower costs assmiated uith the long-term contract that expired in increases of $29 million elTative Nmember 1993 and November Cetober 1993, partially oliset by the costs of new contracts.The 1994.The performance adjustment charge varies annually based upon timing elTect of fuel and purchawd power cmt collution aho con-the performance of our Pilgrim Nuclear Power Station.This charge is tributed to the decrease in fuel and purchased pmer expenses. Fuel further desaibed in our discussion of financial condition. ami purchawd gxmer expenses are substantially all recoverable In addition to the retail rate increases, our resuhs of operations through fuel and purchased pmer rnenues. were alTected by the recovery of DSM program costs, accounting Othe operations ami maintenance expense increased 8.7% pri. adjustments and the timing and recognition of certain expenses as marily due to higher employee benclit expenses. Pension expense further described in the ftdlowing Resuhs of Operations section. inacawd $20 n&on due to a higha contribution made to the pen. Our state regulators previously~ appnwed a three. year settlement sion plan for the year. In accordance with the 1992 settlement agree-agreement elTative Nmember 1989.That agreement also pro ided ment, we aconi pension exgwnse in the amount of the contribution
" to du plan.
us with retail rate increases and specified certain accounting adjust. ments.The 1989 agreement primarily allected our results of opera. cPreciation and amortization expense increased pimarily due tions through 1992. to a higher depreciable plant balance. In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. In We do not currently plan to make a base rate fi!ing upon the expiration of the 1992 settlement agreement, therefore we antici. accordance with the 1992 settlement aEreement we did not exIwnse any of these costs in 1993. pate that base rates will remain in etrect at their current levels. Amortization of deferred nuclear outage cmts consists of amounts related to the 1991 and 1991 refueling outages at Pilgrim Results of Operations station. In 1991 we deferred approximately 5i4 milhon of reructing outage costs.We began to amortire these cmts in June 1993 over 1994 versus 1993 # I"#" 'EP"" '" ""'"*'"'E""*""I' The 52 million decrease in demand side management programs Earnings per common share were 52.41 in 1994 and 52.28 in 199 3, expense was due to the timing of recmery of program costs. DSM The increase in earnings was primarily the result of the expiration of expense includes some program costs recmered mer tuche months a long-term purchased pmer mntract in October 1993, a retail base and other program costs recovered mer six years.The 1994 expense rate increase effective Nmember 1991, a 2.0% increase in retail mnsists of 522 million of cmts primarily related to 1994 expendi. kWh sales and an award relating to an eminent domain case.These tures and 513 million of cmts capitali7ed in 1992 through 1994. positive changes were partially olTset by higher operations and main- Municipal property and other taxes increased primarily as a tenance, depreciation and amortization and income tax expenses. result of higher Boston pniperty taxes due to a tax rate increase and capital additions. Operating revenues Our eilistise annual income tax rate for 1994 was 31.4% vs. Operating rnenues increased 4.5% mer 1991 as follows: 2 3.4% for 199 3. Both rates were reduced by adjustments to deferred On thousan<h) income taxes of s10 million in 1994 and 520 million in 1991 made in Retail electric revenues 562,945 anonlance w e t M2 settlement agreement. No further deferred income tax adjustments may be made and we exp ct our ellictise tas Demand side management rnenues 5,056 - rate to be close to the statutory rate in 199 2 ' Wholesale and other rnenues (2,919) Short-term sales revenues 1,219 Other income increase in operatine rnenues $66,301 in Nmember 1994 a court ruhng bname elIcctise prmiding us with an additional s 5.7 million gain on a 1989 cminent domain taking of f our property 16
Interest charges the lower generation, and lower costs associated with the long-term interest charges in total did not change significantly. Interest charges contract that expired in October 1993.The decreases in expense on long-term debt decreased due to the first mortgage bond and were partially offset by the timing efTect of fuel and purchased debenture redemptions in 1994 and the significant first mortgage Power cost collection. bond refinancing in 1993 at lower interest raten.nis decrease was par. Other operations and maintenance expense increased 7.1% pri. tially olTset by higher amortization of redemption premiums. Other marily due to increases in employee benefits and nuclear production interest charges increased due to higher short term interest rates par. expenses. Postretirement benefits expense increased by $7 million tially ofTset by a lower average short. term debt lesel. Allowance for Primarily as a result of the adoption of a new acccunting standard and borrowed funds used during construction (AFUDC), which represents Pension expense increased by $5 million; both are prmided for in our the financing costs of construction, increased as a result of a higher 1992 settlement agreement and further explained in Note E to the AFUDC rate related to higher short-term interest rates. consolidated financial statements A refueling outage at Pilgrim Station in 1993 resulted in higher nuclear production expenses. 1993 versus 1992 Depreciation and amortization expense increased in 1993 pri-Earnings per common share were 52.28 in 1993 and $2.10 in 1992. marily due to a higher annual decomtnissioning charge for Pilgrim The increase in earnings was primarily the result of a retail rate Station efTective November 1992 provided by the 1992 settlement increase efTective November 1992, the expiration of a long-term agreement.The charge is based en a 1991 estimate of decommis-purchased power contract in October 1993, no amortization of sioning costs as further discussed in Note D to the consolidated deferred cancelled nuclear unit costs and lower interest expense. financial statements. In additi on, the effect of lower depreciation These positive changes were partially offset by higher operations and rates implemented in accordance with the settlement agreement was maintenance, income tax and property tax expenses. ofTset by the elTect of a higher depreciable plant balance. In accordance with our 1992 settlement agreement we did not Operating revenues expense any of the s19 million of remaining deferred costs associat-Operating revenues increased 5.0% over 1992 as follows: ed with the cancell<d Pdgrim 2 nuclear unit in 1993. (in thousands) Amortization of deferred nuclear outage costs consists of Retail elutric revenues $70,8 37 am unts related t the 1993 and 1991 refueling outages at Pilgrim Demand side management revenues 33,601 Station as discussed in the results of operations for 1994 sersus 1993. The increase in demand side management programs expense is Wholesale and other revenues (2,794) consistent with the increase in DSM revenues. DSM expense Short-term sales revenues (31,144) includes some costs recovered over twelve months and other msts increase in operatin; revenues $70,500 recovered over six years.We began to recover presiously deferred DSM expenses in August 1992, in 1993 we expensed and collected Retail electric revenues increased $71 million.ne November from customers approximately 5 30 million of deferred 1991,1992 1992 and 1993 rate increases resulted in $40.6 million of additional and 1993 program costs. Oser six years we are expensing and col-revenues in 1993. Fuel and purchased power revenues increased lecting from our customers s1I million of costs capitalized in 1992 s29.5 million over 1992 primarily due to the timing elTect of fuel and s 37 million of costs capitalized in 1993.The 1993 expense relat-and purchased power cost collection and lower revenues received ed to these capitalized costs was $7 million. from short term power sales as discussed below. Municipal property and other taxes increased in 199 3 due to the We began recosery of certain demand side management program absence of tax abatements. In 1992 property taxes were reduced by costs, lost base revenues and incentives in Any 1992. Our 1993 s 10.4 million of tax abatements in accordance with our 1989 settle. resenues provided $45.9 million related to 1991,1992 and 1993 ment agreement. DSM programs. Our 1992 revenues of $12.3 million related primar- Our elTective annualincome tax rate for 1993 was 23.4% vs. ily to 1991 programs. 8.7% for 1992. Both rates were significantly reduced by adjustments The decrease in wholesale and other revenues reflects an esti- to deferred income taxes of $20 million in 1993 and 523 million in mated provision for refunds to customers of 58.6 million in 1993 as 1992 made in accordance with the 1992 and 1989 settlement agree-a result of orders from our state regulators on our generating unit ments.The 1992 rate was also reduced due to tax benefits of performance program. approximately $7 million resulting from mandated payments made Lower short-term power sales revenues were a result of changes in accordance with the 1989 agreement. Our adoption of a new in our generation availaislity and the needs of short-term power pur- accounting standard for income taxes in 1993 did not significantly chasers. Revenues from short-term sales serve to reduce fuel and afTect earnings. purchased power billings to retail customers and therefore have no elTect on earnings. Interest charges and preferred and preference dividends Operating expenses Total interest charges decreased 54 million in 1993. Interest on long-term debt decreased primarily due to the refinancing of substantially Total fuel and purchased power expenses decreased s 12 million. Fuel all our first mortgage bonds m 1993 at lower interest rates, partially expense decreased primarily due to a 21.5% decrease in fossil gener- ofTset by higher amortization of redemption premiums. Other inter-ation and an 8.5% decrease in nuclear generation, resulting from est charges decreased due to a lower short term debt lesel and hmcr planned plant overhauh and a nuclear refueling outage. Purchased short-term interest rates. AFUDC decreased as a result of a lower power expense reflects both higher interchange purchases, caused by AFilDC rate related to lower short-term interest rates. 17
Preferred and preference dhidends decreased 5.1% due to the cantly from the 1995 amount in the four years thereafter.We have replacement of a preferred and a preference stock i2ue with less long term debt and preferred stock payment requirements of costly issues of preferred stock. $102.6 million in 1995, $ 103.6 million per year in 1996 through 1998 and $ 3.6 million in 1999.
, External financings continue to be necessary to supplement our Fi:ancial Condition i"ternally 8enerated funds, primarily through the issuance of short-Our 1992 settlement agreement is providing us with increased rev- term commercial paper and bank borrowings.We currently have enues from retail customers over the three-year period ending authority from our federal regulators to issue up to $ 350 million of October 1995. Additionally, a significant long-term purchased power short-term debt.We have a $200 million revolving credit agreement contract expired in October 1993 with no change in related rev- and arrangements with several banks to provide additional short-enues.The settlement agreement also limits the annual rate of return term credit on a committed as well as on an uncommitted and as available basis. At December 31,1994 we had s215 million of short-on equity during the three-year period to 11.75%, excluding any penalties or rewards from performance incentives. term debt outstanding, none of which was incurred under the Our ability to achieve or exceed the i1.75% rate of return on rev tving credit agreement. In 1994 our state regulators apprmed
"'II"^"Ci"E P an l to issue up to 5500 million of securities through equity is primarily dependent upon our ability to control costs and to earn performance inccntives from generation performance mech. 1996.The proceeds will be used to refinance short and long-term anisms.The est significant impact that incentises can have on our securities and for capital expenditures. Refer to Note H to the con.
