ML20065K265
| ML20065K265 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/31/1993 |
| From: | Fairbank R, May T, Reznicek B BOSTON EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 2.94.038, NUDOCS 9404190255 | |
| Download: ML20065K265 (125) | |
Text
{{#Wiki_filter:L BOSTON EDISON higrim Nudear Power Station 600 Rocky Hill Road Plymouth, Massachusetts 02360 April 8,1994 10CFR50.71(b) 10CFR140.15(b)(1) 2.94.038 U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 License DPR-35 Docket 50-293 Annual Financial Statement in accordance with 10CFR50.71(b) and 10CFR140.15(b)(1), Boston Edison is submitting the 1993 Annual Report and the Securities and Exchange Commission (SEC) Form 10-K which corresponds to the 1993 Annual Report. 9 L-f}7;Y7" Ab'" R. V. Fairbank f Manager - Regulatory Affairs and Emergency Preparedness Department RVF/GGW/nas/ANFINRPT ! i cc: Mr. R. Eaton, Project Manager Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Mail.Stop: 14D1 l U. S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike Rockville, MD 20852 U. S. Nuclear Regulatory Commission Region I
.475 Allendale Road King of Prussia, PA 19406 Senior NRC Resident Inspector Pilgrim Nuclear Power Station 0 0p(
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':0 Boston Edison Company W - - 1993 Annual Report ~
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I F, s l I ;e. b_ Financial Highlights:- f h years ended Decemler 31, 7 g(47
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1993 1992 W hange lv t p h 8"$""' Operating revenues (000) 51,482,253 s1,411,753 + 5.0% income available for common stock (000) 5102,513 590,748 F 13.0% E/ .. Common shares outstanding -
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weighted average (000) 44,959 43,144 + 4.2%
. Common stock data; p Earnings per share $2.28 S2.10 + 8.6%
- g. .. , Dnidends declared per share S1.715 51.655 + 3.6%
! M- - Payout ratio 75% 78 % - 3.8% i: Ilook value per share $19.42 516.77 + 3.5% Return on average common e(luity 11.9% 11.5% + 3.5% Fixed charge (overage (SEC) 2.27x 1.93x + 17.6% cenain red.wriutmns hm bwn mad.. to tlw 4ta reponed m the pnor year to adorm t., the meth! of Serviced by Boston EdisonL P""*"" "
- E Northeast Area-B Central Area -
E Southwest Area - EO Wholesale customer
- Contents >
On the Cover: . Ed.itonal .. . . . . .4 Our New corporate Management's discussion and analysis . . . 16 ' Identification Consolidated financial statements . . 21 in recognition of our ever- otes to conw) Mated financial statements . . 24 increasing competitise envi. Selected statistics . . . . 36 romnent, and the need to Omcers & directors . . .40 - e distinguish our.selves from Shareholder information . . 41 the competition, ne recentiv updated our corporate identi-fication. This new identifica-tion evohes from our old signature, but changes About the Company- - enough to take us into the next century. The circle rep-resents the carth and reflects lioston Edison is a public utility engaged principally in the generation. pur- ' chase, transmission, distribution and sale of electric energv. It was incorporat-our commitment to the enti. ronment, and streamlined W M 18SE W hd ii il to m m of woxielv 590 ' square miles within O3' miles of Boston, encompassing the Citv of Boston and sersice for customers. The 39 surrounding cities and towns. The population of the territory served at lines form to communicate retail is groximatelv 1,500,000. energy working in concert ' with the crironment. You'll We also supply electricity to other utilities and municipal electric depart. t now see the ner identifica- ments at w holesale for resale. About 86 percent of our revenues are derived tion in all our con munica- from retail electric sales,12 percent from wholesale sales and 2 percent from tions uith you. other sources. I
Nineteen ninety three was an excellent ycar for Ibston Edison sharehoklers. F;r the lifth consecu-tive year, our management team and employees worked together to proside 'otal returns that beat both market and industry averages. In fact, the total return on your investment, including dis idends paid, was 14.5 percent. Earnings were also good in 1993, rising 8.6 perc :nt, to 52.28 per share. And, the Ikaard of Directors again increased tour dividend by 6 cents, or 3.5 percent. Our positive perlbrmance was the result of our commitment to controlling costs and continued operational excellence. To control costs in 1993, u e completed several refinancings, which dramat-ically altered the make-up of our debt and some of our preferred stock, resuking in annual sasings of mme dun 5 l 1 million in interest and dividend costs. We also continued to reduce the number of employees in our workforce resulting in a decrease from 4,540 in 1992 to 4,404 in 1993, a redue tion of 136 positions. Since 1991, our workforce has been reduced mainly through attrition bv cl >se to 400 positions, or nine percent. Operationally in 1993, Pilgrim Nuclear Power Station completed its shortest refueling outage ever at 57 days, and earned its best " report card' from the Nuclear Regulatory Commission. Three of our lossil units completed major overhauls on time and within budget, preparmg us for strong unit perfbrmance and reliable power for customers for many years to come. Our Ibcus on competition intensified in 1993 as evidenced by our strategic pian. Its details emphasi/e reduced costs and imprmed service to both w holesale and retail customers, more efli-I- cient and effective technology and new energy-related businesses, while recognizing the need to continue providing investors with steady financial growth that outperforms the industry. Our financial condition nill improve from recent s ictories in the wholesale (ustomer market. In 1993, we signed agreements with two existing wholesale customers and added a new customer to our list: the Ewn of liraintree. We have now successfully negotiated contracts to supply power to live w holesale customers until at least the year 2002. I or our retail customers, we seek to provide price stability. To that end, we have set an aggressive goal to not seek any additional base rate increases, beyond w hat is already appnwed, through the year 2000. Our managers are therefbre challenged to continue providing financial growth for share-hohlers, while holding prices steady for customers. This can only be accomplished by simultaneous-ly increasing revenues and reducing the costs of doing business. Increasing sales is largely dependent upon the strength of our local economy. Therefbre, we bas e assumed a leadership role in helping our cities and our state create jobs, and we are lending our material and human resources to buiki solid and safe communities. Recent reports indicate some
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success as local unemployment figures fell below the national average, ollice vacancies decreased, ! consumer confidence improved, and home starts and sales have begun to rise. Given these positis c ' 'j indicators, we base resised our ihrecasts for imprmed sales growth to 1.5 percent. f 1
We will also improve revenue gnm th hs actitch marketmg new electric tedumlogies, pnxlucts, and senices to our customers to improse their operations and help the emironment. By combining neu electric technologies uith demand-side managemt programs, we u ill olier customei s a total value pa( kage of energy options and sen ices to run their homes and businesses, and create athli-tional revenues for Boston Edison.
~li> help control costs, we will continue to ' et k out and imest in technologies that enable us to work more eMcienth ard effectitch. Io that end, ne hase established a new technology research and desclopment function u hich will evaluate and int < grate new tec hnologies into our operations to lower costs and enhance customer service.
Finally, we h.ne a strategy to pursue eln tricity-related business opportunities through our first unregulated subsidiarv, the Boston Energ Lhnology Group. We willinvest up to $45 million over I three years in new businesses, including an electric schicle rn harging distributorship. Our latest new business anjuisition, REZ-TEK International Corp., is a compam which has developed an innovative l n stem that treats cooling water used in c ommercial and industrial air conditioning a stems in an l energy 0$cient and environmentally sound tuanner that climinates diemical treatment. None of u hat we base discussed is achies able u ithout limusing on the human side of our enter-pr'sc. Employees base been responsible for our success to date, and u ill be key to creating our future. Thes are responsible fc cont,..uing to improve internal operations and offering pnnlucts and services to increase value to our customers. Our 19H performance is esidem e of our strength and comiction to succeed. We are in con-trol of our business, and by continuoush impnning all aspect of our operations, we are creating our future. l4%uL - g Bernard W. Rc/nicek Thomas J. May Chairman and President and Chief Executive Ollhtr Chief Operating Omcer l l Februan 17,1994 1 The inset (top a , .el of our n - pag Ce schedu This center w inco yra a . g -. mppte . system
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i l l 0 rClain and CAfand OUr (UslomCr baSC, nC must delicer calue in ll1Chim ofencry e[]icient and environmentalic beneficial T frOJUlls and <juality scrcices UDJ businCSSC$. j l Customer Sales, Service and Marketing i l Customers demand excellent senice, and look Ior sarictv of medical customers in our territory, electric "one stop" shopping lo accomplish this, uc'se disinfection and mlume reduction sutems olTer a cost-restructured and refocused our sales and senice cifectise, environmentally sound way to treat and dis-organintions, and elevated standards for perf or- pose of hazardous medical w astes. We're al4o working mance. We're creiting a with residential customers to olfer advanced heating customer drisen, profit. and cooling systems for significant cost sasings. m'. enhancing marketing- plan,
\\. ,c ve reallocated our customer representatises' building the skills and mm-y-.
f time to hclp us accomplish our gcJ. The result: pctencies of.our markrtinge
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uill spend and sales forces, and, most . . more tune in the field, p) importantly, reengineering ' working one-on one with service delisen processes customers, with the full Wenda Vesquer for our customers. support of.an in house is a customer
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representative ter understanding of our tive team. These represen- % who helps tatises will prmide customer market segments customers with so that we may bn onn- custorners value through a billing gisestions, service issues. energy consultants for each s arielv of sersices, includ-Tom Puddister is end apphcations group. This understanding ing real-time information ,,,,,,,,,,,, for new#slectric u d. l imprm e our ability to na customers, energy auto mechamcs i proside customers with a usage and patterns accessed who mamtams I our fleet of varicts of demand side through lap top computers ,,, ,, management programs, as well as qualitv senices and and remote data links to ..d v ns eflicient dectric technologies w hich meet their needs corporate headquarters. and expectations. A system talled Some of the new, energy cliicient technologies and cal)lM AGE will provide emironmentally beneficial prulacts we're off ering us with saluable computer graphics, database map-include electric ( hillers u hich provide ellicient, reli- ping, and facilities management needed in our daily able cooling for large conunertial facilities. For the ficId operations. 4
Our RETAIL CUSTOMER MIX it stabitued by the commercial and residential sec. tors which help minimue effects of regional economic swings. Industrial
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Resideetial Commercial We are also athling 3ervices that 28 % . li3% _- . firms and more than S I million in
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alhm us to use our technical knoul-annual base resenues for Boston Edi-edge to meet customers' internal - . :, ,, son. In addition, we'se heen instru-operating needs, thus expanding our , mentalin deseloping and role to prmide customer services on implementing a program in which the other side of the meter. local CEOs promote Massachusetts While many of our elTorts are to CEOs around the country, in order to attract hu<iness to the state, targeted to existing customers, uc'll continue to pursue new ones Finally, we'll continue to support aggressively, especially in the u hole- EROM OPERATIONS the electric vehicle and electric mass sale inarket. We are currently rose 8.6% in 1993. transit markets through infrastruc-preparing a number of active hids ture development, coordination w ith for new uholesale customers which s2 50 ---- _ Ocet managers to encourage the pur. indude value added programs and $\23 chase of electric schicles, support of sersices that should help set us apart . lcg j 3lation, tise of electric vehicles in from the (ompetition. $2.00 -- - - our llect, delnonstrations at area Customers expect Boston [dison $tse schools, and loaning schicles to P ' media and opinion leaders. hxpan-to he a good corlTorate citizen, and * ^
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to take our role in the community 1---- r smn of.t he electric tranprtation seriousIV. In athlition to corporate } market is good new s for the emiron-I gis ing, education, and em ironmen- $100 - -- -- - ent,andf.or revenue grow th, tal protection programs, we fulfill - f i Our success uill he measured by our corporate responsihility by help-stronger customer relationships, ing to bring jobs to Massa (husetts. $0'50 - ---
.mt r glop oportuniti%a Our 1993 elTorts garnered solid I l j -
larger customer base, and increased l results: our economic dese}opment g g ] __ revennes and profits, l rate, w hich provides 4-Vear rate dis- 1909 1990 1991 1992 1993 counts to eligihle tustomers, helped attract sesen new manufacturing 5 . - .
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.. CADIMAGE is a computer f' T~ .a graphic and database I4 j.5 Y. ,.
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) Arlington to investigate how CADIMAGE may provide TK" .- communities with value-added services. CADIMAGE may have applications in servicing municipal needs such as planning, assessing. engmeermg, and public safety. Left to right are Arlington Town Manager, Don Marquis; CADIMAGE Development Coordinator, Dick Cohane; and Executive Vice President, George Davis.
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ustomer satis @ction depends, in large part, on the price and reliabihty of our product. lb provide a reliabic, competitively priced C product ne must controlcosts technologies that improve cl]iciencies and reduce costs. Cost Control & Operational Excellence stable, predictable prices are important to cuo specific service job tomers. So, we'se recently announced a goal to amid descriptions into just four ; J requesting hase price increases, heyond w hat is dassifications. These alreach approsed, through the year 2000. emplovces are now being ,. trained, and will he - A E accomplish the goal, ne must continue our - g responsihle for handling a ' efl. orts to control costs. We mu:,t continue to make f uider variety oflleld work full use of employees' skills and asailahle for imprmed customer Al Abramson is a technology. Thanks to improved empimec service at a lower cost. sphcer m our clmhetenes and better use of. technology,'w e,ve been
- electnc customer able to reduce our l'ursuing technological servece area who workforce, primarih. advances in metering can - memtams and also helPus save nmney repairs the through attrition. We'll underground continue to reduce our through faster payment of customer hills, louer lahor ht. ' '. -
f otal numher of provide power to costs per meter read, and our customers
.. * . employees hased on U further tethnological amidance of safety and advances and access problems for our meter readers. In 1994, we'llinvest nearly 57 million Ed Foley is a fossil restructurings for station mechanic improved eflicienev, in equipment that reads, disconnects, and reconnects who provides meters remotely, maintenance for Management and union all major plant . We'll control costs hy better managing our leaders have worked well equipment et our .
inventories. In 1993, we reduced inventon hv s13 ' New Boston together to improve , nullion, and in 1994, ne,11 nork w.ith our vendors to power plant to performance and reduce ensure its safe- incorporate a"just-in time inventory philosophy f. or costs. Iur example, m. rehabl's, and . further savings and efficiencies. gc;,,, 1993, we worked with operation. our union. represented Effectise maintenance of our plants and sy stems is employees and their necessary for success. In 1994 and hemnd. we'll leadership to combine 14 henefit from 1993's presentise maintenance overhauk 8 l _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ -
I of half our fossil units. In fact, this senice, and emimnmental increased focus on maintenance has performance, the company will permitted us to extend our fossil unit use benchmarking tools. merhaul ncles from live to six years, Looking outside the company, and refueling intenals at Pilgrim , we 11 continue our work w.ith 5tation to esert tuo scars. This will . state omcials and regulators on help us to exceed the on-line capacity rules which affect the methods range of 60 - 68% set by our state we use and the costs we incur to regulators for Pilgrim Station. , meet customers power To control maintenance and demands. Our state regulators equipment costs, ne'll use hase created an integrated (omputerized models and available resource management (IRM) technologies such as sihration process in u hich electric utilities monitoring to identify problems forecast future energy needs and before thes hecome sncre. The propose how they uill meet result: minimum unit dou n-time, them by halancing conservation and reductions in rush orders and programs and all other availahle high cost replacement equipment, supply options. We're working closely with regulators to ensure Critical to our goals of cost - the IRM process results in control and continuous improse-meeting- customer demand for ment will he the ongoin*o power at the lowest possible cost. imolvement ol.our managers. I.hese empimees will run their departments as small business units.
'Io help our managers monitor performan(c again t the competition in areas such as employee productisity, cu tomer 9
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FIELD-BASED ENERGY CONSULTING LOADMAP is a software application developed by our employees to help customers manage their energy usage and costs. LOADM AP provides computerized spreadsheets of monthly energy, demand, and efficiency statistics. U .h '- LOADMAP and other software programs are offered by our customer sales representatives to nearly 200 commercial and inderial custe.ners as important field-based energy consulting tools. For instance, The Gillette Company's South Boston manufacturing center uses LOADMAP to help them analyze their power s., ; , consumption and the impact i; I .p py their production operations 4 v q y ;f" - have on energy usage and
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'}j y} j Alison Alden; and The Gillette 3ai Company's Manager of Power
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mph7ec involvement is crucialjbr Boston Edison's success in a competitive environment. Our employees serve customers, implement corporate Estrategies, run our business, and emphyces understand the competitive nature ofour business, the importance ofcost control, and the need to provide exccHent service and value to our customers. Ile must continue to provide emphyces with the tcols, iryormation, involvement, and management necessary]or success. Employee Effectiveness and Involvement As the largest single sharehohler group, holding near- should he climinated, process improvements for h 2 nullion shares, hoston ldison emplmees are per- greater CIIiciencies, and appropriate staffing le\cls for sonalh and profcwinnally imested in our conipam's the3e new functions. suc c~ess, in addition, more than N'o ol our emplov- . And long al,ler the design teams haic done their ces are also our (ustomers, sin (e they h,\c within our , sersice territory. Joh, we,ll continue to keep employees imoh u, l m. making it easy I.or customers to do husiness uitgi us. Emplmees ha\e heen ()ne emplovec te,uli, called the Kc) 3cCount Group, instrumental in all aspects is currently defining how uc'll uork uilh our major of our ciolution to a strolig customers. Another (cam, called the Customer Sup. competilis e company. port Group, is reengineer- , 4 Design teams of emploires ing the sertices we pro \ide ( ' ha\e shaped reorgani/atiom to inedium and large si/ed of our workforce to ensure customers. '
. floss Menard as a we hate the right process . . .
career Another team is nienti- 1.; - development es, proc edures, organ.l/a- ' A hing process and tec hnolo- n specialist who tions and people to meet a improvements to k./, . maneges our job 6's customers' demands. rotation program streamline new customer Jean Dickson is a for employees These teams base ana- uork orders. These facilitator who h /cd the work ue do, the imprm ements w ill reduce . leads employee teams in re-value of the work to the the iost of.prouding new designing work customer, the processes im oh ed, and the existing sers i( es, w hile offering . proc ....and stamng lesels. Thev identified low ulue unrk that hetter t ustomer sersice. organiiational - structure. 12 l 1
OlVIDENDS PAID PER SHARE mcreased on a percentage , basis by more than the industry average m each of the last four years l l
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- ? i I ooking ahead, our managers fully understanding our new are better ab!c to see into the l
business em ironment, so that : . future and plan strategically, so go m they mas respond to it elTectise- 1901.911.92i93134 thanks to a new tool called the Proforma ly. A series of competitise hmi. orkfora hannig mdl 'I'b ness issue sideo4 and fact sheets computeriicd tec hni<jue uill help hase been produced, a standing- managers forecast stafling room only series of utility requirements by analv/ing vari-ANNUAL TOTAL RETURN TO linance dasses were introduced, ables such as attrition rates and SHAREHOLDERS has exceeded and our popular lunchtime lec- industry and market averages productivity figures. ture series has been refocused to for the past five years. emphasize the new challenges
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we face in tr3 i ng to keep aml attract customers. 33 5 % limployees are also learning j
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saluahic new perspectises ihrough a new company initia. ! l tise, lly participating in joh ,l } 9, gg rotations in 1991, several 20a m -q - - .- ~ j p emplosecs mosed to new areas, l 14 5 % l managed new projects and peo. J. l l plc, and learned new skills ios ! . -.,,, ' *y. - [ l _ important to our suu ess. g l, A [! ! afiI 1989 1990 1991 1992 1993 13
a EWH/ HUH: Forward Beverse T tal: 5491.88 0.00 . A: 2046.44 f9 ide B: 3445.43 4ji stantan 4 o e Alues-Hue YT ~ f is . EUA Total O 1.3 9 Side A
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***. tp Max Power:. 11.442 kWattsj Max Uoltage: 263.13krolts; Min Voltage: 92 volts Aug Battery Volta W 3.71 vo ts Mete Outages: '2 ,
Last Outaie Duration 2624 secaj M
Managing with Information ServiceNet is an integrated, computerized technology featuring two-way radio communications that allows for remote reading, connecting and disconnecting of meters, and the ability to gather real-time intelligence on the operation of our power distribution systems. 4 ServiceNet is one of several new technologies we've incorporated to help our meter reading em-playees work efficiently, manaDe with infarmation, reduce customer complaints, and lower meter reading, billing, and collection costs. By using another technology 1- called ENSCAN, employees can
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,5 Technology Research and 1[g(p,,
7 } 4,t .' Development, Dick Hahn; and Q fY
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Management's. Discussion and An.alysis resenues increased $29.5 million mer 1992, iurtly due to hmcr iesenuc reccised from short term i=cr sales as l discu, sed hchm. ! Regulatory Proceed.mgs l We began reo nery ol.(crtain <lematal side maragement flef ull sef ficment dgreements prograin (mts, hnt hase resenues and incentises in ;\ugust Ufectise Nmember 1992 our state regulators, the Maw. 1992. ()ur 1941 resenues prmided $45.9 million related to achusetts Department of Pubhc Utihties, appiuved a three- l'N1,1992 and 19H 1)sM programs. Our 1992 revenues of year settlement agreement. This agreement prmi<les us with s 1 A 1 nullion relateil primarily to 1991 programs. retad rate increases, allou s liar the rermery of demand side The det rease in ,holesale ainl other resenues redes ts an management ilml) t onsenation program npenditures, estimated pnnision for refunds to iustomers of apprmimately specifics iertain auounting adjustments aint clarities the tim- SS million as a result of orders from our state regulators on l ilig and Troynithin ol certain C\pensCS. The Jgiccincitt abil our gt nerating utlit perlortnance progratn. sets a linut on our rate of return on common equits of 11.75% limi r sinirt term ptmer sales resenues were a result of for 1991 through 1995, culudmg am penalties or reu ards t hanges in ur generation asailabihty and the needs of short-from performanic mt entiscs. term pimer purt hasers. All resenues from simrt term sales I he retad rate im reases consist of a neu annuall u rfor- sene to reduce fuel .and part based jumer hilhngs to retail cus-mance aihustment t harge cifcoise Nmember 1992 and tuo tomu s and hase no effcci on earnings. ad.htional rate increases of $ 29 million efice tisc Nmember 19H an i Nm ember 1994. The performam e adjustment Operating cipenses tharge saties annually hasal upon the performance of our I ucl npense decreased s 19,5 million primarily due to a higrim Nuilear hmer station. This t harge is further 21.Niccrease in generation, resuhing from planned mer. des rihed m our ihscuuion of financial (omlition. hauh of our ionil plants. Inten hange pun bases im reased due i ()ur 19H inuhs of operations were affet ted in the to the louer generation, rest,lting in a 57.5 milhon net l renacn of INI program npemhtures, atoiunting adjust - im rease in purc hased p<mer expense. The net increase aho mems and iiming aml reoignition of certain npenses as fur. reib ts sasings of apprmimately slo million from a long. term ther dew rihed in the folhming itesuhs of Opciations section. pun based [wm er contract that npired in October 19H. ihith ( >ur state regulators apprmed a presinus t}u ceacar set. our luel and pun based ptmer npenses are substantialh f ully tlement agreement elb tisc Nmember 1989. That agreement reunerable through fuel and purt based ptmer resenues. also prouded us with retail rate increases anil specified certain Other operations and maintenance npense increased at coum ng adjusoncnts. I he 1989 agreement prunarih 7.1% primarily due to increases m emphnee hent lits and affected our resuhs of operations through 1992 not lear production npenses. Postretirement benefits npe nse int reased by s7 nullion primarily as a result of the adoption of Results of Operations a new at counnng standard and pension npense im rcased by si million; hoth are prmided for in our 1992 settirment 1991 Versus 1992 agreement and l.urther nplained m. Note I to the (onsolidated I.arnings per t onunon share ucre $.2.25 in 199 4.md s2.10 in finant ial statement s. A refueling outage at Pdgrim Station in 1992. The increase in carnings is primarily the result of an 19,H resuhed in h;gher nuclear produc tion mpenses. annual rate increase eflet tisc Nmeinher 1992, louer Iiur l)c pretiation and amorti/ation npense incrcased m. (hased poner c\ pense due to a long term (ontract npiration, l,),Il prituarih. ilue to a higher annual decolluniwinning i harge no amorti/ anon ol.dcl. cried cam elled nuclear unit t osts aml . lor Pdgrim Station cIlecthe N. member 1992 prosiiled by the h mt r interest npense. These positn e c innges ucre partialh .
;,,192 si ttlernent agt ecmt nt. .Ihe new t harge is based on a
( d b.et In highcr tiperations and maintename npense and 149l cstimate of decomminioning (osts as f.urther discussed in higher income ta\ and properts tax espenses s '. N.ote 1) to the (onsolidated imancial statements. In addition,
. the cifn t of lower depretiation rates iluplemented in accor-OperatIrnj rencnues .
dance with the settlement agtectnent u as ol.het by the cIfet t ()perating icsrnues im reased 5"h mei 1992 as loih m s of a highci depreciable plant halance. on thouswlo In act ordance with our 1992 settleincut aorecment O we did itetad. t lectt ic snenues 5,0,8 17 not npense any of the $ 19 milhon of. remaining deferred ( osts I)cmand side managelnent resenues 13,601 awociated with the canceded Pdp' rim 2 nu(lear unit in 199l. M
%.holnale and othc r rnenues (2,794 will npense the remaining costs in 1994 and/or 19%.
short term sales rnenues <it,144> - Amortization of. deferred nuclear outage (osts int ludes im rease in operating' resenun s70,500 amounts related to the 199 5 and 1991 ref.ueling outages at Pdgriin 5tation, in 199 } we deferred appro\imately s 14 mil-Iterad clearic reu nues increased s70.8 milhon. .I he
. lion of.rel.uchng outage costs. M hegan to amortiec these Nmember 1992 and 1991 rate increases resuhed m. s40.6 nni -
t mts in June 1991 mer lise scars as apprmed in the 1992 wt-hon of adduional n wnues in 1491. I uiI and purt based power tiement agreement. 16
%c fricrease in demand side roanagement programs Operating revenues expenne is condstent with the inacase in DSM resenues. Operating resenues increased 4.2% over 1991 as follow s:
DsM expense includes some costs recovered mer a twelse onthous.mdo
- month period and other cmts rennered over six years. We 1(etail elect ric res enues $27,672 '
began to reemer presiously deferred DSM expenses in August I)cmand side management resenues 12,343 1992. In 199 3 we expemed and collected from customer $ Wimleule and other resenues 1,881 approumately 5 30 million of deferred 1991,1992 and 1993 Short-term sales revenues 15,356 program costs. Over six years we are expensing and collecting increase in operating revenues $ 57,252 imm our customers 5 I I million of costs capitalized in 1992 and $37 million of cmts capitalized in 1993. The 1993 Itetail electric resenues increased 527.7 million. We expeme related to these capitalized costs was 57 million. n.n.ncil a 525 million rate innvase elli ctive November 1991 as Munitipal property and other taxes increased in 199 3 part of the 1989 settlement agreement. We also earned 58.2 mil-due to the absence of tax abatements. In 1992 property taxc5 lion in incenthe resenues in 1992 as a result of Pilgrim Station's were reduced by 510.4 million of tax abatements in accor- cag.ity factor emeding its target set in the agreement. Fuel and dance with our 1989 settlement agreement
- purchased power revenues decreased approximately 55 million due Our cfTe(tise annualincome tax rate for 199 3 wa' to higher purchased powtr nists more than offset by higher rev.
