ML20148T075

Annual Financial Statement for 1996. Securities & Exchange Commission Form 10-K Which Corresponds to Responds to 1996 Annual Rept,Encl

ML20148T075
Person / Time
Site:	Pilgrim
Issue date:	12/31/1996
From:	Desmond N BOSTON EDISON CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
BECO-2.97.069, NUDOCS 9707080384
Download: ML20148T075 (120)

Text

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p, 10CFR50.71 V

10CFR140.15(b)(1) ,

Boston Egioon Pilgrim Nuclear Power Station Rocky Hill Road Plymouth, Massachusetts 02360-5599 j l

July 1, 1997 l l BECo Ltr. 2.97.069 U. S. Nuclear Regulatory Commission '

Attention: Document Control Desk Washington, DC 20555

• Docket No. 50-293 License No. DPR-35 Annual Financial Statement for 1996 I In accordance with 10 CFR50.71(b) and 10CFR140.15(b)(1), Boston Edison submits the enclosed 1996 Annual Report and the Securities and Excharige Commission (SEC) Form 10-K which 1 corresponds to the 1996 Annual Report.

If you have any questions on this documentation, please contact Mr. Robert Cannon at (508) 830-8321.

l I/Ib j Nancy L. Desmond Group Manager Regulatory Relations RLC/dmc/10K-96 Attachment f

cc: Mr. Alan B. Wang, Project Manager Project Directorate 1-3 g s i Office of Nuclear Reactor Regulation () L ' I MailStop: OWF14B2 U. S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike i Rockville, MD 20852 U.S. Nuclear Regulatory Commission  ;

Region i 475 Allendale Road King of Prussia, PA 19406 Senior Resident inspector Pilgrim Nuclear Power Station.

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& Boston Edison

Albout The Company in addition to the two new joint ventures desenbed in t detail in this report, the company participates in unregulated activities through its wholly owned Boston Edison is a public utility engaged principally subsidiary, Boston Energy Technology Group (BETG) in the Deneration, purchase, transmission, distribution and sale of electric energy. It was incorporated in 1886. We supply electricity at retail to an area of CDNECO approximately 590 square miles within 30 miles of Boston, encompassmg the city of Boston and 3') CONECO is an energy management services company surrounding cities and towns. The population of the acquired by Boston Edison in 1994. CONECO started territory served at retail is approximately 1,500,000. as a lighting retrofit company, but quickly adapted to a changing marketplace and evolved into a full-We also supply electricity to other utilities and service energy management services company.

municipal electric departments at wholesale for CONECO has provided project management services resale. About 88 percent of our revenues are derived and energy-efficient retrofits in more than 2,000 from retail electric sales and 12 percent from commercial, industrial and government buildings.

wholesale sales.

In its most recent venture CONECO partnered with The Conservation Group, a New York state conservation company, to perform energy efficiency j ', [ projects, totaling approximately $20 million, in six g Empire State school districts.

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R CONEC0 has offices in Boston, New York, florida,

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A aw . Indiana and Washington, D.C.

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'N Northwind A ,

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h Thermal Technologies of Chicago, owner and g, ;l3 ,

h operator of the largest ice-based district cooling

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develop district cooling systems to provide envimnmenta!!y responsible air conditioning service to large buildings in Boston's Back Bay and Financial District Using Northwind's ice storage technology, customers eliminate on-site chillers that use ozone.

depleting chlorofluorocarbons (CFCs).

The Northwind Back Bay f acility. its first, is expected to begin commercial operation in early 1998.

Positive Financial Performance Strong Operational Performance At Headquarters:

a Reached a settlement agreement with the O A growing economy in Massachusetts helped Massachusetts Attorney General and fuel a 2 0% increase in retail kilowatt hour Massachusetts Division of Energy Resources on sales.

issues relating to industry restructuring

- highest commercial building occupancy rat 6 5 Entered two exciting new business ventures; in 15 years.

one to market electricity, natural gas and energy

- non-manufacturing employment up 1.9% services throughout New England, and the other over 1995. to provide retail telecommunications services.

O Earnings per common share and return on equity At Pilgrim Station:

continued to show a steady increase.

M Maintained good reputation with the Nuclear

- earnings per common share of $2.61 Regulatory Commission for reactor safety.

represents an increase of 3 6% over 1995, a Achieved a 90.5 percent capacity factor-a excluding the nonrecurring restructuring best-ever performance for Pilgrim and third best charge in 1995. in the world for boiling water reactors.

- return on equity of 12 4% highest in a a Achieved unit run of 601 days out of a possible decade. 619 days since its last refueling D All business units cc,ntinued to streamline At Fossil:

processes, improve productivity and reduce a Maximized the value of fossil assets by costs.

implementing a "best practice" operating

- lowest total spending and strongest cash philosophy.

flow in ten years. s Maintained a high unit availability of 84.8 percent.