financial results is based on Pilgrim Station's annual capacity factor, s lidated financial statements for specific information relating to our An annual capacity factor between 60% and 68% would provide us recent financing activities. with approximately $47 million of revenues in the performance year ended October 1995. fur each percentage point increase in capacity Outlook for the Future factor above 68%, annual revenues will increase by approximately 5690,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease Electricity sales by approximately 5790,000. Pilgrim's capacity factor for the perfor- A significant portion of our electricity sales are made to commercial mance year ending October 1995 is currently expected to be customers rather than industrial customers. As a result our sales have approximately 69%, a decrease from the 72% capacity factor been only moderately impacted by the unfavorable economic factors achieved in the performance year ended October 1994, primarily alTecting the manufacturing industry in Mawachusetts, including due to the refueling outage scheduled for 1995.We earned approxi- defense cutbacks and continued downsizing in the computer indus-mately $47 million in revenues related to Pilgrim's capacity factor in try. Increased sales to commercial customers more than offset the the performance year ended October 31,1994. decrease in sales to industrial customers as economic factors provid. Pilgrim Station automatically shut down in August 1994 as a ed growth in the commercial sector in 1994. Total retail sales result of a non-nudear problem with its electrical generator.The increased 2% in 1994. plant returned to service three months later following the comple- Implementation of DSM programs, which are designed to assist tion of necessary repairs as well as maintenance work origmally customers in reducing electricity use, will result in lower growth in scheduled for an October 1994 mid-cycle outage The power needs electricity sales. We receive approval from our state regulators for uaually met by the station were met by our other generating plants annual DSM spending levels and recovery amounts.Through 1994 or purchased from other suppliers as necessary.We do not believe we collected from customers certain DSM program costs primarily that the generator damage resulted from actions within our control, in the year incurred and other DSM program costs over a six-year however, our recovery of the incremental purchased power costs period.We are also provided with incentives and recovery oflost during the outage through fuel and purchased power evenues is revenues based on the actual reduction in customer electricity usage subject to review by our state regulators under our generating unit from these programs and a return on the costs that we recover over performance program. six years. Beginning in 1995 all costs are expected to be collected As discussed in Regulatory Proceedings, we do not plan to make primarily in the year incurred.We will continue to recover the DSM a bar rate filing with our state regulators upcm the expiration of the costs capitalized during 1992 through 1994 along with a return on 1992 settlement agreement, therefore we anticipate that our base investment on the unrecovered balance. rates will remain in effect at their current levels. Competition Liquidity The electric utility business is in a period of transition from a tradi-tional rate-regulated environment based on cost recovery to an emi. We meet our capital expenditure cash requirements primarily with ronment with both competition and modified regulation.The effects internally generated funds.These funds provided for 98%,76% and of competition to date have been most evident in the wholesale elec-Ha% of our plant and nuclear fuel expenditures in 1994,1993 and tric market. In response to ir. creased competition from other elec-1992, respectively. Our current estimate of plant expenditures for tric utilities and non-utility generators to sell electricity for resale, 1995 is $200 milhon.These expenditures will be used primarily to we have secured long term power supply agreements with our five maintain and improve existing transmission, distribution and genera. w holesale customers.These agreements set our rates through the tion facilities.We do not expect plant expenditures to vary signifi. year 2002 and beyond. 18
We are also beginning to face some forms of competition in the We are aho subject to our state regulators' integrated resource retail electric market.This is happening as iulustrial and large com- management (IRM) process in w hich electric utilities forecast their mercial customers pursue their options to generate their own electric future energy needs and propose how they will meet those needs by power, as customers look to obtain 'iower electricity prices and to sub- balancing conservation programs w ith all other supplies of energy. We = stitute natural gas or oil for clectricity for heating or cooling purposes submitted an IRM filing in 1994 and received a favorable ruling in and as large facilities factor the cost of electricity into their decisions January 1995. Our regulators found that we do not have a need for to rekicate into or out of a gi ren service territory. In the future, the additional resources through 2001 and we are not required to issue a potential exists for electric utJ. ties and other energy suppliers to sell competitive request for proposal for new generating capacity at this electricity to retail customers tIother electric utilities without regard time.We are required to update our IRM filmg in january 1996. for existing service territories. In addition, our state regulators are narrently investigating two issues related to the onset of competition, Non-utility businesa incentive regulation andindustry restructuring' In 1993 we created an unregulated subsidiary, Boston Energy We are re3ponding to the current and anticipated retail competi-Technology Group (BETG), following approval from our state regu-tive challenges in several ways. We do not plan on seeking any addi-lators.We have authority to invest up to 545 million in this wholly-tional base rate increases until at least the year 2000 and are working owned subsidiary. BETG engages in demand side management activi-
~
to accomplish this by controlling costs and increasing operating effi-ties and businesses involving electric transportation and the related ciencies without sacrificing quality of service or profitability. During infrastructure through two wholly-owned subsidiaries. In 1994 1994 we reduced our workforce by 8.4%, we negotiated six year BETG acquired a substantial majority interest in two additional busi-contracts with our two union locals which resulted in cost-saving changes and limits wage growth and we implemented various other nesses. REZ-TEK International Corp. produces systems that treat cost control strategies. We also developed customer alliances and cooling water used in commercial and industrial air conditioning sys-provided economic development rates to some customers. In addi- tems in an energy eflicient and environmentally sound manner, and tion, we filed with our state regulators for approval oflower rates Coneco Corporation provides engineering and project management for a small number of large manufacturing customers on a limited services to energy and water conservation project developers and contractors.These acquisitions were not material. basis.These actions all signify our commitment to be a competitively We do not currently have a substantial in estment in BETG and priced, reliable provider of energy. We are also actively participating in regulatory and legislative discussions and proceedings concerning do not anticipate it sigmficantly impacting our results of operations m the next several years. the future structure of the electric utility industry.We do not expect ' the economic development rates or the proposed lower manufactur-ing customer rates to have a significant impact on our financial con-Other Matters dition or results of operations. As a regulated company, we are subject to certain accounting rules that are not applicable to other businesses and industries.These f"*I'"""'"'"I accounting ruks allow regulated companies, as appropriate, to We are subject to numerous federal, state and local standards with record certain costs as regulatory assets instead of expenses when respect to waste disposal, air and water quality and other environ-they are incurred.These regulatory assets are expected to be recov- mental considerations.These standards can require that we modify cred from customers through future rates.The elTects of competition our existing facilities or incur increased operating costs. or changes in regulation could ultimately cause us to no longer be We ou n or operate 48 properties where hazardous materials able to follow these accounting rules, in which case our regulatory were released in the past. We are required to clean up these proper-assets would have to be fully expensed at that time. ties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing Resource regulation to evaluate the costs associated with their cleanup.There are uncer. Our state regulators require utilities to purchase power from quali- tainties associated with these costs due to the complexities of fying non-utility generators at prices set through a bidding process, cleanup technology, regulatory requirements and the particular char-In 1993 our state regulators ordered us to purchase 132 megawatts acteristics of the different sites. We also continue to face possible lia. of power from an independent power producer, Altresco Lynn, LP, bility as a potentially responsible party in the cleanup of ten multi. starting as early ai 1995,We oppose this order since we do not party hazardous waste sites in Masochusetts and other states w here , believe we need any new power for several years.We asked the we are alleged to have generated, transported or disposed of haz. h Massachusetts Supreme Judicial Court (SJC) to reverse the order ardous waste at the sites. At the majority of these sites we are one of and in 1994 the SJC remanded the case to our state regulators for many potentially responsible parties and we currently expect to have further consideration. Our regulators then issued an order requiring only a small percentage of the potential liability.Through December us to negotiate a contrad with Altresco Lynn.We filed an appeal of 31,1994, we have accrued approximately 57 million related to our this order with the SJC in October 1994 and are currently awaiting cleanup liabdities. We are unable to fully determine a range of rea-a decision. In addition, we supported an appeal filed by other parties sonably possible cleanup costs in excess of the accrued amount, of a state regulatory body's conditional approval of construction of although based on our assessments of the specific site circumstances, Altresco Lynn's generating station projed. in January 1993 the SjC we do not expect any such additional costs to have a material impact reversed the regulator's approsal on the basis that there was no on our financial condition. Ilowever, additional provisions for showing of need for the project in Massachusetts prior to 2000. cleanup costs could have a material impact on our results of a 19
reporting periott allow the units to meet the provisions of the 1995 standards. Uncertainties continue to exist with respect to the disposal of Depending upon the outcome of certain DEP air quality modeling both low. level radioactive waste (LLW) and spent nuclear fuel studies currently in progress, additional emission reductions may also resulting from the operation of Pilgrim Station. In July 1994 our be required by 1999.The extent of any additional reductions and the access to off site LLW disposal facilities ended. Until access is cost of any further modifications is uncertain at this time. attained to other disposal facilities we are managing LLW through in recent years there have been increasing public concerns anoite storage.The United Stttes Department of Ene gy (DOE)is regarding electrcmagnetk Ceids (EMF) associated with electric responsible for the ultimate disposal of spent nuclear fuel, however transmission and distribution facilities and appliances and wiring in there are uncertainties regarding the DOE's schedule of acceptance buildings and homes. Such concerns have included the possibility of of spent fuel for disposal. Refer to Note D to the consolidated finan- adverse health effects caused by EMF as well as perceived elTects on cial statements for further discussion regarding LLW and spent property values. Some scientific reviews conducted to date have sug-nuclear fuel ds.posal gested associations between EMF and potential health etTects, while Under a 1991 consent order with the DEP and other interested other studb na'e not substantiated such associations.We support parties we made certain improvements in the emission control sys- further research into che subject and are participating in the funding tems at New Boston Station.These improvements included the of industry. sponsored studies.We are aware that public concern replacement of four existing chimney stacks with two taller stacks in regarding EMF in some cases has resulted in litigation, in opposition order to improve the air quality in the vicinity of the station, and the to existing or proposed facilities in proceedings before regulators or installation oflow nitrogen oxides burners.The capital costs of these in requests for legislation or regulatory standards concerning EMF modifications along with other associated improvements, which were levels.We have addressed issues relative to EMF in various legal and substantially completed in 1994, were approximately $80 million. regulatory proceedings and in discussions with customers and other New Boston Station has the ability to burn natural gas, oil or concerned persons; however, to date we have not been significantly both. Beginning in April 1995, as part of the DEP consent order, we alTected by these developments.We continue to closely monitor all will be required to operate the station fueled exclusively by natural aspects of the EMF issue. gas, except in certain emergency circumstances.We have made arrangements for a firm supply of natural gas to run the station at a Litigation minimum level We are developing a least-cost plan for operation In 1991 we were named in a lawsuit alleging discriminatory employ-beyond this minimum level involving principally the utilization of ment practices under the Age Discrimination in Employment Act of interruptible gas supplies or short-term capacity purchases. 1967 concerning 46 employees alTected by our 1988 reduction in The 1990 Clean Air Act Amendments will require a significant force. Legal counsel continues to vigorously defend this case. Based reduction in nationwide emissions of sulfur dioxide from fossil fuel- on the information presently available we do not expect that this liti-lired generating units.The reduction will be accomplished by restrict- gation or certain other legal matters in which we are currently ing sulfur dioxide emissions through a market-based system of involved will have a material impact on our financial condition. allowances.We currently have allowances that are in excess of our liowever, an unfavorable decision ordered against us could have a needs and which may be marketable. Any gain from the sale of these materialimpact on our results of a reporting period. may be subject to future regulatory treatment. Other provisions of the 1990 Clean Air Act Amendments invohe limitations on emissions Executive Ofice Changes of nitrogen oxides from existing generating units. Combustion system in July 1994 our former President, Thomas May, became Chairman modifications made to New Boston and Mystic Stations, including the and Chief Executive Oflicer, former Executive hice President installation of the low nitrogen oxides burners at New Boston, will Geg Davis became President and Chief Operating Ollicer and former Chairman and Chief Executive Officer Bernard Reznicek retired. In January 1995 George Davis announced his anticipated retirement effective September 1995, 1 l 20
CONSOLIDATED STATEMENTS OF INCOME years ended December 31, (in thousands except earnings per share) 1994 1993 1992 Operating revenues $ 1,548,554 $ 1,482,2 5 3 5 1,411,753 Operating expenses: Fuel I56,95I I70,799 200,774 Purchased p<mer 356,874 370,049 352,030 Other operations and maintenance 441,423 406,271 379,350 Depreciation and amortization 149,122 137,722 129,045 Amortization of deferred cost of cancelled nuclear unit 19,791 0 24,381 Amortization of deferred nuclear outage costs 7,721 6,546 4,901 Demand side management programs 35,438 37,504 8,221 Taxes - property and other 100,132 93,102 80,426 Income taxes 54,279 34,941 11,725 Total operating expenses 1,321,731 1,256,934 1,190,853 Operating income 226,823 225,319 220,900 Other income (expense), net 5,658 589 (2,074) Operating and other income 232,481 225,908 218,826 Interest charges: Long-term debt 102,570 104,375 106,850 Other 12,167 9,778 12,525 Allowance for borrowed funds used during construction (7,478) (6,463) (7,847) Total interest charges 107,459 107,690 111,528 Net income 125,022 118,218 107,298 Preferred and preference dividends prosided 15,765 15,705 16,550 Balance availablefor common stock $ 109,257 $ 102,513 $ 90,748 Common shares outstanding (weighted average) 45,338 44,959 43,144 Earnings per share of common stock $ 2.41 2.28 5 s 2.10 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS years ended December 31, (in thousands) 1994 1993 1992 Balance at beginning of year $ 218,292 5 192,948 5 174,477 Net income 125,022 118,218 107,298 Subtotal 343,314 311,166 281,775 Cash dividends declared: Preferred stock 15,765 15,705 14,923 Preference stock 0 0 1,953 Common stock 80,545 77,169 71,951 Subtotal %,310 92,874 88,827 Balance at end of year $ 247,004 5 218,292 192,948 s The accompanying notes are an integral part of the consolidated financial statements. l l 21
CONSOLIDATED BALANCE SHEETS December 31, (in thousands) 1994 1993 Assets Utility plant at original cost: In service $ 4,074,810 $ 3,904,776 Less: accumulated depreciation 1,144,452 s 2,730,158 1,258,359 $ 2,646,417 Nuclear fuel 291,836 273,867 Less: accumulated amortization 216,219 55,597 220,477 53,390 Construction work in progress 144,048 144,835 , I 2,930,001 2,844,642 investments in electric companies, at equity 24,678 24,292 1 Nuclear decommissioning trust 82,811 66,060 Current assets: j Cash and cash equivalents 6,822 8,768 Accounts receivable 189,382 171,098 Accrued unbilled revenues 32,240 29,823 Fuel, materials and supplies, at average cost 71,560 79,381 Prepaid expenses and other 26,705 326,709 9,738 298,808 Deferred debits: ) Regulatory assets 197,455 210,144 Intangible asset pension 22,849 0 4 Other 32,085 252,189 33,342 243,486 Total assets $ 3,616,610 $ 3,477,288 Capitalizatwn and Liabilities Common stock equity 5 915,747 5 876,479 Cumulative preferred stock: Non mandatory redeemable series 121,000 123,000 Mandatory redeemable series 94,000 96,000 ' Long term debt 1,136,617 1,272,497 Current liabilities: j Long-term debt / preferred stock due within one year $ 102,250 $ 2,000 Notes payable 214,786 204.151 Accounts payable 139,119 117,614 Interest accrued 24,464 25,467 Dividends payable 21,513 22,696 Pension benefits 11,908 22,005 Other 76,615 612,675 32,477 426,410 Deferred credits: Power contracts 40,277 36,275 Accumulated deferred income taxes 515,454 484,785 Accumulated deferred imestment tax credits 67,048 71,140 Nuclear decommissioning reserve 92,404 73,744 Other 19,188 734,571 16,958 682,902 Commitments and contingencies - - Total capitalization and liabihties $ 1,616,610 $ 3,477,288 The accompanying notes are an integral part of the comolidated fmancial statements. I i
CONSOUDATED STATEMENTS OF CASH FLOWS years ended December 31, (in thousands) 1994 1993 1992 Cash flows from operating activities: Net income $ 125,022 s i18,218 $ 107,298 Adjustments to reconcile net income to net cash prmided by operating actisities: Depreciation 142,932 130,074 123,243 l Amortization of nuclear fuel 18,810 21,816 25,473 Amortization of deferred cost of cancelled nuclear unit, net 19,% 7 0 22,340 Amortiration of deferred nuclear outage costs 7,721 6,546 4,901 Other amortization 13,% 7 9,433 2,132 Deferred income taxes (4,184) 10,303 17,165 Imutment tax credits (4,092) (4,073) (4,273) Allowance for borrowed funds used during construction (7,478) (6,463) (7,847) Net changes in: Accotmts receivable and accrued unbilled revenues (20,701) 13,206 (18,188) Fuel, materials and supplies 3,093 9,722 (2,330) Accounts payable 21,505 (18,465) 35,759 l Rate and contract settlements 0 (31,363) (175) l Other current assets and liabilities 36,908 25,209 3,575 Other, net 15,561 (19,548) (15,844) Net cash provided by operating activities 368,131 295,803 262,04i investing adivities: Plant expenditures (excluding AFUDC) (198,760) (246,763) (213,827) Nuclear fuel expenditures (21,934) (6,491) (17,198) Capitalized demand side management expenditures (37,007) (37,156) (11,469) Sale of plant assets, net 15,972 0 0 Nuclear decommissioning trust imestments (16,771) (15,189) (7,210) Electric company investments (186) 1,106 1,836 Net cash used by investing activities (258,886) (304,493) (247,868) Financing activities: Issuances: Common stock 10,634 10,855 70,412 Preferred stock 0 40,000 40,000 Inng term debt 15,000 815,000 60,000 Redemptions: Preferred and preference stock (2,000) (40,000) (40,333) Long-term debt retirements (50,000) (648,625) (123,600) Net change in short-term debt 10,635 (71,349) 65,200 l Dividends paid (95,460) (92,370) (86,184) Net cash provided (useJ) byfinancing activities (ll1,191) 13,511 (l4,505) , f Net increase (decrease) in cash and cash equivalents (1,946) 4,82I (332) l Cash and cash equivalents at the beginning of the year 8,768 3,947 4,279 Cash and cash equivalents at the end of the year 5 6,822 5 8,768 5 3,947 Cash paid during the year for: Interest, net of amounts capitali/ed $ 108,462 s 103,720 $ 113,076 Income taxes $ 46,074 $ 30,305 $ 10,095 The accompanying notes are an integral part of the consolidated 11nancial statements. 23 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ . ._. 0
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note A.Significant Accounting Policies
- 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our w holly-ow ned subsidiaries, liarbor Electric Energy Company and Boston Energy Technology Group. All significant intercompany transactions base been eliminated.