2 3.4% ss. 8.7% for 1992, lloth tates wcre significantl} enues receised fnim short term pmer sales as discussed below, reduced by adjustments to deferred income taxes ni 520 mil" in 1992 we began to re(cise resenues ihr the recmcry of lion in 199I and 52 3 inillion in 1992 made in accordance with certain I)SM program costs, lost base resenues and incentives. the 1992 and 1989 settlement agreements. The 1992 rate wa$ The 1992 rewnues relate primarily to 1991 DSM programs-aho reduced due to tax benefits of approximately 57 million Our short-term power sales increased in 1992 as a result resulting from mandated pay ments made in accordance w ith of our high generating unit availability and the greater power the 1989 agieement. Our adoption of a new acmunting stan- needs of other New hngland utihties. All revenues from dard for income taxes in 1993 did not significantly alTect short-term sales serted to reduce fuel and purchased power carnings. We expect our elliTtise tax rate to be clme to the billings to retail customers and had no clTect on earnings. statutory rate in 1994. Operating etpenses frstercsf charges andprc[crredundprefercmc disidends Purcheed power expense increased 518 milhon in 1992 due
'Iotal interest charges decrened 5 3.8 million in 199 3. Interest to new longterm purchased power contracts, lloth our fuel on long term debt decreased primarily due to the relinancing and purthued power expenses are substantially fully recover-of substantially all our first mortgage bonds in 1993 at lower able ihmugh fuel and purchased power resenues.
interest rates, partially offset by higher amortization of other operations and maintenance expense increased redemption premiums. ( >ther interest charges decreased duc 2.3% due primarily to increases in employee benefit expenses to a lower short term debt level and lower short term interest and bad debts. rates. Allowance for funds used during construction Amortization of deferred nuclear outage costs in 1992 (Af UDCh w hich represents the financing costs of comtruc. and 1991 includes amounts primarily related to the 1991 tion, decreased as a resuh of a lower AillDC rate related to refueling outage at Pdgrim Station. In 1991 we deferred-hmer short-term interest rates. approximately 523 million of refueling outage costs. W, Preferred and preference dhidends decreced 5% due to began to expeme these costs mer five years in September the replacement of a preferred and a preference stm k issue 1991 as apprmed by our state regulators. with less costly issues of preferred stock. Municipal property and other taxes increased 21% pri-marily due to a reduction in residential and commercial real ' 1992 Versus 1991 estatbalues caused by the depressed economy. This resulted Earnings per common share were 52.10 in 1992 and 51.96 i" in higher tax rates applied to our personal property values. In 1991. The inacase in carnings b prknarily the result of a rate accontwe with our 1989 settlement agreement, municipal increase clTectise Nmend.cr 1991, incenthe revenues earned property tax expenses were reduced by tax abatements of from the performance of Pilgrim Station and lower income tax
$ 10A million in 1992 and 513.6 million in 1991.
and interest expenses. These increases were partially offset by Our effective annualincome tax rate for 19Y2 was 8.7% higher operations and maintenance and property tax expense' n 16.5% for 1991, lloth rates were significantly reduced by We aho had a one time charge in 1992 lbr costs incurred for a adjustments to deferred income taxes of $2 3 million % 1992 deferred generating plant pro}cct-and 513 million in 1991 made in accordance with the 1989 settlement agreement. We also reccised tax benefits in both 3 years as a resuh of payments mandated by the agreement. ! U
Other inmme and espense liquidity in 1992 we expensni s8 million of custs previonsh imested in M mect our plant npenditure cash rn}uirements primarily the proposed I:dgar Energy Park pencration project. This pro. jn t w as deferred imh limtely as aihhtional generating (apady with internaHy generated hunk T hese funds (culuding pay-ments inade related to settlement agreements) pros idnl for is nat expn ted to be needed for socral wars 74%,90% aml 89% of our plant expenditures in 1994,1992 Interest charges and prcjerred andprefereme disidends and I991, nspectisely. Our current estimate of plant expen. Total interest < harges drocasal 4 A primarily due to limer ditures for 1994 is $211 million, im iudmg s20 million of inti rest rates on our ascrage sinirt-term bornmings. Al L.ll)C nuclear fuel additions. These npenditures w ill be usul pri-detreased 12.7"n due to a hmer Al til)C raic related to hmer marily to maintain and imprme existing transmission, distrihu-short term interest rates. tion and generation facilities. We aho estimate capitali<able Pn ferred and prefcn nce disideruls da reasal approsi. lWM npen<htures to be s 18 million in 1994, ubic h will be mately s I milhon prunarily due to the replacement of two pref. colin ted from customers over six years. We &> not expet t crence stm k series with less unth issues of preferred stot L. plant expenditures, culuding rmt lear fuel and INI, to vary sigmlicantly f rom the 1994 amount in the four years thereaf ter. I arnings per sharc We haw long term debt and preferred stot k payment require-Net income incicased l 1"o. I hm cwr, car nings per i ommon ments of $2 million in 1994, 5102.6 million in 1995, arul sharc for 1992 itu n ased only 7"o, reller ting an increase in the s 10 L6 million per ) car in 1996 through 1998. urighted awrage number ol u>nunon sharcs outstanding pri. I stet nal finam ings uintinue to be accessary to supple-marily a result ol our 1991 and 1992 onmm>n stoi k issuantes. ment our internalh gcncrated fumb, primardy the issuance of short term (otumercial paper aml bank bornmings. We cur-Financial Condition renth lme authorii3 n>m i our fnh ral regulators to issue up to s MO milhon of short term dcht. We have a s 200 million ( Jur 1992 settlement agrccmcol ponides us uith increased resolving credit aprecInent and arrangements uith several icwnues f rom retad (ustomers mer the three-war pctmd end- banks to prm hic addit.ional slnirt term credit on a (ummitted ing October 199 i. A4hoonally, a long term pun hased p4mer a* uell as on an uncommittnl and as avadable basis. At omtract u nh annualilurges of appnisimately s60 milhon 1)cc cmber 11,1993 ue had s2N.I mdhon of sluirt-term debt npired . mOc toher lo9 3 w ith no related ( hange in rnenues. outstandmg, none of w hi< h n as incurrnt under the revohin*o N. are limited to an annual rate of. return on etIuin durinee the - credit agreement. In 199 I our state regulators approved a three-year per ind of. ( (,75%., ncludmg any penaltics or-linancing plan albming us to iwuc up to $1.1 billion in ren ants f. rom perf ormance int entiws. set uritics throuch 1994 and to use the pro (enh to refinance ()ur (outinunl abilitt to athiew or ncced the l1.75% longterm securin,es and short term debt. At 1)cccmher 31' rate of n turn on n[uin will be primarih dependent upon out ne had sm imHion nanaining authorized to be issued abihty to iontrol t osts and to carn perlNrmam e irn enuws hom generation performam e mn hanisms specified in both Inuler the plan w hit h can he osal to issue conunon stot k, pre-in rol sto(k .uul lonptuni &bt As a nsuh of our niinanc-the t 959 aml 1992 settlement agrecments. t he mmt signiti ing artisitics in 199 3 uc npect to n alier annuaheed s.nings of cant impact that im entiws can har on our finam ial results i, approximately 511.5 milhon. N fer to Note F to the consoli-basn! on Pdgrim station \ annuali apacin factor. I fintiw Nowmber 1991 an annual t apaan fac tor heturen 60% and datni financial statements for specilic information relating to our recent financing actisitin. 6SN u di pnnide us with approximately 54 5 milhon of rn-enues iluuugh the pedorm ma ad nstment i c harge. I or cat h Outlook for the Future pen entage point increase in < apacity f actor abinc 68%, annual rnenues u di inen.ase in 3670,000. Iur cai h irrcentaSe .. I I.let trout e sala point da rease in capacity las tor belou 60% 00 a nuninuun of A u.'t m l.. i< ant portion of.our electricity sales is made to com-3 5n'o) annual ini nues u ill decrease In 9.._(),tio(). // Pdgr.
' uns inn cial cusionicl% Tatber tban inilust rial cust(oners, As3 (apacin, f.u tor for the polormam c war emhng t h tober 1994 nwult om sa aw n n onh inoderately impacted by the is npn ted to be appnhimatelv Sid (assuminh normal oper.
da hiu in the loi al Maw.u huscus cronono Our retail sales ating ometionsh an im rease mer the 66% capacin factor n . n .u ne an pale onh s!ight gnnyth in at hined in ths pt rforinatu e y car ended ( ktoher [991, as no retail sales in the near term, refueling outage is stheduled for 1994. We earned appnni. huplanentadon of I M lnopanu, w hit h an* doigned mately 540 million in performam e c harge rnenut s m the per-(" d"ist custonu rs m icdudng electricity use, will n suit in f ormance ycar ended ( htoht r 199 L I"un you th in electricity sales. The 1992 settlement agree-Our fouit generation unit performam e (an pnn-ide an nu nt niahhshal annual I M1 9ending lewh owr s 50 million im rease or decrease of up to 54 miHinn in naenues in each dirough 1994. The agreement pon nles for colla tion from paformance war hounct, uc do not npa t am rnenue '""""" "I """I" '"su prim rdy in the y ear incurred and adjustments f rom this mn hanism. others < - it year perid We are aho pnnided with int entiws and reoncry of hnt rewnues based on the actual redm tion in customer clectricuy (nage from these pnigrams and a n turn on the onts that ur reoner mer six years.
Cornpctition Othsr Matters As we are operating in a time ofincreasing competition from hn ironmental
- other cle(tric utihtics aml non utihty generators to sell cice We are suhicct to numerous federal, wate and local standants with tricity for resale, ur hae secured long term inmer supply rnpcci to air and w ater quahn, waste ilisp.nal ami other cm iron.
agreements u ith our four u holesale couomert Thnngh mentA u,nsider.uiont These uandants can require that oc these agierments our rato are *ct principally through the ycar 2002. We also ni,tained a new u holesale cuuomer in 199 I I"' ninary our niaing fardnics or incur increasnl operating <usts in 1991 we entered into a consent unler with the uhh h we u di prmide up to 10 megan atts ofiontract elemaml W hm tu IMixunent ofI minimnentA Pn>tcction (DI:P) power for ten years begiiming Nmember 1990 ain) other intercued partin to undertalic certain improvements our state regulator
- require utihtics to pun haw p""" in the emission iontrol systems at Ncu lloston Station. Thne froni quMifyilig min utthly getierators at pricn sci dirough a '
i r ments im huled tlic replacemerit of IInir existilig t hind bialmg pros cu. In June 1991 our state regulator s orderni n' nn au k3 with two taller oat Ls in onler to impnne the air to pun ha+c 1 D meg. matt
- ofl umer from an irnicpcinient "
quahn in the sirinity of the uation, ami the installation of low p.mcr producer, starting a catly as 199L M op!"ne thi' n nohen mido buri$crt The capital cost of these mmhfica' order sim e ne do not behew uc need any new inmer for se" tions Mong w ith otlict associated impnnements has been tralycars. In July 199 I uc asked the Mawat hmetts Noine"'" nio,imatch $7s million through 199 4 with an adhtional 5 3 Judicial Couri to rnerse the onlcr. We arc < urrently an anting milhon espected io t omplete thesc in ojn ts in 19W. a ila ision h om the i our i. In a4tition, our state icgulator s New Boston station has the abihty to burn natural gas, oil hac i rcated an integrated resource management (1101) or 1,oth. As part of the l >l Piument onh r uc also agiced to pnn ess in u hit h cln o it utilitics h>recat tin ir futute energy o crate the station using natural gas a fuel for a minimum of nine necih and propose hon ihc3 uill meet tho c needs lly balanc- ,,A r wlicponigin @ril 199L Beginningin April ing conu i s ation jungrams uith all other supphes of cocrgt 199; we uili lie nyuin d to operate the station fueled cu lusisely We will submit an 1101 tilmg in Manh 19% k naturA gw cwept in cenain emergem y c iaumstam n. % 1)irect competition uith other ch itric utihties f or iclad cln tricity sales is stdl subin i to substanilal limitations but
} i 4 un cmems him nine inonth supply of natural gas to the sution unul April 1995 and are t unently in the piouw of these hmnanons may be irduced in the future. In 19H uc nep anng widi namrA ge supphen and transporters concerning anmiuncrd our goal ol not sn Ling additional rate inurecs the economics .ind asailability of natural ge to Neu llowon on a other th.m dnne pnnided in the 1992 settlernent agrecrnent' lot our resalential, uimmcicial and imimtrial customers until wm n,und b.nis 4ter that time. Year-round gu supplies are cur-6 mn mdMile n, the uation and, e a result, the outcome of at leet the ycar 200(1 We plan to anomplish this by mnin l-itui ns u di naturA gn suppien and tonsporten and ling cous and inoceing operating efliciencies without sacrihc-die impxt on die operation of New llosion Station are um ertain.
ing quabiy of senice or protitabihty. I he annoontement The 1990 Clean Air Act Amenanents will require a sig, n On u our urong commionent to be a iompctitivly priced nificant redut tion in nationu nie emi%iom of sulfur dioside rehable prmider ol encrE)- from fmsd fuct find generating unitt The reduction will be Non-utility bmine" accomplishnt h restrii ting *ulfur amide emiwiom through a in 19H uc creatol an unregulated subsidiary known e the mMabad noem of Alnwamn. We behne that we will AW m iwurd to m that are in exens of ont needs aml Itouon I'ncrgy in knology Group (Bl TG) hillowing appros A from our state regulators. We haw authority to imnt up to di h may be macuhle. Any g.un hom the sale of these may 54$ milhon in this wholly ownnl subiaary ou r the next be mlvb fmme wgulamry treatment. ()ther pnnisiom of the 1990 Clean Air At t Amcmlmentu imohe limitatjom on thwe yent 1[IG u ill engage in demami side manap ment actisitics through its w holh ow ned subsidiary Fncr G Vision' emiwioin of nitrogen oxides from niaing generaung units. Gmbuoion worm m,4Hotiom made to New llosion and inc. ami bminewn imoh ing cln tric transportation ami the related infrastrm iure through its w holly ow ned suhidix} At tic stations, induding the imtallation of the lou nitrogen i w bm nen at Neu lloston, will allow the units to meet the Tre Hn n ic Senim Corporation. We do not c urrently har a suhtantialime,nornt in 101 G and do not anticipate it pnnisions of the 1995 stamlantt licpemling upon the out-signihcantly impacting om inuhs of operatiom in the next me of nruin mr paa modchng umbn, a4htional emis-seural years. so wa tiom ma Am iic wquired liy 1999, The extent of
,ny ,gi;gny n.dE tiom and the cows of any funher modifico j in January 19H HFTG acquired a suhtantiA rualonty internt in the awets ofit! XJII K International, Inc, a manu- i ons is uncertain at this time. I iw dmom asid in 1991 require that propertin facturer of wonc water treatment systemt Ibe neu entity' w his b w ill bc know n e RITII K International Corp , u di dm rden of brusan matriAs occurred in the past be continue the bmmcw of pn dming a sntcm that ncais conhng No r & d 9 rwrdmg on a timeMile dneloped by the u ater med in (onunen ial and innhntrial air constioning M
- i WP. We are urrently naluating the poti ntial omts awociat-tenn in an en-rgy cifiocot and emironmentalk sound manner.
bl h si } we be been idenufinl e dm ono or operan,n Ihoc an um cruintin awociated with 19
. .these potential costs due to the complexities of cleanup tech. Litigation
'nology, regulatory requirements and the particular characteris- In Marc h 1991 we were named in a lawsuit alleging discrimi.
tics of the different sites. We also continue to face possible lia- natory employment practices under the Age Discrimination in - bility as a potentially responsible party in the cleanup of cer. Employment _Act of 1967 concerning 46 employees affected by
. tain other multi party huardous waste sites in Massachusetts our 1988 reduction in Ibrce. Legal counsel is vigorously and other states. At the majority of these other sites we are defending this case.11ased on the information presently avail <
one of many potentially responsible parties and our alleged able we do not expect that this litigation or certain other legal share of the responsibility is a small percentage. We do not matters in which we are currently involved will have a material expect any of our potential cleanup liabilities to have a material impa(t on our nnancial condition.110 wever, an unfavorable
' impact on financial condition, although provisions for cleanup decision ordered against us could have a material impact on
. costs could have a material impact on quarterly earnings. quarterly earnings.
L l We presently dispose oflow level radioactise waste (LLW) generated at Pdgrim Station at licensed disposal facili. Labor negotiations ties in llarnwell, South Carolina. As a result of developments We began negotiations involving our labor contracts in early j u hich have occurred pursuant to the Low-Level Itadioactive February 1994. These contracts expire on May I 5,1994. We anticipate favorable resolution of these negotiations prior to j j : Waste Policy Amendments Act of 1985, our continued access l' to such disposal facilities has become wverely limited and sig- that date. ] nincantly increased in cost. Itefer to Note D to the consolidat-ed Gnancial statements for further discussion regarding LLW New accounting pronouncements disposal. We will adopt Statement of Financial Accounting Standards In recent years a number of published reports have dis- (SFAS) No. I12, Employers' Accounting for Postemploy ment cussed the possibility that atherse heahh effects may be caused llenefits, and SFAS No. I 15, Accounting lbr Certain - by electromagnetic fields (EMF) associated with electric trans. Investments in Debt and Equity Securities, in the first quarter
. mission and distribution facilities and appliances and wiring in of 1994. Refer to Notes I and j to the consolidated Gnancial buihlings and homes. Some scientine reticu s conducted to statements ihr further discussion of these pronouncements.
date by sescral state and federal agencies have suggested associ- 1 ations between EMF and such health effect. s , while other stud-ies have not substantiated such associations. We support fur-ther research into the subject and are participating in the ftmd-ing ofindustry sponsored studies. We are anare that public concern reganling EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities before regula-tors, or in requests for legislation or regulatory standants concerning EMF levels. We have not been signincantly affect-ed to date by these desclopments and cannot predict their potential impact on us, however, we continue to closely moni-tor all aspects of the EMF i, sue. 20
~ . ..
Copsolidated Statements ofincome years ended December 31, on thous.uuh, euert earning per dure) 1993 1992 1991 gerating/ tcienues S 1,482,251 5 1,411,753 5 1,354,501 Operating expenses: 1:ucl 176,366 195,873 200,912 Purcha,ed power 364,482 356,931 338,994 Other operations and maintenance 406,271 379,350 370,758 Depreciation and amortization 137,722 129.045 126,151 Amortuation of deferred cost of cancelled nuclear nnit 0 24,181 24,38i Amortiration of deferred nuclear outage costs 6,546 4,901 2,443 Demand side management programs 37,504 8,221 1,674 Taxes - property and other 93,102 80,426 66,216 Income taxes 14,94I I1,725 17,1Ii , lbtal operating expenses 1,256,934 1,190,853 1,148,640 Operating imome 225,319 220,900 205,861 Other income (expense), net 589 (2,074) 5,684 Operating and other income 225,908 218,826 211,545 Interest charges: lung-term debt 104,375 106,850 108,912 Other 9,778 12,525 16,947 Alhmance for borrowed funds used during construction (6,463) (7,847) (8,984)
~1btal interest ( harges 107,690 111,528 116,875 Nct imome 118,218 107,298 94,670 Preferred and preference disidends provided 15,705 16,550 17,611 llalance available for common stock S 102,513 s 90,748 s 77,059 Common shares outstanding (weighted aserage) 44,959 43,144 39,348 i:arnings per share of common stock $ 2.28 s 2.10 s 1.96
. Consolidated Staternents of. Retained Earcings years ended December 31, on thous.udo 1993 1992 1991 Halance at beginning of year $ 192,948 s 174,477 $ 161,143 Net income i18,218 107,298 94,670 Subtotal 311,166 281,775 255,813 Cash dividends declared:
Preferred stock 15,705 14,923 9,476 Preference stock 0 1,953 8,135 Common stoc k 77,169 71,951 61,725 Subtotal 92,874 88,827 81,336 Halance at end of scar S 218,292 s 192,948 s 174,477 The accompanying notes are an integral part of the consolidated financial statements. 21 :- - - - L __________ _ _ _ _ _ _ _ _ _ _ _ _
Consolidated Balance Shqpts
!)cccmher 31, 1993 1992 (in thomandu sissets Propertv, plant and equiprnent, at original cost:
litility plant in sersice 5 3,904,776 s 1,629,727 1,258,159 $ 2,646,417 1,177,294 s 2,452,411 j i ess: an umulated depreciation Nuclear fuel 273,867 270,420 j 220,477 51,190 201,978 68,442 j iess: accumulated amortitation 144,815 182,458 j Construction work in progress lbtal 2,844,642 2,703,111 24,292 25,398 Imestments in electric companies, at equity l 66,060 50,871 Nuclear det ommissioning fund, at (ost Curn nt assets: Cash aml cash equis alents 8,768 3,947 Accounts ru citable 171,098 185,563 A(crued unbilled resenues 29,821 28,564 I nel, materials and supplies, at aserage cost 79,381 91,911 9,7 18 298,808 6,644 'l l 8,649 Prgaid expenses and other I)clerred dt hits: Power wntrat ts 36,275 43,717 Cancelled nuclear unit 19,067 19,067 Nu(lear outage costs 25,524 17,970 Pension and postretirement costs 24,416 10,449 Reilemption premiums 59,116 40,506 26,916 0 Regulatory asset - income taxes, net Other 52,181 241,497 64,? 4 195,983 lbtal assets S 3,477,299 5 3,294,234 Capitalitation and Ilabilities
$ 876,479 $ 840,312 Conunon stm k eqmty Cumulatise preferred stot k:
Non-mandatory redermable series 121,000 123,000 Mandatort redunable a rics 96,000 98,000 lirst mortgage bonds 40,000 611,825 12,497 24,248 Seuage facihty resenue bonds, net 1,200,000 385,000 , Dt1ienturcs linsecured medium-term notes 0 50,000 { Current liabilities: f 2,000 $ 6,800 j i ong term debt / preferred stot k dne within one scar 5 i Notes p.nable 204,151 275,500 At counts payable 144,760 154,251 Interest accrned 25,467 21,497 1Midends pas able 22,696 22,192 27,316 426,410 12,482 492,722 Other i Deterred ( redits: Pow er cont rat t
- 16,275 43,717 Accumulated deferred income taxes 484,796 448,720 Accurnulateil deferred investment tax credits 71,140 75,213 Nuclear deconunissiomng reserse 73,744 57,165 Other 16,958 682,911 24,312 649,127 Conumunents and contingern ies
~1btal capnalitation and liabilities S 1,477,299 5 1,294,214 The accompanying notes are an integral part of the consolidated linancial statements.
22
Consolidated Statements of Cash Flows . years ended December 31, on diousan,M 1993 1992 1991 Cash ihm s f rom operating actis ities: Net income $ 118,218 s 107,298 5 94,670 Ad)ustments to reconcile net income to net cash prmided by operating actisities: Deprecianon 110,074 123,241 121,572 Amortization of nuclear luel 21,816 25,473 19,869 Amortiration of deferred cost of cam elled nudear unit, net 0 22,140 21,112 Other amorti/ation 9,413 2,132 1,696 Allou ante for funds used during construction (6,461) (7,847) (8,984) Deferred income taxes 10,301 17,165 24,476 lovestment tax credits (4,073) (4,273) (4,290) ! (Deferral) amortiration of nuclear outage cmts, net (7,554) 4,901 (22,062) Net c hanges in: Accounts receisah!c and accrued unbilled resenues 11,206 (18,188) (3,519) Fuel, materials and supplies 9,722 (2,330) 12,716 Au ounts payable (9,491) 41,899 (19,510) flate and contrac t settlements (175) (31,363) (44,546) Other current assets and liabilities 16,408 (2,565) 3,079
- Other, net (4,958) (l3,777) (24,5S8)
Net cashprovided by operating acthitics 196,466 264,108 171.69i Cash ihm s prmided (used) by imesting actisities: Plant and nuclear fuel (exduding AFilDC) (251,885) (231,025) (214,213) Capitali<cd itemand side management costs (37,156) (l1,469) 0 Decommissioning fund (15,189) (7,210) (5,696) Imestments in electric companies 1,106 1,836 (1,515) Net cash used byimesting activitics (305,124) (247,868) (221,624) Cash ihm s prmided (used) by linancing artis ities: Issuances: Connnon stock 10,823 68,345 68,800 Preferred stock 40,000 40,000 50,000 inng tcrm debt 815,000 60,000 146,120 lledemptions: Debt retirements (648,625) (123,600) (118,600) Preferred / preference stot L (40,000) (40,333) (50,000) Net change in short-term debt (71,349) 65,200 35,770 Disidends pahl (92,170) (86,184) (79,545) Net cash prmided (uscJ)yinanring actis ities 13,479 (l6,572) 52,545 Net increase (deocase) in cash and cash equisalents 4,821 (l32) 2,612 Cash and cash equisalents at the beginning of the scar 1,947 4,279 1,667 Cash and cash equisalents at the end of the year S 8,768 5 3,947 5 4,279 Cash paid during ihe ycar for: Interest, net of amounts capitalized S 101,720 $ 113,076 s 115,488 Income taxes S 10,105 5 10,095 $ 18,979 i The a< compan)ing notes are an integral part of the consolidated financial statements. t I 23
Notes to Consolidated Financial S,tatements Note A. Significant Accounting Policies I, liasis of Conwlidation and Accounting The consolidated financial statements imlude the actisities of our wholly. owned subsidiaries, Ilarbor Flectric Energy Company and lloston Energy Technology Group. All significant intercompany transauions base been climinated. We follow accounting pohcies prescribed by our federal and state regulators. We are also subject to the accounting and report-ing requirements of the Sc(unties and fichange Commission. The financial statements mmply with generally aca pted accaunting principles. Certain prior period amounts on the financial statements were reclassi6ed to conform with current presentation. L Itevenue itecognition We reconl resenues for electricity used by our (ustomers, but not yet billed, in onler to more closely mat (h res enues uith expenses. L l'orecasted fuel and Purchased Poner Itates f he rate < harged to retail customers for fuel and purc hased jumer allows for all fuel nists, the capacity portmn of some purchased p<mer costs and some transmission costs to be billed to customers monthly using a forecasted rate. The diflerence between actual and estimated costs is included in acmunts receisable on our consohdated balance sheets until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel rates if they find that we base been unreasonable or imprudent in the opera-tion of our generating units or in purchasing fuel.
- 4. Depreciation and Nuclear iuct Amortitution Our phy sical property was depreciated on a straight.line basis in 1991,1992 and 1991 at composite rates of approximately 3.09%,
L 36% and 1.41% per year, resprotisch, based on estimated useful lives of the various classes of property. The cost of decommis-sioning Pdgrim station, our nuclear unit, is culuded from the depreciation rates. When property units are retired, their cost, net of sahage salue, is < harged to accumulated depreciation. The cost of nuclear fuelis amortized based on the amount of energy Pdgrim Station pnnluces. Nuclear fuel expense aho include, an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for the decontamination and decommissioning of the linited States enrichment facilitics used in the production of nuclear fuel. These costs are recmcred from our customers through fuel c harges.
- 5. Allonamejor Iunds Used During Construaion (AlUDC)
AlllDC represents the estimated costs to finance plant expenditures. In acconlance with regulatory accounting, ARIDC is included as a cost of utility plant. Al UDC is not an item of current cash income, but payment is receised for these costs from cus-tomers mer the sersice life of the plant in the form ofincreased resenues collet ted as a result of higher depreciation expense. Our AlllDC rates in 1991,1992 and 1991 were L62%,4.48%, and 6.8 W, respectisely, and represented only the cmt of debt.
- 6. Cash and Cash ! quicalents Cash and cash equivalents are comprised of highly liquid securities uith maturities of three months or less.
- 7. Allonancejor Doubtful Anounts Our accounts receivable are substantially all termerable. This recovery occurs both from customer pay ments and hum the portion j of customer c harges that pnnides for the termery of bad debt expense. Acconhngly, we do not maintain a significant allowance l for doubtful an ounts balance.
L Deferred Debits Deferred debits consist primarily of costs incurred w hit h will be collected from customers through future (harges in accordance with agreements uith our state regulators. These costs will be expensed when the corresponding resenues are receised in onter to appropriat(lv matc h resenues and expenses. A portion of these costs is cur rently being charged to and collected from customers.
- 9. Amortiration of Dinounts, Premiums and itedemption Premiums on Sc(urities We expense discounts, premiums, redemption premiums and related expenses associated uith issuances of securities or refinancing of existing securities in equal annualinstallments over the hfe of the replacement securities subject to regulatory approval.
24 ._.