- lowest staffing levels since 1940's.

m Reduced non-fuel operating costs by more than D Economic development program helped t 13 percent over 1995.

secure jobs for Massachusetts workers.

- signed up over 15.000 kilowatt-hours of new electric load amounting to over $5 million in u Expanded installation of automatic meters for annual revenues. more accurate, less costly meter reading and billing.

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!  : a implemented Field Service System for faster employee dispatch to customer locations, improving labor productivity by 200 percent.

a Continued' upgrade of our electric distribution system, resulting in a 50 percent reduction in outage time in areas where upgrades have been completed.

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Earnings Per Share Dividends Paid Per Share

$2 75 -

$2,00 -

$2 61 ,

$188

$2 52*

$2 50 -

$182 11 76

$175 -

$2 26 Il 70

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$210

$2 00 - ' ' ' ' ' 51 y - t 8 3 I i 1992 1993 1994 1995 1996 1992 1993 1994 1995 1996

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$0 44 restructurmg charge i' i' r

years ended December 31, 1996 1995 Operating revenues (000) $1,666,303 $1,628,503 income available for common stock (000) $126,181 $96,739 (a)

!, Common shares outstanding - weighted average (000) 48,265 46,592

. Common stoc'k data:

i Earnin s per sharb j $2.61 $2.08 (a)

Dividends declared per share $1.880 $1.835 Payout ratio 72 % 88 % (a)

Book value per share $21.37 $20.61 Return on average common equity 12.4 % 10.0 %(a)

Fixed charge coverage (SEC) 2.91 2.38 (c) includes a $34 million, or 50.44 per share, restructuring charge.

Contea's Letter to Shareholders 2 Our Strategy 4 Financial Section 1S Management's Discussion and Analys 17 Notes to Consolidated financial Statements 28 Officers and Directors 47 Important Shareholder Information 48 j l

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Dear Shareholder,

The developments of 1996 were pivotal for the statewide plan to restructure the electric power industry and for your company, as deregulation industry, marking a dramatic change in the way came into sharper focus. The Massachusetts the electric utility industry has operated by Department of Public Utilities set and met an separating the generation of electricity from the aggressive schedule with its issuance of final delivery of electricity and by making competition restructuring guidelines in December. In a reality. This represents the most sweeping tandem with this effort, Boston Edison has been change in Boston Edison's history. A 110-year-working to address past commitments while old business is being transformed as Boston sustaining solid financial performance and Edison prepares to sell its non-nuclear positioning itself for the future. Simultaneously, generation business and essentially become a the gas, electric and telecommunications distribution company.

markets began to converge.

aped @e sedem will Me m in last year's report, I spoke to you about orderly transition to deregulation, putting industry reform, the direction of public policy and uncertainty behind us and allowing us to focus the unbundling of the industry. As I outlined, aggressively on the future. This transition 2

Boston Edison had a seat at the table as the represents momentous change and daunting industry was reshaped. Because of this challenges. We are becoming a very different successful collaboration, we were able to reach company, yet we have demonstrated a a settlement agreement with the Massachusetts successful track record that will serve the Attorney General and the Massachusetts company and its shareholders well in the future.

Difsion of Energy Resources which is consistent This is crucial, because as our core utility witt the Department of Public Utilities' business restructures, we must look to guidoNes. We have agreed to participate in a diversification for our future growth.

We will continue to execute.our business plans in  !

ways that create value for our shareholders.

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We have laid out a clear strategy, executed our

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plans with speed and agility, joined with

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historic agreement with key opinion leaders in the state. But the job is not done. In fact, it has only begun. We must continue to execute our business plans in ways that create value for our shareholders. We will do that by concentrating

. on the delivery of exceptional service for the best possible value to our customers, by continuing to focus on best practices in all The solid performance of our cot 3 business segments of our business and by seizing operations in the midst of deregulation was ,

emerging growth opportunities.

impressive. Earnings per share in 1996 were

$2.61, an increase of 16% over 1995's leval, Our ongoing ability to understand and meet excluding the nonrecurrirg restructuring charge in customer needs will be the ultimate measure of our success. We will couple this with the use of 3 1995. Our aggressive attention to process improvements and cost control allowed us to innovative technology to differentiate ourselves achieve our lowest spending levels in a decade, in the marketplace and with the utilization of the significantly strengthen our balance sheet and right people who know how to get the job done.

dramatically improve productivity across all As you will see in this report, Boston Edison has business units. Our financial strength allowed us made several bold moves which caught the to maintain our dividend at $1.88 per share despite attention of industry experts and customers the unresolved issues surrounding the industry. alike. In short Boston Edison has set the These milestones were reached simultaneously with the convergence of the telephone, cable, Thomas J. May electric and gas markets. Boston Edison has ,

capitalized on this trend, establishing a leader-

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ship position with our two recently announced joint ventures in both telecommunications with

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Chairman, President and Chief Executive Officer RCN Telecom Services, Inc., a subsidiary of C-TEC, and in retail energy marketing with Williams Energy Services Company, a subsidiary of The Williams Companies.