We follow accounting policies prescribed by our federal and state regulators. We are also subject to the accounting and reporting requirements of the Securities and Exchange Comniission. The financial statements comply with generally accepted accounting principles. Certain prior period amount < on the Gnancial statements were reclassified to conform with current presentation.
- 2. .%eraues We record resenues for electricity used by our customers but not yet billed at the end of each accounting period.
- 3. Forecasted fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased p mer allows for fuel and some purchased power costs to be billed to customers using a forecasted rate. The difference between actual and estimated costs is recorded as an adjustment to fuel and purchased power expenses and is includ.
ed in accounts receisable until subsequent rates are adjusted. State regulators hase the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel. .t. Depreciation and Nuclear Fuel Amortization Our physical property was depreciated on a straight-line basis in 1994,1991 and 1992 at composite rates of 3.11%,3.09% and 3.36% per year, respectisely, based on estimated useful lives of the various classes of property. The cost of decommissioning Pilgrim Station, our nuclear unit,is excluded from the depreciation rates. When property units are retired, their cost, net of sahage value, is charged to accumulated depreciation. He cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are reemered from our customers through fuel rates. S. Amortiration of Deferred Nuclear Outage Costs We expense deferred nuclear outage costs over five years as approved in the 1992 settlement agreement. The deferred cost balances in 1994 and 1993 consist of amounts related to the 1993 and 1991 refueling outages at Pilgrim Station.
- 6. Amortization of Discounts, Premiums and Redemption Premiums on Debt We expense discounts, premiums, redemption premiums and related costs associated with issuances or redemptions oflong-term debt or the refl.
nancing of existing debt over the life of the debt or the replacement debt subject to regulatory approval.
- 7. Allonancefor Funds Used During Construction (AFUDC)
Al UDC represents the estimated costs to finance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction ofinterest charges. Although AFUDC is not a current source of cash income, the costs are reemered from customers mer the senice life of the related plant in the form ofincreased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1994,1991 and 1992 were 4.45%, 3.62% and 4.48%, respectively, and represented only the cost of short-term debt.
- 8. Cash and Cash Equivalents Cash and cash equisalents are comprised of highly liquid securities with maturities of three months or less. Outstanding checks are included in cash and accounts payable until they are presented for payment.
- 9. Allowancefor Doubtful Accounts Our accounts receisable are substantially all recmerable. This recovery occurs both from customer payments and from the portion of customer charges that prosides for the recmery of bad debt expense. Accordingly, we do not maintain a signincant allowance for doubtful accounts balance.
- 10. Regulatory Assets Regulatory assets represent costs incurred which will be collected from customers through future charges in accordance with agreements with our state regulators. These costs are to be expensed when the corresponding resenues are received in order to appropriately match revenues and ,
expenses. A portion of these costs is currently being recovered from customers. No return on investment was carned on the regulatory assets. Regulatory assets consisted of the following: December U, 1994 1993 Redemption premiums s 52,859 s 59,116 income taxes, net 44,745 26,916 Power contracts 40,277 36,275 Pension and postretirement costs 22,761 24,416 Nuclear outage cmts 17,804 25,524 Cancelled nuclear unit 0 19,067 other 19,009 18,830
$ 197,455 5 210,144 24
i l Note B. Retail Settlement Agreements in 1992 and 1989 our state regulators, the Massachusetts Department of Public titilities, approved three year settlement agreements relating to our rate case proceedings These agreements prusided for retail rate increases, accounting adjustments and demand side management program expendi-tures; clarified the timing and recognition of certain expenses and set limits on our rate of return on common equity. Refer to Management's Discussion and Analysis for further information related to these settlement agreements. The settlement agreements did not afTect our contract or wholesale power rates charged to other utilities, which are regulated by our federal regulators, the Federal Energy Regulatory Commission. j l l Note C. Income Taxes ll in 1993 we prospectively adopted Statement of Financial Accounting Standards No.109, Accounting for incomeTaxes (SFAS 109). This required us to change our meth<xlology of accounting for income taxes from the deferred method to an asset and liability approach. The deferred methtxl was ba3ed on the tax elTects of timing diiTerences between income for ilnancial reporting purposes and taxable income. The asset and liability approach ; requires the recognition of deferred tax assets and liabilities for the future tax clTects of temporary ditTerences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we reconled net regulatory assets of 544.7 million and 526.9 million and corre-sponding net increases in accumulated deferred income taxes as of December 31,1994 and December 31,1991, respectively. The regulatory assets represent the additional future revenues to be colleded from customers for deferred income taxes. Accumulated deferred income ta .cs consisted of the following: December 31, I (in thousands) 1994 1993 l Deferred tax liabilities: ' Plant-related $ 511,572 5 496,731 Other 105,786 95,161 617,358 591,892 Deferred tax assets: Plant-related 13,216 9,999 investment tax credits 41,271 45,914 Alternative minimum tax 1,332 18,672 Other 44,081 32,522 101,904 107,107 Net accumulated deferred income taxes s 515,454 5 484,785 No valuation allowances for deferred tax assets are deemed necessary. Components ofincome tax expense were as follows: years ended December 31, (in thousands) 1994 1993 1992 Current income tax expense S 62,819 5 28,711 $ (385) Deferred tax expense (4,468) 10,301 16,383 Investment tax credits (4,092) (4,073) (4,273) Income taxes charged to operations 54,279 34,941 11,725 Taxes on other income: Current 2,550 1,205 (2,348) Deferred 284 0 782 2,8 14 1,205 (1,566) Totalincome tax expense $ 57,113 $ 36,146 s 10.159 The elTective income tax rates reflected in the consolidated Gnancial statements and the reasons for their ditTerences from the statutory federal income tax rate were as follows: 1994 1993 1992 Statutory tax rate 15.0% 35.0% 34.0*o State income tax, net of federal income tax beneGt 4.1 4.2 3.9 invet,tment tax credits (2.1) (2.6) (3.6) Municipal property tax adjustment - (0.6) (l.6) Adjustment of deferred taxes on cancelled nuclear unit - - 2.7 Reversal of deferred taxes-settlement agreement (5.5) (13.0) (19.6) Federal tax benefit of mandated payments from settlement agreements - (6.2) Other 0.4 (0.l) (0.9) EtTective tax rate 11.4 % 23.4 % 8.7% 25
Note D. Nuclear Decommissioning and Nuclear Waste Disposal I. Nuclear Dewmmissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommiwion the plant. We are expeming an estimate of the decommissioning costs mer Pilgrim's expected sersice hfe. The 1994 expense of approximately 5 I 5 million is included in depreciation expense on the consolidated income statement. The estimate used to determine our annual expense is based on a 1991 study w hich documents a ;ost of approximately 5128 million to decommission the plant using the" green ticki" methml, w hich pnnides for the plant site to be completely restored to its original state. The cost estimate, w hich imohes many uncertainties, was incorporated in our 1992 retail settlement agreement. We receise recovery of the annual expense from charges to our retail customers and from other utility companies and municipalities w ho purchase a contracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted so that they may only be used li>r decommissioning anil related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning fund balance and nudear decommissioning rescrse, thus reducing the amount to be tollected from customers. The 1991 decommissioning study was partially updated for internal planning purpnes to evaluate the potentialimpact oflong-term spent fuel storage options resulting from delays in United States Department of Energy (DOE) spent fuel remmal on the estimated decommissioning cost. (See part 2 below for a discussion of spent fuel remmalb The partial uplate indicates an estimated decommissioning cost of approximately 5400 million in 1991 dollars based upon a revised spent fuel remosal schedule and utilization of dry spent fuel storage technology. No further update is currently available, however we will continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate. In 1994 the Financial Accounting Standants Board begar to resiew the accounting for decommissioning. If current industry accounting practices are changed our annual detummissioning expense couhl increase and trust fund earnings couhl be reported as imestment income. In a<hhtion, the total estimated liability for decommissioning costs may be recortled on the balance sheet, most hkely fully olTset by an achhtion to utility plant costs. We do not expect that these potential changes would hase a material etrect on our results of operations. L Spent Nuclear Fuel in 1994 we receised a license amendment from the Nuclear Regulatory Commission to mmhfy our fuel storage facility at Pilgrim Station to provide sullicient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. We base mahlied the facility to prmide spent fuel storage capacity through approximately 2003, howeser any further modifications are subject to review by our state regulators. In addi-tion we are actisely exploring the feasibihty of other spent fuel storage facihties and technologies. It is the ultimate responsibility of the DOE to permanendy thspose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. We currently pay a fee of s 1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract uith the DOE. The fee is collected from customers through fuel charges. The DOE is currently conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political oppmition and the DOE has publicly stated that it may be unable to construct suth a repository in a timely manner. In June 1994 we and other interested parties filed peti-tions in the ll S. Court of Appeak for the D.C. Circuit seeking declaratory rulings that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. The DOE has sought to dismiss those petitions and a court ruling is awaited. It is unknown at this time w hether and on what u hedule the DOE will esentually construct a spent fuel repository and what the eifect on us will be of any delays in sut h construction. L Lon-Level Radioactive Waste our access to lowdesel radioactise waste (LLW) dispmal facihties located in Barnwell, South Carnhna ended in July 1994. Lintil access is attained to other disposal facihties we are managing i LW generated at Pilgrim Station through on-site storage. I egislation has been enacted in Massachusetts estabhshing a regulatory process for managing the state's i LW including the possible siting,litensing and construction of a disposal facihty within the state, or, alternatisely, an agreement with one or more other states, lloweser,it appears unhkely that either option nill he asail able in the near future. Pending the construction of a disposal facility within the state or the adoption by the state of some other LtW management procedure, we will continue to monitor the situation and imestigate other asailable options.
- 4. Other Nuclear Units We are an imestor in and customer of tuo other domestic nutlear units. Iloth of these units receise, through the rates charged to their customers, an amount to cmer the estimated cmts to dispose of their spent nuclear fuel and to decommission the units at the end of their useful hses.
Note E. Pensions, Other Postretirement and Postemployment Benefits I. Pensions We hase a delined benefit funded retirement plan nith certain contributory features that cmcrs substantially an employees. Benefits are based upon an employce's years of sersice and compensation during the last years of employ ment. Our funding policy is to contribute an amount cath year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Plan assets are pri-marily equities, bonds, insurance contracts and real estate funds. Net pension cost consisted of the folhming components: 26
l years ended December 31, (in thouaands) 1994 1993 1992 Current sersice cost twnelits carned 5 15,057 $ 11,7 34 s 10,685 Interest cost on projected benefit obligation 31,961 31,181 32,287 Actual net loss /(return) on plan assets 214 (44,470) (23,281) Net amortization and deferral (12,169) 8,528 (l3,549) Net pension cost (a) 5 17,061 5 8,973 5 6,140 (a) in accordance with an agreement with our state regulators we deferred the (htference in net pension costs and the annual funding amounts. Net deferred msts amounted to 56 milhon and s 14 milhon at December 11,1994 and 1993, respectively. Net pension tmts recorded as expense were 525 million in 1994,55 milhon m 1991 and 50 in 1992. We used the fcdlowing assumptions for calculating pension cost: 1992 I 1994 1993 Discount rate 7.00 % 8.25 % 8.25% Exjwcted long. term rate of return on assets 10.00 % 10.00 % 10.00 % Compensation increase rate 4.50 % 4.50 % 4.50 % The pension plan's funded status was as follow s: December 31, (in thousands) 1994 1993 Actuarial present value of benetit obligations: Accumulated benellt obligation, including sested benefits of 5 305,632 and $ 384,t 50 $ 321,072 s 400,895 Plan assets at fair value $ 289,164 5 394,233 j Projected obligation for sersice rendered to date (387,910) (509,661) Projected benefit obligation in excess of plan assets (98,746) ( l I 5,428) Unrecogni/cd prior sersice cost i3,128 8,139 Linrecognized net loss 67,161 75,352 linrecognized net obligation 8,998 9,932 Minimum liability adjustment (b) (22,849) 0 Net pension liabilitv 5 (31.908) 5 (22,005) (b) statement of financial Accounting Standards No. 87,imployers' Accounting for Pensiom (SFAS 87), requires the recognition of an additional minimum liability for the esceu of accumulated benefits over the fair value of plan assets and accrued pension msts, in accordance with Si As 87 we recorded an ad<htional mini-mum liability and corresponding intangible asset of $2 3 milhon on our consohdated balance sheet at December 11,1994. We used the following assumptions for calculating the plan's year-end funded status: 1994 1993 i Discount rate 8.25% 7.00 % j Compensation increase rate 1.90 % 4.50 % We aho provide defined contribution 40ltk) plans for substantially all our employees. We match a percentage of employees' mluntary contri-butions to the plans, w hich amounted to $8 million in 1994,57 million in 1991 and s 5 million in 1992.