Note B, Retail Sett:ement Agreements in 1992 and 1989 our state regulators, the Massachmetts Department of Puhhc Utilities, apprmed threegear settlement agrec4 ments relating to our rate case proceedings. These agreements prusided for retail rate increases, accounting adjustments and demand side management program expenditares; 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 Anak sis for further information reltted to these settlement agreements. The settlement agreements did not affect our contract or w holesale power rates charged to other utilities, w hich are regulat-ed by our federal regulators, the Federal Energy Regulatory Conunission. Note C,Inceme Taxes in the first quarter of 199 3 ue prospet tisely adopted Statement of Financial Accounting Standards No.109, Accounting for income Tnes (SLAs 109). This required us to change our methodology of accounting for income taxes from the deferred method to an awet and liabihty approat h. The deferred method of accounting was based on the tn effects of timing differences between imome for financial reporting purposes and tauble income. The asset and liability approach requires the remgnition of deferred in liabihties and assets for the future in effects of temporary ihlferences beturen the carrying amounts and the tu basis of assets and liabihties in ao ordance with SFAS 109 ue rec orded a net regulatory asset of 526.9 million and a corresponding net increase in accumulated deferred income tnes as of December ll,199 3. The regulatory asset represents the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income tnes on our consolidated balance sheet at December 31,1993 indudes s 587.8 million of gross deferred inmme tn liabilitics net of s 10 3.0 million of gross deferred income tax assets. We base approximately $ 19 million of alternative minimum tax carryforwards available at December 31, 1993. The major components of accumulated deferred income tnes are a result of differences between book and tn expenses relating to property, plant and equipment. Deieried income tn expense rellected in our consolidated income statements is incurred w hen certain income and expenses are reported on the in return in different years than reported in the financial statements. Investment tn credits are included in income mer the estimated usclul lises of the related property. Components ofincome tax expense are as follow s: nn 6. mwh I993 1992 1991 Excess tax depreciation mer imok depreciation $ 12,382 s 9,765 5 10,802 Deferred fuel expense (3,142) 2,587 56 Debt portion of allowance for funds used during mostruction 2,114 2,495 2,856 Massac husetts corporate fran hise tax 5,0S9 6,134 7,140 Deferred nuclear outage expense 2,472 (1,558) 7,014 Cost of remmal 3,272 6,904 4,277 Rate and contract settlements 0 10,013 10,196 Municipal property tnes (489) 3,351 3,745 Demand side management programs 3,775 2,978 2,256 Cantelled nuclear unit 0 (4,621) (8,998) Resersal of deferred tnes - settlement agreement, net (19,231) (23,000) (13,000) Adjustment of prior year income tax au rual (2,154) 4,1 14 2,563 l l Call pri miums on refunded bond issues 5,821 1,029 (288) Trust mntributions - postretirement benefits 3,451 0 0 Other (3,057) (3,828) (5,395) Subtotal defer red income tnes 10,303 16,383 21,224 Current int ome tn expenst 28,711 (385) (1,823) Imestment tax credits (4,073) (4,273) (4,290) Prmision for inmme tnes 34,941 11,725 17,111 Tues on other income: Current 1,205 (2,348) 405 Deferred 0 782 1,252 Subtotal 1,205 (1,566) 1,657
'Ibtalincome tn expense $ 36,146 5 10,159 s 18,768 25
m , _ . - - . _ .._ ._ 7 The effective income tax rates reflected in the consolidated iinancial statements and the reason, for their <hfrerences from the
' statutory federal income tax rate are explained beksw:
- 19M 1992 1991 L Statutory tax rate 35.0 % 34.0 % 34.0 % -
State income tax, net of federal income tax benellt 4.2 3.9 4.1 Imestment tax credits _(2.6) (3.6) ( 3.8) Municipal property tax adjustment (0.6) (1.6) (1.6)
- Adjustment of deferred taxes on cancelled nuclear unit - 2.7 -
, Reversal of deferred taxes settlement agreement '(13.0) - (19.6) .. .(11.5)
Federal tax benefit of mandated payments from settlement agreements - (6.2) (3.3) Other 0.4 (0.9) -(1.4) , Effective tax rate 23.4% 8.7% - 16.5 % Note D. Estimated Future Costs of Disposing of Spent Nuclear Fuel and Hetiring Nuclear Generating Plants The existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995.
' We have a request for a license amendment pending before the Nuclear Regulatory Commission (NRC) to allow mothlication of -
. the storage facility to pnnide sullicient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. The NRC is reviewing our request and we expect approvalin 1994. At that time we willinitially modify the facility to pro-vide spent fuel storage capacity through approximately 2003. It is the ultimate responsibility of the tinited States Department of Energy (DOE) to permanently dispose of spent nuclear fuel as required by the N_uclear Waste Policy Act of 1982. We currently pay a fee of 51.00 per net megawatthour sohl from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges.
When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant, During rate pr6 ccedings we prmided our regulators a 1991 study documenting a cost of s 328 million to decomminion the plant. The study is based on the " green lichr* method of decommissioning, w hich provides for the plant site to be completely restored to its original statei We are expensing these estimated decommissioning costs over Pilgrim's expected service life. The.1993 expense of approx-imately s 13 million is included in depreciation expense on the consolidated income statements. We recche recovery of this 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 for decommissioning and related expenses. The net earnings on the trust funds, w hich are also restrioed, increase the nuclear decommissioning fund balance and nuclear decommissioning reserve, thus reducing. the amount to he collected from customers. The 1991 decommissioning study has been partially updated for internal planning . purposes to evaluate the potential financial impact of long-term spent fuel storage options resulting from delay s in DDE spent fuel I rt moval on the estimated decommissioning cost. The partial update indicate $ an estimated decommissioning cost of approxi.mately
$400 million in 1991 dollars based upon a revised spent fuel removal schedub an I utilization of dry spent fuel storage technology.
We will continue to monitor DOE spent finel removal schedules and developments in spent fuel storage tet hnology along with . their impact on the decommissioning estimate. We are also an investor in tuo other domestic nuclear units.110th of these units recche through the rates charged to their customers an amount to cover the estimated cost to dispose of their spent nuclear fuel and to retire the units at the end of their useful lives. We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in llarnwell, South Carolina. As a result of developments u hich have occurred pursuant to the 1 ow Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost, We ha>e access to the south Carolina site through July 1994, but do not presently heliese that disposal site access will be pro.
' vided after that date. Although legislation has been enacted in Massachusitts establishing a regulatory method for managing the state's LLW including the possible siting, licensing and construction of a LLW disposal facility within the state, it appears unlikely '
that $uch a facility will be constructed in a timely manner. Pending the construction of a disposal facility within the state or the
. adoption hy the state of some other ! LW management method, we continue to monitor the situation and are investigating other available options, including the powihility of on+ site storage.
Note E. Cancelled Nuclear Unit
. In May'1982 we hegan to expense the cost of our cancelled Pilgrim 2 nuclear unit mer approximately elesen and one-half years in
;accordance with an order received from state regulators. We did not expense any of these costs in 1993. Instead, the remaining
' balance of approximately 519 million at December 31,1993 and 1992 will be expensed in 1994 and/or 1995 as approved by our state regulators in our 1992 settlement agreement.
26 j
l l Nate F. Capital St:ck and indebtedness ; Capital Stod December 31, l Clullan in thousan.h, emy. pi r share annuntsj 1991 1992 1991 I Common stock equity; Common stoc k, par salue 5 I per share, 100,000,000 shares authorized; 45,129,227, 44,763,05 5 and 42,047,356 shares issued and outstanding S 45,129 5 44,763 5 42,047 Premium on common stock 612,653 602,196 536,567 Retamed earnings 218,292 192,948 174,477 Surplus invested in plant 405 405 405
'1btal common stoc k equity S 876,479 5. 840,312 s 753,496 Cumulative preferred stock:
Par value s 100 per share,2,410,0(K) shares currently authorized; issued and outstanding: Non-mandatory redeemable series: Current Shares Redemption Series Outstanding Price / Share 4.25% 180,000 $ 103.62 5 5 18,000 s 18,000 5 18,000 4.78 % 250,000 s102.800 25,000 25,000 25,000 7.75 % 400,000 40,000 0 0 S.25 % 400,000 - 40,000 40,000 0 8.SS% 0 - 0 40,000 40,000
'fotal non mandatory redeemable series 5 123,000 $ 123,000 $ 83.000 Mandatory redeemable series:
Current Shares S( ries Outstanding 7.27% 480,000 S 48,000 $ 48,000 5 50,000 8.00 % 500,000 50,000 50,000 50,000
~Iotal mandatory redeemable series 98,000 98,000 100.000 ,
Less: due suthin one year 2,000 0 0
'Ibtal mandatory redeemable series, net S 96,000 5 98,000 s 100,000 Cumulatise preference stock:
Par value 51 per share, 8,000,000 shares authorized; none currently issued and outstanding Non-mandatory redeemable series: s 1.46 series 5 0 s O s 2,675 Premium on s 1.46 series 0 0 35,658
'Ibtal preference stock $ 0 S 0 s 38,333 6
Dividends Declared per Sharc Common stoc k $ 1.715 s 1.655 5 1.595 ' Preferre<1 st ock: 4.2 5% series S 4.253 s - 4.250 $ 4.250 4.78% series 4.785 4.780 .4.780 7.27% series 7.270 7.270 7.270 7.75% serics 5.707 0 - 8,00% neries 8.000 8.000 1.3 8,2 5% series 8.250 5.2 18 S.S8% series 2.220 8.880 8.880 Preference stock: S t .46 series - S 0 s 0.365 5 1.460 i Stated rate auction preference sto(k 0 0 6.900 j 27 i
i Indebtedness December 31, I (douars in thbusanan 1993 1992 Long-term debt: I First mortgage bonds: Interest Series Rate Maturity I 4.750 % 1995 $ 0 $ 25,000 J 6.125" 1997 0 40,000 K 6.375% 1998 0 50,000 L 9.000 % 1999 0 50,000-M 9.375 % 2000 0 60,000 N 8.125 % 2001 0 75,000 S Variable 2002 25,000 25,000 Q 9.750 % ^ '10 3 0 59,375 R 10.950% 0 44,250 l' 9.250 % 0 60,000 LI 10.250 % 2014 15,(XX) 15,000 W 9.500 % 2016 0 135,000 lbtal first mortgage bonds 40,000 638,625 Less: due within one year 0 6,800 Total first morteace bonds, net S 40,000 5 631,825 Sewage facility revenue bonds $ 36,300 $ 36,300 Less: funds hehl by trustec 3,803 12,052 Total sewace facility resenue be,_ act $ 32,497 S 24,248 Debentures: 8.875%, due 1995 $ 100,000 $ 100,000 5.125%, duc 1996 100,000 0 5.700%, duc 1997 100,000 0 5.950%, due 1998 100,000 0 6.800%, due 2000 65,000 0 6.050%, due 2000 100,000 0-6.800%, due 2003 150,000 0 9.875%, due 2020 100,000 100,000 9,375%, due 2021 125,000 125,000-8.250%, duc 2022 60,000 60,000 7.800%, duc 2023 200,000 0 Tbtal debentures $ I,200,000 -5 385,000 linsecured medium-term notes 5 0 $ 50,000 Short-term debt: Notes payable: 11ank loans 5 106,501 s 162,500 Commercial paper 97,650 113,000 lbtal notes payable S 204,151 $ 275,500 28
- 1. Common Stock c Since December ll,1990, we issued the following shares of conunon stock:
Number 'lotal Premium on on ihmn.uulo of Shares Par Value Common Stock Balance December 31,1990 38,998 5 194,993 5 114,822 Diudend reinvestment plan 449 2,181 6,844 Change in par value of common stock (a) 0 (157,727) 157,727 New hsue 09 2,600 2,600 57,174 llalance December 31,1991 42,047 42,047 536,567 Dhidend reinvestment plan 416 416 9,658 New issue N 2,300 2,300 55,971 llalance December 31,1992 44,763 44,761 602,196 Dhidend reinvestment plan (d) 366- 366 10,457 Italance December 31,1991 45,129 $ 45,129 s 612,651 (a) In November t991 nur Armlen of Organintion were amendnt to increase authoriecd oinunon stock hom 50 milhon to iou nullion shares and reduce the par ulue from 55 to 51 per common share. (b) We uwd the net prwceds of tlw 1991 common stock inuance to retire 5 5 5 rmilior of scrica X,11% Grst mortgage Imnds. (c) We used the nei pnueds of the 1992 mmnmn sux k iwuance to reduce short tcrm debt. (4 At Den mher 11,199 L the remaming authorimi comnmn shares resenn! hit future swuance under the Dm. lend Reimestment and Conunon h k Pusch.w Plan wcre 815.170 shares.
- 2. Cumulatise Non-Mandatory Redeemable Preferred and Preference Stmk in June 1992 we issued 400,000 shares of 8.25% cumulati e non mandatory redeemable preferred stock at par. The simk is redeemable at s 100 per share plus accrued dhidends beginning in June 1997. These shares were sold in the form of 1.6 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 s1.46 series cumulathe non-mandatory redeemable preferente stock.
In May 199 3 we issued 400,000 shares of 7.75% cumulathe non-mandatory redeemable preferred stock at par. The stock is redeemable at s100 per share plus accrued dhidends begmning in May 1998. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We u,cd the proceeds of this issue to fully retire the 8.88% series cumulative non-nundatory redeemable preferred stock.
- 3. Cumulative Mandatory Redeemable Preferred Stmk The 480,000 shares of our 7.27% sinking fund series cumulathe preferred stock are currently redeemable at our option at s104.36. The redemption price declines annually eac h May to par value in May 2002. In May 1993 the stock became subject to sinking fund requirements to retire 20,000 shares at s 100 per share plus accrued dhidends each year through May 2002. In 1992 we purchased 20,000 shares at a thscount on the open market which satisfied the mandatory sinking fund requirement for May 1993. Iteginning in 1993, we base the non cumulatise option each May to iedeem additional shares, not to exceed 20,000, for the sinking fund at 5100 per share plus accrued dividends.
We are not able to redeem any part of our 500,000 shares of s 100 par value 8% cries rumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 200 at t 100 per share, plus accrued dividends.
- 4. long-krm Debt Substantially all our property, plant, equipment, materials and supplies are subject to tien under the *erms of our Indenture of Trust and first Mortgage dated December 1,1940, and its supplements. Currently only the outstanding Series S and Li first mort-gage bonds are subject to the terms of the indenture.
The aggregate principal anmunts of our first mortgage bonds, debentures, and sewage facility resenue bonds gncluding sinking fund requirements) due in 1994 and 1995 are 50 and $100.6 million, respectively, and $101.6 million per year in 1996 through 1998. Our first mortgage bonds, Series S, adjustable rate duc 2002, paid interest at 9.2% per year for the period January 15,1993 through January 14,1994. The rate is adjusted annually and is based upon the ten year constant maturity Treasury rate as published by the Federal Reserse Hoant. The interest rate for the period January 15,1994 through January 14,1995is8.2 %. In September 1992 we issued 560 million of 8.25% debentures uhich mature in September 2022. The debentures are redeemable at prices decreasing from 103.78% of par beginning in September 2002, to 100% of par beginning in September 2012. We used the net proceeds from the sale to reduce short-term debt. In October 1992 we redeemed the rennining balance of $45 mdlion Series X first mortgage bonds. In February 199 3 we issued $65 million of 6.8% debentures due in 2000. We used the proceeds of this nsue to reduce short term debt. These debentures are not redeemable prior to maturity. 29
-- . . .~ . -
o
- i
. In March 199 3 we hsued 5650 million of ddientures and usett the proceeds to retire ten of twelve outstamimg series of firt t mortgage homh and trduce short term ddit. The debentures were issued in live separate scrics with interest rates ranging from 5.125% to 7#6 and matoring betwcen 1996 and 2021. The 5 l/8%lebentures duc 1996, 5.70% duc 1997, 5.95% duc 1998 aml 6.80% due hKB are not redermable prior to maturity. The 7.W:6 debentures duc 202 3 are first redermable in Man h 2001 at a redemption ju itr of 101.7 3%. 't he redemption price decreases annually eat h Man h to par value in March 2013. There is no sinking fund requirement for any series of the debentores, in Augmt 1993 we iu.ued $ 100 mi'llion of 6.05% debentures due in 2000. We owd the proceeds funn this sale to reduce shot t term debt, 'lbese debentures a.ie not trdremable prior to maturity and hase no sinking fund requirements.
We redeemed 550 milhon ol 9.65% medium term notes in September 1992 and $ 50 million of 9.75% methum term notes in September 199 3. 5, Senage f acility itesenue Bornis in December 1991, Ilas bor I:lec tric I:ncrgy Company (Ilhlf h a w holly am ned subsidiary, issued 5 36.3 million of long. term sewage f.u ility revenue bomk The bomb are tatewmpt, subjei t to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. The weighted ascrage interest rate of the honds is 7.3% A portion of the proceeds from the bomb was used to retire s21 million of short term seuage f.uility revenue bomb at maturity. The remainder of the procceth, a hich h on deposit with the trustre, h being used to finance the comtruction oflif I C's permanent substation located on Deer bland (in Boston Haibor) awl to fund an amount u hich mmt remain in rescrse with the trustec.. If iti!EC shoubt have insullkient funds to pay certain costs on a timely bash or be unable to mcci certain net worth requirements, we uoubl be required to make adlitional capital contributions os Imns in the subsidiary up to a raaximum of 57 million.
- 6. Simrt-lerm Dcht We base arrangements with < crtain banks to prmide short. term crecht on both a conunitted and an uncommitted and as asailable basis. We runently base authority to iwuc up to $150 million of short-term debt.
We base a 5200 nullion revohing credit agicement with a group of banks. This agreement h intemled to prmide a standby . source of short.tcim bornmings. Ilnder the ternn of this agreement we are required to maintain a common equity ratio of not less than Wu at all times, Conunitment feen must be paid on the unused portion of the total agreement amount, Information iegardmg our shott ictm borrow ings, comprised of bank loam and conuncreial paper h as follow s: oh..u.au,t a ,nwo 1991 1992 1991 Maxinuun short-term borrowings $ 320/A)0 $ 114,998 5 324,400-Wrighted ascrage amount outstandmg $ 220,149 5 2 H,286 5 221,481 Weichted ascraec interest rates, culmiing t ommitment fees 3.4 % 4.1% 6.4 % Noto G. fair Value of Securities The following metho<h and awumptions ucre med to estimate the fair value of c.u h class of sceuritics for w his h it h prat ticable to estimate the salue: Nuclear Jewmmissioningfund The lair ulue of 570,I million h based on quoted mar ket pris es of securities held. Cash and sash equhalents 'Ihe car rying amount of 58.8 rndlion approximates fair salue due to the short term nature of these securities. Mandatory redeemable eumulative prefered stock,jirst mortgage bonds, wnagejatility resenue bands and debentures. The fair salues of these securitics are b.wed upon the quoted market prices of similar inues. Carrying unounts and fair values as of ' December 11,1991 are as folkm s: Carrying . Iair On thouundo A mount %lue Mandatory redeemable cumulatisc preterred sioi k 5 98,000 $ 105,915 first morigage bomb 40,000 44,132 Scwage facility resenue bomb 16,300 40,528
- Debentures 1,200,000 1,237,924 30
Note H. Csmmitments and Contingencies
- 1. Capital Commitments At December 31,1993, we had estimated wntractual obligatiom for plant and equipment of approximately $71 million.
- 2. Lease Commitments We have leaws for certain facilities and equipment. Our estimated minimum rental conunitments under both noncancelable leases and transmission agreements for the years after 1993 are as follow s:
On thouun<l9 1994 s 27,375 1995 23,878 1996 21,299 1997 19,217 1998 17,969 Years thereafter 139,474 Total s 249,212 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 transmission agreements for 199 3,1992 and 1991 was s 30 million,5 30 million and 5 3 3.5 million, respectiscly, net of capitali/ed expenses of s 5 million, s 5 million, and s4.8 million, respectisely.
- 3. flydro-Quebec We have an approximately 11% equity ow nership interest in two companies which own and operate transmission facilities to import cledricity from the Hydro Quebec system in Canada, which is induded in our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our un n share, the total obligations of those participants uho do not meet certain credit criteria and are compensated accordingly. At December 11,1993, our portion of these guarantees was approximately $22 million.
.l. Dmkee Atomic Liectric Companr In February 1992 the Board of Directors of Yankee Atomic Electric Company (Yanker Atomic) decided to permanently discontin-ue power operation of the Yankee Atomic nuclear generating station and, in time, decommission that facility. We relied on Yankee Atomic for less than one pen ent of our system capacity. We base a 9.5% stosk imestment of approximately $2 million in Yankee Atomic. .; In 1993 Yankee Atomic receised approval from federal regulators to continue to collect its imestment and decommissioning wsts through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and msts of decommissioning is approximately $ 3 3 million as of December 31,1993. This estimate is recorded on our consolidated , balance sheet as a power contract liability in deferred credits. An offsetting power contract regulatory asset is included in deferred l debits as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement. L Nuclear Insurame The federal Price- Anderson Act currently provides 59.4 billion of financial protection ' for public liability claims and legal costs arising from a single nuclear related accident. The first 5200 million of nuclear liability is covered by commercial imurance. Additional nuclear liability insurance up to approximately 58.8 billir,n is prm hled by a retrospectise assessment of up to $75,5 million per incident lesied on each of the 116 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 insuranc e amount may change as new commercial nuclear units are licensed and existing units give up their licemes. In addition to the nuclear liability retrospective assessments, if the sum of all public liability daims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional fise percent of the maximum retrospective assessment. We base purchased insurance from Nuclear Electric Insurance I imited (NEIL) to cover some of the costs to purchase replacement power dnring a prohmged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or deconmiissioning of our utility property resulting from cmcred incidents at Pilgrim Station. Our maximum potential total assessment for losses u hich occur during current policy years is approximately s 14.6 million under both the replacement power - and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactise 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 hdiese are hkely to result in an assessment. 31-
l
- 6. I.itigation In Man h 1991 ne ut re named in a law suit alleging discriminatory employ ment prat tices under the Age I crimination in 1 mplos ment Art of 1967 o>nu ining 46 cmplmecs alTerini by our 198S rnlurtion in ton c. I egal rounsel is sigoroudy defending this c ase, lla cd on the information ptrsently asadable we do not npn t that this litigation or certain other legal matters in w his h we are cut renth imohol will lme a material impai t on our finam ial < ondition. I hmner, an unfasoiable decision onlered against us oiul I h.nc a matenal impat t on quarterly earnings
- 7. Ilivardom it' aste State irgulatiom resisal in 1991 iequire that properties w here releases of haranlous materials ou urrni in the past he f urther cleannt up acronhng to a timetable descloped by the Mawat husett.s I)cpartment of I mironmental Protection, We are currentiv naluating the [witential cost.* associatni with the ileanup of site *, w here ue base been i lentdini as the im ner or operator. There are uncer tiuntics assos iatnl with these potential costs due to the compInitit s of cleanup in hnology. regulatory requirements and the particular i haracteristi,s of the ihnerent sitet we also continue to fat e powihle liahdity as a potentially responsible party in the (Icanup of < crtain other multi party ha/anlous naste sites in Massai husetts and other states At the majority of these other sites we are one of many potentiall) Irspomihle parties and our alleged share of the responsibility is a small percentage. We do not npn t any of our potential (leanup liabilitics to hase a material impact on financial conihtion, ahhough provisions for ileanup costs conhl hase a materialimpait on quarterly earningt Note 1, Pensions, Other Postrctirement and Postemployment Benefits I. Pensiom We h.ne a nonconn shutory funded ictiicmen'. plan, with certain features that alhm soluntars contnhutions. lienefits are based
, upon an emphnee's years of sen h e and mmpensation during the last ycars of employ ment. Our funding policy is to contribute ca(h year an amount that is not less tlun the minimum required mntribution under loieral law or greater than the maximum tax dntm oble amount. Plan assets are primarily njuitics, bonds, insuram e contracts and real estate, Net pension cost induded the folhming components: on ihous.nu to 1991 1992 1991 Curn nt ser sit e rost - benellts carned $ 11,714 s 10,681 s 8,567 l Interest < mt on pro}n tnl henclit obligation 11,181 12,287 29,817 I Actual return on plan assets (44,470) (21,2H1) (60,873) I Net ann.ru/ation and defenal ~ 8,528 (I1,549) 26,811 Net pcmion mst m 5 8,971 s 6,140 5 4,322 on in au nolanu w nh an agnrnwn u nh our sme o pl.a.n s, m ileiro nt one nei pon+n com in i m .on.1 the annual fun.hng .unounts anil soll enoser l l thr se' n olt lr i In l usta inn f s t es ol fighc. M t ls TMbin ie s%IN et s trotol as osjtt nw u rt r apltioslinah l% $ 511u!bstn in t D t Ani! %u lu 19'd anel lWI . I We used the folhm ing assumptions for cah nlating pension rost: 1991 1992 1991 l bronnt raic 8.25 % 8.25"o _9,00 % Expected long term rate of return on assets 10.00 % 10.00 % 10.00 % Compensation increase rate 4.50 % 4,50 % 4.50 % We (hanged our discount ate assumption to 7.0% for (alculating pension ont cliertise january 1994.
'I he plan's furnini status at 1)n ember 11,1991 and 1942 w as as follows:
on thousanilo 1993 1992 Actuarial present sahte of hentlit ohhgations: Accumulated benefit oblication, int ludine sestnl honefits of 5 384,150 and s 122,N 16 $ 400,895 s i19,035 l'lan anets at f air salue 5 194,211 s W2,407 Projected obligation for scrsit e rendered to date (509,661) (418,312) l'rojected hencilt ohhgation m est ew of plan awets (l15,428) (25,905) linrrcogni/cd prior wrsic e mst 8,1 19 8,817 linrecogni/ed net (gain) lou 75,352 (6,810) linteroeniecd net oblication 9,9 12 10,866 Net pcmion habihts % (22,005) $ (11,(IU) We nu d the foihming assumptiom for cah ulating the plan's ) car end funded statm: 1991 1992 1% ount ratc 7,00 % 8.25 % l {omp nsation im icase rate 4.50 % 4.50 % ! 32
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l'
- 2. Other ['ostretirement Bentfits In adtlition to pension benefits, we also t urrently panide health care and other henefits to our retired employees u ho meet certain age and years of sersice eligibihty requirements. I Ifedhe january 1993 we adopted Statement of]inancial Acconnling Standanh h 106, Employer's Ac counting for Pmtretirement Ilenefits Other Than Pensions (SFAS 106). This requires us to record a liabili.
l ty during the working years of employees for the espected costs of providing their postrelitenient benelits other than pen Ams
- (PilOPs). Prior to 1993 our policy was to revird the cost ofI'llOPs when paid. Our transition obligation on January 1,1993 was approximately $ 18 i rnillion, whi(h we elected to recognl/c mei 20 years as permitted by SI AS 106. Our total cost of PilOPs mnler SI AS 106 in 1993 was apprmimately $28 million, an inacase of approsimately $ 18 million mer costs incurred under our prior met lHHI of accounting for PllOPs. ()ur 1992 settlernent agrectnent provides us with a phasc in of a portion of the increased (osts and allows us to defer tlie a:Iditional costs in excess of the phase'in amounts to the extent that ue futid an esternal trust. In
()ct ember 199 % we dep<nited $ 18 million on a tax dedut tible basis into external trusts for the payment of PllOPs. Accordingly, in 1993 we recorded an expense OIapprotunately $ 16 tuillion, reflecting the anmunt of cost recmcry from custonn ts, and deferred approximately $ l 2 tuillion for future rennery. % capitali/cd apprm mately 19% of these costs. Pmtretirernent benefits iost consisted of the folhming in 1991 bn thousantle Current sersit e (mt - henefits carned $ 4,151-Interest cost on transition obhgation 14,286 Amorti/ation of tramition obligiiin 9,15i Net postretirement benefits cost $ 27,788 We used an SJr4 wrighted aserage discount rate and 4.5% rate of mmpensation increase assumption for calculating the tran. sition ohhgation and the 19H postretirement benefits cost. Our espectediong term rate of return on assets is 93rS We aho assumed a 12.W heahh care cost trend rate. I Ifectise January 1,1n94 we changed the discount and heahh care cost trend rates to 7.0% and 9.0%, respectisely, in order to more accurately estimate our future benellt pay ments. Ihe heahh care cost trend rate k assumed to decrease by one percent each year to 5% in 1998 and wars thereafter. Changes in the health care cost trend rate will alfcct our mst and obligation anmunts. lur example, a one percent increase in the rate wouhlincrease the total sersice and interest costs in 19H by apprmimately 16% and wouhl increase the an umulated obbgation at December 11,199 3 by apprmimately 13% The postretirement benchts program s funded status at December 11,1994 was as folkms: on A mamio Trust aucts at lair salue $ 18,016 Accmnulated obligation for senice rendered to date from: Itetirecs $ (75.216) Actiw or.ployces eligible to retite (64,880) j Actise emphnees not chgible to retire (73,285) (213,38I) At cumulated benefit obligation in rstess of trust assets (195,165) linremgnized loss 21,497 Unrecogniini net obligation 173,868 Net pmtretirement benelits liahihts 5 0 The trust aswts mmist of money market fumb at December H,19H.