1 Our Strategy in 1996 alone,12 major utikty consolidations were announced across the country with a combined market value of $70 billion. Market pressure will drive the industry toward greater economies of scale, especially in high-concentration areas like New England, where numerous utilities currently exist. Naturally, we want to be a bigger player-even at a time when utilities' traditionallines of business are shrinking. Boston Edison will be a smaller company after the sale of the fossil generating units. But with the

" wires" business, or distribution, as the core focus, we expect to claim our share of a burgeoning unregulated energy market with expansion plans across New England. Additionally, we will leverage our " ground floor" position in telecommunications.

Emerging businesses in this new, competitive world will require size and scale. That can be achieved in several different ways, including mergers and acquisitions, which we believe will continue to accelerate in the industry and, specifically, in New England. Much of the future consolidation will be in local distribution businesses for both electric and gas. Another way to ensure diversification and growth, as Boston Edison has demonstrated, is through 5

Previously separate businesses; electric, gas, telephone, cable and Internet access, are coming together to provide a new package of services to customers Boston Edison is on the cutting edge of this convergence.

THE WILLIAMS COMPANIES,INC.))[

" Boston Edison is a forward thinking and aggressive utility that understands who the customer is and that the customer will soon have choices," said Steve Cropper, j President and CEO, Williams Energy Services Company. "This

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evolving market."

5 affiliations. The affiliations with RCN, a subsidiary of C-TEC, for

• M telecommunications and with Williams Energy Services Company, part of The Williams Companies, for the marketing of electricity, gas and energy services, prove that good joint ventures are a marriage of strengths. Involvement with

,, Speed to market is critical in this strong partners will help us secure our collective future. We will anticipate business," said C-TEC Chairman the market and adapt quickly, with clear vision and a penchant for action.

and CEO David C. McCourt.

Our future depends on offering innovative customer solutions, achieving best- " Boston Edison has demonstrated practice status, effectively running regulated delivery systems and to us that it can move quickly and maintaining best-in-class marketing skills in our unregulated businesses. with agility, both of which are essential to success."

In order to achieve these goals most effectively, we recently filed with the Department of Public Utilities a proposal to form a holding company, an umbrella structure under which all of our businesses, joint ventures and subsidiaries would reside. Our business unit structure, implemented in early 1995, began the functional separation of our regulated businesses from the unregulated. Further

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restructuring to a holding company is now required so that these businesses can be effectively separated, an issue that has been of keen importance from the public policy perspective, for Boston Edison, a holding company provides greater flexibikty to diversity and expand as the industry restructures. from the regulatory viewpoint, a holding company structure minimizes the likelihood that companies will engage in unfair competitive activities.

Boston Edison is facing the tough realities of the deregulated environment by collaborating with the leading state consumer advocate-the Attorney Generars office-and other interested parties, on how best to proceed with industry restructuring and how to deliver real cost savings to customers We worked successfully with these parties and, in December, reached an agreement as to how to bring market competition and customer choice to Massachusetts consumers.

Our settlement agreement will need to be approved by the Massachusetts Department of Public Utikties. In its current form it resolves the uncertainty surrounding stranded investments, a key issue in the industry restructuring debate, by allowing for full cost recovery. Alsi outlined in the settlemcat b a commitment from Boston Edison to reduce its rates by 10 percent once customer choice begins.

Boston Edison successfully worked with many interested parties to settle complex restructuring issues. Full recovery of stranded investments will allow us to invest in innovative new technologies to meet }

changing customer demands.

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7 The settlement also provides for a competitive transition charge which would decline over a period of 12 years Additionally, the agreement calls for the company to sell its fossil generating plants. A detailed divestiture plan will be filed in May 1997 and we expect divestiture to be completed no later than six months after retail access begins. Boston Edison will continue to own and operate h; gam Nuclear Power Station, with future revenues based on the market price of energy. Pilgrim will continue to work toward a regional model for nuclear power operations.

We are exiting a large portion of our generation business and are now focusing on the steps necessary to operate our " wires," or distribution l

business, under new and more demanding performance criteria. At the same time, the company is pursuing innovative growth opportunities that will complement the core distribution business.

mm This settlement addresses public policy supporting customer choice and also our desire to establish a reasonable, workable transition from past regulatory practices. Once the settlement is filed with the Department of Public Utilities, a process of hearings and deliberation on the matter will begin. We expect that the Massachusetts legislature will take a necessary and active role in the restructuring debate over the next several months.