- 2. Other Postretirement Benefits in addition to pension benefits, we also currently proside health care and other benefits to our retired employees u ho meet certain age and years of service eligibility requirements. In 1993 we adopted Statemcnt of Financial Accounting Standards No.106, Employers' Accounting for l Postrctirement lienefits OtherThan Pensions (SFAS 106). This requires us to record a liability during the working years of employees for the expected costs of proiiding their postretirement benefits other than pensions (PITOPs). Prior to 1993 our policy was to record the cost of PilOPs u hen paid. Our transition obligation upon adopting this standard uas approximately s 18 3 million, w hich we elected to recognize oser 20 years as permitted by SFAS 106.
Our 1992 settlement agreement prosides us uith a phase-in of a portion of the higher PilOP costs incurred under SI AS 106 and allow s us to defer the additional costs in excess of the phase-in amounts to the extent that we fund an external trust. Our funding policy is to contribute 100% of postrctirement benefit costs to external trusts. Accordingly, we recorded expenses of s 17 million in 1994 and s 15 million in 1993, reflecting the amount of current cost reemery from customers, and deferred the net costs in excess of amounts expensed for future re(mery. Net deferred costs amounted to 516 million and $10 million at December 31,1994 and 1993, respectively. i i 27
. . _ - . _. ~ - . . .
Net postretirement benefits cost consisted of the following components: years ended December 31, (in thousands) 1994 1993 Current service cost . benelits earned $ 4,978 $ 4,351 Interest cost on accumulated benellt obligation 13,632 14,286 i Actual return on plan assets 0 (187) Amortization of transition obhgation 9,151 9.151 Net amortization and deferral (2,581) 0 ; Net postretirement benelits cost $ 24,993 $ 27,788 l l We used the following assumptions for calculating postretirement benefits cost: 1994 1993
)
Discount rate 7.0% 8.0% Ex;weted long-term rate of return on assets 9.0% 9.0% i llealth care cost trend rate 9.0% 12.5% ) The health care cost trend rate is assumed to decrease by one percent each year beginning in 1995 to 5% in 1998 and years tnereafter. Changes in the health care cost trend rate will alTect our cost and obligation amounts. A one percent increase in the assumed health care cost trend rate would increase the total sersice and interest cost components by 20% and would increase the accumulated benefit obligation at December 31,1994 by 18%. The postretirement benclits program's funded status was as follows: December 31, (in thousands) 1994 1993 Trust assets at fair value $ 33,300 $ 18,016 Acmmulated obligation for sersice rendered to date from: Retirees $ (93,960) $ (75,216) Acthe employees eligible to retire (31,159) (64,880) Actise emplovees not eligible to retire (51,545) (176,664) (73,285) (213,381) Accumulated benefit obligation in excess of trust assets (143,364) (195,365) Unrecogni/ed prior service cost (19,502) 0 , Unrecognized net (gain)/ loss (1,849) 21,497 ' Unrecognized transition obligation 164,715 173,868 Net postretirement benefits liability $ 0 5 0 The weighted average discount rates we used to measure the accumulated benefit obligation were 8.25% in 1994 and 7.0% in 1993. The trust assets consist of equities, bonds and money market funds.
- 2. Postemployment llene)Its in 1994 we adopted Statement of Financial Accounting Standards No.112, Employers' Accounting for Postemployment Benefits (SFAS 112). This 1 required us to record a liability for the estimated costs of providing postemployment benefits. Postemployment benefits provided to former or inactive employees, their beneficiaries and covered dependents consist primarily of disability-related benefits, including workers' mmpensation. We prestously recogni/ed the costs of these benefits primarily as claims were paid. The adoption of SFAS 112 did not have a material etTed on our results of operations.
1 Note F. Eminent Domain Taking i in Nmember 1994 a Norfolk Superior Court ruling against the Massachusetts Metropolitan District Commission (MDC) became effective, prmid. ing us with an additional 5 5.7 million gain on an eminent domain land taking case. We had filed suit against the MDC in 1992 related to the emi. nent domain taking of certain of our property in 1989. 1 Note G. Cancelled Nuclear Unit l in May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear unit over approximately cleven and one half years in accordance with j an order received from state regulators. We did not expense any of these costs in 1993. The remaining balance of s19 million was fully expensed in i I 1994 as allowed by our state regulators in our 1992 settlement agreement. l l l l l 28
Note H. Capital Stock and 1:debtedness Capital Stuk 1)ccember 31, (dollars in thousands, enept per share amounts) 1994 1993 1992 Common stock equity: Common stock, par value 5I per share, 100,000,000 shares authorized; 45,535,477, 45,129,227 and 44,763,055 shares issued and outstanding: $ 45,515 5 45,129 5 44,763 Premium on common stock 622,803 612,653 602,196 Retained earnings 247,004 218,292 192,948 Surplus invested in plant 405 405 405 Total common stock equity $ 915,747 5 876,479 5 840,312 Cumulative preferred stock: Par velue $100 per share,2,890,000 shares authorized; issued and outstanding: Non-mandatory redeemable series: Current Shares Redemption Series Outstanding Price / Share 4.25 % 180,000 $ 103.625 $ 18,000 $ 18,000 $ 18,000 4.78 % 250,000 $ 102.800 25,000 25,000 2 5,0(X) 7.75% 400,000 . 40,000 40,000 0 8.25 % 400,000 - 40,000 40,000 40,(XX) 8.88 % 0 0 0 40,000 Total non-mandatory redeemable series 5 121,(XX) 5 123,000 5 123,000 Mandatory redeemable series: Current Shares Series Outstanding 7.27% 460,00() $ 46,000 5 48,(XX) 5 48,000 8.00 % 500,000 50,000 50,000 50,000 Total mandatory redeemable series %,000 98,000 98,0(X) Less: due within one year 2,000 2,000 0 Total mandatory redeemable series, net S 94,(XX) 5 96,000 $ 98,000 Dividends DeclaredperShare Common stock $ l.775 5 1.715 5 1.655 Preferred stock: 4.25% series S 4.250 5 4.253 5 4.250 4.78% series 4.780 4.785 4.780 7.27% series 7.270 7.270 7.270
. 7.75% series 7.750 5.707 0 8.00% series 8.000 8.000 8.fXX) 8.25% series 8.250 8.250 5.278 8.88% series 0 2.220 8.880 Preference stock: l 51.46 series $ 0 5 0 5 0.365 1
I I l 29
indebtedness December 31, (dollars in thousands) 1994 1993 Long-term clebt: 4 First mortgage bonds: Series S, variable rate, due 2002 $ 0 5 2 5,0(X) Series U,10.250%, due 2014 0 15,000 Total first mortgage bonds 0 40,000 l l Sewage facility revenue bonds 36,300 36,300 lxss: due within one year 600 0 less: funds held by trustec 4,083 3,803 Net long-term sewage facility resenue bonds 31,617 32,497 Debentures: 8.875%, due 1995 100,(XX) 100,000 5.12 5%, due 1996 100,(XX) 100,000 5.700%, duc 1997 100,(XX) 100,000 5.950%, due 1998 100,(XX) 100,000 6.800%, due 2000 65,000 65,000 6.03(M, due 2tXX) 100,0(X) 100,00() 6.80m., due 2001 150,(XX) 150,000 9.875%,due 2020 100,fXX) 100,(XX) - 9.375%,due 2021 115,000 125,000 8.250%, due 2022 60,000 60,000 l 7.800%, due 202 3 200,0.X) 200,000 Total debentures 1,190,0(X) 1,200,000 Less: due within one year 100,0tX) 0 Net long-term debentures 1,090,000 1,200,000 Massachusetts industrial Finance Agency Innds: 5.750%,due 2014 15,000 0 Total long-ter m debt 5 1,136,617 5 1,272,497 Short-term debt: Notes payable: Bank loans 5 80,786 5 106,501 Commercial paper 114,000 97,650 7btal notes pavable 5 214,786 5 204,151 1, Common Stock Since December 31,199 8, we issued the following shares of common stock: Number Total Premium on , (in thousands) of 5 hares Par Value Common Stock l Italance December 31,1991 42,047 5 42,W7 5 516,567 j Disidend reinvestment plan 416 416 9,658
)
New issue (a) 2,300 2,300 55,971 j llalance December 31,1992 44,763 44,763 602,196 l Disi< lend reinvestment plan 166 366 10,457 Italance December 31,1991 45,129 45,129 612,653 Dhidend reimestment plan (b) 406 406 10,150 Halan(c December 11,1994 45,535 5 45,535 5 622,801 (a) We uwd the net proceeds of the 1992 conunon stm k issuante to redute short -term debt. (b) At December 31,1994, the remaining authoriecd common shares restned for future issuance under the Disidend Reimestment and Conunon sam k Purchase j Plan were 2,408,920 shares. j
- 2. Cumulatise Non-3fandatory Redeemable Preferred Stock in May 199 3 we issued 400,000 shares of 7.75% cumulatise non-mandatory redeemable preferred stock at par. The stock is redeemable at 5100 per share plus accrued dividends beginning in May 1998. These shares were sohl in the form of L6 million depositary shares, each representing a one. fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulatise non-mandatory redeemable preferred stock.
- 3. Cumulative Alandatory itedeemable Preferred Stock The 460,000 shares of our 7.27% sinking fund series cumulatise preferred stock are currently redeemable at our option at s 103.88. The redemp-tion price declines annually each May to par salue in May 2002. The sem-L is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued disidends. We also base the non-cumulatise option each May to redeem additional shares, not to exceed 20,000, through the sinking fund at s100 per share plus accrued disidends.
We are not able to redeem any part of our 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in Duemtwr 2001 at $100 per share, plus accrued disidends. L 1.ong-Term Debt The aggregate principal amounts of our debentures and sewage facility resenue Imnds (including sinking fund requirements) due are 5100.6 million in 1995, $101.6 milhon per year in 1996 through 1998 and s 1.6 million in 1999 In February 199 3 we issued $65 million of 6.80% debentures due in 2000. We used the proceeds of this issue to reduce simrt-term debt. These debentures are not redeemable prior to maturity. In March 1993 we issued $650 million of debentures and used the proceeds to retire ten series of first mortgage bonds and reduce short term debt. The debentures were issued in the separate series with interest rates ranging from 5.125% to 7.8% and maturing between 1996 and 2023. The 31/8% debentures due 1996, 5.70% duc 1997, 5.95% duc 1998 and 6.80% due 2003 are not redeemable prior to maturity. The 7.80% debentures duc 202 3 are first redeemable in March 200 3 at a redemption price of 103.7 3% The redemption price decreases annually each March to par salue in March 2013. There is no sinking fund requirement for any series of these debentures. In August 199 3 we issued s 100 million of 6.05% debentures due in 2000. We used the pn ceeds from this sale to reduce short term debt. These debentures are not redeemable prior to maturity and hase no sinking f und requirements. In March 1994 the Massachusetts industrial Finance Agency, on our behalf, issued $15 million of 5.75% tax-exempt unsecured bonds due in 2014. The lunds are redeemable begmning in February 20m at a redemption price of 102% The redemption price decreases to 10l% in February 2005 and to par in February 2006. The pn>ceeds from this issuance together with sufhcient other funds were used to fully redeem the Series U first mortgage bonds. We redeemed at par the 52 5 million sariable rate Series S first mortgage imnds in 1994. These bonds paid interest at 9.2% for the period January 15,199 3 through January 14,1994. The rate was adjusted to 8.2% beginning January 15,1994 based upon the ten-year constant maturity Treasury rate as published by the Federal llesene Ibard. As a result of the redemption of all outstanding Grst mortgage bonds, the Indenture of Trust and Iirst Mortgage that had mortgaged substan-tially all our property since 1940 was terminated m Nmember 1994. Sewage facility resenue bonds were issued by liarbor Flectric Energy Company OlEEC), a w holly-owned subsidiary. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. The weighted aserage interest rate of the bonds is 7.3% A portion of the proceeds from the Imnds is in reser e with the trustee. If HEEC should hase insufGcient funds to pay cer-tain costs on a tunely basis or be unable to meet certain net worth requirements, we wouhl be required to make additional capital contributions or loans to the subsidiary up to a maximum of 57 million.
- 5. Short-Term Debt We base arrangements with certain banks to pnni.le short-term credit on Imth a committed and an uncommitted and as asailable basis. We cur-rently have authority to iwuc up to s 350 million of short term debt.