- 3. Mtemployment Benefhs Statemem of Fmancial Acmunting Standards No. I12, F.mployers' Acmunting for Postemployment llenclits, aill be effecthe for the first quarter of 1994. This statement uill require us to remrd a liability computed on an actuarial basis for the estimated emt of )
pnniding pmtemploy ment benelits. Postemploy ment benefits pnnhied to former or inacthe employees, their beneficianes and i nnered dependents im lude salary continuation, sewrance benefits, disabilitprelated benefits (including workers' compensation), I job training and counsehng and mntinuation of heahh care and hfe imurance emerage. We currently recogni/c the ont of these benefits primarily aulaims are paid. We do not anticipate a material effect on net inmme from adopting thintatement, Note J.New Accounting Pronouncement We will adopt Statement ofl'inamial Accountmg Standards No. I15, Accounting for Certain lmestments in Debt and Equity Seenrities, in the first quarter of 19M. This statement may require us to das .ify the investments in our Ludear deconunissioning fund on our comolidated balance sheet based on how long we interal to hohl the indhidual securities. These imestments may be classilled as "asailable lor sale" and we mas aho be required to report any unrealierd gains and losses on the imestments as a separate component of shareholders' cquig. We do not espect the adopnon of this statement to hase a material effect on sharehohlers' equity. 33
Note K. Long-Trrm Power Contracts I, long-krm Contractsfor the Purchase of Electricity We purt base electric power uraler sescral long-term contracts for which we pay a share of the generating unit's capital and fixed operating costs through the contract expiration date. T he total cost of these contracts is includeel in purchased power expense in our consolidated income statements, information relating to these contracts as of December 31,1993 is as follou s: i proportionate share (in thousands) 1993 1993 Interest Debt l Cont ract linits of Minimum Portion of Outstanding f Expiration Capacity Purchased Debt Minimum Through Cont. Contract Date % MW Service Debt Sersice Exp. Date Canal unit 1 2001 25.0 142 5 .781 $ 314 $ 2,118 l Mass. flay Transportation Authority 2005 100.0 35 th) <h) (b) Connecticut Yankee Atomic 2007 9.5 56 2,579 1,670 15,808 Ocean State Power , Unit i 2010 23.5 65 5,323 3,948 22,747 Ocean State Power - limt 2 2011 23.5 65 4,422 3,376 19,401 j Northeast I nergy Assotlates to (c, 219 to (o to l.'Energia 2013 73.0 64 <di (d) hb
'lotal 646 $ 13,105 5 9,308 5 60,164 ea) I bc Northeast I nergy Amiates vintrac t represents 6.4N of our tot.d aptem generanon < apahihty. I he remannng units h3tal ah n c reprnent i 2.tA in uital.
l (h> We are requirol to pay the girater of 5 2DM per kiloa att.ycar or % of the New I ngland Pou er Pool capahdity rceponahd;ty adjustment (harge up to u L0n per kik u att gear timn the <juahtied < apaoty n urrently rated at ? I 6MW) plus int remental operating, maintenance and fuel rosts. The total iharp s for this contra < t in IvH were apprmimaicly 52 nulhon. O> We part ha c appioxnnairly 7;. W of the energy output of this unit under tuo contracts. One contract reprnents i MMW and espires in the ycar 2nli The other contrat t is for HMW and expirn in 2nt0. We pay for this energy based on a prac per kWh attually rncised. We do not pay a pro-portionate share of the uniNapital and fned operatmg mstt The total thargcx for these mntra< ts in 19H w crc approximaicly 5 i 16 mdlion. (d) I he t 'l nergia mntra,i started in Mart h 199 L We pun base 7 W of the en< igy output of this umt. We pay for this energy hwil on a pri(r per LWh ; at tually rccciu d t he total < hargo under this mntract for 19H wtre apprmimau ly 5 I 5 mi! bon. Our total fixed and variable costs for these contracts in 1993,1992 and 1991 were approximately 5225 million,5217 mil-j hon aml $ 154 million, respectively. Our minimum thed pasments under these contracts for the ) cars after 1993 are as follow s: (in thomando 1994 -s 69,432 1995 72,418 1996 75,176 1997 71.147 1998 72,429 Years thereafter - 725,236 Total 5-1,086,038 lotal piesent salue 5 558,600
- 2. l.ong-krm Pooer Sales in addition to our power sales to four wholesale customers, we sell a percentage of Pilgrim Station \ output to other utilities under
-long term wntracts. Information relating to these contrac ts is as follon s:
Contract Expiration Units of Capacity Sohl Contract Customer Date % MW Commonucalth I lectric Company 2012 11.0 73.7 Montaup 1:lectric Company 2012 11.0 73.7 Various municipalities 2000(a) 3.7 25.0 Iotal 25.7 172.4 m subin i to ernain 4.1,ust ment t llnder these wntracts the utilities pay their proportional share of the costs of operating Pilgrim Station and awociated trans. mission fatihties. These costs intlude operation and maintenance expenses, insurance, local taxes, depreciation, deconunissioning and a setur n on capital. 34
l l l To the Stockholders'and Directors of Boston Edison Company we hase audital the at a,miunying consoli<latal balance sheets of thiston blison company and subsidiaries ohe company) as of Dn ember 31,199 I aml 19H anil the relatal consoliilatal statements ofinunne, n:tained earnings an<l cash Il<m s for eat h of the three ycars in the perioil ended De<cmher 31,1991. I hese finant ial statements are the responsibility of the company's manage- , ment. Our responsibility is to cyucss an opinion on these financial statements basal on our ambts. l We nonducted our ambts m acconlance with generally a(ceptal awhiing stanilants. 'lhose standants rnluire that ue plan l and perfonn the auth: to obtain reasonable assuranic about whether the unancial statements are free of material mintatement. An l aniht in< lmics exanoning, on a test basis, esiden(c supporting the anuounts and diulmures in the financial statements. An audit I also in(Imles auc5 sing the at c,unting prinoples usal and signific ant estimates made by management, as well as esaluating the mer-all knancial statement presentation. We beline that our au< hts poni<le a reasonable basis hir our opinion. In our opinion, the ainsolnlated financial statt ments n ferrnt to abmc present fairly, in all material respects, the financial pmioon of the compam as ofI)ccomber 11,1991 and 1992, and the (onsolalatal results ofits operations anil its cash now
- for cat h of the thice scars in the perioil emini December 11,1991, in conformity with generally acceptol accounting principles.
4 , Ibton, Massachusetts January 25,1994 I l 1 I l l 35
Selected Consolidated Financial Statistics (Unaudited) Quarterly Financial Data on tin,usan.ls, nupt .arning, per shang Italant e Asailable 1 arnings Operating ( 1perating Net for Conunon Per . share of Rnt nues income incorne Stot k Conunon Sto(.k (*) 1991 lirst quarter s 154,752 s 41,721 $ 15,452 $ 11,177 5 0.25 set and quarit r 146,074 49,282 22,S29 19,125 0,43 Ihinltjuarter 416,021 96,119 70,015 66,052 1.47 luurth quarter 145,101 17,997 9,922 5,959 0.13 1992 l'irstquarter s 343,505 5 41,913 s l l,S l 6 $ 9,551 5 0.21 Secon l quarter 100,566 12,629 4,951 N52 0.02 'thiniquarter 408,255 100,890 71,698 69,591 1.60 Itourth quar ter 159,427 45,451 14,S il 10,750 0.24 (4) Bael nra.n the uophint aarage number of omunein harn ounuminig sh. ring the quarter. ()ur electri(its sales and revenues are seasonal in nature, with both heing louer in the spring and fall seasons. Quarterly carnings for 1991 relin t a i hang- in the months for w hkh (ertain customers ucre hilled at higher rates as mandated h) our state regulators. These customors wen. hdleil at these higher rates in July through ( h tohcr in 1992 and in June through September in 199 3. Ihc clunge m hilling increased sn ond quarter cainmgs and reduced fourth quarict earnings by approtimately $0.21 per share in 1991. Quarterly Stock Data i ollow ing are the icpm tal high ami lou sales prices or our (onunon stot L on the New Wrk stot L is hange as reported daily in the ll;llNrrect fournallor cat h of the quarters in 199 $ and 1992 and the disidends declared per share during each of those quarters: 1991 1992 < llich Iou I)isidends liigli 1ow I)ividenils lirst <purter $ 10 I /2 s 26 1/8 5 0.425 $ 245/8 s 22 1/8 5 0.410 Second quarter 10 7/M 27 7/N 0.425 26 22 1/8 0,410 I hird quar ter 12 5/S 29 1/4 0.425 26 7/S 24 7/S 0.410 fom th quat ter 42 I/4 27 7/8 0.440 28 l/4 24 1/4 0.425 3G
Selected Consolidated Operating Statistics (Unaudited) 1991 1992 1991 1990 1989 Cap.xity - M\% New limton Station 760 760 760 760 760 l'ilgrim Station 670 670 670 670 670 My stic Station 1,006 1,005 1,015 1,014 1,018 W.l!. Wyman Unit 4 36 36 lb 36 36 lct turbines 283 2S1 281 281 273
'lotal 2,755 2,752 2,762 2,761 2,757 Contra (t pur(liases 9 18 1,157 1,293 924 1,102 Contrac t sales (283) (303) (293) (173) (171)
Net capabilitv at scar-eml 3,410 3,606 3,762 3,512 3,688 Net (apability at peak-MW 3,663 3,587 3,695 3,505 3,483 Capability respon ibility to NI: POOL at peak-MW 3,190 3,196 3,311 3,393 3,443 lilison territory: llourly peal-MW 2,662 2,545 2,652 2,548 2,626 1.oa:l factor 60.5 % 62.5 % 60.096 62.2 % 61.4 % Generating station economy: (llTU/ net LWh) 10,345 10,234 10,331 10,403 10,309 Aurage emt of luel (Company ) - c per million llTLI: Iossil 250.42 246.69 240.18 255.51 254.56 Nuc lear 50.67 52.18 56.18 59.05 56.79 Composite 162.02 166.93 I SO.49 191.48 223.86 Capabihty (net LWp hmil 84 % 819u 81 % 81 % 82% Nuilcar 16 % 19 % 19"6 19 % 18 % Generation (system LWh exclu< ling intenhange): fussil 68 % 69 % 70 % 72 % 87% Nm lear 32 % 31 % 30 % 28 % 13% litility plant 0 in 000's): INpemlitures 247,394 213,621 202,589 240,902 234,253 Retirements 34,147 34,036 30,333 27,180 14,042 Accumulate <l ilepret tation 1,258,359 1,177,294 1,097,991 1,015,371 950,298 Depreciable plant 3,841,752 3,567,160 3,488,269 3,277,616 3,130,011 Number of employees at year-eml 4,404 4,540 4,6 37 4,738 4,686 q l
,i 1
37
Selected Consohdated Sales Statistics (Unaudited) 1991 1992 1991 1990 1989 Ilectric energn (k fl'h in thouwnds) . hour (cs (systcru output): Generated 9,787,092 11,679,824 10,602,110 12,744,2 IS I1,679,060 Pun hased 5,126,224 5,449,225 4,651,101 1,305,491 4,177,079 Neu I ngland Pouer Pool 1,575,110 912,121 1,274,522 1,005,731 1,170,847 lotal 16,6H8,626 18,061,170 16,527,711 17,115,460 17,026,986 Diyosition: l<ctail sales: Conuncreial 7,292,681 7,202,580 7,132,179 7,181,147 7,095,297 Itcalential 1,487,170 1,424,275 1,182,106 1,430,720 1,411,801 Industrial 1,590,669 1,678,242 1,6S4,864 1,750,125 1,845,441 ()ther
- 145,242 292,510 279,540 275,211 259,762 Total retail lulled 12,515,962 12,597,607 12,478,889 12,619,605 12,614,301 Wholesale and contract sales W 2,272,669 2,517,247 1,660,082 1,674,114 1,138,682 New I:nglanal Power Pool 877,978 1,898,059 1,251,797 1,885,165 2,090,238
' Intal sy stem 15,666,609 17,012,911 15,191,76S 16,198,8S4 15,841,221 Mistellaneous usage 1,020,017 1 048,257 1,135,965 _
916,576 1,181,765
~lbtal 16,686,626 18,061,170 16,527,711 17,115,460 17,026,986 Kilowatthours annual grou tl pei 'ent:
Itetail sales: Con ma rcial 1,1% l.0"o 10.7)% 1.2% 1.1 % Residential 1.8 1.2 ( 1.4 ) 0.5 (0.5) Indust r ial (5.2) (0.4) ().7) (5.1) 0,1 Oiher ( 50.1) 4.6 1.6 6.0 16.9 lbtal retad billed N~ (0.6) 1.0 (l.0 0.2 0.9 Wholesale and i ontract sales (9.7) 51.6 (0.8) 47.0 85.2 Neu 1.ngland Power Pool (51.7) 51.5 (11.5) (9.S) 149.0
'lbtal sntem (7,9)% 10 % (5.01"o 2.2% 13.6"o
' Intal electric operating resenues h) t lass: Conunen ial 49% 47% 47"o 46% 45% liesidential 27 % 26 % 26 % 27 % 26 % Industrial 10 % 10 % 10 % 10 % 10 % Wholesale and i ontract 12 % 11% 12 % 11% 15% Other 2% 4% 5"o 4% 4% l In Iric sales statisti(s: Re4lential ascrages: Annual kWh use 6,160 6,101 6,051 6,150 6,160 Resenue per kWh I l .49p 10.S4r 10.60c lO.09c 10.1Sc Annual bill 5 709.75 s 657.41 5 641.62 s 620.54 5 625.24 Customers: Ascrage number 651,141 646,215 642,967 642,041 617,871 on i on ene i ebour) Iw I a touwr o tuliuso.nier became a w hoh, ale t uoomer n 4llow ed under Alma < husi n. stan law I u ludmg the ella t ohhis
, uo..mcr's i hange in si.u us, t. it al ter.nl sales lidl<d ini reasul I .1N, in i W L Certam rn lassilications and rn alculations ucre inatle to the ilata reported in ju jor 3 cars to c onform with the metho I ol' presentation used in 1991.
38
Selected Consolidated Financial Statistics (Unaudited) l99I I992 1991 1990 1989 Operating resenues (f M)o) 5 1,482,255 5 1,411,751 s 1,354,501 5 1,114,440 5 1,319,956 Italant e for connnon (000) 5 102,513 5 90,748 s 77,059 5 77,788 5 (l1,788) Per (ornmon share: l arning,, (low ) $ 2.28 s 2.10 $ 1.96 5 2.01(') 5 (0.88)do 1)is idends dc t lar ed 5 1,715 s 1.655 5 1.591 5 1.535 5 1.745 l >isidends paiil 5 1.70 s 1.64 5 1.58 5 1.52 s 1.82 liook salue 5 19.42 5 IN.77 5 17.92 5 17.22 s 16,71 Operating cash llon O' 5 6.60 s 6.85 5 5.50 5 5.68 s 6,19 Payout ratio 75% 789o 81% 76 % A Ikturn on aserage cotomon e qmts i 1.9% l 1. 5 n i 1. P 6 11.8 % (4.6)% Year-end ilnidend yichl 5,9% 6. 2% 6.6% 7.9% 7.6% lh ed charge u nerage 61 Ci 2.27 x 1.9 h 1.86x 2.1 h 0.52x Capitah/ation:
%tal debt 57 % 56 % 58"o 59 % 57 %
Preferrol ami preferentc equity 9% 9% 10% 10 % 11 % Conunon equity 14 % 15"o 12 % 31"o 12 % Inng ierin debt (000) $ 1,272,897 s 1,091,071 s I,116,765 s 1,074,025 s 948,819 Mandatory redeemable preferred / preference stoc ks (0(Hi> $ 98,000 s 98,000 s 100,000 s 100,(810 $ 100,000 bial assets (000) 5 1,477,299 5 3,29 t ,214 s 1,i 19,28 5 5 3,012,589 $ 2,876,691 Internal generation alter l dis idends (000)") 5 186,918 s 207,148 s 191,016 $ 187,954 5 147,449 i Plant and nuricar fuel ex pemht ures (000) $ 253,885 5 111.025 5 214,211 5 255,784 s 215,946 Internal generation "' 74 % 90 % 89 % 73% 62 % Conunon stoc kholders it year enil 42,192 44,063 44,687 45,826 49,149 i Common sharn outstanding: Weighted aset age 44,959,050 43,143,953 39,347,824 38,778,901 38,145,648 Year. cnd 45,129,227 44,763,055 42,087,156 18,998,531 18,526,085 Stm L prire Iligh 32 5/8 28 1/.4 24 7/8 20 I/4 22 1/8
.Iow 26 1/8 22 I/8 18 1/4 161/2 15 3/8 Year end 29 3/4 27 1/2 24 1/4 20 20 Year.cnd tnarket salue (000) S 1,142,595 s 1,210,984 s 1,010,672 s 779,971 $ 764,913 Trashng solume (shares) 18,729,400 26,460,900 17,464,100 19,652,300 29,938,900 Market / hook ocar eml) 1.51x 1.47x 1.lSx 1.16s 1.20x Prit e/canings ratio () car end) 13.0 13.1 12.6 10.0 -(d' W Indud, s 50.4 I per inmm..n slure from an au onnnng dunge.
tqi inclu.lcs 278 ;wr common s, hare lou apphiable to rate and u.ntr,n t seulcins nn.
- 6) I uluda ettu t of rate and uintras t ritirn,cnn.
(di Not cats ulati d basi d ispini a loss jwr ti,mrivui share. A pasout ratio ut 581 #o and a pricc/carinngs ratio <>f 1.1.5 were caltulated based uliori 51.'iti t arnmgs per umunon share, exdudmg the R78 per a nnmon sharc low due to ide and contract srulenwnn. Cc tain reclassihca0nns and recah ulations were made to the data reported in prior years to conform uith the method of presentation uwd in Iw1. 39
Officers Directors Bernard W. Reinicek, Chairman of the Board and aal William F. Connell, Chairman and Chief Executise , Chief Executisc OHlcer 00icer, Connell 1imited Partnership (metals recy- l Thomas J. May, President and Chief Operating OHicer "E " "8 u F"h'd"O d,f Gary L. Country man, Chairman of the lloard and Chief G.eorge W. Dasis, lhecutise Vice President Executw.e Ofhseer, liberty MutualInsurance l E. Thomas Boulette, Senior Vice President - Nuclear Company i l Cameron D. Daley, Senior Vice President - Power Supply George W. Dasis, Executive Vice President, Boston Edison Company i John J. Desmond, Ill, Senior Vice President - I egal j a.e,f Thomas G. Dignan, Jr., Partner, Ropes & Gray < L. L.arl G.uson, S.enior\..ice Pres.i dent - Marketing & (lan h,rm.) Corporate Relations ba ,d Charles K. Gifford, President, Bank of Boston John J. liiggins, Jr., S.enior \, ice President lluman Resources . C.orporation (hank hohling company) and .I.he first Ronahl A. Ledgett, Senior Vice President - Power Delisers National llank of Iloston Charles E. Pt ters, Jr,, Senior Vice President - Finance b.f Nelson S. Gilford, former Vice Chairman, Asery Dennison Corporation (pressure-sensitive adhesives Alison Alden, Vice President - Sales & Service and materials, oHice products, product identincation and control systems and .spccialty chemicals) Marc S. Alpert, \, ice Pres.alent and .I.rcasurer <
. . a.c Kenneth L Guscott, General Partner, Long Bay L,. Bruce Damrell, \..n e Presu. h nt -I.ngmeermg,
, Management C,ompany (real estate development) Operations & Sersices - -
. a.b 4 Matina S. Ilorner, Executise Vice President, Teachers Richard S. Ilahn, \.. ice President - ret hnology Researt h &
Insurance and Annuity Association and College Deselopment Retirement Equities Fund Douglas S. Iloran, General Counsel a.c Thomas J. May, President and Chief Operating OBicer, Joel Y. Kamya, Vice President - Production Operations lloston Edison Company
- Martin S. Karl, Vice President - Marketing b.d Sherry 11. Penney, Chancellor, Unisersity of Edward S. Kraft, Vice President - Nuclear Operations and j Station Dire (tor a.c Bernard W. Reznicek, Chairman and Chief Executive O c r, Bmton Fdien Company Arthur P. Phillips, Jr., Vice President - Corporate Information Sersices e.f flerbert Roth, Jr., Former Chairman of the Board and Chief Executive Ofneer, LI E Corporation Robert J. Weat.er,Jr.,\..ice Pres.n ient, C,ontroller and Chief. . .
(t rafhse and industrial process control ss stems) ] Accounting Ol,heer c.: Stephen J. Sucency, Former Chairman of the lloard and S. L.omisser, t,lerk of. the c,orporan. on ' ...heodora i C.hief Executise Onicer, Boston Edison Com' any Donahl Anastasia, Awistant Treasurer pg . James J. Jtalge, Assistant Treasurer and Director - (law firm) Corporate Plannine - e.r Charles A. Zraket*, Trustec, The MITRE Corporation Wayne R. Irigard, Assi tant Clerk of the Corporation (not.for profit system research and engineering firm) a Monber of I m uuse Commmee b Mendwr of Auiht, hnance and Iwk Managonent Conamitec { c Member of Pricing Committee d Ember of I sceutne Permnm-l Conunittre e Wmber of Nudcar Du rsight Committce f Mender of Capital bnestment Comnuttec
- Wdl rt un on Aptd U,19H.
40
Dividend Reinvestment Plan Our Dividend Heimestment and Conunon Stock Purchase Plan (the plan)is available to our wmmon and preferred stockhoklers. Linder the plan, common and preferred stockhohlers may base their dividends reinvested in our common stock at current market prices. All participants may imnt optional cash contributions, up to a maximum of 5 5,000 per quarter, w hit h will be invested at the current market price. Participants do not pay fees or commissiom. All recordhoklers ni shares of conunon and preferred stock are eligible to participate directly in the plan. Beneficial owners of our stock w hose shares are registered in names other than their ou n (e.g., a broker or bank nomince) must arrange participation with the recordholder.11 for any reason a benencial mvner k unable to arrange participation with their broker or bank nominee, they must become a recontholder by hasing the shares transferred to their own name. All correspomience concerning changes in plan ownership shouhl be directed to the plan agent: The I-irst National llank ofiloston Dividend Reinvestment Unit Alail Stogn 45-01-06 P. O.Ilox 1681 11oston, Alassachusetts 02105-1681 Importarit Stockholder Information Annuai Alceting SFC Form 10-K Our Annual Ateeting of Stot kholders will be held on April 22, Stockhohlers may obtain a copy of our annual report to the 1994,atl1:00 a.m. If you wish to receise a copy ofliernie Securities and Fxchange Conuni% ion on Form 10-K by mak-Retnicek's remarks, please write to our Investor Relations ing a written request to our Investor Relations Department. Department at the General Ouices address listed behm- Quarterly lleport to Sharehoblers Company Conta( t Henc0cial owners of our stocks whose shares are registered in Theodora Comisser names other than their ou n (e.g., a broker or bank nominee) Clerk of the Corporation tuay obtain copin of our Quarterly Reports to Sharehohlers on an on-going basis by making a written request to our Im estor Relations Contact imestor Relatiom Department to be placed on their maihng Dan Desjanlins list. Note that the Annual Report will continue to be mailed Director, Imestor Relations to benencial owners directly by their bank or broker. General OHices Inquiries Concerning Stock If you hase questions concerning your dividend pasments, divi-800 Hoyhton street. Hoston, Atassachusetts 02199 8003 - dendih. rect depos.it, dn. ulend rein estment plan status, trans-(617)424 2000 fer procedures or other stock account matters, please contact Stock 1.istings our Stock Transfer Agent at the following address: New York and Boston stock exchanges The First National llank ofIloston Stock Symbol Sharalder Service Division BSi! Alail Stop: 45-02-09 Dividend Payment Dates P. O, llox 644 lloston, Alassachusetts 02102-0644 Conunon and Pref. erred: Ist of February, Alay, August, Nmember If you ne submitting thxuments requesting a transfer, address Tax Status of 1991 Dividends change or account consolidation, please use this same address with Generalh unless you are subject to certain exemptions, all Alail Stop: .45-01-05. If you wouhl like to contact the bank by dividen$,on our common or preferred stock are to be comid. ICh' phone cau 617-575-2900 or toll-free I-800-442-2001. cred 100% taxahic. Stock Transfer Agent, Registrar of Stock and Dividend lleimestment Plan Agent , The First National Bank of Boston 41
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3- ] SECURITIES AND EXCHANGE COMMISSION g Washington, D.C. 20549 1 FORM 10 K ' [X] : ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE , JACT OF 1934 [ FEE REQUIRED] For the fiscal year ended December 31,1993 OR '[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] s For the transition period from to Commission file number 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter) Massachusetis 04-1278810 (State or other jurisdiction of (f.R.S. Employer incorporation or organization) Identification No.) 800 Hovlston Street. Hoston. Massachusetts 02199 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 617-124 2000 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which recistered Common stock, par value $1 per sharc New York Stock Exchange
- Boston Stock Exchange Cumulative preferred stock:
7.75% Series, par value $100 per share New York Stock Exchange (represented by depositary sharcs-cach represents one-fourth interest in par value) 8.25% Series, par value $100 per sharc New York Stock Exchange ; (represented by depositary shares-cach ! represents one-fourth interest in par value) Securities registered pursuant to Section 12(g) of the Act: None Indicate by che'ck mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge,in definitive proxy or information statements incorporated by reference in Part ., 111 of this Form 10-K or any amendment to this Form 10-K. [X) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
' Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such ' . reports), and (2) has been subject to such filing requirements for the past 90 days.' YES,X NO,_.
The aggregate market value of the voting stock held by non affiliates of the registrant as of February 28,1994 computed by ) D
! reference to the last reported sale price of the common stock, $1 par value, of the registrant of the New York Stock Exchange composite ' tape on that date: $1,220,739,336.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Outstandine at February 28.1994 Class 'l ' Common Stock, $1 par value 45,212,568 shares DOCUMENTS INCORPORATED BY REFERENCE ' hrt ' Document -1 111 Portions of definitive Proxy Statement dated March 17,1994 for Annual Meeting of Stockholders to be held April 22,1994 ! Exh! bit list appears on page St.
, ~, __ _ . _ _ . . ._ _
^
l Boston Edison Company form 10 K Annual Report December 31. 1993 Paae Part I Business 2 Item 1.
- 2. Properties and Power Supply 10 Item
- 3. Legal Proceedings 13 Item Item 4. Submission of Matters to a Vote of Security Holders 13 Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 17 Item 6. Selected financial Data 18 Management's Discussion and Analysis 19 Item 7.
Item 8. Financial Statements and Supplementary Financial Information 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 48 Part III Item 10. Directors and Executive Officers of the Registrant 48 Item 11. Executive Compensation 48 Item 12. Security Ownership of Certain Beneficial Owners and Management 49 Item 13. Certain Relationships and Related Transactions 49 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on form 8-K 50 1
Eart I Item 1. Business (a) General Development of Business Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law. The Company operates in the energy and energy services business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of demand side management (DSM) programs. In 1993 the Company established an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from the Massachusetts Department of Public Utilities (DPU). The Company was granted authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management, electric transportation and electric generation and distribution activities through its wholly-owned subsidiaries Ener-G-Vision, Inc. and TravElectric Services Corporation. In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc. The new entity, REZ-TEK International Corporation, will continue the business of manufacturing ozone water treatment systems. The Company does not currently have a substantial investment in BETG and does not expect the subsidiary to significantly impact the results of operations in the next several years. (b) Financial Information about Industry Seaments The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable. (c) Narrative Descriotion of Business Principal Products and Services The Company supplies electricity at retail to an area of approximately 590 square miles encompassing the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 1993 the Company served an average of approximately 651,000 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Revenues by class for the last three years are as follows: 1993 1992 1991 Retail electric revenues: Commercial 49% 47% 47% Residential 27% 26% 26% Industrial 10% 10% 10% Other 2% 4% 5% Wholesale and contract revenues 12% 13% 12% 2
Sources and Availability of Fuel The Company's generating units, other than Pilgrim Nuclear Power Station, are fueled by oil, natural gas or both. The Company's generation by type of fuel and the cost of fuel for each of the last five years are as follows: Percentage of Company Average Cost (Dollars per Hillion) __Seneration by Source (%) of BTV's on a Burned Basis ($1 1993 1992 1991 1990 1989 1993 1992 1991 1990 1989 Oil 31.3 33.7 42.8 33.6 53.7 2.38 2.40 2.60 2.76 2.67 Gas 24.3 25.7 24.9 33.3 31.7 2.67 2.55 2.08 2.35 2.34 Nuclear 44.4 40.6 32.3 33.1 14.6 0.51 0.52 0.56 0.59- 0.57_ The majority of the Company's residual oil purchases consists of imported oil acquired primarily frem international suppliers. The Company has contracts with major oil companies that can supply most of its estimated requirements, assuming no major disruptions in oil producing regions. Within contract provisions, the Company has the ability to purchase significant amounts of oil in the spot market when it is economical to do so. Most of the Company's natural gas is supplied on an interruptible basis whereby a contract permits interruptions in deliveries by the supplier when natural gas pipeline capacity is unavailable. Deliveries of natural gas to the Company's generating units from suppliers may also be dependent on the availability of pipeline capacity to the New England region and competitive forces prevailing in the pipeline industry. Beginning in April 1995 the Company will be required to operate New Boston Station using exclusively natural gas as fuel, except in certain emergency circumstances, as part of a 1991 consent order from the Massachusetts Department of Environmental Protection (DEP). The Company has arrangements for a nine month supply of natural gas to the station until April 1995 and is currently in the process of negotiating with suppliers and transporters concerning the economics and availability of natural gas to the station on a year-round basis after that time. Year-round gas supplies are currently not available to the station and, as a result, the outcome of the Company's negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain. In order to obtain nuclear fuel for use at Pilgrim Station the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication that will individually allow operation of Pilgrim Station through 1998, 2000, 2001 and 2012, respectively. Franchises Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for 3 1
. I the Company's electric transmission'and distribution lines are obtained from -1 municipal and other state authorities, which in granting these locations act as agents for the state. In some cases the action of these authorities is subject to appeal to the DPU. The locations are unlimited in time, but their rights are not vested and are subject to the action of these authorities and the legislature.