Consensus building marked the entire negotiation process for the settlement, which will ensure that utilities can obtain recovery for their past commitments and minimiza litigation, for the best interests of consumers as well as shareholders.

We realize, however, that exiting a major portion of our business has an impact on employees and host communities where plants operate. We will be working on a comprehensive approach to ease the transition and meet the needs of those affected.

The settlement and the sale of fossil generating plants are consistent, g however, with the company's strategic direction. Additionally, our strategic shift is aligned with public policy for unbundhng, and the stranded cost recovery provisions allow us to pursue market share in the emerging businesses of the new millennium.

Boston Edison's newly formed joint ventures will allow us to expand the services we offer customers in our existing service territory as well as to expand our presence in both the Greater Boston and New England markets.

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; A single strand of fiber optic cable can transfer an almost

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limitless amount of information-ten gigabites per fg%" l ,

second, or the equivalent of 160,000 telephone lines.

Fiber optics are used to carry voice, video, data and

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The settlement, when approved, will also set the stage for the company to pursue new business opportunities by providing a platform for financial ,; i stability going forward. [ .s Telecommunications [ gj . - -

J Boston Edison and RCN, a subsidiary of C-TEC Corporation, have formed a joint venture to provide local and long-distance telephone service, video, /' .

high speed Internet access and, eventually, energy management and property monitoring services. RCN was attracted to Boston Edison as a partner g

because of our focus on innovative technology, our sales and marketing expertise and our reach into 100 percent of the homes and busineeses in the Boston market.

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• Speed to market is critical in this business," said C-TEC Chairman and CEO I

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i David C. McCourt. Boston Edison has demonstrated to us that it can move quickly and with agibty, both of which are essential to success."

This joint venture is one of the most comprehensive in the nation between an

, electric company and a broadband network company to provide one-stop shopping for energy and telecommunications services. RCN is already providing services in Boston and New York City and expects additional rollouts this year.

The projected cost of creating the Edison /RCN telecommunications network for a population of over 1.5 million in the Greater Boston area is about $300 million. The venture, in the form of an unregulated entity, will utilize Boston Edison's 200 miles of existing fiber optic cable. wt.ich is more than that owned by any other electric company in Massachusetts or by many telecommunications companies.

We recognize that we are in the customer service business, and we want to to become the best at maximizing technology to deliver new services as they

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become available. This venture will offer customers one-stop shopping for In the competitive world, speed to market is an important advantage.

We won't mimic our competitors. Rather,

-we will move before the market tells us to, and in so doing, establish a leadership position with the help of compatible partners.

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The joint venture partnership, announced in September between Boston Edison and RCN Telecom Services, Inc., will provide customers one-stop shopping for telecommunications and electric services.

their total telecommunications needs, including voice, business / residential pr gpr If video, internet access and private data networks. Steady growth is expected -

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years. This will be spurred by the internet explosion, more frequent use of

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customer data needs. .

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Since Boston Edison is well established in the Boston market, we are a good Mk

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match for RCN. Conversely, RCN's technological leadership and presence in V77 ,.

the telecommunications market make them an ideal chone for us as well.

! Customers can expect added benefits from this joint venture over time, including interactive communications with their energy provider, opportunities 1

to receive many competitively priced services from one source and economies of scale that can lead to price advantages as the system grows. i

i The convergence of the telecommunications and information industries is creating a new definition of one-stop shopping for the information Age.

Retail Energy Marketing Boston Edison was among the hrst in the nation to bring a leading regional electric utility together with a national full-service energy company to offer customers an expanded menu of energy and energy services. Last October, we announced our partnership with Williams Energy Services Company, a subsidiary of the Oklahoma-based Williams Companies, to form EnergyVision, a limited liability retail company, to market electricity, natural gas and energy services to customers in all six New England states. Williams has a tremendous breadth of capabilities in energy transportation and in risk management. In fact, they own the largest natural gas pipeline infrastructure in the United States. Williams also brings a wide scope of financial products and packages to customers to meet their energy acquisition needs.

12 Boston Edison has attracted nationally recognized partners-multi-billion dollar companies and major players in their j

respective businesses. Why did these i

companies choose Boston Edison?

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. They recognized our, business acumen, <_

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F This map depicts The Williams Companies' natural gas pipelines.

Williams owns and operates the nation's largest system of interstate natural gas pipelines.

The formation of EnergyVision will allow us to become an aggressive player in the New England energy arena, a $5 billion market for gas and electricity alone. Add the energy services market in the region for an additional $2 billion, and the opportunities are indeed immense.

k "This joint venture will give customers a broad variety of energy choices at i market-based prices and will rapidly adapt to changing customer needs," said Williams Energy Group President and CEO Steve Cropper.