We base a s200 milhon resohing creth: agreement with a group of banks. This agreement is intended to pnnide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. Information reganling our short-term bornmings, comprised of bank loans and commer ial paper is as follows: (in thousands of dollars) 1994 1993 1992 Maximum short term imrrowings 5 268,100 5 320,000 5 314,998 Weighted aserage amount outstanding 5 214,640 5 220,149 5 233,286 Weighted aserage interest rates,culuding tommitment fees 4. 5% 3.4% 4.1 % l i l l 31
Note 1. Fair Val:e of Securities The following methoth and assumptiom were used to estimate the fair salue of each dass of securities for w hich it is practicable to estimate the value: Nuclear decommissioning trust The cmt of $82.8 million approximates fair value based on quoted market prices of securities held. l Cash and cash equivalents The carrying amount of $6.8 million approximates fair value due to the short. term nature of these securities. Alandatory redeemable cumulative preferred stod, sewagefacilhy revenue bonds and unsecured debt The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 1994 are as follows: Carrying Fair (in thousanth) Amount Value Mandatory redeemable cumulatise preferred stock 5 96,000 $ 93,780 Sewage facility revenue bonds 36,300 37,037 Unsecured debt 1,205,000 1,111,317 Note J. New Accounting Pronouncement Statement of Financial Accounting Standards No. I15, Accounting for Certain investments in Debt and Equity Securities, became effective in 1994. This statement did not have a material elTect on our consolidated financial statements. Note K. Commitments and Contingencies I. Capital Commitments At December 31,1994, we had estimated contractual obligations for plant and equipment of approximately $ 50 million.
- 2. Lease Commitments We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both noncanceliable leases and transmission agreements for the years after 1994 are as follows:
(in thousands) 1993 $ 26,540 1996 24,305 1997 21,396 1998 19,438 1999 17,794 Years thereafter 127,646 Total $ 237,119 We will capitalire a portion of these lease rentals as part of plant expenditures in the future. Our total expense for both lease rentals and trans-mission agreements was $27 million in 1994 and 5 30 million in 199 3 and 1992, net of capitalized expenses of 54 million in 1994 and $ 5 million in 1993 and 1992.
- 3. Ilydro-Quebec We have an approximately 11% equity ou norship interest in two companies which own and operate transmission facilities to import electricity from the Ilydro-Quebec system in Canada, which is included in our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants w ho do not meet certain credit criteria and are compensated accordingly. At December 31,1994, our [mrtion of these guarantees was approximately $21 million.
- 1. Yankee Atomic Electric Company We base a 9.5% stock investment of apprmimately 52.5 million inYankee Atomic Electric Company (Yankee Atomic). In 1992 the Board of Directors of Yankee Atomic decided to permanently discontinue pmer operation of theYankee Atomic nuclear generating station and decommission the facility. We relied onYankee Atomic for less than one percent of our system capacity under a long-term purchased power contract.
In 199 3 Yankee Atomic received approval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approxi- l mately $39 million as of December 31,1994. This estimate is recorded on our consoli<hted balance sheet as a pmer contran liability and an offset-ting regulatory asset as we continue to collect these costs from our customers in accordance uith our 1992 settlement agreement. ) 32
i l l l T. Nudear Insurance l The federal Price. Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately 58.3 billion is prosided by a retrospective assessment of up to $75.5 million per incident levied on each of the 110 units licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as existing units gise up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional live percent of the maximum retrospective assessment. We hase purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or decommissioning of our utility property l resuhing from cmered incidents at Pilgrim Station. Our maximum potential total assessment for losses u hich occur during current policy years is l approximately s14.8 million under both the replacement pimer and excess property damage, decontamination and decommissioning policies. All companies imured uith NEIL are subject to retroactive assessments iflosses are in excess of the total funds available to NEIL. While assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in an assessment.
- 6. Litigation in 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 con-cerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition. Ilowever, an unfavorable decision ordered against us could have a material impact on our results of a reporting period.
- 7. Hazardous Waste We own or operate 48 properties where hazardous materials were released in the past. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Emironmental Protection and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potentialliability. Through December 31,1994, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any sucL additional costs to have a material impact on our financial condition. Iloweser, additional pnnisions for cleanup costs could have a material imput on our results of a reporting period.
33
Note L Long Term Pzwer Contracts l 1, long-Term Contractsfor the Purchase of Electricity l We purchase electric power umler several long-term contracts for which we paj a share of the generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense in our consolidated income state-ments. Information relating to these contracts as of December 31,1994 is as follows: proportionate share (in thousands) i 1994 1994 Interest Debt l Contract Units of Minimum Portion of Outstanding Expiration Capacity Purchased (a) Debt Minimum Through Cont. Generating Unit Date % MW Service Debt Service Exp. Date Canal Unit i 2001 25.0 140 5 796 5 321 5 1,928 l Mass. Bay Transportation Authority 2005 100.0 34 (b) (b) (b) ConnecticutYankee Atomic 2007 9.5 55 2,607 1,695 14,678 l Ocean State Power Unit i 2010 23.5 67.5 5,072 3,653 21,563 Ocean State Power - Unit 2 2011 23.5 67.5 4,266 3,223 18,316 Northeast Energy Associates (c) (c) 219 (c) (c) (c) L'Energia 2013 73.0 64 (d) (d) (d) MassPower (e) 2013 44.3 117 12,642 8,088 86,538 Total 764 s 25,183 s 16,980 5143,023 (4) The Northeast Energy Anociates contract represents 6.4% of our total system generation capability. The remaining units listed ahme represent t 5.9% in total. (b) We are required to pay the greater of 522.00 per kilowatt-year or 90% of the New England Power Pool capabihty responsihihty adjustment <harge up to s61.00 per kilowatt. year times the quahned capacity (currently rated at 14MW) plus incremental operating, maintenance and fuel cmts. The total charges for this contract in 1994 were approximately 52 million. (c) We purthase apprnximately 75.5% of the energy output of this unit under two contracts. One contract represents i15MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for this energy based on a prite per kWh actually receised. We do not pay a progmrtionate share of the unit's capital and Axed operating cmts. %e total charges for these contracts in 1994 were approximately s i19 milhon. (d) We pay for this energy based on a price per kWh actually received. The total charges under this contract for 1994 were approximately 5 31 milhon. (c) The MassPower contract startal in January 1994. Payments are based on a stipulated price per MW rating of the unit subject to the unit maintaining a twelve month average asailability of at least 90% Payments are adjusted proportionately if the twelve month average is behiw 90%. If the twelve month aserage is less than 10% no payment b required. Total charges for this contract in 1994 were approximately 547 million. Our total fixed and variable costs for these contracts in 1994,1993 and 1992 were approximately 5286 million,5225 million and 5217 million, respectively. Our minimum fixed payments under these contracts for the years after 1994 are as follows: (in thousand3) 1995 s 105,574 1996 108,I87 1997 105,622 1998 109,837 1999 108,196 Years thereafter 1,118,008
'li>tal s1.855,424 'lotal present value 5 Wo.594
- 2. Long-Term Power Sales l In addition to our power sales to fise wholesale customers, we sell a percentage of Pilgrim Station's output to other utilities under long-term con-tracts. Information relating to these contracts is as follow s:
Contract i Fxpiration Units of Capacity Sold Contract Customer Date % MW Commonwealth Electric Company 2012 11.0 73.7 l Montaup Electric Company 2012 l 1.0 73.7 f Various municipalities 2000 (a) 3.7 25.0
'Ibtal 25.7 I72.4 (a) Suhject to certain adjustments.
Under these contracts, the utilities pay their proportional share of the costs of operating Pilgrim station and associated transmission facilities. The.se costs include operation and maintenance expenses, insurance, h> cal taxes, depreciation, decommiuioning and a return on capital. 34
Report of Independent Accountants To the StodholJers and threctors of Boston EJuan Comptny We have audited the accompanying consolidated balance sheets of Boston Edison Company and subsidiaries (the Company) as of December 31, 1994 and 1993 and the related consolidated statements ofincome, retained earnings and cash flow s for each of the three years in the period ended December 31,1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these Onancial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable awurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, esidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and signiGeant estimates made by management, as well as evaluating the metall Onancial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the Gnancial position of the Company as of December 11,1994 and 1993, and the consolidated results ofits operations and its cash Hows for each of the three years in the period ended December 31,1994, in conformity with generally accepted accounting principles. fU , . . 6 Boston, Massachusetts january 26,1995 1 1 i l l 35 i 1
Selected Consolidated Quarterly Financial Data (Unardited) . 1 (in thousands, except earnings per share) j Balance Earnings l Available Per Average , Operating Operating Net for Common Common J Revenues Income Income Stock Share 1994 First quarter $ _377,449 5 45,795 $ 19,812 $ 15,850 $ 0.35 Second quarter 368,655 50,395 23,982 20,031 0.44 Third quarter 449,094 96,599 70,182 66,256 1.46 , Fourth quarter 353,356 34,034 11,046 7,120 0.16 1993 First quarter $ 354,752 3 41,722 $ 15,452 $ 11,377 $ 0.25 Second quarter 346,074 49,282 22,829 19,125 0.43 Third quarter 436,024 96,319 70,015 66,053 1.47 Fourth quarter 345,403 37,996 9,922 5,958 0.13 Selected Quarterly Stock Data Following are the reported high and low sales prices of our common stock on the New York Stock Exchange as reported daily in the Nil Street purnal for each of the quarters in 1994 and 1993 and the dividends declared per share during each of those quarters: 1994 1991 i High Low Dividends High Low Dividends First quarter $ 29 7/8 5 26 3 0.440 5 30 I/2 5263/8 $ 0.425 Second quarter 29 1/8 25 1/4 0.440 30 7/8 27 7/8 0.425 , Third quarter 27 5/8 22 3/4 0.440 32 5/8 29 3/4 0.425 Fourth quarter 24 1/4 21 1/2 0.455 32 1/4 27 7/8 0.440 l 1 l I l l 1 l l l l 1
Selected Consolidated Operating Statistics (Unaudited) 1994 1993 1992 1991 1990 Capacity - MW: New Boston Station 760 760 760 760 760 Pilgrim Station 669 670 670 670 670 Mystic Station 1,006 1,006 1,005 1,015 1,014 W.F.Wyman Unit 4 36 36 36 36 36 Jet turbines 287 283 281 281 281 Total 2,758 2,755 2,752 2,762 2,761 Contract purchases 1,035 938 1,157 1,293 924 Contract sales (373) (283) (303) (293) (173) Net capability at year-end 3,420 3,410 3,606 3,762 3,512 Net capability at peak - MW 3,484 3,663 3,587 3,695 3,505 Capability responsibility to NEPOOL at peak MW 3,306 3,190 3,396 3,311 3,393 Edison territory: Hourly peak - MW 2,798 2,662 2,545 2,652 2,548 Load factor 58.9 % 60.5 % 62.5 % 60.0 % 62.2 % Generating station economy (BTU / net kWh) 10,408 10,345 10,234 10,331 10,403 Average cost of fuel (Company) .
$ per million BTU: ,
Fossil 2.321 2,504 2.467 2.402 2.555
- Nuclear 0.501 0.507 0.522 0.562 0.591 Composite 1.613 1.620 1.669 1.805 1.915 Capability (net kW):
Fossil 84 % 84 % 81 % 81 % 81o Nuclear 16 % 16% 19% 19 % 19 % Generation (system kWh excluding interchange): Ibssil 75 % 68 % 69% 70 % 72 % Nuclear 25% 32 % 31 % 30 % 28 % Utility plant (s in 000's): Expenditures 198,760 246,763 213,827 202,589 240,902 Retirements 45,673 34,147 34,036 30,333 27,180 Accumulated depreciation 1,344,452 1,258,359 1,177,294 1,097,991 1,015,371 Depreciable plant 3,994,212 3,841,752 3,567,160 3,488,269 3,277,616 Number of utility employees at year-end 4,026 4,397 4,540 4,637 4,7 38 Certain reclassifications were made to the data reported in prior years to conform with the method of presentation used in 1994. 37
Selec.ed Consolidated Sales Statistics (Unaudited) 1994 1993 1992 1991 1990 Electric energy (kWh in thousands): Sources (systein output): Generated 9,428,931 9,787,092 11,679,824 10,602,110 12,744,238 Purchased 5,920,065 5,326,224 5,449,225 4,651,101 3,305,491 New England Power Pool 1,535,335 1,575,310 932,121 1,274,522 1,065,731 Ltal 16,884,131 16,688,626 18,061,170 16,527,733 17,115,460 Disposition: Commercial 7,478,631 7,263,358 7,178,281 7,143,484 7,178,134 Residential 3,534,372 3,477,870 3,413,252 3.386,681 3,427,410 Industrial 1,539,385 1,580,969 1,671,564 1,685,184 1,743.848 Other (a) 130,721 145,242 292,510 279,540 275,213 Totai retail sales 12,683,109 12,467,439 12,555,607 12,494,889 12,624,605 Wholesale and contract sales (a) 2,367,589 2,272,669 2,517,247 1,660,082 1,674,114 New England Power Pool 725,439 877,978 1,898,059 1,252,797 1,885,165 Total system 15,776,137 15,618,086 16,970,913 15,407,768 16,183,884 Miscellaneous usage 1,108,194 1,070,540 1,090,257 1,i19,965 931,576 Total 16,884,131 16,698,626 18,061,170 16,527,733 17,115,460 : . Kilowatthours annual growth: Commercial 3.0% 1.2% 0. 5% (0.5)% 1.2% , Residential I.6 1.9 0.8 (1.2) 0.4 Industrial (2.6) (5.4) (0.8) (3.4) (5.5) Other (10.0) (50.3) 4.6 1.6 5.9 Ltal retail sales (a) 1.7 (0.7) 0.5 (l.0) O.I wholesale and contraa sales 4.2 (9.7) 51.6 (0.8) 47.0 - New England Power Pool (17.4) (5 3.7) 51.5 ( 3 3.5) (9.8) Ltal system 1.0% (8.0)% 10.1 % (4.8)% 2.2%
~
Electric operating revenues by class: Commercial 50 % 49% 48% 48 % 49a 6 Residential 28 % 28 % 27 % 27 % 28 % Industrial 9% 10 % 10 % 10 % 11 % Wholesale and contract i1% 12 % 13% 13% 9ab Other 2% 1% 2% 2% 3% Electric sales statistics: Residential averages: Annual kWh use 6,197 6,143 6,081 6,060 6,144 Revenue per kWh 12.06c 11.62e 10.80e 10.66e 10.18e Annual bill $ 749.47 5 709.89 5 657.4! 5 641.62 5 620.54
- Customers:
Aic rage number 655,707 651,141 646,215 642,967 642,041 (a) L&ctive frbrua7 199 3 a former rerul customer became a wholesale customer as allowed un<ler hacht et's state Irv. Exclu< ling the cEct of this customer's change in status, total retail sales ina .ssed 2.0". in 1994 and 1.2% in 1993. Certain reclassifications and re A ' ions were made to the data reported in prior years to conform with the method of presentation used in 1994 I r---------------- .