Seasonal Nature of Business The Company's kWh sales and revenues have historically been less in the spring and fall than during winter and summer 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 DPU. Accordingly, a significant portion of annual earnings occurs in the Company's third quarter. See Selected Consolidated Quarterly financial Data (Unaudited) in Item 8. Working Capital Practices The Company has no special practices with respect to working capital that would be considered unusual for the electric utility industry or significant for the understanding of the Company's business. Customer Dependence . l No material portion of the Company's business is dependent upon one or a few customers. Government Contracts i No material portion of the Company's business is subject to renegotiation or termination of government contracts or subcontracts. Competitive Conditions i The Company is experiencing a substantial increase in competition from , other electric utilities and non-utility generators to sell electricity for ! resale. In respense to the current environment the Company has secured long-term power supply agreements with its four current wholesale customers which set rates principally through the year 2002. The Company also obtained a new ! wholesale customer for which it will provide up to 30 megawatts (MW) of ) contract demand power for ten years beginning November 1994. l The DPU has created an integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how .I they will meet those needs by balancing conservation programs with all other I supplies of energy. The Company submitted a draft IRM filing in March 1994 that covers the period 1994 through 2004. In this filing the Company-concluded that adequate resources exist to meet customer needs for continued reliable, low cost power through the period without procurement of any new generation resource's. The IRM process requires a settlement period in which intervenors and other interested parties have the opportunity to review, comment and request information on the draft filing. Any settlements reached will be reflected in the Company's final IRM filing to be submitted in July 1994. Any remaining issues will be litigated at the DPU through formal proceedings. 4
Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. The Company and other Massachusetts electric utilities are protected in several ways by the DPU and municipal statutes against other utilities offering service to retail customers in their service areas. Another electric utility may not extend its service area to include municipalities other than those named in its agreement of association or charter without DPU authorization granted after notice and public hearing. Also, another company may not obtain an initial location for its lines in a municipality served by the Company without the approval of municipal authorities, subject to the right of appeal to the DPU. Additionally, a municipality may not engage in the electric utility business without complying with statutes requiring specific city or town approval and the purchase of Company property within municipality limits. However, the Company is currently experiencing some forms of competition in the retail electric market. Current legislation allows industrial and large commercial customers to own and operate their own electric generating units. Retail customers may also substitute natural gas or oil for electricity as fuel for heating and cooling purposes. The Company is responding to the current and anticipated competitive pressures with a commitment to cost control and increased operating efficiencies without sacrificing quality of service or profitability., Research Acttvitles The Company actively participates in several industry-sponsored research activities. These expenditures, included in other operations and maintenance expense on the consolidated income statements in item 8, were not material in 1993. Environmental Matters The company is subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require modification of existing facilities or curtailment or termination of operations at facilities, delay construction of new facilities or increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. The Company's capital expenditures for environmental purposes during the five years 1989 through 1993 were approximately $125 million. Environmental-related capital expenditures for the years 1994 through 1998 are currently expected to approximate $43 million, including $17 million in 1994 and 59 million in 1995. These amounts exclude costs associated with asbestos ,
. removal which were approximately $11 million during the five years 1989 ;
through 1993 and are currently expected to be approximately $10 million for j the years 1994 through 1998. The 1994 expected capital expenditures for l environmental purposes include costs to complete modifications at New Boston l Station in order to improve air quality and reduce emissions of. nitrogen I oxides, as discussed in the Environmental section of Other Matters in Item 7, and to install air monitoring systems at other Company generating units. 5
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.l Substantial additional expenditures could be required as changes in environmental requirements occur.
The Company is subject to regulation by the. United States Environmental Protection Agency (EPA) and the Massachusetts Department of Environmental Protection (DEP) with respect to discharges of effluent from the Company's generating stations into receiving waters. The Federal Clean Water Act and the Massachusetts Clean Waters Act require the Company to receive permits that limit discharges in accordance with applicable water quality standards and are subject to renewal every five years. The Company has received discharge permits as required by the EPA and the DEP for each of its electric generating stations. The Company is also subject to EPA and DEP regulation relative to emissions from its fossil-fired generating units pursuant to Federal and Massachusetts clean air laws, including the 1990 Clean Air Act Amendments. These regulations require the installation of various emissions controls and the use of low sulfur content fuels in certain cases. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section in Item 7. The Company is subject to various federal, state and local laws and regulations pertaining to the generation, treatment, transportation, storage and disposal of certain hazardous substances and to the cleanup of locations where such substances have either been disposed of or spilled. One of the requirements of these laws and regulations is that certain facilities which treat, store or dispose of hazardous wastes must be licensed. The only facility owned by the Company which requires such a license is Pilgrim Station. Currently Pilgrim Station has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive. The Company has exposure to potential joint and several liability for the cleanup of sites where hazardous wastes may have been spilled or disposed of in the past. The Company has been notified of such potential liability for approximately twelve sites, most of which involve numerous parties. Complex litigation or negotiations among the parties and with regulatory authorities is in process concerning the scope and cost of cleanup and the sharing of costs among the potentially responsible parties for several of these sites. The Company also faces additional exposure for the cleanup of Company-owned or operated sites due to state regulations revised in 1993. The potential hazardous waste liabilities are further described in the Environmental section of Item 7. The Company currently disposes of low-level radioactive waste (LLW) generated at Pilgrim Station through arrangements with licensed disposal facilities located in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, the Company's continued access to such disposal facilities has become severely limited and significantly increased in cost. See Note D to the consolidated financial statements in Item 8 for further discussion regarding LLW disposal. j The Company's existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. A request for a license amendment to allow modification of the storage facility 6 1
to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012 is pending before the Nuclear Regulatory Commission (NRC). The Company expects approval of the request in 1994. At j that time the Company will initially modify the facility to provide spent fuel l storage capacity through approximately 2003. In addition, the United States ; Department of Energy (DOE), which is ultimately responsible for the disposal of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982, is currently conducting scientific studies evaluating a potential spent nuclear ; fuel repository site at Yucca Mountain, Nevada. The potential site, however, I has encountered substantial public and political opposition and litigation and the 00E has publicly stated that it may be unable to construct such a i repository in a timely manner. The Company is unable to predict whether and I on what schedule the DOE will eventually construct a repository and what the l effect will be on the Company. Published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields associated with electric i transmission and distribution facilities and appliances and wiring in o buildings and homes. This topic is discussed more fully in the Environmental l section of Item 7. Number of Employees The Company had 4,404 full-time and 14 part-time employees as of the end l of 1993, 2,775 of which are represented by two locals of the Utility Workers l Union of America, AFL-CIO. The current four-year labor contract in effect l with the locals is scheduled to expire in May 1994. Labor contract negotiations began in early February 1994 and the Company anticipates favorable resolution of these negotiations. l (d) Financial Information about Foreion and Domestic Operations and Export Sales See Principal Products and Services for information regarding the geographical area served by the Company and revenues by class for the last three years. (e) Additional Information Regulation The Company and its wholly-owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the DPU, whose jurisdiction includes supervision over retail rates for electricity, financing, investing and accounting. In addition, the Federal Energy Regulatory Commission (FERC) has jurisdiction over various phases of the Company's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of such power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation. Recent requirements imposed on the Company by the DPU are discussed under Competitive Conditions of this item and Non-Utility Generator Purchase Contracts in Item 2. 7 eqg- y vw
. .. - .- - - . _. = = l The Company is required to submit to the DPU annual performance ! standards applicable to its generating units and other units from which the Company purchases power under long-term contracts. The Company provides quarterly generating unit performance progress reports to the DPU. The DPU i has the right to reduce subsequent fuel clause billings if it finds that the Company has been unreasonable or imprudent in the operation of its generating units or in the procurement of fuel. In 1993 the Company received a generating unit performance order from the DPU for the performance period November 1990 through October 1991. The order required the Company to make refunds to its customers due to its not meeting certain performance standards. A subsequent order was received from the DPU in February 1994 for the performance period November 1991 through October 1992. The Company is currently assessing the potential customer refunds associated with missed performance goals. The Company has not yet received an order from the DPU for the performance period November 1992 through October 1993. The Company believes that its current provision for refunds will be sufficient to cover all potential refunds. The NRC has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which was issued in 1972 and expires in 2012. Continuing NRC review of existing regulations and certain operating occurrences at other nuclear plants have periodically resulted in the imposition of additional requirements for all domestic nuclear plants, including Pilgrim Station. NRC inspections and investigations may result in the issuance of notices of violation. These notices may be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties. In addition, the Company might undertake certain actions in regard to Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations (INP0), a voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants. Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests for various kinds of federal, state and local legislative or regulatory. action, direct voter initiatives or referenda or litigation. The Company cannot predict the . extent, cost or timing of any modifications to Pilgrim Station which might be required in the future as a result of additional regulatory or other requirements nor can it determine the effect of such future requirements on the continued operation of Pilgrim Station. The Company continues to evaluate the operation of the station from the standpoint of safety, reliability and economics and believes that such continued operation is in the best interests of the Company and its customers. 8
Capital Expenditures and Financings The Company's most recent estimate of capital expenditures, allowance for funds used during construction (AFUDC), long-term debt maturities and sinking fund requirements for the years 1994 through 1998 are as follows: (in thousands) 1994 1995 1996 1997 199Q Capital expenditures (1) $201,000 $206,000 $184,000 $181,000 $172,000 AFUDC (2) 6,000 4,000 4,000 5,000 5,000 Long-term debt - 100,600 101,600 101,600 101,600 Preferred stock sinking fund 2,000 2,000 2,000 2,000 2,000 (1) Excludes estimated nuclear fuel expenditures of $19,000, $9,000,
$23,000, $12,000 and $25,000, respectively and capitalized DSM expenditures.
(2) Excludes estimated AFUDC on nuclear fuel of approximately $1,000 per year. The estimated AFUDC rate varies from 4.0% to 6.5%. l The Company conducts a continuing review of its capital expenditure and financing programs. These programs and the estimates shown above are-therefore subject to revision due to changes in environmental standards, regulatory requirements, availability and cost of capital, interest rates and . other assumptions. In addition, depending upon the outcome of certain air i quality modeling studies, the Company may be required to make additional ) expenditures by 1999 in order to comply with the provisions of the 1990 Cican Air Act Amendments. The extent of any additional expenditures is uncertain at this time. j 1 Capital expenditures in 1993 were approximately $247 million and l consisted primarily of additions to the Company's transmission and distribution systems and fossil and nuclear generation facilities. Significant projects included spending for transmission and distribution of , approximately $13 million for the replacement of electric system property, $9 million for a new substation and $7 million for a new energy control system. ] l l l Capital spending for fossil generation facilities included approximately $24 million for environmental modifications at New Boston Station as described in the Environmental section of Other Matters in Item 7. Expenditures in 1993 for Pilgrim Station included approximately $32 million to improve efficiencies and meet regulatory requirements and $8 million for a new administrative building. Funds generated internally represented approximately 74%, 90% and 89% of capital expenditures in 1993, 1992 and 1991, respectively. It is expected that a significant portion of future capital expenditures will be funded internally, i The Company intends to continue spending significant amounts on its DSM programs. The Company spent approximately $53 million on these programs in 1993, of which $37 million was capitalized and is being collected from customers over six years in accordance with the Company's 1992 settlement agreement. See the Liquidity and Outlook for the Future sections in Item 7 i for further discussion regarding the Company's DSM programs. 9 i
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i e in 1993 the DPU approved a financing plan allowing the Company to issue up to $1.1 billion in securities through 1994 and to use the proceeds to refinance long-term securities and short-term debt. See Note F to the consolidated financial statements in Item 8 for specific information relating to the Company's financing activities. 4 Item 2. Properties and Power Supply Company-Owned Facilitles The Company's total installed electric generation capacity as of December 31, 1993 is as follows: Installed Capacity Year Unit location (MW) Tvoe Insta_lled Pilgrim Nuclear Plymouth, MA 678 Nuclear 1972 Power Station New Boston Station South Boston, MA 718 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, MA Units 4-5 6 469 Fossil 1957-1961 Unit 7 617 Fossil 1975 Combustion turbine Various 239 Fossil 1966-1971
.qenerators (ten)
All of the Company's steam fossil fuel-fired electric generating units are located at tide water and have access to fuel oil storage and/or natural gas or oil pipelines from nearby suppliers. The Company is also a 5.888% joint owner in W,F. Wyman Unit 4. The 619 MW oil-fired unit located in Yarmouth, Maine began operations in 1978 and is operated by Central Maine Power Company. Additional electric generation capacity _is available to the Company through its contractual arrangements with other utilities and non-utilities - and its participation in the New England Power Pool as further described in this item. As of December 31, 1993 the Company's transmission system was comprised of approximately 362 miles of overhead circuits operating at 115,000, 230,000-and 345,000 volts and approximately 155 miles of underground circuits operating at 115,000 and 345,000 volts. .The substations supported by these lines consist of 42 transmission or combined transmission and distribution substations with transformer capacity of 10,025 megavolt amperes (MVA), 71 distribution substations with transformer capacity of 1,238 MVA and 18 primary-network units with 88 MVA capacity. In addition, high tension service was delivered to 231 customers' substations. The overhead distribution system covers approximately 4,652 miles of streets and the underground distribution system extends through approximately 892 miles of streets. HEEC, the 10
Company's regulated subsidiary, has a distribution system that consists principally of a 4.09 mile ll5Kv submarine distribution line and a temporary substation which is located on Deer Island in Boston, Massachusetts. The Company's significant items of property consist of electric generating stations, substations and certain service centers and are generally located on Company-owned land, with certain exceptions as set forth in the Company's First Mortgage Bond Indenture and its supplements. The Company's high-tension transmission lines are generally located on land either owned by the Company or subject to easements in its favor. The Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by local or state authorities. The Massachusetts Energy facilities Siting Board (EFSB) must approve Company plans for the construction of certain new generation or transmission facilities based upon findings that such facilities are consistent with state public health, environmental protection and resource use and development policies. The Company currently has no proceedings before the EFSB. l.ong-Term Power Contracts . Refer to Note K to the consolidated financial statements in Item 8 for further information regarding the following contracts. The Company also has short-term agreements with several other utilities for varying periods for purchases of system and unit power, for sales of Company system and unit power and for transmission services. Mility Purchase Contrantn The Company has a contract with a subsidiary of Commonwealth Energy System and two other utilities in which the participants are sharing in equal amounts the output of an oil fired electric generation plant. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return over a period of approximately 33 years for its proportionate share of generation. The Company has two long-term purchased power contracts with the Massachusetts Bay Transit Authority (MBTA) for the availability of two-of the MBTA's jet turbines. The MBTA retains the right to utilize the jets for its own emergency use and for testing purposes but the Company retains New England Power Pool credit for their capacity and output. The Company owns 9.5% of the common stock of Connecticut Yankee Atomic Power Company, which operates a nuclear generating unit. The Company is entitled to receive 9.5% of the unit's output and is obligated to pay Connecticut Yankee 9.5% of its fixed and operating costs plus an annual return on investment. Non-Utility Generator Purchase Contracts: The Company currently purchases approximately 500 MW of capacity and I associated energy from non-utility generators. A majority of these purchases ' are from Ocean State Power and Northeast Energy Associates. In 1993 the L'Energia facility located in Lowell, Massachusetts was declared commercial and the Company began purchasing electricity from this unit under a ' twenty-year agreement. In addition, the Company is purchasing power from two 11
small hydro facilities, and began purchasing capacity and energy from the MassPower facility located in Springfield, Massachusetts in Januery 1994. In June 1993 the DPU ordered the Company to purchase 132 MW of power from Altresco Lynn, LP, an independent power producer, starting as early as 1995. The Company opposes this order since it does not believe it needs any new power for several years. In July 1993 the Company asked the Massacb*Jsetts Supreme Judicial Cout t to reverse the order. The Court has not yet ruled on the Company's request. The Company has supported an appeal filed by other interested parties of the Energy facilities Siting Board's conditional approval of Altresco Lynn's project. In February 1994 Altresco Lynn alleged that the Company's actions in opposing the project were improper and that it may seek to hold the Company responsible for any resulting damages. Sales Contractn The Ccmpany has agreements with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, and with Commonwealth Electric Company, a subsidiary of Commonwealth Energy System, under which Montaup and Commonwealth each purchase 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and operating costs plus an annual return. Montaup and Commonwealth have aise agreed to indemnify the Company to the extent of 11% each of all loss, 'iability or damage not covered by insurance resulting from the operation, c',ndemnation, shutdown or retirement of the unit, In addition, the Compaay has similar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station. New England Power Pool The Company is a member of the New England Power Pool (NEP00L), a voluntary association of electric utilities in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To assume maximum benefits of power pooling, the electric facilities of all member companies are operated by NEP00L as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest cost generating and transmission equipment available at any given time. This operation is the responsibility of NEP00L's central dispatch center, the New England Power Exchange (NEPEX). As a result of its participation in NEP00L, the Company's operating revenues and costs are affected to some extent by the operations of the other members. The table below sets forth certain information as of the date of the Company's 1993 summer and 1993-1994 winter peak loads: January 19, 1994 July 7, 1993 (Winter 1993-94) (Summer 1993) NEPEX utilities installed capacity: Seasonal maximum rating 25,529 MW 24,368 MW Seasonal normal rating 25,232 MW 24,160 MW NEPEX peak load (estimate) 19,422 MW 19,570 MW Company territory peak load 2,474 MW 2,662 MW 12
The Company's net capacity was 3,663 MW at its summer peak and 3,533 MW at is winter peak. Its corresponding NEP00L capacity obligations were estimated to be 3,190 MW and 3,289 MW, respectively. In 1983 the NEP00L participants signed an agreement, known as Phase I, with Hydro-Quebec of Canida to provide up to three million MWH of hydro-electric power annually to NEP00L from 1986-1997. In 1985 a second agreement, known as Phase II, was made betvieen NEP00L and Hydro-Quebec to provide an additional seven million MWH of hydro-electric power annually for ten years. This agreement required expansion of the existing 690 MW Phase I interconnection. The Company and other N w England electric utilities entered into an agreement to expand tht interconnection with the Hydro-Quebec system , of Canada to 2,000 MW. The Phase Il facilities began full commercial operation up to the 2,000 MW level in July 1991. The price of this energy is based on the average cost of fossil fuel in New England for the previous year. The contract price for the first five years is 80% of that average, and for the second five years will h 95% of that average. The Company receives capacity credit through NEP00L for approximately 11% of the generation equivalent of the total Hydro-Quebec interconnection. The company has an approximately 11% equity ownership interest in the two companies which constructed the Phase II facilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants not meeting certain credit criteria. Amounts so guaranteed by the Company were approximately $22 million at December 31, 1993. As a result of the continuing additions to New England generating capacity and minimally increasing energy requirements, the dispatching of Company-owned generating facilities by NEPEX may be affected. Item 3. Leaal Proceedinag in March 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts 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 is vigorously defending this case. Based on the information presently available, the Company does not expect that this litigation will have a material impact on the Company's financial condition. However, an unfavorable decision ordered against the Company could have a material impact on quarterly earnings. See also Item 1, Environmenta7 Natters and Note H to the consolidated financial statements-in item 8 for a discussion of legal issues involving hazardous waste sites. Item 4. Submission of Malters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the fourth quarter of 1993. 13
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1 hutive Officers of the Reaistrant 1 The names, ages, positions and business experience during the last five years l of all the executive officers of Boston Edison Company and its subsidiaries as . f of March 1,- 1994 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding between any Company officer and another person pursuant to which the officer was elected. Officers of the Company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until their respective successors are chosen and qualified. Business Experience Name, Ace and Position Durina Past Five Years Bernard W. Reznicek, 57 Chairman of the Board and Chief Chairman of the Board and Executive Officer (since 1993), Chief Executive Officer formerly Chairman, President and Chief Executive Officer (1992-1993), President and Chief Executive Officer (1990-1992) and President and Cnief i Operating Officer (1987-1990). . Director (since 1987). Chairman of the Board, Chief Executive Officer and Director, Harbor Electric Energy Company, Boston Energy Technology . Group, TravElectric Services Corp. l and Ener-G-Vision, Inc. Thomas J. May, 46 President and Chief Operating Officer President and Chief (since 1993), formerly Executive Vice Operating Officer President (1990-1993) and Senior Vice President (1987-1990). Director (since 1991). President, Chief Operating Officer and Director, Harbor Electric Energy Company; President and Director, Boston Energy Technology Group; Director, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ-TEK International Corp. 1 14 l
I l Business Experience tiame. Aae_and Position Durina Past Five Yean George W. Davis, 60 Executive Vice President-(since I Executive Vice President 1992), responsible for all power supply and delivery operations. Director (since 1991). Senior Vice President - Nuclear (1990-1992). 1 Vice President - Nuclear Administration'(1989-1990), , E. Thomas Boulette, 51 Senior Vice President Nuclear Senior Vice President - Nuclear (since 1993). Vice President - . Nuclear Operations and Station Director (1992-1993). Vice President
- Operations (1989-1992) and Plant Manager (1988-1989) of Maine Yankee Atomic Power Company.
Cameron 11. Daley, 48 Senior Vice President - Power Senior Vice President - Power Supply Supply (since 1989). Vice President
- Power Production (1982-1989).
John J. Desmond, 111, 60 Senior Vice President - Legal (since Senior Vice President - Legal 1992). Vice President and General Counsel (1985-1992).
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L. Carl Gustin, 50 Senior Vice President - Marketing & Senior Vice President - Marketing & Corporate Relations (since 1989). Corporate Relations Vice President - Corporate Relations (1986-1989). , John J. liiggins, Jr. , 61 Senior Vice President - Human ! Senior Vice President - Human Resources Resources (since 1990). Vice i President - Human Resources (1988- ~ 1990). Ronald A. Ledgett, 55 Senior Vice President - Power Senior Vice President - Power Delivery (since 1991). Director, j Del ivery Special Projects (1989-1991). 1 I 15
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Business Experience ! Name. Ace and Position Durina Past Five Years Charles E. Peters, Jr., 42 Senior Vice President - Finance Senior Vice President - Finance (since 1991). Chief Financial l Officer and Senior Vice President of Genrad, Inc. (1985-1991). Vice President, Treasurer and Director, Harbor Electric Energy Company; l Treasurer and Director, Boston Energy Technology Group; Director, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ-TEK j International Corp. 4 Marc S. Alpert, 49 Vice President and Treasurer (since Vice President and Treasurer 1988). Assistant Treasurer, Harbor j Electric Energy Company and Boston ! Energy Technology Group. I Robert J. Weafer, Jr., 47 Vice President, Controller and Vice President, Controller and Chief Chief Accounting Officer (since Accounting Officer 1991). Controller and Chief l Accounting Officer (1988-1991). l Theodora S Convisser, 46 Clerk of the Corporation (since Clerk of the Corporation 1986). Clerk of Harbor Electric l Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ--TEK International Corp. 1 16
l .c Part II Item 5. Market for the Reaistrant's Common Stock and Related Stockholdgr ; Matters fa) Market Informatiqn The Company's common stock is listed on the New York and Boston Stock Exchanges. Following are the reported high and low sales prices of the ' Company's common stock on the New York Stock Exchange as. reported daily in the Vall Street Journal for each of the quarters in 1993 and 1992: 1993 1992 Hiah low Hiah low First quarter $30 1/2 $26 3/8 $24.5/8 $22 1/8 ' Second quarter 30 7/8 277/8 26 22 3/8. Third quarter 32 5/8 29 3/4 26 7/8- 24 7/8 Fourth auarter 32 1/4 27 7/8 28 1/4 24 3/4 lb) Holders As of December 31, 1993, the Company had 42,392 holders of record of its common stock (actual count of record holders). Is) Dividendt following are the dividends declared per share of common stock for each of the quarters in 1993 and 1992: 1993 1932 First quarter $0.425 $0.410 Second quarter 0.425 0.410 Third quarter 0.425 0.410 fourth quarter 0.440 0,425 17
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Item 6. Selected Financial Data l i The following table summarizes five years of selected consolidated i financial data of the Company (in thousands, except per share data), 1993 1992 1991 1990 1989 Operating revenues $1,482,253 $1,411,753 $1,354,501 $1,314,440 $1,339,956-Net income / (loss) 118,218 107,298 94,670 79,616(a) (16,135)(b) Earnings /(loss) per common . . share 2.28 2.10 1.96 1.60(a) (0.88)(b)~ Total assets 3,477,299 3,294,234 3,119,285 3,012,589 2,876,691 Long-term debt 1,272,497 1,091,073 1,136,765 1,074,025 948,839 Redeemable preferred / preference ' stock 221,000 221,000 221,333 221,333 221,333 Cash dividends declared per common share 1.715 1.655 1.595 1.535 1.745 (a) Before cumulative effect of change in accounting principle ($15,824 or-
$0.41 per common share).
(b) Includes $106,280 or $2.78 per common share loss applicable to rate and contract settlements. 18
Item 7. Manaaement's Discussion and Analysis Regulatory Proceedings Retail settlement agreements Effective November 1992 our state regulators, the Massachusetts Department of Public Utilities, approved a three-year settlement agreement. This agreement provides us with retail rate increases, allows for the recovery of demand side management (DSM) conservation program expenditures, specifies certain accounting adjustments and clarifies the timing and recognition of certain expenses. The agreement also sets a limit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any penalties or rewards from performance incentives. The retail rate increases consist of a new annual performance adjustment charge effective November 1992 and two additional rate increases of $29 million effective November 1993 and November 1994. The performance adjustment charge varies annually based upon the performance of our Pilgrim Nuclear Power Station. This charge is further described in our discussion of financial condition. Our 1993 results of operations were affected by the recovery of DSM program expenditures, accounting adjustments and timing and recognition of certain expenses as further described in the following Results of Operations section. ] Our state regulators approved a previous three-year settlement agreement j effective November 1989. That agreement also provided us with retail rate increases and specified certain accounting adjustments. The 1989 agreement primarily affected our results of operations through 1992. Results of Operations 1993 Versus 1992 Earnings per common share were $2.28 in 1993 and $2.10 in 1992. The increase in earnings is primarily the result of an annual rate increase effective November 1992, lower purchased power expense due to a long-term contract expiration, no amortization of deferred cancelled nuclear unit costs and lower interest expense. These positive changes were partially offset by higher operations and maintenance expense and higher income tax and property tax expenses. Operating revenues Operating revenues increased 5% over 1992 as follows: lit thousnds) Retail electric revenues $70,837 Demand side management revenues 33,601 Wholesale and other revenues (2,794) Short-term sales revenues (31.144) Increase in operatinq revenues $70.500 19
Retail electric revenues increased $70.8 million. The November 1992 and 1993 rate increases resulted in $40.6 million of additional revenues in 1993. Fuel and purchased power revenues increased $29.5 million over 1992, partly due to lower revenues received from short-term power sales as discussed below. We began recovery of certain demand side management program costs, lost base revenues and incentives in August 1992. Our 1993 revenues provided $45.9 million related to 1991, 1992 and 1993 DSM programs. Our 1992 revenues of
$12.3 million related primarily to 1991 programs. >
The decrease in wholesale and other revenues reflects an estimated provision for refunds to customers of approximately $8 million as a result of orders from our state regulators on our generating unit performance program. Lower short-term power sales revenues were a result of changes in our generation availability and the needs of short-term power purchasers. All revenues from short-term sales serve to reduce fuel and purchased power billings to retail customers and have no effect on earnings. Operating expenses Fuel expense decreased $19.5 million primarily due to a 21.5% decrease in generation, resulting from planned overhauls of our fossil plants. Interchange purchases increased due to the lower generation, resulting in a
$7.5 million net increase in purchased power expense. The net increase also reflects savings of approximately $10 million from a long-term purchased power contract that expired in October 1993. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues.
Other operations and maintenance expense increased 7.1% primarily due to increases in employee benefits and nuclear production expenses. Postretirement benefits expense increased by $7 million primarily as a rasult. of the adoption of a new accounting standard and pension expense increasd by
$5 million; both are provided for in our 1992 settlement agreement and further explained in Note I to the consolidated financial statements. A refueling outage at Pilgrim Station in 1993 resulted in higher nuclear production expenses.