" Boston Edison is a forward thinking and aggressive utility that understands who the customer is and that the customer will soon have choices This alliance provides an excellent retail development opportunity to serve an important, rapidly evolving market."

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lo the new competitive energy market, different customers will want different products and services, from shopping the market for the best commodity price to seeking a supplier to help reduce the total cost of operations. EnergyVision will be a retail company that can meet these diverse customer needs.

Boston Edison is a changing and dynamic company. As we enter competitive markets we will continue to focus our efforts on performing well for our shareholders. We recognize the synergy inherent within the company and throughout the external market, a simple but powerful principle that the whole is greater than the sum of its parts.

Throughout this groundswell of industry change, we will continue to provide customer value in each business. Many others are already in the energy and energy services business. We know that our long-term success depends on understanding the needs of customers, helping them manage through this competitive transition and delivering value better than anyone else. This will u be the formula for maintaining the momentum of our financial strength.

We will continue to look for more

, efficient ways to run Boston Edison, L enhance teamwork and provide customer value, And we will continue to evolve, constantly

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, looking to identify and sch upw opportunities for growth.

i A definitive partnership agreement i between Williams Energy Services Company and Boston Edison Company was signed in January 1997.

It represents one of the most exciting and dramatic h 'd f![ steps in the evolution of Boston Edison from a local 15 i electric utility to a regional j energy provider. l

[ Employees Made it Happen i

Our achievements are the fruits of hard work by all our employees in the face of real and persistent challenges. Yet, the rapidly evolving competitive l marketplace presents us with an ever-increasing set of performance - >

expectations. Our employees fully understand the impact of competition on our business, and are aware that, in every other industry that deregulated, the service quality increased while the price of service decreased. All of us at Boston Edison are committed to meeting the challenges ahead with

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d Retail Sales Growth Return On Equity 4 0% -

13 0% -

3.0% -

28%

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12 4%

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• 1995 percentage excludes a 50 44 restructuring charge.

k Capital Expenditures hn minions) 5250 1247 5225 -

$214

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$175'

$151

$150

$125- ' ' ' ' '

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Resident.e127%

Commeroel 60%

l Industoel & Other 13%

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M:n:g:m:nt's Discussion end Analysis able access charge d@d to recover all of our stranded costs which are currently utimated to be approximately 53 billion.

Positioning in the Industry These costs inclue .he above-market commitments under existing purch_ , power contracts, our net generation plant 8:ckground invea...ent, nuclear decommissioning commitments and regula-Electric utilities have traditionally operated under a monopo- tory assets related to our generation business.

listic regulatory framework. Under this framework customers As part of the settlement we have agreed to divest our fossil  !

have been restricted to a single electricity provider, typically a generating plants no later than six months after the Retail vertically integrated electric utility engaged in the generation, &.::s Date. We expect to continue operation of Pilgrim transmission and distribution of electricity. However, since Nuclear Power Station with a new revenue mechanism for the 1970's, the electric cr.ergy business has become increasing- rvovery of Pilgrim's future costs and have agreed to estimate ly competitive. With the enactment of the Public Utility the market value of the station by December 31,2002.

Regulatory Policies Act of 1978, a new independent power Regulatory assets related to our generation business and our producer industry commenced, competing with traditional net generation plant investment will be recovered with a return electric utilities for opportunities to generate electric power. over a twelve-year period. As an incentive to mitigate stranded in recent years many state utility commissions, including the costs, our return on equity will be increased for mitigation prior Massachusetts Department of Public Utilities (MDPU), have to the Retail Access Date and as the transition access charge initiated inquiries into restructuring the electric utility indus- declines thereafter. The aggregate amount of the access charge try with a goal of promoting competition and extending to all will be reduced by the net proceeds from the fossil divestiture customers the option of choosing their own electricity suppli- and the market vahation of Pilgrim Station. Nuclear decom-ers. In 1996, Massachusetts electric utilities and other inter- missioning commitments and above-market commitments ested parties participated in the industry restructuring pro- under existing purchased power contracts will be collected over ceeding before the MDPU. This process culminated in the the lives of the underlying obligations which are expected to latter part of the year with a series of settlement agreements exceed twelve years. Certain severance, employee training and and the issuance by the MDPU ofits formal electric industry community-related transitional payments are also recoverable restructuring plan. through the access charge.