Selected Consolidated Financial Statistics (Unaudited) I994 1993 1992 1991 1990 Operating revenues (000) $ 1,548,554 5 1,482,253 $ 1,411,753 5 1,354,501 5 1,314,440 Balance for common (000) $ 109,257 5 102,513 $ 90,748 s 77,059 s 77,788 Per common share: Earnings $ 2.41 3 2.28 2.10 1.96 5 5 5 2.01(*) Dividends declared $ 1.775 s 1.715 1.655 5 $ 1.595 5 1.535 Disidends paid $ l.76 s 1.70 s 1.64 1.58 5 s 1.52 lhmk value $ 20.11 s 19.42 !8.77 5 5 17.92 s 17.22 Operating cash flow (b) $ 8.12 5 6.58 s 6.80 s 5.50 5 5.68 Payout ratio 73% 75% 78 % 81% 76 % Return on aserage common equity 12.1 % i 1.9% 11.5% 11.3 % .t 1.8% Year-end dividend yield 7.6% 5.9% 6.2% 6.Ma 7.9% Fixed ch rge cmcrage (SEC) 2.45 2.22 1.89 1.81 2.02 Capitalization: Total debt 56 % 57 % 56 % 5% 59 % Preferred and preference equity 9% 9% 9% . 0% 10 % Common equity 35 % 34 % 35% 32 % 31 % Long term debt (000) $ 1,136,617 s 1,272,497 s 1,091,073 5 1,136,765 s 1,074,025 Mandatory redeemahic preferred / / preference stock (000) $ 96,000 5 98,000 $ 98,000 s 100,000 s 100,000 Total assets (000) $ 3,616,610 $ 3,477,288 s 3,274,234 s 3,119,285 5 3,012,589 Internal generation after dividends (000) $ 216,305 5 193,484 5 2(M,248 5 193,019 s 187,954 Plant and nuclear fuel expenditures (000) $ 220,694 s 253,254 5 231,025 s 214,213 255,784 s Internal generation 98 % 76 % 88 % 90 % 73% Common shares outstanding: Wei 'hted aserage 45,337,661 44,959,050 43,143,953 39,347,824 38,778,901 Year-nd 45,535,477 45,129,227 44,763,055 42,047,356 38,998,531 Stock price Ifigh 29 7/8 32 5/8 28 1/4 24 7/8 20 1/4
- Low 21 1/2 26 3/8 22 1/8 18 t /4 16 1/2
- Year-end 24 29 3/4 27 1/2 24 3/4 20 Year-end market value (000) $ 1,092,851 s 1,342,595 5 1,230,984 5 1,040,672 5 779,971 Trading volume (shares) 25,095,100 18,729,400 26,460,900 17,464,300 19,652,300 Market / book ratio (year-end) I.19 1.53 1.47 1.38 1.16 Price / earnings ratio (year end) 10.0 13.0 13.I 12.6 10.0 (a) inclu,1cs 50.41 per common share Inam an accounting change.
(b) Euludes efTect of rate and contract settlements. Certain reclassifications and recalculations were made to the data reported in prior years to conform uith the method of presentation used in 1994 I 39
0FFICERS DIRECTORS Thomas J. May, Chairman of the Ibard and Chief Executive OMcer a,d William F. Connell, Chairman and Chief Executive Omcer, Connell Limited Partnership (metals recycling and pro-GeorgeW. Davis, President and Chief Operating Omcer cessing and industrial produdion) E. Thomas Ibulette, Senior Vice President - Nuclear d,f Gary L. Countryman, Chairman of the Board and Chief Cameron 11. Daley, Senior Vice President - Power Supply Executive Omcer, Liberty MutualInsurance Company
. a,c George W. Davis, President and Chief Operating Omcer, L. Carl Gustin, Senior b,.ce President - Marketing & L.orporate R u i n3 lbst n Edison Company a,e,f Thomas G. Dignan, Jr., Partner, Ropes & Gray (law firm)
John J. Iliggins, Jr., Senior Vice President - lluman Resources ' b,d Charles K. GifTord, President, Bank of Boston Corporation Ronald A. Ledgett, SeniorVice President - Power Delisery (bank holding company) andThe First National Bank of Charles E. Peters, Jr., Senior Vice President - Finance Ibston
,c, e s n S Gifford, FormerVice Chairman, Avery Dennison Alison Alden,Vice President - Sales & Service Corporation (pressure-sensitive adhesives and materials, Marc S. Alpert,Vice President andTreasurer omce products, prmluct identification and contrcl systems and specialty' chemicals)
Richard S. Hahn,Vice President -Technology Research & Development a,e Kenneth I. Guscott, General Partner, Long Bay Management Company (real estate development) Douglas S. lloran,Vice President and General Counsel a,b,c Matina S. llorner, Executise Vice President, Teachers joel Y. Kamya,Vice President - Production Operations insurance and Annuity Association and College Retirement Leon J. Olivier,Vice President - Nuclear Operations and b" "" " Station Director a,c Thomas J. May, Chairman of the Board and Chief Executive a,lbston Edison Cmnpany Arthur P. Phillips, J ,Vice President - Corporate information Services b,c,d Sherry 11. Penney, Chancellor, University of Massachusetts at Boston Robert A. Ruscitt%Vice President - Electric Customer Service e,f Bernard W. Reznicek, Former Chairman of the Board and Robert J.Wea'er, ir., s' ice President, Controller and Chief Chief Executive Omcer, Boston Edison Company and Accounting UMccr Dean, College of Business Administration, Creighton Theodora S. Convisser, Clerk of the Corporation Unimsity e,f lierbert Roth, Jr., Former Chairman of the Ibard and Chief Donald Anastasia, AssistantTreasurer Executive Omcer, LFE Corporation (trathse and industrial James J. Judge, AssistantTreasurer and Director - process control systems) Corporate Planning e,f Stephen J. Sweeney, Former Chair. nan of the Ibard and Wayne R. Frigard, Assistant Clerk of the Corporation Chief Executiw Omccr,lbston Edison Company b,d Paul E.Tsongas, Partner, Foley floag & Eliot (law firm) a Member of Executive Committee b Member of Audit, Finance and Risk Management Committee c Member of Pricing Committee d Member of Executive Personnel Committee e Memtwr of Nuclear Oversight Committee f Member of Capital Investment Committec
DIVIDEND REINVESTMENT PLAN Our Disidend Reimestment and Common Stmk Pur hase Plan (the plan) is available to our common arai preferred stakhohlers. Linder the plan, common anil preferred stm khohiers may have their dividends reimested in our common stmk at current market prices. All participants may imest optional cash contributions, up to a maximum of 5 5,(XX) per quarter, w hich will be inves+ed at the current market price. Participants do not pay fees or commissiom. All recordholders of shares of common and preferred stm k are eligible to participate directly in the plan. Beneficial owners of our stock whose shares are registered in names other than their own (e.g., a broker or bank nomince) must arrange participation with the recordholder. If for any reason a beneficial owner is unable to arrang,e participation with their broker or bac.k nominee, they must become a recordhohler by hasing the shares transferred to their ou n name. All correspondence concerning changes in plan ownership .shouhl be directed to the plan agent: The first National llank of 11oston Dividend Reinsestment (Init Mail Stop: 45-01-06 P O. Ilox 1681 Hoston, Massachusetts 02105-1681 IMPORTANT STOCKHOLDER INFORMATION Annual Meeting SEC Form 10-K Our Annual Meeting of Stm khohlers will be held on May 12,1995, at Stakholders may obtain a copy of our annual report to the i1:00 a.m. If you wish to receise a copy of Tom May's remarks, Securities and Exchange Commission on Form 10-K, by making a please write to our imestor Relations Department at the General writte n request to our imestor Relations Department. Ollices address listed below. Quarterly Report to Shareholders Company Con %t Beneficial ouners of our stmk u hose shares ce registered in names Theodora Com ssei other than their ou n (e.g., a broker or bank nomince) may obtain Clerk of th- Lorpor2imn cop,es d our Quarterly Reports to Shareholders on an ongoing basis
' y making a w ritten request to our lmestor Relations Department to Insestor Relations Contact [ placed on their mailing list. Note that the Annual Report will Phil trmbo continue to be mailed to beneficial owners directly by their bank or Director, Imestor Relations '
.er.
General Oflices Inquiries Concerning Stock 800 Boylston Street, Boston, Massachuwtts 02199-8001 If you have questions concerning your disidend payments, disidend (617) 424-2000 direct deposit, disidend reinvestment plan status, transfer procedures or other stm k account matters, please contact our Stock Transfer Stotk Listings Agent at the following address: New York and flmton stock cuhanges The first National Bank of Boston Stod Symbol Shareholder Services Dis ision lig Mail Stop: 45-02-09 P O.!!ox644 Dividend Payment Datc5 Bost on, Massach uset ts 02102-0644 Common and Preferred B.you are submitting documents requesting a transfer, address ist of l. ebruary, May, August, N,ovember change or atcount consolidation, please use this same address with Tax Status of 1994 Dividends Mail Stop: 4 5-01-05. If you woukt like to contact the bank by Generally, unless you are subject to certain exemptiom, all disidends te phom call 617-575-1100 or toll free 1-800-716-1001, on our common or preferred stock are to be considered l(xFo taxable. Stock Transfer Agent, Registrar of Stoc k and Dividend Reinsestment Plan Agent , The first National Bank of Boston t 41 l
& Boston Edison InvestorRelations P356 800 Boylston Street Boston, Massachusetts 02199-8003 s
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6 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549' ! FORM 10-Q i [x] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act.of 1934 i LFor the-quarterly period ended September 30,'1995 or ; I) Transition report pursuant to Section 13 or 15(d) of the Securities l Exchange Act of 1934 l For the transition period from to Comission file number 1-2301 BOSTON EDISON COMPANY' . (Exact name of registrant as specified in its charter) Massachusetts 04-1278810 i (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 800 Boylston Street, Boston, Massachusetts 02199 (Address of principal executive offices) (Zip Code) l Registrant's telephone number, including area code: 617-424-2000-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
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such filing requirements for the past 90 days. Yes No x Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at September 30, 1995 Common Stock, $1 par value 47,890,445 shares
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4 Part I - Financial Information
-Item 1. Financial Statements Boston Edison Company Consolidated Balance Sheets (Unaudited)
(in thousands) September 30, December 31, 1995 1994 Assets Utility plant in service, at original cost $4,239,525 $4,074,810 Less: accumulated depreciation 1,430,307 1,344,452 2,809,218 2,730,358 Nuclear fuel, net 56,331 55,597 Construction work in progress 82,357 144,048 Net utility plant 2,947,906 2,930,003 Investments in electric companies, at equity 23,717' 24,678 Nuclear decommissioning trust 98,282 82,831 Current assets: Cash and cash equivalents 28,970 6,822 Accounts receivable 234,183 189,382 Accrued unbilled revenues 37,283 32,240 Fuel, materials and supplies, at average cost 62,872 71,560 Prepaid expenses and other 22,263 26,705 Total current assets 385,571 326,709 Regulatory assets: , Redemption premiuns 46,604 52,859 Income taxes, net 45,777 44,745 Power contracts 33,203 40,277 Pension and postretirement costs 16,645 22,761 Nuclear outage costs 15,778 17,804-Other 8,362 19,702 Total regulatory assets 166,369 198,148 other deferred debits: Intangible asset - pension 33,184 22,849 Other 31,382 31,392 Total assets $3,686,411 $3,616,610 l l l i j The accompanying notes are an integral part of these financial statements. ) 1 l 2 1 . l
l 1 Boston Edison Company consolidated Balance Sheets ] (Unaudited) ! (in thousands) l l September 30, December 31, 1995 1994 Capitalization and Liabilities o Common stock equity: common stock $ 728,610 $ 668,338 ; Retained earnings 290,601 247,409 Total common stock equity 1,019,211 915,747 Cumulative preferred stock: Non-mandatory redeemable series 123,000 123,000 Mandatory redeemable series 92,000 94,000 Long-term debt 1,160,256 1,136,617 Current liabilities: Long-term debt / preferred stock due within one year 203,067 102,250 Notes payable 74,420 214,786 Accounts payable 84,155 139,119 Interest accrued 15,096 24,464 Dividends payable 24,582 23,533 Pension benefits 34,718. 31,908 Other 109,296 76,615 Total current liabilities 545,334 612,675 Deferred credits: Power contracts 33,203 40,277
' Accumulated deferred income taxes 507,762 515,454 ,
Accumulated deferred investment tax credits 63,979 67,048 ) Huclear decommissioning reserve 100,139 92,404 Other 33,527 19,388 Total deferred credits 746,610 734,571 Commitments and contingencies - Total capitalization and liabilities $3,686,411 $3,616,610 1 1 I l l The accompanying notes are an integral part of these financial statements. l l 3 l l
Boston Edison Company Consolidated Statements of Income (Unaudited) (in thousands, except per share amounts)- Three Months Ended Nine Months Ended September 30, September 30, 1995 1994 1995 1994 Operating revenues $500,179 $449,094 $1,265,794 $1,195,198 operating expenses: Fuel .52,431 42,114 125,475 125,499 Purchased power 90,915 94,013 278,772 267,909
'Other operations and naintenance 116,820 109,825 333,638 320,640 Depreciation and. amortization 38,520 37,487 113,839 112,051 Amortization of deferred cost of cancelled nuclear unit -0 4,948 0 14,844 Amortization of deferred nuclear outage costs 12,765 1,930 16,625. 5,791 Demand side management programs 15,223 9,405 39,646 27,451 Taxes - property and other 26,267 25,038 80,506 76,370-Income taxes 44,709 27,735 72,289 51,854 Total operating expenses 397,650 352,495 1,060,790 1,002,409 -Operating income 102,529 96,599 205,004 192,789 other income (expense), net (342) 819 140 2,477 Operating and other income 102,187 97,418 205,144 195,266-Interest charges:
Long-term debt 28,312 25,560 79,605 77,346 Other 2,692 3,934 11,665 9,182 Allowance for borrowed funds used during construction (1,185) (2,258) (4,833) (5,238) Total interest charges 29,819 27,236 86,437 81,290 Het income 72,368 70,182 118,707 113,976 Preferred dividends provided 3,890 3,926 11,681 11,839 Balance available for common stock $ 68,478 $ 66,256 $ 107,026 $ 102,137 Weighted average common shares outstanding 46,861 45,382 46,129 45,286 Earnings per share of common stock $1df M M $2.26 Dividends declared per common share 60.455 $0.440 $1.365 $1.320 The accompanying notes are an integral part of these financial statements. i 4
. Bosten Ediccn Comptny Cencolidatcd Stctcments of Cach Flewa , (Unnuditsd) l (in thousands)