Depreciation and amortization expense increased in 1993 primarily due to a higher annual decommissioning charge for Pilgrim Station effective November 1992 provided by the 1992 settlement agreement. The new charge is based on a 1991 estimate of decommissioning costs as further discussed in Note D to the consolidated financial statements. In addition, the effect of lower depreciation rates implemented in accordance with the settlement agreement was offset by the effect of a higher depreciable plant balance. In accordance with our 1992 settlement agreement we did not expense any of the $19 million of remaining deferred costs associated with the cancelled Pilgrim 2 nuclear unit in 1993. We will expense the remaining costs in 1994 and/or 1995. Amortization of deferred nuclear outage costs includes amounts related . to the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we 1 deferred approximately $14 million of refueling outage costs. We began to i I 20
4 amortize these costs in c*e 1993 over five years as approved in the 1992 settlement agreement. The increase in demand side management programs expense is consistent with the increase in DSM revenues. DSM expense includes some costs recovered over a twelve month period and other costs recovered over six years. We began to recover previously deferred DSM expenses in August 1992. In 1993 we expensed and collected from customers approximately $30 million of deferred 1991, 1992 and 1993 program costs. Over six years we are expensing and collecting from our customers $11 million of costs capitalized in 1992 and $37 million of costs capitalized in 1993. The 1993 expense related to these capitalized costs was $7 million. Municipal property and other taxes increased in 1993 due to the absence of tax abatements. In 1992 property taxes were reduced by $10.4 million of tax abatements in accordance with our 1989 settlement agreement. Our effective annual income tax rate for 1993 was 23.4% vs. 8.7% for 1992. Both rates were significantly reduced by adjustments to deferred income taxes of $20 million in 1993 and $23 million in 1992 made in accordance with the 1992 and 1989 settlement agreements. The 1992 rate was also reduced due to tax benefits of approximately $7 million resulting from mandated payments made in accordance with the 1989 agreement. Our adoption of a new accounting standard for income taxes in 1993 did not significantly affect earnings. We expect our effective tax rate to be close to the statutory rate in 1994. Interest charges and preferred and preference dividends Total interest charges decreased $3.8 million in 1993. Interest on long-term debt decreased primarily due to the refinancing of substantially all our first mortgage bonds in 1993 at lower interest rates, partially offset by higher amortization of redemption premiums. Other interest charges decreased due to a lower short-term debt level and lower short-term interest rates. Allowance for funds used during construction (AFUDC), which represents the
. financing costs of construction, decreased as a result of a lower AFUDC rate related to lower short-term interest rates.
Preferred and preference dividends decreased 5% due to the replacement of a preferred and a preference stock issue with less costly issues of preferred stock. 1992 Versus 1991 Earnings per common share were $2.10 in 1992 and $1.96 in 1991. The increase in earnings is primarily the result of a rate increase effective November 1991, incentive revenues earned from the performance of Pilgrim Station and lower income tax and interest expenses. These increases were partially offset by higher operations and maintenance and property tax expenses. We also had a one-time charge in 1992 for costs incurred for a deferred generating plant project. 21
)
l Operating revenues Operating revenues increased 4.2% over 1991 as follows: (in thousands) Retail electric revenues $27,672 Demand side management revenues 12,343 Wholesale and other revenues 1,881 Short-term sales revenues 15.356 Increase in operatinq revenues $57.252 Retail electric revenues increased $27.7 million. We received a $25 million rate increase effective November 1991 as part of the 1989 settlement I agreement. We also earned $8.2 million in incentive revenues in 1992 as a ! result of Pilgrim Station's capacity factor exceeding its target set in the agreement. Fuel and purchased power revenues decreased approximately $5 l million due to higher purchased power costs more than offset by higher I revenues received from short-term power sales as discussed below. In 1992 we began to receive revenues for the recovery of certain DSM program costs, lost base revenues and incentives. The 1992 revenues relate primarily to 1991 DSM programs. Our short-term power sales increased in 1992 as a result of our high generating unit availability and the greater power needs of other New England utilities. All revenues from short-term sales served to reduce fuel and purchased power billings to retail customers and had no effect on earnings. l { Operating expenses Purchased power expense increased $18 million in 1992 due to new long-term purchased power contracts. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues. Other operations and maintenance expense increased 2.3% due primarily to increases in employee benefit expenses and bad debts. Amortization of deferred nuclear outage costs in 1992 and 1991 includes amounts primarily related to the 1991 refueling outage at Pilgrim Station. In < 1991 we deferred approximately $23 million of refueling outage costs. We l began to expense these costs over five years in September 1991 as approved by our state regulators. Municipal property and other taxes increased 21% primarily due to a . reduction in residential and commercial real estate values caused by the I depressed economy. This resulted in higher tax rates applied to our personal property values. In accordance with our 1989 settlement agreement, municipal property tax expenses were reduced by tax abatements of $10.4 million in 1992- , and $13.6 million in 1991. ! Our effective annual income tax rate for 1992 was 8.7% vs.16.5% for 1991. Both rates were significantly reduced by adjustments to deferred income taxes of $23 million in 1992 and $13 million in 1991 made in accordance with the 1989 settlement agreement. We also received tax benefits in both years as a result of payments mandated by the agreement. 22 1
i i i Other income and expense in 1992 we expensed $8 million of costs previously invested in the proposed Edgar Energy Park generation project. This project was deferred indefinitely as additional generating capacity is not expected to be needed for several years. Interest charges and preferred and preference dividends Total interest charges decreased 4.6% primarily due to lower interest ' rates on our average short-term borrowings. AFUDC decreased 12.7% due to a lower AFUDC rate related to lower short-term interest rates. Preferred and preference dividends decreased approximately $1 million primarily due to the replacement of two preference stock series with less costly issues of preferred stock. Earnings per share Net income increased 13%. liowever, earnings per common share for 1992 increased only 7%, reflecting an increase in the weighted average number of common shares outstanding primarily a result of our 1991 and 1992 common stock issuances. Financial Condition Our 1992 settlement agreement provides us with increased revenues from retail customers over the three-year period ending October 1995. Additionally, a long-term purchased power contract with annual charges of approximately $60 million expired in October 1993 with no related change in revenues. We are limited to an annual rate of return on equity during the three-year period of 11.75%, excluding any penalties or rewards from performance incentives. Our continued ability to achieve or exceed the 11.75% rate of return on eqtity will be primarily dependent upon our ability to control costs and to carr. performance incentives from generation performance mechanisms specified in both the 1989 and 1992 settlement agreements. The most significant impact that incentives can have on our financial results is based on Pilgrim Station's annual capacity factor. Effective November 1993 an annual capacity factor between 60% and 68% will provide us with approximately $45 million of revenues through the performance adjustment charge. For each percentage point increase in capacity factor above 68%, annual revenues will increase by
$670,000. For each percentage point decrease in capacity factor below 60% (to ,
a minimum of 35%) annual revenues will decrease by $770,000. Pilgrim's capacity factor for the performance year ending October 1994 is expected to be approximately 81% (assuming normal operating conditions),.an increase over the i 66% capacity factor achieved in the performance year ended October 1993, as no refueling outage is scheduled for 1994. We earned approximately $40 million in performance charge revenues in the performance year ended October 1993. Our fossil generation unit performance can provide an increase or decrease of up to $4 million in revenues in each performance year, however, we do not expect any revenue adjustments from this mechanism. 23 4
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s Liquidity We meet our plant expenditure cash requirements primarily with internally generated funds. These funds (excluding payments made related to settlement agreements) provided for 74%, 90% and 89% of our plant expenditures in 1993, 1992 and 1991, respectively. Our current estimate of plant expenditures for 1994 is $233 million, including $20 million of nuclear fuel additions. These expenditures will be used primarily to maintain and' improve existing transmission, distribution and generation facilities. We also estimate capitalizable DSM expenditures to be $38 million in 1994, which will be collected from customers over six years. We do not expect plant expenditures, excluding nuclear fuel and DSM, to vary significantly from the 1994 amount in the four years thereafter. We have long-term debt and preferred stock payment requirements of $2 million in 1994, $102.6 million in 1995, and $103.6 million per year in 1996 through 1998. External financings continue to be necessary to supplement our internally generated funds, primarily the issuance of short-term commercial paper and bank borrowings. We currently have authority from our federal regulators to issue up to
$350 million of short-term debt. We have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At December 31, 1993 we had $204.1 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1993 our state regulators approved a financing plan allowing us to issue up to $1.1 billion in securities through 1994 and to use the proceeds to refinance long-term securities and short-term debt. At December 31, 1993 we had $245 million remaining' authorized to be issued under the plan which can be used to issue common stock, preferred stock and long-term debt. As a result of our refinancing activities in 1993 we expect to realize annualized savings of approximately $11.5 million. Refer to Note F to the consolidated 1 financial statements for specific information relating to our recent financing activities.
Outlook for the Future l Gectricity sales A significant portion of our electricity sales are made to commercial customers rather than industrial customers. As a result our sales have been only moderately impacted by the decline in the local Massachusetts economy. Our retail sales increased 1.2% in 1993 and we anticipate only slight growth in retail sales in the near term. Implementation of DSM programs, which are designed to assist customers in reducing electricity use, will result in lower growth in electricity sales. The 1992~ settlement agreement established annual DSM spending levels over $50 million through 1994. The agreement provides for collection from customers of certain costs primarily in the year incurred and others over a six-year period. We are also provided with incentives and recovery of lost revenues based on the actual reduction in customer electricity usage from these programs and a return on the costs that we recover over six years. Competition As we are operating in a time of increasing competition from other electric utilities and non-utility generators to sell electricity for resale, we have secured long-term power supply agreements with our four wholesale customers. Through these 24 t
i agreements our rates are set principally through the year 2002. We also obtained a new wholesale customer in 1993 for which we will provide up to 30 megawatts of ) contract demand power for ten years beginning November 1994, j Our state regulators require utilities to purchase power from qualifying non-utility generators at prices set through a bidding process. In June 1993 our state regulators ordered us to purchase 132 megawatts of power from an independent power producer, starting as early as 1995. We oppose this order since we do not believe we need any new power for several years. In July 1993 we asked the Massachusetts Supreme Judicial Court to reverse the order. We are currently awaiting a decision from the court. In addition, our state regulators have created an integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs with all other supplies of energy. We will submit an IRM filing in March 1994. Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. In 1993 we announced our goal of not seeking additional rate increases, other than those provided in the 1992 settlement agreement, for our residential, commercial and industrial customers until at least the year 2000. We plan to accomplish this by controlling costs and increasing operating efficiencies without sacrificing quality of service or profitability. The announcement reflects our-strong commitment to be a competitively priced reliable provider of energy. Non-uti1ity business In 1993 we created an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from our state regulators. We have authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management activities through its wholly-owned subsidiary Ener-G-Vision, Inc. and businesses involving electric transportation and the related infrastructure through its wholly-owned subsidiary TravElectric Services Corporation. We do not currently have a substantial investment in BETG and do not anticipate it significantly impacting our results of operations in the next several years. In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc., a manufacturer of ozone water treatment systems. The new entity, which will be known as REZ-TEK International Corp., will continue the business of producing a system that treats cooling water used in commercial and industrial air conditioning systems in an energy efficient and environmentally sound manner. Other Matters Environmental We are subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require that we modify our existing facilities or incur increased operating costs. In 1991 we entered into a consent order with the Massachusetts Department of Environmental Protection (DEP) and other interested parties to undertake certain improvements in the emission control systems at New Boston Station. These 25
improvements included the replacement of four existing chimney stacks with two taller stacks in order to improve the air quality in the vicinity of the station, and the installation of low nitrogen oxides burners. The capital cost of these modifications l along with other associated improvements has been approximately $78 million through 1993 with an additional $3 million expected to complete these projects in 1994. ] New Boston Station has the ability to burn natural gas, oil or both. As ) part of the DEP consent order we also agreed to operate the station using ] natural gas as fuel for a minimum of nine months per year beginning in April ( 1992. Beginning in April 1995 we will be required to operate the station 1 fueled exclusively by natural gas, except in certain emergency circumstances. l We have made arrangements for a nine month supply of natural gas to the station until April 1995 and are currently in the process of negotiating with l l natural gas suppliers and transporters concerning the economics and l availability of natural gas to New Boston on a year-round basis after that i time. Year-round gas supplies are currently not available to the station and, as a result, the outcome of our negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain. l The 1990 Clean Air Act Amendments will require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel-fired generating units. The reduction will be accomplished by restricting sulfur dioxide emissions through a market-based system of allowances. We believe that we will have allowances issued to us that are in excess of our needs and which may be marketable. Any gain from the sale of these may be subject to future regulatory treatment. Other provisions.of the 1990 Clean Air Act Amendments involve limitations on emissions of nitrogen oxides from existing generating units. Combustion system modifications made to New Boston and Mystic Stations, including the installation of the low nitrogen oxides burners at New Boston, will allow the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain air quality modeling studies, additional emission reductions may also be required by 1999. The extent of any additional reductions and the cost of any further modifications is uncertain at this time. State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the DEP. We are currently evaluating the potential costs i associated with the cleanup of sites where we have been identified as the owner or operator. There are uncertainties associated with these potential 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 certain other multi-party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings. We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disparal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. Refer to Note D to the consolidated financial statements for further discussion regarding LLW disposal. In recent years a number of published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields (EMF) associated 26
- _ - = - . _.- . . . -
a with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Some scientific reviews conducted to date by several state and federal agencies have suggested assoc ations between EMF and such health effects, while other studies have not substantiated such associations. We support further research into the subject and are participating in the funding of industry sponsored studies. We are aware that public concarn regarding EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities before regulators, or in requests for legislation or regulatory standards concerning EMF levels. We have not been significantly affected to date by these developments and cannot predict their potential impact on us, however, we continue to closely monitor all aspects of the EHF issue. Litigation in March 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal ounsel is vigorously defending 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. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings. Labor negotiations We began negotiations involving our labor contracts in early February 1994. These contracts expire on May 15, 1994. We anticipate favorable resolution of these negotiations prior to that date, New accounting pronouncements We will adopt Statement of Financial Accounting Standards (SFAS) No, 112, Employers' Accounting for Postemployment Benefits, and SFAS No.115, Accounting for Certain Investments in Debt and Equity Securities, in the first quarter of 1994. Refer to Notes I and J to the consolidated financial statements for further discussion of these pronouncements. 27 , I
,c-, ~-p .- m ,
j Item 8. Financial Statements and Supplementary Financial Information Consolidated Statements jof. Income-- years ended December 31, Jin thousands, except earninas per share) 1993 1992 1991 Doeratino revenues $1.482.253 $1.411.753 $1.354.501 Operating expenses: Fuel 176,366 195,873 200,912 Purchased power 364,482 356,931 338,994 Other operations and maintenance 406,271 379,350 370,758 Depreciation and amortization 137,722 129,045 126,151 Amortization of deferred cost of cancelled nuclear unit 0 24,381 24,381 Amortization of deferred nuclear outage costs 6,546 4,901 2,443 Demand side management programs 37,504 8,221 1,674 Taxes - property and other 93,102 80,426 66,216 income taxes 34.941 11.725 17.111 Total operatina expenses 1.256.934 1.190.853 1.148.640 Operating income 225,319 220,900 205,861 Other income (excense), net 589 (2.074) 5.684 Op3ratina and other income 225.908 218.826 211.545 Interest charges: Long-term debt 104,375 106,850 108,912 Other . 9,778 12,525 16,947 Allowance for borrowed funds used durina construction (6.463) (7.847) (8.984)' Total interest charaes 107.6.20 111.528 116.875
- et income 118,218 107,298 94,670-Preferred and preference dividends provided 15.705 16.550 17.611 Sclance available for common stock $ 102,513 $ 90.748 $ 77,059 Common shares outstanding (weighted average) 44,959 43,144 39,348 Farninas per share of common stock $ 2.28 $ 2.10 $ 1.96 Consolidated Statements of Retained Earnings years ended December 31, (in thousands) 1993 1992 1991 Balance at beginning of year $192,948 $174,477 $161,143 Net income 118.218 107.298 94.670 Subtotal 311.166 281.775 255.811 Cash dividends declared:
Preferred stock 15,705 14,923 9,476 Preference stock 0 1,953 8,135 Common stock 77.169 71.951 63.725
. Subtotal 92.874 88.827 81.331 Balance at end of year $218.292 $192.948 $174.477 The accompanying notes are an integral part of the consolidated financial statements.
28
.Consolida'ted Balance Sheets December 31,
' fin thousands) 1993 1992 Assets Property, plant and equipment, at original cost: Utility plant in service $3,904,776 $3,629,727 Less: accumulated deprecialian 1.258.359 $2.646.417 1.177.294 12.452.433 Nuclear fuel 273,867 270,420 Lqss: accumulated _ amortization 220 477 53.390 201.978 581142 Construction work in proaress 144.835 182.458 lotal 2,844,642 2,703,333 Investments in electric companies, at equity 24,292 25,398-Nuclear decommissioning fund, at cost 66,060 50,871 Current assets: Cash and cash equivalents 8,768 3,947 Accounts receivable 171,098 185,563 Accrued unbilled revenues 29,823 28,564 fuel, materials and supplies, at average cost 79,381 93,931 Prepaid expenses and other 9.738 298.808 6.644 318.649 Deferred debits: Power contracts 36,275 43,717 Cancelled nuclear unit 19,067 19,067 Nuclear outage costs 25,524 17,970 Pension and postretirement costs 24,416 10,449 Redemption premiums 59,116 40,506 Regulatory asset-income taxes, net 26,916 0 Other 52.1f 3 l_43.497 64.274 195.981 Total assets ,
$.3.477,299__ $3t294.234 Capitalization and liabilities Common stock equity $ 876,479 $ 840,312
. Cumulative preferred stock: Non-mandatory redeemable series 123,000 123,000 Mandatory redeemable series 96,000 98,000 .First mortgage bonds 40,000 631,825 ' Sewage facility revenue tonr!s, net 32,497 24,248 Debentures 1,200,000 385,000 Unsecured medium-term notes 0 50,000 ' Current liabilities: Long-term debt / preferred stock due within one year $ 2,000 $ 6,800 Notes payable 204,151 275,500 Accounts payable 144,760 154,251 Interest accrued 25,467 21,497 Dividends payable 22,69G 22,192 Other 27.336 426.410 12.482 492.722 Deferred credits: Power contracts 36,275 43,717 Accumulated deferred income taxes 484,796 448,720 Accumulated deferred investment tax credits 71,140 75,213 Nuclear decommissioning reserve 73,744 57,165 Other 16.938 682.913 24.312 649.127 Commitmen1 Land continaencies - Total _gapitalization and liatti_lities_ $3,477.299 $3,294, L34 The accompanying notes are an integral part of the consolidated financial statements. 29
l
? consolidated Statements of Cash flows .
years ended December 31, I (in thousandO 1993 1992 1991 ) Cash flows from operating activities: )
$107,298 $ 94,670 Net income $118,218-Adjustments to reconcile net income ;
to net cash provided by operating activities: Depreciation 130,074 123,243 121,572 ; Amortization of nuclear fuel 21,816 25,473 19,869 R Amortization of deferred cost of cancelled nuclear unit, net 0 22,340 21,112 Other amortization 9,433 2,132 1,696 Allowance for funds used during construction (6,463) (7,847) (8,984) Deferred income taxes 10,303 17,165 24,476 investment tax credits (4,073) (4,273) (4,290) (Deferral) amortization of nuclear outage costs, net (7,554) 4,901 (22,062) Net changes in: Accounts receivable and accrued unbilled revenues 13,206 (18,188) (3,519) Fuel, materials and supplies 9,722 (2,330) 12,716 ( Accounts payable (9,491) 41,899 -(19,510) ' Rate and contract settlements (175) (31,363) (44,546) Other current assets and liabilities 16,408 (2,565) 3,079 , Other. net (4.958) (13.777) (24.588) l Net cash orovided by oDeratina activities 296.466 2641Q8 171.691 Cash' flows provided (used) by investing activities: Plant and nuclear fuel (excluding AFUDC) (253,885) (231,025) (214,213) i Capitalized demand side management costs (37,156) (11,469) 0 Decommissioning fund (15,189) (7,210) (5,896) i Investments in electric companies 1.106 _1.836 (1.515) 1 F h aJh used by investina activities (305.124) (247.868) (221.624) l Cash flows provided (used) by financing activities: l Issuances: Common stock - 10,823 68,345 68,800 Preferred stock 40,000 40,000 50,000 Long-term debt 815,000 60,000 146,120 Redemptions: Debt retirements (648,625) (123,600) (118,600) Preferred / preference stock (40,000) (40,333) (50,000) ' Net change in short-term debt (71,349) 65,200 35,770 Dividends paid (92.370) (86.1841 (79.545) Net cash orovided fused) by financina activities _13.479 (16.572) 52.545 Net increase (decrease) in cash and cash equivalents 4,821 (332) 2,612 Cash and cash equivalents at the beainnina of the year 3.947 4.279 1.667 Cash and cash eauivalents at the end of the Year 5 8,768 $ 3.947 5 4.279 Cash paid during the year for: Interest, net of amounts capitalized $103,720 $113,076 $115,488 Income taxes $ 30,305 $ 10,095 $ 18,979 The accompanying notes are an integral part of the consolidated financial statements. 30 i
iNotes to Consolidated Financial Statements Nste A. Significant Accounting Policies
.1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly-owned subsidiaries, Harbor Electric Energy Company and Boston Energy Technology Group. All significant intercompany transactions have 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 Commission. The financial statements comply with generally accepted accounting principles.
- Certain prior period amounts on the financial statements were reclassified to conform with current presentation.
- 2. Revenue Recognitton We record revenues for electricity used by our customers, but not yet billed, in order to more closely match revenues with expenses:
- 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for all fuel costs, the capacity portion of some purchased power costs and some transmission costs to be billed to customers monthly using a forecasted rate. The difference between actual and estimated costs is included in accounts receivable on our consolidated balance sheets until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.
- 4. Depreciation and Nuclear fuel Amortization Our physical property was depreciated on a straight-line basis in 1993, 1992 and 1991 at composite rates of approximately 3.09%, 3.36% and 3.41% per year, respectively, 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 salvage value, is charged to accumulated depreciation.
The 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 the decontamination and decommissioning of the United States enrichment facilities used in the production of nuclear fuel. These costs are recovered from our customers through fuel charges.
- 5. Allowance for Funds Used During Construction (AFUDC) }
1 AFUDC represents the estimated costs to finance plant expenditures. In accordance with : regulatory accounting, AFUDC is included as a cost of utility plant. AFUDC is not an item of l current cash income, but payment is received for these costs from customers over the service life of the plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1993, 1992 and 1991 were 3.62%, 4.48%, and 6.85%, respectively, and represented only the cost of debt. 31 i
- 6. Cash and Cash Equivalents
& Cash and cash equivalents are comprised of highly liquid securities with maturities of three months or less.
- 7. Allowance for Doubtful Accounts Our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery l of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
- 8. Deferred Debits Deferred debits consist primarily of costs incurred which will be collected from customers through future charges in accordance with agreements with our state regulators.
These costs will be expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. A portion of these costs is currently being charged to and collected from customers.
- 9. Amortization of Discounts, Premiums and Redemption Premiums on Securities We expense discounts, premiums, redemption premiums and related expenses associated with issuances of securities or refinancing of existing securities in equal annual installments over the life of the replacement securities subject to regulatory approval.
Note B. Retail Settlement Agreements In 1992 and 1989 our state regulators, the Massachusetts Department of Public Utilities, approved three-year settlement agreements relating to our rate case proceedings. These agreements provided for retail rate increases, accounting adjustments and demand side management program expenditures; 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 affect our contract or wholesale power rates charged to other utilities, which are regulated by our federal regulators, the Federal Energy Regulatory l Commission. Note C. Income Taxes In the first quarter of 1993 we prospectively adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). This required us to change our methodology of accounting for income taxes from the deferred method to an asset and liability approach. The deferred method of accounting was based on the tax effects of timing differences between income for financial reporting purposes and taxable income. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded a net regulatory asset of $26.9 million and a corresponding net increase in accumulated deferred income taxes as of December 31, 1993. The regulatory asset represents the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income taxes on our consolidated balance sheet at December 31, 1993 l includes $587.8 million of gross deferred income tax liabilities net of $103.0 million of gross 32 {
)
l
~ deferred income tax assets. We have approximately $19 million of alternative minimum tax -carryforwards available at December 31, 1993. The major components of accumulated deferred income taxes are a result of differences between book and tax expenses relating to property, plant and equipment. Deferred income tax expense reflected in our consolidated income statements is incurred when_certain income and expenses are reported on the tax return in different years than reported in the financial statements. Investment tax credits are included in income over the ' estimated useful lives of the related property. Components of income tax expense are as follows:
- (in thousands) 1993 1992 1991 Excess tax depreciation over book depreciation $12,382 $9,765 $10,802 Deferred fuel expense (3,142) 2,587 56 Debt portion of allowance for funds used during construction 2,114 2,495 2,856 Massachusetts corporate franchise tax 5,089 6,134 7,140 Deferred nuclear outage expense 2,472 (1,558) 7,014
' Cost of removal 3,272 6,904 4,277 = Rate end contract settlements 0 10,013 10,196 Hunicipal property taxes (489) 3,351 3,745 Demand side management programs 3,775 2,978 2,256 -Cancelled nuclear unit 0 (4,621) (8,998) Reversal of deferred taxes-settlement agreement, net (19,231) (23,000) (13,000) Adjustment of prior year income tax accrual (2,154) 4,134 2,563 Call' premiums on refunded bond issues 5,821 1,029 (288) l Trust contributions-postretirement benefits 3,451 0 0 Q1her (3.057) (3.828) (id151 Subtotal deferred income taxes 10,303 16,383 23,224 Current income tax expense 28,711 (385) (1,823) Investment tax credits (4.013) (4.273) (4.290) Provision for income taxes 34.941 11.725 17.111 . Taxes on other income: Current 1,205 (2,348) 405 Deferrad 0 782 1.25] Subtotal 1 205 (1.566) 1.657 Total income tax expense $36,146 $10.159 $ 18.768 The effective income tax rates reflected in the consolidated financial statements and the 1 reasons for their differences from the statutory federal income tax rate are explained below: l l 1993 1992 1991 l l Statutory tax rate 35.0% 34.0% 34.0% State income tax, net of federal income tax benefit 4.2 3.9 4.1 Investment tax credits (2.6) (3.6) (3.8) , Municipal property tax adjustment (0.6) (1.6) (1.6)- 1 Adjustment of deferred taxes on cancelled nuclear. unit - 2.7 - Reversal of deferred taxes-settlement agreement (13.0) (19.6) (11.5) Federal tax benefit of mandated payments from settlement agreements - (6.2) (3.3) , Other 0.4 (0.9) (1.4) Effective tax rate 23.4% 8.7% 16.5% 33
4 Note D. Estimated Future Costs of Disposing of Spent Nuclear Fuel and Retiring Nuclear Generating Plants The existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. We have a request for a license amendment pending before the Nuclear Regulatory Commission (NRC) to allow modification of the storage facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. The NRC is reviewing our request and we expect approval in 1994. At that time we will initially modify the facility to provide spent fuel storage capacity through approximately 2003. It is the ultimate responsibility of the United States Department of Energy (00E) to permanently dispose of spent nuclear fuel as required by the Nucigar Waste Policy Act of 1982. We currently pay a fee of $1.00 per net megawatthour sold fr'm o Pilgrim ' Station generation under a nuclear fuel disposal contract with the D0E. The fee is collected from customers through fuel charges. When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. During rate proceedings we provided our regulators a 1991 study documenting a cost of $328 million to decommission the plant. The study is based on the " green field" method of decommissioning, which provides for the plant site to be completely restored to its original state. We are expensing these estimated decommissioning costs over Pilgrim's expected service life. The 1993 expense of approximately $13 million is included in depreciation expense on the consolidated income statements. We receive recovery of this expense from charges to our retail customers and from other utility companies and municipalities who 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 for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning fund balance and nuclear decommissioning reserve, thus reducing the amount to be collected from customers. The 1991 decommissioning study has been partially updated for internal planning purposes to evaluate the potential financial impact of long-term spent fuel storage options resulting from delays in DOE spent fuel removal on the estimated decommissioning cost. The partial update indicates an estimated decommissioning cost of approximately $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. 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. We are also an investor in two other domestic nuclear units. Both of these units receive through the rates charged to their customers an amount to cover the estimated cost to dispose of their spent nuclear fuel and to retire the units at the end of their useful lives. We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. We have access to the South Carolina site through July 1994, but do not presently believe that disposal site access will be provided after that date. Although legislation has been enacted in Massachusetts establishing a regulatory method for managing the state's LLW including the possible siting, licensing and construction of a LLW disposal facility within the state, it appears unlikely that such a facility will be constructed in a timely manner. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management method, we continue to monitor the situation and are investigating other available options, including the possibility of on-site storage. 34
. l Cote E. Cancelled Nuclear Unit In May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear unit over approximately eleven and one-half years in accordance with an order received from state regulators. We did not expense any of these costs in 1993. Instead, the remaining balance of approximately $19 million at December 31, 1993 and 1992 will be expensed in 1994 and/or 1995 as approved by our state regulators in our 1992 settlement agreement.