. Our electric delivery business will remain fully subject to ElIctn. c utility .mdustry restructuring U rate regulan.on. As part of the agreement, while there w.ll i be i in December 1996, we reached a settlement agreement with some rate design changes, our base rate revenue level (non-fuel) the Massachusetts Attorney General and the Massachusetts will be frozen until the Retail Access Date when customer Division of Energy Resources that resolves certain necessary choice begins.

issues sunounding electric industry restructuring. This agree- Effective with the commencement of retail choice and pur-ment must be fded with and approved by the MDPU. If suant to the settlement agreement, our electric delivery business approved, the settlement agreement allows retail electric cus- will annually file with the MDPU a computation supporting tomers the ability to choose their electricity supplier (referred our return on average common equity associated with distribu- ,

to as retail access). Retail access would occur at the later of tion system operations. The return on equity would be subject January 1,1998 or the date when retail access is made available to a floor of 6% and a ceiling of 11.75%. If the return on equi.

to all customers of Massachusetts investor-owned utilities (the ry is below 6%, we would be authorized to add a surcharge to Retail Access Date). The settlement agreement provides us customer rates in order to reach the 6% floor. If the return on with the ability to fully recover our stranded costs incurred equity is above 11%, we would be required to adjust customer under the traditional electric raremaking structure. rates by an amount necessary to reduce the calculated return on Under the settlement agreement, all retail customers will equity between 11% and 12.5% by 50%, and a return above have the opportunity to select their electricity provider starting 12.5% by 100%. No adjustment would be made if the return on the Retail Access Date. Retail customers will continue to on equity falls between 6% and 11%.

receive electric delivery service under regulated rates. The settlement also provides for the continued protection Customers who choose not to participate in the competitive of the environment through stringent emissions standards, a market wil! have the option of continuing to buy power from continued commitment to energy conservation and renewable our electric delivery business at " Standard Offer" prices for resource programs and protections for low-income customers.

seven years. The " Standard Offer" will provide customers with In October 1996, another major electric utility in electric service at rates designed to give a 10% savings in electric Massachusetts, along with the Massachusetts Attorney General, prices. Our electric delivery business will purchase power for the Massachusetts Division of Energy Resources and other parties

" Standard Offer" service from suppliers through a competitive filed a settlement agreement with the MDPU. Their settlement bidding process. agreement provides for retail choice, full compensation for poten-Commencing with the Retail Access Date, the retail deliv- tial stranded costs and the divestiture ofits fossil and hydroelec- i ery rates of our distribution business will include a non-bypass- tric generating business. In addition, customers that do not l

choose an alternative supplier would receive " Standard Offer" ser- Holding Comprny vice that would provide a 10% savings in electric prices upon the in January 1997, we announced a plan to form a holding com-Retail Access Date. On February 26,1997, the MDPU issued an pany structure. The holding company structure, which is sub-order accepting dus utthrys settlement agreement-We anticipate that the MDPU willissue a decision on our ject to shareholder and regulatory approvals, is intended to pro- .

vide increased fmancial, managerial and organizational flexibili-settlement agreement in the second or third quarter of 1997.

ty in order to better position us to operate in the changing elec- '

Implementation of the settlement will also be subject to enact-tric utility industry. h will permit us to take advantage of ment of enabling legislation by the Massachusetts legislature nonutility business opportunities in a more timely manner. In and rulings by the Federal Energy Regulatory Commission ,

addition, the holding company structure will clearly separate (FERC). In the first quarter of 1997, both the Massachusetts our regulated and unregtdated lines of business enabling us to Governor and a Joint Committee of the Massachusetts legisla-pursue nonutility business ventures in a manner consistent with ture filed separate bills on restructuring the electric utility the electric utility industry restructuring principles outlined by industry. The major principles of these bills are substantially the MDPU. The holding company structure is a well-estab-consistent with those of the MDPU restructuring plan. includ-lished form of organization for companies conducting multiple ing the opportunity for stranded cost recovery and redaed elec~

iines of business, particularly entities engaging in both regulated  !

cricity prices. The bilis clarify the MDPU's authority to create and unregulated activities. All investor-owned Massachusetts l the opportunity for red customer choice by January 1,1998.

electric utilities, other than Boston Edison, are currently orga-In December 1996, the MDPU issued its formal electric nized in a holding company structure, industry restructuring plan. The stated goal of the plan is to reduce costs, over time, for all consumers of electricity. Under 1992 Rate Settlement the MDPU's proposal, the current monopoly regulatory frame ~

wek will evolve into a competitive market system featuring As referred to in the following Results of Operations, the )

MDPU had previously approved our three-year setdement agree- l consurcer choice among providers of generation services. The ment efTective November 1992. This agreement provided us .

transmission and distribution of electricity will remain monop '

with retail rate increases, allowed for the recovery of demand side lies subject to rate regulation.