Nine Months Ended September 30, 1995 1994 l Operating activities: 1 Net income $118,707 $113,976 l Adjustments to reconcile net income to net I cash provided by operating activities: I Depreciation 110,036 107,581 l Amortization of nuclear fuel 13,279 16,738 l Amortization of deferred cost of ( cancelled nuclear unit, net 0 14,301 j Amortization of deferred nuclear outage ; costs 16,625 5,791 1 Other amortization 11,975 11,000 l Deferred income taxes (8,991) 12,114 l Investment tax credits (3,069) (3,055) : Allowance for borrowed funds used during construction (4,833) (5,238) Net changes in: Accounts receivable and accrued unbilled revenues (49,844) (36,188) Fuel, materials and supplies 5,143 2,045 Accounts payable (54,964) (20,486) Other current assets and liabilities 31,614 21,504 ) Other, net 19,386 19,488 I Net cash provided by operating activities 205,064 259,571 Investing activities: Plant expenditures (excluding AFUDC) (125,468) (124,370) ! Nuclear fuel expenditures (12,298) (9,956) , Capitalized demand side management l expenditures 0 (15,325) l Nuclear deconadssioning trust investments .(15,451) (11,750) Electric company investments 961 (205) Net cash used by investing activities (152,256) (161,606) Financing activities: Issuances: Common stock 61,773 7,978 Long-term debt 125,000 15,000 Redemptions: Preferred stock (2,000) (2,000) Long-term debt (600) (28,600) Net change in notes payable (140,366) (22,237) Dividends paid (74,467) (71,549) Net cash used by financing activities (30,660) (101,408) Increase /(decrease) in cash and cash equivalents 22,148 (3,443) Cash and cash equivalents at beginning of year 6,822 8,768 Cash and cash equivalents at end of period S 28,970 $ 5,325 Cash paid during the period for: Interest $100,638 $99,944 Less: amounts capitalized 4,833 5,238 S 95,805 $94,706 Income taxes S 63,177 S28,690 The accompanying notes are an integral part of these financial statements. 5
l c Notes to Consolidated Financial Statements A) Basis of Presentation The accompanying unaudited consolidated financial statements should be read in conjunction with the Boston Edison Company (the Company) 1994 Form 10-K Annual Report and Forms 10-Q for the periods ended March 31, 1995 and June 30, 1995. In the opinion of the Company, the accompanying unaudited consolidated financial statements reflect all adjustments (which are all of a normal recurring nature, except for the amortization of deferred nuclear outage costs as described in Note B) necessary to present fairly the financial position as of September 30, 1995 and the results of operations for the three and nine months ended September 30, 1995 and 1994 and the cash flows for the nine months ended September 30, 1995 and 1994. Certain reclassifications have been made to the prior year data to conform to the current presentation. The results of operations for the three and nine months ended September 30, 1995 are not indicative of the results which may be expected for the entire year. The Company's kWh sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. In addition, the Company bills higher base rates to commercial and industrial customers during the billing months of June through September as mandated by the Massachusetts Department of Public Utilities (DPU). Accordingly, greater than half of the Company's annual earnings typically occurs in the third quarter. B) Deferred Nuclear Outage Costs In the third quarter of 1995 the company changed the amortization period of deferred nuclear outage costs to two from five years. The two year amortization period is consistent with the two year cycle between nuclear refueling outages at Pilgrim Station. The change from the prior five year amortization period per the 1992 settlement agreement was made following the DPU's August 1995 order on electric industry restructuring, which is discussed further in the outlook for the future section of management's discussion and analysis. This order requires utilities to mitigate potentially strandable costs by available and reasonable means. The prior regulatory treatment of recovery over a five year period resulted in a significant lag between the expenditure and recovery of outage costs. The Company decided not to request recovery of the buildup of costs resulting from this regulatory lag. Accordingly, the remaining $9 ndllion of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 were written off. Approximately $15 million of deferred costs from the 1995 refueling outage are being amortized over two years. C) Commitments and Contingencies In 1991 the company was named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by the Company's 1988 reduction in force. Legal counsel continues to defend this case vigorously. Based on the information presently available, the company does not expect that this litigation or certain other legal matters in which the Company is currently involved will have a material impact on its financial condition. However, an unfavorable decision ordered against the Company could have a material impact on the results of a reporting period. The Company, currently owns or operates 42 specific properties where hazardous materials were released in the past. The company is required to clean up these properties in accordance with a timetable developed by the Massachusetts 6
l I i Department of Environmental Protection and is continuing to evaluate the costs l associated with their cleanup. There are uncertainties associated with these ; costs due to the complexities of cleanup technclogy, regulatory requirements , l and the particular characteristics of the different sites. The Company also continues to face possible liability as a potentially responsible party in the i cleanup of eight multi-party hazardous waste sites in Massachusetts and other I states where it is alleged to have generated, transported or disposed of l hazardous waste at the sites. At the majority of these sites the Company is one of many potentially responsible parties and currently expects to have only a small percentage of the potential liability. Through September 30, 1995, the company has accrued approximately $7 million related to its cleanup liabilities. The Company is unable to fully deterndne a range of reasonably i possible cleanup costs in excess of the accrued amount, although based on its l assessments of the specific site circumstances, it does not expect any such additional costs to have a material impact on its financial condition. 1 However, additional provisions for cleanup costs could have a material impact j on the results of a reporting period. I D) Corporate Reorganization In July 1995 the Company announced a corporate reorganization into four separate business units effective November 1, 1995: Customer, Generating- , Fossil, Generating-Nuclear and Corporate Services. As part of this l reorganization, the company intends to reduce its workforce by approximately l 450 employees by the end of 1996. Part of this reduction will be achieved l through a voluntary retirement incentive. The company announced voluntary I enhanced retirement programs for all employees who are at least 55 years old with varying years of service requirements for management and union employees. Approximately 600 employees are eligible for the programs, which are available until early December. A majority of the eligible employees are expected to participate in the progranm. The Company will incur a one-time charge to fourth quarter earnings as a result of the programs; the charge will be determined by the number of employees that accept the offer. Approximately 70 of the company's upper and middle management positions and related administrative support positions will be eliminated by the end of 1995 regardless of the results of the enhanced retirement programs. A special severance program was announced for these affected employees who are not eligible for or do not accept the enhanced retirement program, which resulted in a one-time, pre-tax charge to third quarter earnings of $7 million. The total of the $7 million third quarter charge and the fourth quarter charge to be incurred from the enhanced retirement prograns is estimated to be approximately $25 million on a pre-tax basis. Depending on the level of participation, the charge could be higher or lower. The Company is currently evaluating its options in order to achieve the 450 employee reduction if it is not achieved through the enhanced retirement program and the management and administrative support reduction. 7
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- l E) Income Taxes 1 The following table reconciles.the federal statutory' income tax rate to the annual estimated effective-income tax rate for 1995 and the actual effective ,
income tax' rate for 1994. 1995 1994 Statutory tax rate 3!!0% 35.0% State income tax, not of federal income tax benefit 4.3 4.3 Investment tax credits (2.0) (2.3) Reversal of deferred taxes - L settlement agreement .- (5.5) Other 0.5 (0.1) Effective tax rate 2741% 2141% F) Long-Term Securities on September 29, 1995, the Company sold one million shares of common stock with net proceeds of $26 million'to Merrill Lynch & Co. as underwriters for a public offering. .The proceeds, which are included in the cash balance at September 30, were used to reduce short-term debt in early October. I Item 2. Management's Discussion and Analysis-Results of Operations - Three Months ended September 30, 1995 vs. Three Months ended September 30, 1994 Earnings per common share amounted to $1.46 for both the three months ended September 30,_1995 and 1994. Third quarter earnings in 1995 include a one- . time charge of $0.09 per share for severance benefits relating to the Company's restructuring, which is discussed in the outlook for the future - , section. Excluding the one-time charge, earnings increased due to a $29 million annual retail base rate increase effective November 1994, lower i revenue reserves and the ending of amortization of deferred cancelled nuclear costs in 1994. These positive changes were partially offset by higher amortization of deferred nuclear outage costs and income tax expense. The results of operations for the quarter are not indicative of the results which may be expected for the. entire year due to the seasonality of the Company's kWh sales and revenues.- Refer-to Note A to the consolidated financial statements. t Qperating revenues Operating revenues increased 11.4% in the third quarter of 1995 as follows: ; (in thousands) Retail electric revenues $26,488 Demand side management revenues 9,173 Wholesale and other revenues 11,157 Short-term sales revenues 4,267 Increase in operatino revenues $51,085 Retail electric revenues increased $26.5 million. The November 1994 base rate ' increase resulted in approximately $17 million of the increased revenues and approximately $4 million was due to a 2.3% increase in retail kWh sales. Performance revenues, which vary annually based on the operating performance 8
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l 1 of Pilgrim Nuclear Power Station, increased approximately $5 million mainly as a result of an outage that occurred at the station in 1994. 1 A new annual conservation charge for recovery of demand side management (DSM) I program costs was implemented in February 1995. Under this current charge ( substantially all 1995 program costs are recovered in the current year. This l results in higher DSM revenues and expenses than in prior years when certain i program costs were capitalized for recovery over six years. The net increase in wholesale and other revenues is primarily due to $10 ndllion of revenue reserves recorded in 1994 mainly related to potential customer contract issues. j
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Increased short-term sales revenues are the. result of higher. company 1 generating availability in 1995. Revenues from short-term sales serve to reduce fuel and purchased power billings to retail customers and therefore have no effect on earnings. i l Operating expenses Total fuel and purchased power expenses increased $7 ndllion due to the timing effect of fuel and purchased power cost collection. In addition to the timing effect, fuel expense increased despite lower fossil fuel prices primarily due j to a 41% increase in company generation, while purchased power expense i decreased due to a 28% decrease in kWh purchases. Fuel and purchased power expenses are substantially all recoverable through fuel and purchased power revenues. The increase in other operations and maintenance expense is due to a $7 million one-time charge for severance benefits. Refer to the outlook for the l future section for more information regarding the severance program related to .J the company's restructuring. ; In 1994 the company fully expensed the remaining deferred costs of the - cancelled Pilgrim 2 nuclear unit. 1 The 1995 amortization of deferred nuclear outage costs reflects a change in the amortization period to two from five years as discussed in Note B to the consolidated financial statements. The remaining $9 million of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 were written off. Approximately $15 million of deferred costs from the 1995 refueling outage are being amortized over two years. The increase in demand side management programs expense is related to the increase in DSM revenues. Beginning with the annual conservation charge implemented in February 1995, DSM costs are recovered and expensed primarily in the year incurred. Property and other taxes increased due to higher property taxes imposed by a majority of the municipalities in which the company operates. The Company's estimated ef fective annual income tax rate for 1995 is 37.8% versus an actual rate of 31.4% for 1994. The higher rate is the result of a
$10 million adjustment to deferred income taxes in 1994 made in accordance with the company's 1992 settlement agreement.
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Interest charges Interest charges on long-term debt increased primarily due to a $125 million.
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debentures issuance in May 1995. Other interest charges decreased due to a
' lower average short-term debt level partially offset by higher short-term interest rates. . The allowance for borrowed funds used during construction (AFUDC) decreased due to a lower construction work in progress balance partially offset by a higher AFUDC rate related to the higher short-term interest rates.
Results of Operations - Nine Months ended September 30, 1995 vs. Nine Months ended September 30, 1994 Earnings per common share for the nine months ended September 30,.1995 amounted to $2.32 as compared to $2.26 per common share for the nine months ended September 30, 1994. .The increase in. earnings is primarily due to the
$29 ndllion base rate increase ef fective November 1994, the ending of' amortization of deferred cancelled nuclear costs in 1994 and lower revenue reserves. These positive changes were partially offset by higher amortization, of deferred nuclear outage costs and higher operations and maintenance, property tax, income tax and interest expenses. ' The results of operations for the nine months ended September 30, 1995 are not indicative of the results which may be expected for the entire year due to the seasonality of the Company's kWh sales and revenues. Refer to Note A to the consolidated financial statements.