l l 35
Note F. Capital Stock and Indebtedness Cepital. Stock . December 31, Jdollars in thousands, except oer share amounts) 1993 1992 19j!1 Comon stock equity: f Common stock, par value $1 per share, 100,000,000 shares l authorized; 45,129,227, 44,763,055 and 42,047,356 i shares issued and outstanding $ 45,129 $ 44,763 $ 42,047 ) Premium on common stock 612,653 602,196 536,567 ' Retained earnings 218,292 192,948 174,477 SJirolus invested in plal)_t 405 405 405 1 Total common stock equity $876.479 $840.312 $753.496 l l Cumulative preferred stock: Par value $100 per share, 2,410,000 shares currently authorized; issued and outstanding: Non mandatory redeemable series: 1 i Current Shares Redemption Series Outstandina Price / Share ; 4.25% l80,000 $103.625 $ 18,000 $ 18,000 $ 18,000 i 4.78% 250,000 $102.800 25,000 25,000 25,000 7.75% 400,000 - 40,000 0 0 8.25% 400,000 - 40,000 40,000 0 8.88% 0 - 0 40.000 40.000 Total non-mandatory redeemable series $j2h000 $12.3.000 $_81 400 Mandatory redeemable series: Current Shares Series O W 1andina 7.27% 480,000 $ 48,000 $ 48,000 $ 50,000 8.00% 100.000 50.000 50.000 50.000 Total mandatory redeemable series 98,000 98,000 100,000 Less: dur within one year 2.000 0 0 Total mar.datorY redegable series, net $ 96.000 $ 98.000 $100.000 Cumulative preforence stock: Par value $1 per share, 8,000,000 shares authorizco; none currently issued and outstanding Non-mandatory redeemable series:
$1.46 series $ 0 $ 0 $ 2,675 Premium on $1.46 series 0 0 35.653 Total preference stock $ 0 J 0 $ 38.333 Dividends Declared per Share comon stock $1.715 $1.655 $1.595 Preferred stock:
4.25% series $4.253 $4.250 $4.250 4.78% series 4.785 4.780 4.780 ) 7.27% series 7.270 7.270 7.270 l 7.75% series 5.707 0 0 8.00% series 8.000 8.000 1.337 8.25% series 8.250 5.278 0 8.88% series 2.220 8.880 8.880 Preference stock:
$1.46 series $ 0 $0.365 $1.460 Stated rate auction preference stock 0 0 6.900 36
t.. In"debtidness December 31, (dollars -in thousands 1 1993 1992 ; long-term debt: First mortgage bonds: Interest Series Rate Mal _urity I 4.750% 1995 $ 0 $ 25,000 J 6.125% 1997 0 40,000 K 6.875% 1998 0 50,000 .; L 9.000% 1999 0 50,000 ' H 9.375% 2000 0 60,000 N 8.125% 2001 0 75,000 S Variable 2002 25,000 25,000 Q 9.750% 2003 0 59,375 R 10.950% 2004 0 44,250 P 9.250% 2007 0 60,000 U 10.250% 2014 15,000 15,000 W 9.500% 2016 0 135.000 Total first mortgage bonds 40,000 638,625 Less: due within one year 'O 6.800 Total first mortgage bonds, not $ 40,000 $631,825 l Sewage. facility revenue bonds $ 36,300 $ 36,300 Less: funds held by trustee 3.803 12.052 Total sewage facility revenue bonds, net $ 32.497 $ 24,248 l Debentures: 8.875%, due 1995 $ 100,000 $100,000 5.125%, due 1996 100,000 0 ! 5.700%, due 1997 100,000 .0 1 5.950%, due 1998 100,000 0 !' 6.800%, due 2000 65,000 0 6.050%, due 2000 100,000 0 6.800%, due 2003 150,000 0 9.875%, due 2020 100,000 100,000 9.375%, due 2021 125,000 125,000 8.250%, due 2022 60,000 60,000 7.800%. due 2023 200.000 0 , Total debentures $1.200.000 $385,000 I nsecured medium-term notes $ 0 $ 50.000 l Short-term debt: Notes payable: Bank loans $ 106,501 $162,500 Commercial nacer 97.650 113.000 Total notes payable $ 204.151 $275,500 37
- 1. Common Stock Since December 31, 1990, we issued the following shares of common stock:
Number Total Premium on l Lin thousands) of Shares Par Value Common Stost ) Balance December 31, 1990 38,998 $194,993 $314,822 ' Dividend reinvestment plan 449 2,181 6,844 Change in par value of common stock (a) 0 (157,727) 157,727 i New issue (b) 2.600 2.600 Sldli Balance December 31, 1991 42,047 42,047 536,567 Dividend reinvestment plan 416 416 9,658 New issue (c) 2.300 2.300 55.971 Balance December 31, 1992 44,763 44,763 602,196 Dividend reinvestment plan (d) 366 316 10.4EZ Balance December 31. 1993 45.129 $ 45.129 $612,653 (a) In November 1991 our Articles of Organization were amended to increase authorized common stock from 50 million to 100 million shares and reduce the par value from
$5 to $1 per common share.
(b) We used the not proceeds of the 1991 common stock issuance to retire $55 million of Series X, 11% first mortgage bonds. (c) We used the net proceeds of the 1992 common stock issuance to reduce short term debt. (d) At December 31, 1993, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 815,170 shares.
- 2. Cumulative Non-Mandatory Redecmable Preferred and Preference Stock In June 1992 we issued 400,000 shares of 8.25% cumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in June 1997. These shares were sold in the form of 1.6 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 $1.46 series cumulative non-mandatory redeemable preference stock.
In May 1993 we issued 400,000 shares of 7.75% cumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in May 1998. These shares were sold in the form of 1.6 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 cumulative non-mandatory redeemable preferred stock.
- 3. Cumulative Mandatory Redccmable Preferred Stock.
The 480,000 shares of our 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $104.36. The redemption price declines annually each May to par value in May 2002, in May 1993 the stock became subject to sinking fund requirements to retire 20,000 shares at $100 per share plus accrued dividends each year through May 2002. In 1992 we purchased 20,000 shares at a discount on the.open market which satisfied the mandatory sinking fund requirement for May 1993. Beginning in 1993, we have the non-cumulative option each May to redeem additional shares, not to exceed 20,000, for the sinking fund at $100 per share plus accrued dividends. 38
We are not able to redeem any part of our 500,000 shares of $100 par value 8% series
~!
l cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share, plus accrued dividends. j
- 4. Long-Term Debt Substantially all our property, plant, equipment, materials and supplies are subject to lien under the terms of our Indenture of Trust and First Mortgage dated December 1, 1940, and its supplements. Currently only the outstanding Series S and U first mortgage bonds are subject to the terms of the indenture.
The aggregate principal amounts of our first mortgage bonds, debentures, and sewage facility revenue bonds (including sinking fund requirements) due in 1994 and 1995 are $0 and
$100.6 million, respectively, and $101.6 million per year in 1996 through 1998.
Our first mortgage bonds, Series S, adjustable rate due 2002, paid interest at 9.2% per
- year for the period January 15, 1993 through January 14, 1994. The rate is adjusted annually and is based upon the ten-year constant maturity Treasury rate as published by the Federal
. Reserve Board. The interest rate for the period January 15, 1994 through January 14, 1995 is 8.2%. t in September 1992 we issued $60 nillion of 8.25% debentures which mature in September 2022. The debentures are redeemable at prices decreasing from 103.78% of par beginning in i September 2002, to 100% of par beginnirg in September 2012. We used the net proceeds from the . sale to reduce short-term debt. In October 1992 we redeemed the remaining balance of $45 million Series X first mortgage bonds. In February 1993 we issued $65 million of 6.8% debentures due in 2000. We used the
. proceeds of this issue to reduce short-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 of itwelve outstanding series of first mortgage bonds and reduce short-term debt. The debentures
!were issued in five separate series with interest rates ranging from 5.125% to 7.8% and
, maturing between 1996 and 2023. The 5 1/8% debentures due 1996, 5.70% due 1997, 5.95% due 1998
.and 6.80% due 2003 are not redeemable prior to maturity. The 7.80% debentures due 2023 are
- first redeemable in March 2003 at a redemption price of 103.73%. The redemption price decreases annually each March to par value in March 2013. There is no sinking fund requirement for any series of the debentures.
In August 1993 we issued $100 million of 6.05% debentures due in 2000. We used the . proceeds from this sale to reduce short-term debt. These debentures are not redeemable prior 'to maturity and have no sinking fund requirements. We redeemed $50 million of 9.65% medium-term notes in September 1992 and $50 million of 9.75% medium-term notes in September 1993. ' S. Scwage facility Revenue Bonds In December 1991, Harbor Electric Energy Company (HEEC), a wholly-owned subsidiary, issued $36.3 million of long-term sewage facility revenue bonds. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from
' the bonds was used to retire $21 million of short-term sewage facility revenue bonds at l maturity. The remainder of the proceeds, which is on deposit with the trustee, is being used to finance the construction of HEEC's permanent substation located on Deer Island (in Boston 39
Harbor) and to fund an amount which must remain in reserve with the trustee. If HEEC should have insufficient funds to pay certain costs on a timely basis or be unable to meet certain net worth requirements, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $7 million.
- 6. Short-Term Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have authority to issue up to $350 i l
million of short-term debt. l We have a $200 million revolving credit agreunent with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this i agreement we are required to maintain a common equity ratio of not less than 30% at all times. 1 Commitment fees must be paid on the unused portion of the total agreement amount. Information regarding our short-term borrowings,- comprised of bank loans and commercial paper is as follows: (thousands of dollarsi 1993 1992 1991 Maximum short-term borrowings $320,000 $314,998 $324,400 Weighted average amount outstanding $220,149 $233,286 $221,481 l Weighted average interest rates, excluding commitment fees 3.4% 4.1% 6.4% Note G. Fair Value of Securities The following methods and assumptions were used to estimate the fair value of each class i of securities for which it is practicable to estimate the value: I Nuclear decommissioning fund The fair value of $70.1 million is based on quoted market prices of securities held. Cash and cash equivalents The carrying amount of $8.8 million approximates fair value due to the short-term nature of these securities. Mandatory reaeemable cumulative preferred stock, first mortgage bonds, sewage facility revenue bonds and debentures 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, 1993 are as follows: Carrying Fair
.(in thousandsl Amount Value Mandatory redeemable cumulative preferred stock $ 98,000 $ 105,935 First mortgage bonds 40,000 44,132-Sewage facility revenue bonds 36,300 40,528 Debentures 1.200.000 1.237.924 I
Note H. Commitments and contingencies
- 1. Capital Commitments At December 31, 1993, we had estimated contractual obligation., for plant and equipment of ;
approximately $71 million. 40 1 l j
- 2. Lease Commitments We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both noncancelable leases and transmission agreements for the years after 1993 are as follows:
fin thousandsl 1994 $ 27,375
'1995 23,878 1996 21,299 '1997. 19,217 1998 17,969 ' Years thereafter 139.474 Total $249,212 Me will capitalize a portion of these lease rentals as part of plant expenditures in the
- future. Our total expense for both lease rentals and transmission agreements for 1993, 1992 and 1991 was $30 million, $30 million and $33.5 million, respectively, net of capitalized expenses of $5 million, $5 million, and $4.8 million, respectively.
- 3. Hydro-quebec We have an approximately 11% equity ownership interest in two companies which own and
, operate transmission facilities to import electricity from the Hydro-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 who do not meet certain credit criteria and are compensated accordingly. At ' December 31, 1993, our portion of these guarantees was approximately $22 million.
- 4. Yankee Atomic D ectric Company In February 1992 the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and, in time, decommission that facility. We relied on Yankee Atomic for less than one
- percent of our system capacity. We have a 9.5% stock investment of approximately $2 million in Yankee Atomic.
In 1993 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 approximately $33 million as of December 31, 1993. This estimate is recorded on our consolidated balance sheet as a power contract liability in deferred credits. An offsetting power contract regulatory asset is _ included in deferred debits as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement.
- 5. Nuclear insurance The federal Price-Anderson Act currently provides $9.4 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 $8.8 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 116 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 new commercial nuclear units are licensed and existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and 41
legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional five percent of the maximum -retrospective assessment. We have 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 3r decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is approximately $14.6 million under both the replacement power and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses 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. Litigatton In March 1991 we were named in a lawsuit alleging discriminatory employment practices '
under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel is vigorously defending 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. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings.
- 7. Hazardous Waste State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the '
i Massachusetts Department of Environmental Protection. We are currently evaluating the potential costs associated with the cleanup of sites where we have been identified as the owner i or operator. There are uncertainties associated with these potential costs due to the l 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 certain other multi party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings. I I Note I. Pensions, Other Postretirement and Postemployment Benefits .
- 1. Pensions j We have a noncontributory funded retirement plan, with certain features that allow voluntary contributions. Benefits are based upon an employee's years of service and compensation during the last years of employment. Our funding policy is to contribute each year an amount that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Plan assets are primarily equities, bonds, insurance contracts and real estate.
42
P Net pension cost included the following components: 1993 1992 1991
- fin thousands)
Current service cost - benefits earned $11,734 $10,683 $ 8,567 Interest cost on projected benefit obligation 33,181 32,287 29,817 Actual return on plan assets (44,470) (23,281) (60,873) Net amortization and deferral 8.528 (13.549) 26.811 . Net pension cost (a) $ 8,973 $ 6,140 $ 4.322
- (a) In accordance with an agreement with our state regulators, we deferred our net pension costs in excess of the annual funding amounts and will recover these costs from customers over time. Net pension costs recorded as expense were approximately $5 million in 1993 and $0 in 1992 and 1991.
We used the following assumptions for calculating pension cost: 1993 1992 1991 Discount rate 8.25% 8.25% 9.00% Expected long-term rate of return on assets 10.0P% 10.00% 10.00%
- [pmoensation increase rate 4 . 5'1% 4.50% 4.50%
Me changed our discount rate assumption to 7.0% for calculating pension cost effective January 1994. The plan's funded status at December 31,1993 and 199;! was as follows: Jin thousands) _ 199) __1292 Actuarial present value of benefit obligations: Accumulated benefit obligation, including vested benefits of $384.150 anc $322,836 $400,895 $339.035 Plan assets at fair value $394,233 $392,407 Projected obligation for service rendered to date (509 661) (418.312) Projected benefit obligation in excess of plan assets (115,428) (25,905) Unrecognized prior service cost 8,139 8,817 Unrecognized net (gain) loss 75,352 (6,810) Unrecoanized net oblication - 9.932 10.866 Net pension liability $(22,005) $(13.032) We used the following assumptions for calculating the plan's year-end funded status: 1993 1992 Discount rate 7.00% 8.25% Comnensation increase rate 4.50% 4.50%
- 2. Other Postretirement Benefits In addition to pension benefits, we also currently provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements.
Effective January 1993 we adopted Statement of Financial Accounting Standards No.106, Employer's Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). This requires us to record a liability during the working years of employees for the expected costs of providing their postretirement benefits other than pensions (PB0Ps). Prior to 1993 our 43
l policy was to record the cost of PBOPs when paid. Our transition obligation on January 1, 1993 was approximately $183 million, which we elected to recognize over 20 years as permitted by I SFAS 106. Our total cost of PBOPs under SFAS 106 in 1993 was approximately $28 million, an increase of approximately $18 million over costs incurred under our prior method of accounting i for PB0Ps. Our 1992 settlement agreement provides us with a phase-in of a portion of the. j increased costs and allows us to defer the additional costs in excess of the phase-in amounts i to the extent that we fund an external trust. In December 1993 we deposited $18 million on a tax deductible basis into external trusts for the payment of PB0Ps. Accordingly, in 1993 we , recorded an expense of approximately $16 million, reflecting the amount of cost recovery from ! customers, and deferred approximately $12 million for future recovery. We capitalized approximately 19% of these costs. Postretirement benefits cost consisted of the following in 1993: Jin thousands) Current service cost - benefits earned $ 4,351 Interest cost on transition obligation 14,286 Amortization of transition oblication 9.151 Net postretirement benefits cost $27.788 We used an 8.0% weighted average discount rate and 4.5% rate of compensation increase assumption for calculating the transition obligation and the 1993 postretirement benefits cost. Our expected long-term rate of return on assets is 9.0%. We also assumed a 12.5% health care cost trend rate. Effective January 1, 1994 we changed the discount and health care cost trend rates to 7.0% and 9.0%, respectively, in order to more accurately estimate our future benefit payments. The health care cost trend rate is assumed to decrease by one percent each year to 5% in 1998 and years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. For example, a one percent increase in the rate would increase the total service and interest costs in 1993 by approximately 16% and would increase the accumulated obligation at December 31, 1993 by approximately 13%. The postretirement benefits program's funded status at December 31, 1993 was as follows: fin thousands) Trust assets at fair value $ 18,016 Accumulated obligation for service rendered to date from: Retirees $(75,216) Active employees eligible to retire (64,880) Active emoloyees not eliaible to retire (73.285) (213.381) Accumulated benefit obligation in excess of trust assets (195,365) Unrecognized loss 21,497 Unrecoanized net oblication 173.868 Net postretirement benefits liability $ 0 The trust assets consist of money market funds at December 31, 1993.
- 3. Postemployment Benefits Statement of Financial Accounting Standards No.112, Employers' Accounting for Postemployment Benefits, will be effective for the first quarter of 1994. This statement will require us to record a liability computed on an actuarial basis for the estimated cost of providing postemployment benefits. Postemployment benefits provided to former or inactive employees, their beneficiaries and covered dependents include salary continuation, severance benefits, disability-related benefits (including workers' compensation), job training and counseling and continuation of health care and life insurance coverage. We currently recognize 44
1 i l l the cost of these benefits primarily as claims are paid. We do not anticipate a material effect on net income from adopting this statement. Note J. New Accounting Pronouncement We will adopt Statement of Financial Accounting Standards No.115, Accounting for Certain ' Investments in Debt and Equity Securities, in the first quarter of 1994. This statement may require us to classify the investments in our nuclear decommissioning fund on our consolidated ~ balance sheet based on how long we intend to hold the individual securities. These investments may be classified as "available for sale" and we may also be required to report any unrealized gains and losses on the investments as a separate component of shareholders' equity. We do not expect the adoption of this statement to have a material effect on shareholders' equity. Note K. Long-Term Power Contracts
- 1. Long-Term Contracts for the Purchase of Electricity Be purchase electric power under several long-term contracts for which we pay 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 statements. Information relating to these contracts as of December 31, 1993 is as -follows: i I l l l 45
, _-_ - = _ - . . - . ,
l procortionate share (in thousands) i Units of 1993 1993 Interest Debt Contract Capacity Minimum Portion of Outstanding Expiration Purchased (a) Debt Minimum Through Cont. ! Contract Date % MW Service Debt S_ervice Exo. Date Canal Unit 1 2001 25.0 142 3 781 $ 314 $ 2,118 Mass. Bay Trans- l portation Authority 2005 100.0 35 (b) (b) (b) Connecticut Yankee Atomic 2007 9.5 56 2,579 1,670 15,898 Ocean State Power - Unit 1 2010 23.5 65 5,323 3,948 22,747 Ocean State' Power - Unit 2 2011 23.5 65 4,422 3,376 19,401 Northeast Energy Associates (c) (c) 219 (c) (c) (c) L'Eneraia 2013 73.0 64 (d) (d) (d) Total 646 513.105 $9.308 560.164 (a) The Northeast Energy Associates contract represents 6.4% of our total system generation - capability. The remaining units listed above represent 12.6% in total. (b) We are required to pay the greater of $22.00 per kilowatt-year or 90% of the New England Power Pool capability responsibility adjustment charge up to $63.00 per kilowatt-year times the qualified capacity (currently rated at 33.6MW) plus incremental operating, maintenance and fuel costs. The total charges for this contract in 1993 were approximately $2 million. (c) We purchase approximately 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for this energy based on a price per kWh actually > received. We do not pay a proportionate share of the unit's capital and fixed operating costs. The total charges for these contracts in 1993 were approximately $116 million. (d) The l'Energia contract started in March 1993. We purchase 73% of the energy output of this unit. We pay for this energy based on a price per kWh actually received. The total - charges under this contiact for 1993 were approximately $15 million. Our total fixed and variable costs for these contracts in 1993, 1992 and 1991 were approximately $225 million, $217 million and $154 million, respectively. Our minimum fixed payments under these contracts for the years after 1993 are as follows: fin thousands) 1996 5 69,432 1995 72,418 1996 75,376 1997 71,147 1998 72,429 Years thereafter 725.236 Total $1.086,038 Total present value $ 558.600 46
i l
. Long-Term Power Sales In addition to our power sales to four wholesale customers, we sell a percentage of ilgrim Station's output to other utilities under long-term contracts. Information relating to hese contracts is as follows:
Contract Expiration Units of Capacity Sold hntract Customer Date % MW ommonwealth Electric Company 2012 11.0 73.7 Hontaup Electric Company 2012 11.0 73.7 Various municipalities 2000fa) 3.7 25.0 Total 25.7 172.4 (a) Subject to certain adjustments. Under these contracts, the utilities pay their proportional share of the costs of )perating Pilgrim Station and associated transmission facilities. These costs include )peration and maintenance expenses, insurance, local taxes, depreciation, decommissioning and a 7eturn on capital. l % elected consolidated Quarterly financial Data (Unaudited) finthousands,exceptearningspershare) Balance Available Earnings Operating Operating Net for Common Per Share of Revenues Income Income Stock Common Stock (a) 19_93 First quarter $354,752 $ 41,721 $15,452 $11,377 $0.25 $econd quarter 346,074 49,282 22,829 19,125 0.43 ; Third quarter 436,024 96,319 70,015 66,052 1.47 l l Fourth quarter 345,403 37,997 9,922 5,959 0.13 1 19R First quarter $343,505 $ 41,930 $13,816 $ 9,553 $0.23 , 2econd quarter 300,566 32,629 4,953 852 0.02 l Third quarter 408,255 100,890 73,698 69,593 1.60 ! fourth ouarter 359.427 45.451 14,831 10.750 0.24 j ,(a) Based upon the weighted average number of common shares outstanding during the quarter. Electricity sales and revenues are seasonal in nature, with both being lower in the spring and fall seasons. Quarterly earnings for 1993 reflect a change in the months for which certain customers were billed at higher rates as mandated by the DPU. These customers were hilled at these higher rates in July through October in 1992 and in June through September in
- 1993. The change in billing increased second quarter earnings and reduced fourth quarter
@arnings by approximately $0.23 per share in 1993.
47
Item 9. Chanaes in and Disaareements with Accountants on Accountina and Financial Disclosure-None. Part III Jtem 10. Directors and Executive Officers of the Reaistrant (a) Identification of Directors See " Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive Proxy Statement dated March 17, 1994 incorporated herein by reference. . (b) Identification of Executive Officers The information required by this item is included at the end of Part I of this Form 10-K ' under the caption Executive Officers of the Registrant. (c) Identification of Certain Significant Emoloyees Not applicable. (d Family Relationshiol Not applicable. , le)- Business Experience for information relating to the business experience during the past five years and other directorships (of companies subject to certain SEC requirements) held by each person nominated to be a director, see " Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference. For information relating to the business experience during the past five years of each person who is an executive officer, see Executive Officers of the Registrant in this Form 10-K. (f) Involvement in Certain leaal Proceedinas Not applicable. Ig) Promoterf and Control Persons Not applicable. Item 11. ~ Executive Compensatian See " Director and Executive Compensation" on pages 5 through 11 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference. , 48
I Item 12. Security Ownership of Certain Beneficial Owners and Manaaement (a) Senurity Ownershio of Certain Beneficjal Owners i To the knowledge of management, no person owns beneficially more than five percent of the i outstanding voting securities of the Company. (b) Security Ownership of Manacement See " Stock Ownership by Directors and Executive Officers" on pages 4 through 5 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference. (c) Chances in Control Not applicable. Item 13. Certain Relationships and Related Transactions Not applicable. 49
. 1
.1 l
Part IV , Item 14. Exhibits. Financial Statement Schedules and Reports on Form 8-K l (a) Exhibits and Consolidated Financial Statement Schedules Pace Consolidated Statements of Income for each of the three years-in the period ended December 31, 1993 28 Consolidated Statements of Retained Earnings for each of the three years in the period ended December 31, 1993 28 Consolidated Balance Sheets as of December 31, 1993 and 1992 29 Consolidated Statements of Cash Flows for each of the three r years in the period ended December 31, 1993 30 No,tes to Consolidated Financial Statements 31 Selected Consolidated Quarterly Financial Data (Unaudited) 47 Report of Independent Accountants 64 Schedules for years ended December 31, 1993, 1992 and 1991: V - Property, Plant and Equipment S-1 VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment S-4 VII - Guarantees of Securities of Other issuers S-7 IX - Short-Term Borrowings S-8 X - Supplementary Income Statement Information S-9 All other schedules are omitted since they are not required, not applicable, or contain only information which is otherwise provided in the financial statements or notes in Item 8. 50
+ , e e- s e-
Exhibit SEC Docket 3 Exhibit _). Articles of Incorporation and By-laws 1 Incorporated herein by reference: 3.1 Restated Articles of Organization 2(a)4 2-58587 3.1.1 Amendment to Restated Articles of 2.4 2-64975 Organization, filed May 5, 1977 3.1.2 Amendment to Restated Articles of 3.1.2 1-2301 Organization, filed May 26, 1978 Form 10-K for the year ended December 31, 1991 3.1.3 Amendment to Restated Articles of 3.1.3 1-2301 Organization, filed May 6, 1980 Form 10-K for the year ended December 31, 1991 3.1.4 Amendment to Restated Articles of 3,1 1-2301 Organization, filed May 4, 1983 Form 10-Q for the quarter ended March 31, 1983 3.1.5 Amendment to Restated Articles of 3.1 1-2301 Organization, filed April 28, 1986 Form 10-Q for the quarter ended March 31, 1986 3.1.6 Amendment to Restated Articles of 3.5 1-2301 Organization, filed August 27, 1986 Form 10-K for the year ended December 31, 1986 3.1.7 Amendment to Restated Articles of 3.1 1-2301 Organization, filed February 19, 1987 Form 10-Q for the ' quarter ended March 31, 1987 3.1.8 Certificate of Vote of Directors 4.2 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed March 9, 1987 for the quarter ended . September 30, 1988 l 51
Exhibit SEC Docket 3.1.9 Amendment to Restated Articles of 3.1.8 1-2301 Organization, filed May 5,1987 Form 10-K for the year ended December 31, 1987 3.1.10 Amendment to Restated Articles of 4.1 33-24271 Organization, filed May 27, 1988 Registration Statement dated September 22, 1988 l 3.1.11 Certificate of Vote of Directors 4.3 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed October 4, 1988 for the quarter ended September 30, 1988 3.1.12 Amendment to Restated Articles of 3.1.12 1-2301 Organization, filed November 7,1991 Form 10-K for the year ended December 31, 1991 i 3.1.13 Certificate of Vote of Directors 3.1.13 1-2301 Establishing a Series of a Class Form 10-K of Stock, filed November 26, 1991 for the year ended December 31, 1991 3.1.14 Certificate of Vote of Directors 4.1 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed June 8, 1992 for the quarter ended June 30, 1992 3.1.15 Certificate of Vote of Directors 3.1 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed April 30, 1993 for the quarter ended June 30, 1993 3.2 Boston Edison Company Bylaws 3.1 1-2301 April 19, 1977, as amended form 10-Q January 22, 1987, January 28, 1988, for the May 24, 1988 and November 22, 1989 quarter ended June 30, 1990 52
Exhibit SEC Docket Ezhihil_4 Lrtstruments Dqfinina the Riahts of Security Holders. Includina Indentures Incorporated herein by reference: 4.1 Indenture of Trust and First Mortgage B-2 2-4564 c: dated December 1, 1940 with State Street Trust Company 9 4.1.1 Tenth supplemental indenture dated 7.5 2-8349 , April 1,1950 ( 4.1.2 Twelf th supplemental indenture dated 4.2 2-80748 November 15, 1951 4.1.3 Twenty-fourth supplemental indenture 4.1.3 1-2301 dated June 1, 1962 Form 10-K for the year ended December 31, 1990 4.1.4 Twenty-seventh supplemental indenture 4.1.4 1-2301 dated November 1, 1965 Form 10-K for the year ended December 31, 1990 4.1.5 Twenty-ninth supplemental indenture 4.1.5 1-2301 dated June 1, 1967 Form 10-K for the year ended December 31, 1990 4.1.6 Thirtieth supplemental indenture 4.1.6 1-2301 dated November 1, 1968 Form 10-K for the year ended December 31, 1990 4.1.7 Thirty-first supplemental indenture 4.1.7 1-2301 dated December 1, 1969 Form 10-K for the year ended December 31, 1990 4.1.8 Thirty-second supplemental indenture 4.1.8 1-2301 dated July 1, 1970 Form 10-X for the ! year ended December 31, 1990 l I l l l 53
[Jhibit SEC Docket 4.1.9 Thirty-third supplemental indenture 4.1.9 l-2301 dated May 15, 1971 Form 10-K I for the 1 I year ended December 31, 1990 1 4.1.10 Thirty-fifth supplemental indenture 4.1.10 1-2301 j dated April 15, 1977 Form 10-K j for the year ended December 31, 1989 4.1.11 Thirty-sixth supplemental indenture 4.1.11 1-2301 , dated December 15, 1978 Form 10-K i for the ! year ended l December 31, 1989 l 4.1.12 Thirty seventh supplemental indenture 4.1.12 1-2301 dated October 31, 1979 Form 10-K for the year ended December 31, 1989 4.1.13 Thirty-eighth supplemental indenture 4.1.13 1-2301 dated January 1, 1982 Form 10 K for the year ended December 31, 1991 4.1.14 Thirty-ninth supplemental indenture 4.1 1-2301 dated April 15, 1983 Form 10-Q for the quarter ended ' March 31, 1983 4.1.15 Fortieth supplemental indenture 4.1 1-2301 dated April 1, 1984 Form 10-Q for the quarter ended March 31, 1984 l- 4.1.16 Forty-first supplemental indenture 4.1 1-2301 } dated April 1, 1985 Form 10-Q for the quarter ended March 31,_1985 l-l 54-L - - - . - .