management conservation program costs, specified certain Joint ventures accounting adjustments and clarified the timing and recognition of certain expenses. The agreement also set a limit of 11.75%

rs We currently conduct unregulated activines through our wholly owned subsidiary, Boston Energy Technology Group (BETG). on our rate of return on common equity for each of the calendar In December 1996, BETG signed a joint venture agreement years 1993,1994 and 1995, excluding any penalu.es or rewards from performance incentives. The retail rate increases consisted 4 1

with Residenu.al Commum. canons Network, Inc., currently 3 known as RCN Telecom Serv. ices, Inc. (RCN), to form amue h. . d of two annual retail base rate increases of $29 million effecu.ve I liability company to provide local and long-distance telephone November 1993 and November 1994 and an annual perfor- i l

semce, video, high-speed Internet access and odier telecommu- mance adjustment charge effecu.ve November 1992 through ,

i October 2000. The performance adjustment charge varies annu-mcanons-related services (the Telecommumcanons Venture ).

The unregulated enury will be owned up to 49% by BETG, ally based on the performance of Pilgrim Nuclear Power Station. i This charge is further described in the Electric Sales and with RCN havmg the day-to-day management responsibihty.

i We did not make a base rate filing upon the The projected costs of creating the Telecommumcanons Venture" which is planned to serve 1.6 million customers in the m de pm hfor&e ates greater Boston area, is approximately $300 million over several have remained in effect at their 1995 levels.

years. The joint venture agreement is subject to a number of Results of Operations conditions which must be satisfied before formal operations begin, including the obtaining of certain regulatory approvals. 1996 versus 1995 In January 1997, BETG, through one ofits wholly owned Earnings per share of common stock were $2.61 in 1996 com-subsidiaries, signed definitive agreements with Williams pared to $2.08 in 1995. Earnings in 1995 reflected a nonrecur-Energy Services Company (WESCO), a subsidiary of The ring before tax charge of $34 million ($20.7 million net of tax, Williams Companies, Inc., to form EnergyVision, LLC, an or 50.44 per share) associated with our corporate restructuring.

unregulated limited liability company. This " Energy The restructuring is discussed further in Note F to the

! Marketing Venture" will market electricity, natural gas and Consolidated Financial Statements. Excluding the nonrecurring energy-related services to retail customers in the six New restructuring charge, earnings per common share increased England states. EnergyVision began operations in February 3.6% over 1995 primarily due to lower operations and mainte-1997. BETG, through its subsidiary, and WESCO cach own nance and interest expenses and higher Pilgrim performance 50% of the new company, with an expected combined initial revenues. These positive changes were partially offset by an

investment ofless than $10 million. increase in depreciation expense.

l

Opersting rav:nues od of these deferred costs from five years to two years, consis-Operating revenues increased 2.3% over 1995 as follows: tent with the two-year cycle between refueling outages at l (in thousands) Pilgrim Station. l Retail electric revenues $48,649 The 1995 operating expenses reflect a $34 million nonre-curring charge related to our corporate restructuring. Refer to Demand side management revenues (20,545) ,

the Results of Operations for 1995 versus 1994 and Note F to Wholesale revenues (2,072) the Consolidated Financial Statements for additional informa-Short-term sales and other revenues 11,768 tion regarding our 1995 restructuring.

Increase m operating revenues $37,800 Depreciation and amortization increased $32 million. The increase is primarily the result of a change in the estimated Retail electric revenues increased $48.6 million. Fuel and remaining economic lives of our Mystic 4, 5 and 6 fossil gener- ,

purchased power revenues increased approximately $36 million. ating units in the second quarter of 1996, retroactive to the These higher revenues are offset by higher fuel and purchased beginning of the year, and an increase in the depreciable plant power expenses and, therefore, have no net effect on earnings. balance. The change in estimated economic lives of Mystic 4, 5 Performance revenues, which vary annually based on the operat- and 6 resulted in a $22 million increase in depreciation expense ing performance of Pilgrim Station, increased $14.5 million as for the year. Refer to Note B to the Consolidated Financial Pilgrim Station operated at a higher capacity in 1996. Pilgrim's Statements for more information on depreciation expense.

annual performance adjustment charge is discussed further in The decrease in DSM programs expense reflects the decline the Electric Sales and Revenues section. Retail kWh sales in current DSM program expenditures.

increased 2.8% in 1996, primarily due to the positive economic The increase in income taxes is due to higher net income impacts on our commercial customers. and a higher effective mx rate in 1996. Our effective tax rate in Demand side management (DSM) revenues decreased pri- 1996 is 38.2% versus 37.1% in 1995.

marily due to a decline in current DSM prograrn expenditures.

Interest charges The primary reason for the decrease in wholesale revenues is due to a decrease in Pilgrim contract customer revenues. Interest on long-term debt decreased due to the maturity of These revenues decreased despite increased kWh sales due to $100 million 8 7/8% debentures in December 1995 and $100 lower operations and maintenance expense related to Pilgrim million 51/8% debentures in March 1996. These decreases Station. Pilgrim contract customers are billed for their propor- were partially offset by the issuance of $125 million 7.80% 19 tionate share of the unit's costs. debentures in May 1995 which were outstanding for all of .