Operating revenues
- Operating revenues increased 5.9% in the first nine months of 1995 as follows:
(in thousands) Retail electric revenues $39,578 Demand side management revenues 13,880 Wholesale and other revenues 18,234 Short-term sales revenues (1,096) Increase in operatina revenues $70,596 Retail electric revenues it ereased $39.6 million. The November 1994 base rate increase resulted in apprvximately $27 million of the increase. Fuel and purchased power revenues increased approximately $9 million as a result of the timing effect of fuel and purchased power cost recovery. However, these higher revenues are offset by higher fuel and purchased power expenses and have no effect on earnings. Performance revenues increased $4 million primarily due to a higher rate effective in the performance year ended October ~ 1995 and an outage that occurred at the station in 1994. A new annual conservation charge for recovery of demand side management program costs was implemented in February 1995, resulting in higher DSM revenues and expenses, as discussed in the results of operations for the third quarter. The net increase in wholesale and other revenues is~primarily due to a $14 '
'ndllion decrease in revenue reserves. In 1994 $16 million of reserves were recorded primarily related to certain wholesale and contract customers. . The August 1994 acquisition of Coneco Corporation also provided an additional $4 million of revenues in 1995.
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Qperating expenses Total fuel and purchased power expenses increased $11 million primarily due to the timing effect of fuel and purchased power cost collection. The increase in fuel expense due to the timing effect and a 9% increase in fossil station output was offset by lower fossil fuel prices and a 10% decrease in nuclear generation. Other operations and maintenance expense increased 4% due to the $7 million one-time charge for severance benefits in the third quarter and increases in employee benefit expenses. Subsidiary operation expenses also increased due to the Coneco Corporation acquisition. The increase in amortization of deferred nuclear outege costs reflects a j change in the amortization period to two from five yearn as discussed in the results of operations for the third quarter. ; The increase in demand side management programs expense is related to the I increase in DSM revenues. Both revenues and expenses are higher due to the l 1995 change in DSM recovery timing that results in the current year recovery and expense recognition of program costs. The Company's estimated effective annual income tax rate for 1995 is 37.8% , versus an actual rate of 31.4% for 1994 as discussed in the results of I operations for the third quarter, j Interest charges Interest charges on long-term debt increased due to the $125 million debentures issuance in May 1995 partially offset by debentures and first mortgage bond redemptions in 1994. Other interest charges increased due to higher short-term interest rates partially offset by a lower average short- , term debt level. l l Financial condition I The company's 1992 settlement agreement with the DPU lindts the annual rate of l return on equity during 1995 to 11.75%, excluding any penalties or rewards from performance incentives. The Company's ability to achieve or exceed the 11.75% rate of return on equity is primarily dependent upon its ability to control costs and to earn performance incentives, primarily based on Pilgrim Station's annual capacity factor. The capacity factor for the recently concluded performance year ended October 1995 was 67%. The Company does not plan to make a base rate filing following the expiration of the 1992 settlement agreement and therefore anticipates base rates to remain in effect at their current levels. However, as discussed in the outlook for the future section, the Company is required to file a plan with the DPU in February 1996 based on-the recent industry restructuring order. It is uncertain how and when the filing and subsequent negotiations and industry changes will impact the Company's rates. Liquidity The Company supplements internally generated funds with external financings, primarily through the issuance of short-term commercial paper and bank borrowings. The Company has authority from the Federal Energy Regulatory Commission (FERC) to issue up to $350 million of short-term debt. The Company has a $200 million revolving credit agreement and arrangements with several 11
banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At September 30, 1995 the company had $74 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1994 -the DPU approved the Company's financing-plan to issue up to $500 million of securities through 1996 using the proceeds to refinance short and long-term securities and for capital expenditures. See Note F to the consolidated financial statements for specific information relating to recent financing activities. ; Outlook for the Future I i A significant portion of the Company's electricity sales is made to commercial l I customers rather than industrial customers. Aa a result the company's sales have been only moderately impacted by unfavorable economic factors affecting , the manufacturing industry in Massachusetts and have been positively impacted ; by economic growth in the commercial sector. Retail electricity sales I decreased 0.4% in the first nine months of 1995 primarily due to mild winter weather conditions compared to extremely cold weather conditions in 1994. The DPU is currently investigating whether the Company should again be ordered to negotiate a contract to purchase power from an independent power producer, JMC Altresco, Inc. The investigation.is'in response to the Massachusetts-Supreme Judicial Court's (SJC) decision remanding the DPU's previous order due to its failure to evaluate the cost of the project to customers. The Company filed a motion to dismiss the matter, but also filed testimony comparing the ; cost of Altresco to projected market costs and hearings are currently ongoing. In a separate but related matter,.the Company supported an appeal filed by other parties of.the Massachusetts Energy Facilities Siting Board's (EFSB) conditional approval of construction of Altresco's generating station project. In January 1995 the SJC reversed and remanded.the EFSB's approval on the basis that there was no showing of need for the project in Massachusetts prior to 2000. In August 1995 the EFSB issued a subsequent approval for the Altresco project with an in-service date of 1998 finding that the project would provide a necessary energy supply for Massachusetts. The Company appealed the August approval to the SJC based on the denial of the company's petition to intervene and the EFSB's failure to consider current market information and forecasts. In July 1995 the company announced a corporate reorganization as discussed in Note D.to the consolidated financial statements. In order to achieve a workforce reduction of approximately 450 employees by the end of 1996, the company offered enhanced retirement programs and is eliminating certain management and support positions. The Company will incur a one-time charge to fourth quarter earnings as a result of the enhanced retirement prograna; the charge will be determined by the number of employees that accept the offer. A special severance program announced for affected employees who are not eligible for or do not accept the enhanced retirement programs resulted in a one-time, pre-tax charge to third quarter earnings of $7 million. The total of the $7 million third quarter charge and the fourth quarter retirement programs charge is estimated to be approximately $25 million on a pse-tax basis. Depending on the level of participation, the charge could be higher or lower. The Company is currently evaluating its options in order to achieve the 450 employee reduction if it is not achieved through the enhanced retirement programs and the management and administrative support reduction. The Company anticipates ongoing savings as a result of the reorganization. On August 16, 1995, the DPU issued an order on restructuring of the electric utility industry. The order provides for Massachusetts-based electric utilities to restructure their operations to permit more competition for customers. It includes principles for a restructured electric industry that consist of customer choice and the benefits of competition for all customers; 12
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full competition in generation markets; functionally separate generation, transmission and distribution services; universal services support for environmental regulation goals; and incentive regulation for the transmission and distribution of electricity, which remain monopoly services. The DPU's order also set principles to guide the transition from a regulated to a competitive industry structures honor existing commitments; unbundle rates for generation, transmission, and distributioni reduce rates in the near terms maintain demand-side management programs; and ensure an orderly and quick transition which minimizes customer confusion. The order allows a reasonable opportunity for the recovery of net, non-mitigable potentially strandable costs, over a period of five to ten years. These costs include investments in plant that might not be recoverable in a competitive market, liabilities for future decommissioning of nuclear plants, the amounts by which certain purchase power contracts exceed the competitive price for generation, and prudently incurred regulatory assets. The procedure and criteria for recovering potentially strandable costs are uncertain, and the extent of the company's ability to recover all or part of its potentially strandable costs is unknown at this time. The order established only general principles for the transition to a competitive market and did not establish a particular model for the new industry structure. The order requires each of the Massachusetts-based electric utilities to develop a plan for moving toward competition consistent with the DPU's order and encourages utilities to negotiate with all interested parties while doing so. The Company is one of three companies required to file a restructuring plan by February 16, 1996. l 13
l P Part II - other Information Item 5. Other Information -The following additional information is furnished in connection with the Registration Statement on Form S-3 of the Registrant (File No. 33-57840), filed with the Securities and Exchange Commission on February 3, 1993. Price and dividend information per share of common stock Price Dividend High Low Paid First quarter 1995 $25 1/2 $23 1/8 $0.455 Second quarter 1995 27 23 3/8 0.455 ; Third quarter 1995 27 1/2 24 1/2 0.455 The last sales price of the Company's common stock on the New York Stock Exchange as reported in the Wall Street Journal for November 9, 1995 was
$27 3/8 per share.
Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements: Twelve months ended September 30, 1995: Ratio of earnings to fixed charges 2.59 Ratio of earnings to fixed charges and preferred stock dividend requirements 2.18 Item 6. Exhibits and Reports on Form 8-K a) Exhibits filed herewith: Exhibit 12 - computation of ratio of earnings to fixed charges 12.1 - computation of ratio of earnings to fixed charges for the twelve months ended September 30, 1995 12.2 - computation of ratio of earnings to fixed charges and preferred stock dividend requirements for the twelve months ended September 30, 1995 Exhibit 15 - Letter re unaudited interim financial information 15.1 - Report of Independent Accountants Exhibit 27 - Financial Data Schedule ! 27.1 - Schedule UT 14 i i l
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e Exhibit 99 - Additional Exhibits 99.1 - Letter of Independent Accountants Re Form S-3 Registration Statements filed by the company on September 14, 1990 (File No. 33-36824), February 3, 1993 (File No. 33-57840) and May 31, 1995 (File No. 33-59693); Form S-8 Registration Statements filed by the Company on October 10, 1985 (File No. 33-00810), July 28, 1986 (File No. 33-7558), December 31, 1990 (File No. 33-38434), June 5, 1992 (33-48424 and 33-48425), March 17, 1993 (33-59662 and 33-59682) and April 6, 1995 (33-58457) b) No Form 8-K was filed during the third quarter of 1995. l l l l l l l l l l l I
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15 l l
Signature l Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the j undersigned thereunto duly authorized. i i I I BOSTON EDISON COMPANY (Registrant) l Datet November 13, 1995 /s/ Robert J. Weafer, Jr. Robert J. Weafer, Jr. Vice President, Controller and Chief Accounting Officer
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e Exhibit 12.1 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges l
. Twelve Months-Ended September 30, 1995 (in thousands)
Net income from continuing operations & $129,753 l i Income taxes 76,864 l l Fixed charges 129,701 l l Total $336,318 i l Interest expense $119,679 Interest component of rentals 10,022 Total $129,701 Ratio of earnings'to fixed charges 2 19 i 1 17
e Exhibit 12.2 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements Twelve Months Ended September 30, 1995 (in thousands)
+
Net income from continuing operations ~ $129,753 76,864 Income taxes Fixed charges _129,701
$336,318 Total Interest expense $119,679 Interest component of rentals 10,022 Subtotal 129,701 Preferred stock dividend requirements 24,503
$154,204 Total Ratio of earnings to fixed charges and preferred.
stock dividend requirements 2411 18
4 Exhibit 15.1 Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company. We have reviewed the accompanying consolidated balance sheet of Boston Edison ' Company (the Company) and subsidiaries as of September 30, 1995 and the related statements of income for the three and nine-month periods ended September 30, 1995 and 1994 and statements of cash flows for the nine-month periods ended September 30, 1995 and 1994. These financial statements are the responsibility of the company's management. We conducted our review in accordance with standards established by the American Institute of certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsiole for financial and accounting matters. It is substantially less in scope than-an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial
\ statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying financial statements in order for them to be in conformity with generally accepted accounting principles. Boston, Massachusetts COOPERS & LYBRAND L.L.P. October 26, 1995 19
o a Exhibit 99.1 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Re: _ Boston Edison Company Registration on Form S-3 and Form S-8 We are aware that our report dated October 26, 1995 on our review of the -interim financial information of Boston Edison Company for the period ended September 30, 1995 and included in this Form 10-Q is incorporated by reference in the Company's registration statements on Form S-3 (File Nos. 33-36824, 33-57840 and 33-59693) and on Form S-8 (File Nos. 33-00810, 33-7558,-33-38434, 33-48424, 33-48425, 33-59662, 33-59682 and 33-58457). Pursuant to Rule 436(c) under the Securities Act of 1933,.this report should not be considered a part- 'of the registration statements prepared or certified by us within the meaning' of Sections'7 and 11 of that Act. Boston, Massachusetts COOPERS & LYBRAND L.L.P. October 26, 1995 l l l 20
9 BOSTON EDISON COMPANY 1995 INTERNAL CASH FLOW PROJECTION FOR PILGRIM UNIT #1 NUCLEAR POWER STATION (DOLLARS IN THOUSANDS) 12 Months Ended Projected Year 9/30/95 1996 Netincome AfterTaxes $129,753 $141,000 Less Dividends Paid (98.378) (108.000) Retained Earnings 31,375 33,000 Adjustments: Depreciation and Amortization 180,446 260,000 Depreciation Nuclear Outage Costs 18,556 (8,000) Deferred Taxes and ITC (29,395) (38,000) AFUDC (7.073) (4.000) Total Adjustments $162.534 - $210.000 Intemal Cash Flow $193.909 $243.000 Average Quarterly Cash Flow $48.477 $60.750 Percentage Ownership in All Operating Nuclear Units Pilgrim Unit #1 74 % Maximum total Contingency Liability $10,000 l l l macr = l i
. . .- - . - . . - - . _ - . - .. ... . ~ . - . . - - . - . .- .. -. j J ITEM (4) NARRATIVE STATEMENTS OF CURTAILMENT OF CAPITAL EXPENDITURES: The Boston Edison Company would be able to curtail $10 million of capital expenditures within any three month period of the next twelve months if it becomes necessary to pay retrospective premiums. i l I l j M j}}