Exhibit SIC Docket 4.1.17 Forty-second supplemental indenture 4.1 1-2301 dated July 15, 1986 Form 10-Q for the quarter ended June 30, 1986 4.1.18 Forty-third supplemental indenture 4.1 1-2301 dated September 15, 1987 Form 10-Q for the quarter ended September 30, 1987 4.1.19 Medium-Term Notes Series A - Indenture 4.1 1-2301 dated September 1, 1988, between Form 10-Q Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 - 4.1.20 First Supplemental Indenture 4.1 1-2301 dated June 1, 1990 to Form 8-K Indenture dated September 1, dated 1988 with Bank of Montreal Trust June 28, 1990 Company - 9 7/8% debentures due June 1, 2020 4.1.21 Votes of the Pricing Committee of the 4.1 1-2301 Board of Directors of Boston Edison Form 10-Q Company taken December 11, 1990 for the re 8 7/8% debentures due quarter ended December 15, 1995 March 31, 1991 4.1.22 Indenture of Trust and Agreement among 4.1.26 1-2301 the City of Boston, Massachusetts Form 10-K (acting by and through its Industrial for the Development Financing Authority) and year ended Marbor Electric Energy Company and December 31, 1991 Shawmut Bank, N.A., as Trustee, dated November 1, 1991 4.1.23 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 5, 1991 re for the 9 3/8% debentures due August 15, 2021 year ended December 31, 1991 4.1.24 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K for the year ended December 31, 1992 f 55
l Exhibit SEC Docket 4.1.25 Votes of the Pricing Committee of the 4.1.25 1-2301 Board of Directors of Boston Edison Form 10-K , Company taken September 10, 1992 re for the 1 I 8 1/4% debentures due September 15, 2022 year ended December 31, 1992 4.1.26 Votes of the Pricing Committee of the 4.1.26 1-2301 'l Board of Directors of Boston Edison Form 10-K Company taken January 27, 1993 re for the 6.8% debentures due February 1, 2000 year ended December 31, 1992 4.1.27 Votes of the Pricing Committee of the 4.1.27 1-2301 , Board of Directors of Boston Edison Form 10-K ! Company taken March 5,1993 re for the i 5 1/8% debentures due March 15, 1996, year ended 5.70% debentures due March 15, 1997, December 31, 1992 5.95% debentures due March 15, 1998, 6.80% debentures due March 15, 2003, 7.80% debentures due March 15, 2023 Filed herewith: 4.1.28 Votes of the Pricing Committee of the -- -- , Board of Directors of Boston Edison j Company taken August 18, 1993 re 6.05% debentures due August 15, 2000 Exhibit 10 Material Contracts Executive Compensation: , 1 Incorporated herein by reference: 10.1 Key Executive Benefit Plan 10.13 1-2301 ! (1982 Form of Agreement) Form 10-K for the 4 year ended I December 31, 1992 10.1.1 Amendment to Key Executive Benefit 10.4.1 1-2301 Plan dated February 1, 1986 Form 10-K for the- f year ended { December 31, 1985 ) i 10.1.2 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, for the May 1986 quarter ended June 30, 1986 56
Exhib_j_t SEC Docket 10.1.3 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May form 10-K 1986, with modifications, applicable for the to Bernard W. Reznicek, George W. year ended Davis and Thomas J. May December 31, 1991 10.2 Executive Annual Incentive 10.5 1-2301 Compensation Plan Form 10-K for the year ended December 31, 1988 I 10.3 Performance Share Plan 10.1 1-2301 l Form 10-Q for the quarter ended September 30, 1991 10.4 1991 Director Stock Plan 10.1 1-2301 Form 10-Q l for the quarter ended March 31, 1991 10.5 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 1, 1990 Form 10-K for the year ended December 31, 1992 10.6 Boston Edison Company Deferred 10.12 1-2301 Compensation Plan dated Form 10-K January 1, 1990 for the year ended December 31, 1992 10.7 Deferred Compensation Trust 10.10 1-2301 between Boston Edison Company Form 10-K and State Street Bank and for the Trust Company dated year ended February 2, 1993 December 31, 1992 10.8 Description of Supplemental 10.5 1-2301 Fee Arrangement for Certain Form 10-K Directors for the year ended December 31, 1983
- Filed herewith
10.8.1 Directors Retirement Benefit -- -- (1993 Plan) i 57 i
C 0 Exhibit SEC Docket Exhibit 18 letter re Chance in Accountina Principle Incorporated herein by reference: 18.1 Letter of Independent Certified 18.1 1-2301 Public Accountants Form 10-Q for the quarter ended March 31, 1990 Exhibit 21 Subsidiaries of the Reaistrant 21.1 Harbor Electric Energy Company (incorporated in Massachusetts), a wholly-owned subsidiary of Boston Edison Company 21.2 Boston Energy Technology Group, Inc. (incorporated in Massachusetts), a wholly-owned subsidiary of Boston Edison Company 21.3 Ener-G-Vision, Inc. (incorporated in Massachusetts), a wholly-owned subsidiary of Boston Energy Technology Group, Inc. 21.4 TravElectric Services Corporation (incorporated in Massachusetts), a wholly-owned subsidiary of Boston Energy Technology Group, Inc. I 21.5 REZ-TEK International Corporation (incorporated in Massachusetts), a majority-owned subsidiary of Boston Ene,rgy Technology Group, Inc. i 58
Exhibit SEC Docket Exhibit 21 Consent of Indeoendent Accountants filed herewith: 23.1 Consent of Independent Accountants i to incorporate,.by reference, their opinion included with this Form 10-K, in the Form S-3 Reaistration Statements filed by the Company on September 14, 1990 (File No. l 33-36824), February 3, 1993 (File :-l No. 33-57840) and in the 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, j 1992 (33-48424 and 33-48425) and i March 17, 1993 (33-59662 and ( 33-59682). Exhibit 99 Additional Exhibits 1 Incorporated herein by reference:
- 99.1 DPU Settlement Agreement with 28.1 1-2301 -)
Boston Edison Company dated Form 8-K ] October 3, 1989 dated 1 October 3, 1989 99.2 Settlement Agreement between Boston 28.1 1-2301 ! Edison Company and Commonwealth Form 8-K j Electric Company, Montaup Electric dated Company and the Municipal December 21, 1989 Light Department of the Town of Reading, Massachusetts, dated January 5, 1990 99.3 Pilgrim Outage Case Settlement between 28.2 1-2301-Boston Edison Company and Reading form 8-K Municipal Light Department regarding dated Contract Demand Rate, dated December December 21, 1989 21, 1989 99.4 Settlement Agreement Between Boston 28.2 1-2301 Edison Company and City of Holyoke Form 10-Q Gas and Electric Department et. al., for the i dated April 26, 1990 quarter ended March 31, 1990 i l 1 1 59 l
o d Exhibit SEC Docket 99.5 Information required by SEC form - 1-2301 Il-K for certain Company employee Form 8 benefit plans for the years ended Amendments to December 31, 1992, 1991 and 1990. Form 10 K for the years ended December 31, 1992, 1991 and 1990 dated . June 29, 1993, I June 26, 1992 and June 28, 1991, respectively 99,6 DPU Settlement Agreement with 28.2 1-2301 Boston Edison Company, dated Form 10-Q October 23, 1992 for the quarter ended September 30, 1992 I i
.1 60
I L (b) Reports on Form 8-K A Form 8-K dated October 28, 1993 was filed with the Securities and Exchange Commission by the Company. This report announced the Company's earnings for the three and twelve months ended September 30, 1993. A Form 8-K dated January 27, 1994 was filed with the Securities and Exchange Commission by the Company. This report contained a press release announcing the Company's earnings for i the twelve and three months ended December 31, 1993. l l l i 4 l l
;{
61 l.
t-SIGNATURES l Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act I of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BOSTON EDISON COMPANY By /s/ Charles E. Peters. Jr. Charles E. Peters, Jr. Senior Vice President - Finance (Principal Financial Officer) Date: March 24, 1994 Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 24th day of March 1994.
/s/ Bernard W. Reznicek Chairman of the Board and Chief Executive Bernard W. Reznicek Officer
/s/ Thomas J. May President and Chief Operating Officer Thomas J. May and Director 1
/s/ Georae W. Davis Executive Vice President and Director George W. Davis
/s/ RobertJ . Weafer. Jr. Vice President, Controller and Robert J. Weafer, Jr. Chief Accounting Officer
/s/ William F. Connell ~ Director William F. Connell j
/s/ Gary L. Countryman Director Gary L. Countryman Director I Thomas G. Dignan, Jr.
62 i
/s/ Charles K. Gifford Director Charles K. Gifford
/s/ Nelson S. Gifford Director Nelson S. Gifford
/s/ Kenneth I. Guscott Director Kenneth I. Guscott
/s/ Matina S. Horner Director Matina S. Horner
/s/ Sherry H. Penney Director Sherry H. Penney
/s/ Herbert Roth. dr. Director Herbert Roth, Jr.
Director Stephen J. Sweeney
/s/ Paul E. Tsonaas Director Paul E. Tsongas
/s/ Charles A. Zraket Director Charles A. Zraket i
\
63
Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company: We have audited the consolidated financial statements and the financial statement schedules of Boston Edison Company and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. I We conducted our audits in accordance with generally accepted auditing standards. Those j standards require that we plan and perform the audit to obtain reasonable assurance about I whether the financial statements are free of material misstatement. An audit includes 1 '
-examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also incitdes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 1 31, 1993 and 1992, and the consolidated results of its operations and its cash flows for I i each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. In addition, in our opinion, the consolidated financial statement schedules referred to above, when considered in relation to the basic i consolidated financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein, f COOPERS & LYBRAND l i Boston, Massachusetts i i January 25, 1994 i l l 64 l
> Exhibit 4.1.28 Pricing Committee Meeting Boston, August 18, 1993 A meeting of the Pricing Committee of the Board of Directors of Boston Edison Company was held at the Executive Offices of the Company, 800 Boylston Street, Boston, Massachusetts, on Wednesday, August 18, 1993, at five minutes past twelve o' clock p.m., local time, the Chairman presiding. Present: Messrs. Reznicek and May - and present and participating by telephone communications equipment, by means of which all persons participating in the meeting could hear each other at the same time, Mr. N. Gifford and Drs. Horner and Penney - and, by invitation, Messrs. Peters, 1 Alpert, Frigard and Conway and Ms. O'Neil. Absent: None. _ Messrs. Reznicek and Peters presented management's proposal to sell
$100,000,000 principal amount of debentures. Mr. Reznicek summarized the votes being presented for action by the directors. The directors discussed the matters presented.
On motion duly made and seconded, it was: Voted: That, pursuant to votes of the Board of Directors adopted on January 28, 1993, the Company issue and sell $100,000,000 aggregate principal amount of unsecured debentures to be issued under and in accordance with the provisions of Article Three of the Indenture dated September 1, 1988 between the Company and Bank of Montreal Trust Company, as Trustee (the " Trustee") as amended and supplemented as of the date hereof (the
" Indenture").
Voted: That said series of debentures be established as a separate series of securities in accordance with and pursuant to the Indenture, to be entitled as follows: the 6.05% Debentures due August 15, 2000 (the " Debentures"). Voted: That the Debentures be issued with the following terms: Maturity Date: August 15, 2000 Interest Rate: 6.05% Interest Payment Date: February 15 and August 15 of each year commencing February 15, 1994 Price to the Public: 99.935% Proceeds to the Company: 99.31% Redemption Provisions: No call Voted: That the form of the Debentures presented to the Pricing Committee and attached to these votes as Exhibit A is hereby established, adopted and approved with such changes, insertions and omissions as are required or permitted by the Indenture and l' these votes and that such form shall be filed with the minutes of this meeting; and that the chairman, president, any executive or senior vice president, the treasurer or any assistant treasurer of the Company be, and each of them acting 65
singly is, hereby authorized to complete the form of Debenture as provided for in these votes, the completion of such Debentures to be conclusive evidence that the same has been approved by the Company. Voted: That the form of Purchase Agreement presented to the Pricing Committee relating to the Debentures is hereby approved and that the chairman, president, any executive or senior vice president, the treasurer and any assistant treasurer be, and each acting singly is, hereby authorized, in the name and on behalf of the Company, to execute with and deliver to Goldman, Sachs & Co. and Salomon Brothers Inc., a Purchase Agreement relating to the Debentures with such changes, insertions and omissions as the officer or officers executing the same may approve, such execution and delivery to be conclusive evidence of the authorization And approval thereof by the Company. Voted: That Bank of Montreal Trust Company is hereby designated as the transfer agent, registrar and paying agent for the Debentures and that the Trustee and such transfer agent, registrar and paying agent shall be entitled to the estate, powers, rights, authorities, benefits, privileges and immunities set forth in the Indenture; and that such resolutions, if any, as are customarily requested by the Trustee and each such transfer agent, registrar and paying agent with respect to its authority are hereby adopted and shall be filed with the minutes of this meeting. Voted: That the chairman, president, any executive or senior vice president, the treasurer or any assistant treasurer be, and each of them is, hereby authorized to file with the Trustee a certificate setting forth the form and terms of the Debentures - as established by and pursuant to these votes and the written order for the certification and delivery to the purchasers at the time and in the manner specified in the Purchase Agreement for the Debentures; and that the officers of the Company be, and each of them acting singly is, hereby authorized to take such further action and execute such certificates, instruments and other documents as in the judgment of such officers or officer will comply with the provisions of the Indenture and the Purchase Agreement and to issue and deliver the Debentures in accordance therewith. Voted: That the treasurer or any assistant treasurer be, and each of , them acting singly is, hereby authorized and directed to apply the proceeds from the issue and sale of the Debentures to repay I obligations incurred under bank lines of credit and commercial paper for capital expenditures for extensions, additions and improvements to the Company's plant and property and for working capital purposes. Voted: That the officers of the Company are, and each acting singly is, hereby authorized to execute and deliver such other documents and take such further actions in the name of the Company as the officers or officer so acting shall deem j advisable to implement the foregoing votes, such execution and delivery or the taking of any such action to be conclusive evidence of its authorization by the Company. 66
--'"T' -
s t No further business being presented, on motion duly made and seconded, the meeting dissolved at fifteen minutes past twelve o' clock p.m., local time. A true record. Attest: Theodora S. Convisser Clerk O f 67
i i Exhibit 10.8.1 Directors Retirement Benefit (1993 Plan) At its April 6, 1993 meeting, the Executive Committee voted to recommend to the Board of Directors that the Company's retirement benefit for outside [_ directors be amended as follows: Vesting: The benefit will vest upon the earlier of (1) the completion of ten years of service on the Board; (2) service on the Board until retirement at the annual meeting of stockholders following a director's seventieth birthday; or (3) death while serving on the 4 Board. Annual Amount: The annual amount of the benefit will be equal to the cash component of the annual Board retainer plus two annual Committee member retainers, as those retainers I are in effect at the time of a director's retirement ! or death (currently $10,000 + $2,750 + $2,750 or ! $15,500). The annual amount will be paid in quarterly ' installments. Duration of Benefit: A director while living will receive the annual amount for a period of years equal to his or her service on the Board. Survivor Benefit: Should a director die prior to full receipt of the benefit, his or her survivors will continue to receive the benefit for a period of time equal to the lesser of (1) the full years-of-service term to which the director would have been entitled if living or (2) a period of ten years from the commencement of payment of the benefit. Survivors may elect to receive the benefit in the form of a lump sum. The lump sum will be equal to the present value of the remaining benefit, calculated with reference to the Pension l Benefit Guarantee Corporation rate as in effect at the time of the director's death. Commencement of Benefit: Payment of the benefit to a qualified director will commence at the quarterly payment date following the director's departure from the Board and attainment of age 65. Should a qualified director die prior to the l commencement of the benefit, payment of the benefit to his or her survivors as described above will commence at the next quarterly payment date following the i director's death. Applicability: The amended director retirement benefit as proposed herein will take effect for all retirements from the Board occurring in 1993 and thereafter. a 68 l
Service of Less than a Year: Service of less than a year will be calculated with reference to the applicable fraction for determining both vesting and benefit duration. Thus, for example, if a director has service equal to six years and nine months when he retires at age 70, he will receive the annual amount for 6. 3/4 years. 69 , I
Exhibit 23.1 Consent of Independent Accountants We consent to the incorporation by reference in the registration statements of Boston Edison Company on Form S-3 (File Nos. 33-36824 and 33-57840) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424, 33-48425, 33-59662 and 33-59682) of our report dated January 25, 1994 on our audits of the consolidated financial statements and' financial statement schedules of Boston Edison Company as of December 31, 1993 and 1992 and for j each of the three years in the period ended December 31, 1993, which report is included in this Annual Report on Form 10-K. Boston, Massachusetts COOPERS & LYBRAND March 30, 1994 e 70 l
Boston Edison Company Schedule V Property, Plant and Equipment December 31, 1993 (in thousands) Column A Column F Balance.at end of period Classification Electric plant: ~ Land and rights of way $ 38,944 Generating station and substation buildings and misc. structures 472,789 Electric generating equipment 1,622,664 Transmission, distribution, street lighting and other utilization equipment 1,720,798 Capitalized DSM 48.625 Total electric plant 3,903,820 Nuclear fuel 273,867 Non-utility property 956 Construction work in progress ___144.835 . Total $4,323,478 (1) The information required in columns B, C, D and E is omitted as neither the total additions nor the total retirements during the year exceed 10% of the balance at the end of 1993. Total additions and retirements were $252,770 and $34,147, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates' ranging from 1.80% to 4.03% in 1993. For further information relating to the Company's policies regarding depreciation and amortization, see Note A included , in Item 8. (3) Approximately $92,000 of additions in 1993 relate to various modifications made to the Company's transmission and distribution systems, approximately $73,000 represent an increase in generating equipment, approximately $37 million represent capitalized DSM and the remainder includes additions to generating station and other plant. L
.i S-1 I
l l Boston Edison Company Sched'ule V Property, Plant and Equipment December 31, 1992 (in thousands) Column A Column F Balance at end Classification of neriod Electric plant: Land and rights of way $ 38,488 Generating station and substation buildings and misc. structures 427,780 Electric generating equipment 1,484,509 Transmission, distribution, street lighting and other utilization equipment 1,666,525 Capitalized DSM 11.469 Total electric plant 3,628,771 Nuclear fuel 270,420 Non-utility property 956 Construction work in progress 182.458 Total $4,082.605 (1) The information required in columns B, C, D and E is omitted as neither the total additions nor the total retirements during the year exceed 10% of the balance at the end of 1992. Total additions and retirements were $244,215 i and $34,036, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates ranging from 2.67% to 4.29% in 1992. For further information relating to' the Company's policies regarding depreciation and amortization, see Note A included in Item 8. (3) Approximately $95,000 of additions in 1992 relate to various modifications made to the Company's transmission and distribution systems, approximately $78,000 represent.an increase in generating equipment, approximately $31,000 represent increases in nuclear fuel and the remainder includes additions to generating station and other plant. S-2 5
Boston Edison Company Schedule V Property, Plant and Equipment 4 December 31, 1991 (in thousands) {plumn A . Column F Balance at end flassification of neriod
' Electric plant:
Land and rights of way $ 38,495 Generating station and substation
- buildings and misc. structures 408,249 1 Electric generating equipment 1,475,395 j l I t Transmission, distribution, street lighting and other utilization equipment 1.609.912 Total electric plant 3,532,051 Nuclear fuel 256,199 Non-utility property 956 'i' Construction work in progress 99.870 Total $3,889.076 i l
l (1). The information required in columns B, C, D and E is omitted as neither the .j i total additions nor.the total retirements during the year exceed 10% of the balance at the end of 1991. Total additions and retirements were $210,885 ; and $30,333, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates . ranging from 2.84% to 4.59% in 1991. For further information relating to the Company's policies regarding depreciation and amortization, see Note A included in Item 8. (3) Approximately $87,000 of additions in 1991 relate to various modifications made to the Company's transmission and distribution systems, approximately $99,000 i represent an increase in generating equipment and the remainder includes l additions to generating station and other plant, l i i L i S-3 i i t i - - - _ _- - --_ _ - _-_ _ - ..
Boston-Edison Company Schedule VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment ' 1993 (in thousands) Column A Column B Column C Column D Column E Column F Additions Balance at Charged to Balance beginning Costs and _ Other at end Description of period Expenses Retirements Changes of period Depreciation reserve: l Electric plant: Production-fossil $ 275,749 $ 25,981 $17,619 $ 182 $ 284,293
-nuclear 352,997 43,184(A) 2,883 0 393,298
-other 18,884 1,089 579 100 19,494 Total production 647,630 70,254 21,081 282 697,085 Transmission 129,710 6,627 289 46 136,094 Distribution 339,153 29,727 17,863 2,428 353,445 General 58,490 15,584(B) 12,608 65 61,531 r Capitalized DSM 0 6,968 0 0 6,968 Harbor Electric Energy Company 2,311 925 0 0 3.236 Total electric 1,177,294 130,085 51,841 2,821(D) 1,258,359 Accumulated amortization of nuclear- 220,477 201.978 21,815 0 (3,316)(E) fuel (F) $151,900 $51,841(C) $ (495) $1,478,836 Total $1,379,272 (A) Excludes $12,865 of nuclear decommissioning costs.
(B) Includes $9,237 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $17,694 of removal costs. (D) Includes salvage value of property retired of $2,568 and FERC audit adjustments from audit report covering the period 1/1/87 - 12/31/90 of $253. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial statements included in Item 8.
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Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 1992 (in thousands) Column A Column B Column C Column D Column E Column F Additions Balance at Charged to Balance beginning Costs and Other at end Description of period Expenses Retirements Changes of period Depreciation reserve: Electric plant: Production-fossil 5 268,744 $ 26,106 $19,141 $ 40 $ 275,749 l 313,870 39,948(A) 1,209 388 352,997
-nuclear
-other 18.499 1,713 1,978 650 18,884 Total production 601,113 67,767 22,328 1,078 647,630 i Transmission 120,533 9,770 628 35 129,710 l Distribution 323,178 34,362 19,919 1,532 339,153 General 51,795 10,416(B) 3,723 2 58,490 Harbor Electric 2,311 Energy Company 1,372 939 0 0
} Total electric 1,097,991 123,254 46,598 2,647(D) 1,177,294 l Accumulated amortization of nuclear 201,978 180.137 25,473 0 (3,632)(E) fuel (F) 51,278.128 5148,727 $46,598(C) $ (985) $1,379,272 Total l (A) Excludes $5,575 of nuclear decommissioning costs. (B) Includes $5,976 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $12,562 of removal costs. (D) Represents salvage value of property retired. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial statements included in Item 8. S-5
< Boston Edison Company Schedule VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment
' 1991 (in thousands) Column A Column 8 Column C Column D Column E Column F Additions Balance at Charged to Balance beginning Costs and Other at end Description of period Expenses Retirements Chances of period Depreciation reserve: Electric plant: Production-fossil $ 254,402 $ 24,989 $10,790 $ 143 $ 268,744
-nuclear 276,126 38,109(A) 365 0 313,870
-other 16,713 1,788 2 0 18.499 Total production 547,241 64,886 11,157 143 601,113 Transmission 110,369 10,308 148 4 120,533 Distribution 312,855 33,711 25,112 1,724 323,178 General 44,444 10,238(B) 2,889 2 51,795 ,
Harbor Electric 1,372 Energy Company 462 910 0 0 Total electric 1,015,371 120,053 39,306 1,873(D) 1,097,991 Accumulated amortization r of nuclear (3,426)(E) 180,137 163,694 19,869 0 fuel (F) $1,179,065 $139,922 $39,306(C) $(1,553) 51,278,128 Total (A) Excludes $4,675 of nuclear decommissioning costs. (B) Includes $6,179 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $8,974 of' removal costs. (D) Represents salvage value of property retired. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the-consolidated financial statements included in Item 8. 5-6
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Guarantees of Securities of Other Issuers December 31, 1993 (in thousands)
- olumn A Column B Column C Column D Column E Column F Column G.
Amount in l Total amount treasury of guaranteed Amount issuer of Nature of iame of issuer and owned by securities Nature of def ault Title of issue outstandino Company quaranteed quarantee by issuer
)f securities (ankee Atomic ,
Electric Company: $40 Million Amortizing Term Loan - expires ! 1997 $ 1,300 none none guarantee of none principal ed interest , iew England Hydro Finance Company, Inc.: (1) Series A Note - due 2001 $10,000 none none guarantee of none Series B Note - due 2007 6,300 principal Series C Note - due 2015 5,700 and interest Total M (1) As part of Hydro-Quebec Phase II, the Company and other New England electric utilities became equity owners in- k'
' New England Hydro-Transmission Electric Company, Inc. and New England hydro-Transmission Corporation, the parent companies and guarantors of New England Hydro Finance Company, Inc. The Company and other equity participants agreed to guarantee severally their proportionate share of the borrowings outstanding of these companies pursuant to the Note and Guarantee Agreement dated April 15, 1991. The Company and other equity
. participants also guarantee their proportionate share'of the total obligations of the participants who do not meet certain credit criteria.
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Boston Edison Company Schedule IX Short-Term Borrowings Year ended December 31, (in thousands) Column A Column B Column C Column D Column E Column F Weighted Maximum Average average Category of December 31 amount amount interest aggregate Balance weighted outstanding outstanding rate short-term at end average during the during the during the period period period borrowinas of period interest rate
$204,151 3.5% $320,000 $220,149 3.4%
1993 (1) 5275,500 3.8% $314,998 $233,286 4.1% 1992 (1)
$210,300 6.1% $324,400 $221,481 6.4%
1991 (1) (1) Borrowings under: Year ended December 31. 1993 1992 1991 Lines of credit $106,501 $162,500 $ 89,000 Commercial paper 97,650 113.000 121,300 Total $204,151 $275,500 $210,300 For information regarding the Company's borrowing arrangements, see Note F, part 6, to the consolidated financial statements included in Item 8. S-8 L , -
Boston Edison Company- Schedule X Supplementary Income Statement Information Year ended December 31, (inthousands) Column A Column B Charged to costs and expenses Item 1993 1992 1991 Maintenance and repairs * $94,826 $87,113 $102,215 Taxes other than payroll and income taxes: Municipal property $77,238 $63,430 $ 51,486
- Amounts are net of capitalized expenses.
For amortization of deferred cost of cancelled nuclear unit and amortization of deferred nuclear outage costs, see the consolidated statements of income included in Item 8. I I l S-9 j
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