Net short-term sales and other revenues increased $11.8 1996. Other interest charges increased due to an increase in million. Despite lower kWh sales, short-term sales revenues interest on short-term debt caused by the higher average short-increased approximately $6 million due to higher fuel prices. term debt level partially ofTset by a lower average short-term Revenues from short-term sales result in a corresponding reduc. borrowing rate. The short-term debt balance increased as a tion to future fuel and purchased power billings to retail cus- result of the debenture maturities and the redemption of $4 l romers and, therefore, have no net effect on earnings. This million of preferred stock in 1996. Allowance for borrowed increase also reflects an increase in revenue from nonelectric funds used during construction (AFUDC), which represents the sources in 1996. financing costs of construction, decreased due to lower overall i construction activity during 1996, shorter construction periods, 1 Opsrating expenses and lower short-term interest rates. l i

Fuel and purchased power expenses increased $53 million. Fuel 1995 versus 1994 expense increased, despite a slight decrease in company genera-tion, due to significantly higher oil and natural gas prices. Earnings per share of common stock were $2.08 in 1995 com- ,

Purchased power expense reflects a higher volume of energy pared to $2.41 in 1994. Earnings in 1995 reflect the nonrecur- I purchases and an overall increase in energy prices. These ring before tax charge of $34 million ($20.7 million net of tax, increases were partially offset by the timing effect of fuel and or $0.44 per share) associated with our corporate restructuring.

purchased power cost collection. Fuel and purchased power The charge reflects the costs of early retirement and severance expenses are substantially recoverable through fuel and pur- programs implemented as part of our organizational streamlining chased power revenues, and reorganization into business units. Excluding the restructur-Operations and maintenance expense decreased $41 million ing charge, earnings per common share were $2.52 in 1995, an i l

primarily due to lower labor costs resulting from our 1995 increase of 4.6% over 1994. This increase is due to the $29 mil-lion annual retail base rate increase effective November 1994, the restructuring and the continuing cost control efforts of each of our business units. In addition, the amortizarb o' deferred ending of amortization of deferred cancelled nuclear costs in nuclear outage costs decreased $9 million. As m . . sed in No;e 1994, a 1.2% increase in retail kWh sales and lower revenue B to 'the Consolidated Financial Statements, in the third quarter reserve provisions. These positive impacts were partially offset of 1995 we made a retroactive change to the amortization peri- by higher income and property taxes, nuclear outage amortiza-

tion and employee benefit expenses in 1995 over 1994 levels, ing costs in the electric delivery business. Electric generation and a gain recorded in 1994 related to a favorable coun ruling costs increased only 1 % in 1995, primarily due to a refueling on an eminent domain case. and maintenance outage at Pilgrim Station.

Opertting revenues The $34 million nonrecurring restructuring charge was incurred over the third and founh quaners of 1995 as a result Operating revenues increased 5.4% over 1994 as follows:

of our corporate reorganization announced in July 1995. As (in thousands) part of the reorganization,330 employees elected to retire under Retail electric revenues $69,851 enhanced retirement programs and 149 employees whose posi.

Demand side management revenues 8,783 tions were climinated became eligible for benefits under a spe-Wholesale revenues (1,799) cial severance program. Refer to Note F to the Consolidated Short-term sales and other revenues 6,933 Financial Statements for additional information. '

increase in operating revenues $83,768 Depreciation and amortization expense increased due to a higher average depreciable plant balance.

Retail electric revenues increased $69.9 million, in 1994 we fully expensed the remaining deferred costs of Approximately $28 million of the increase was due to the the cancelled Pilgrim 2 nuclear unit.

November 1994 base rate increase while approximately $11 'Ihe increase in demand side management programs million was due to the increase in retail kWh sales. Fuel and ** pense is related to the increase in DShi revenues. Beginning purchased power revenues .mcreased $11 m.d lion as a result of. with the annual conservation charge implemented in February thea.mmg effect of fuel and purchased power cost recovery. 1995, DShi costs are recovered and expensed pn. manly .m the ,

> car mcurred. The 1995 expense m.cludes $31 m. d lion of 1995

• These higher revenues are offset by higher fuel and purchased .

power expenses and, therefore, have no net effect on earnings.

program costs and $14 milh.on of amortization of costs capnal-szed m. 1992 through 1994. r Pilgrim performance revenues m. creased $9 million primarily .

due to a higher performance rate effecn.ve m 1995 and a 17% Property and other taxes mcreased primarily due to higher ,

increase in generation. Boston property taxes resulu.ng from capital addinons.

Our effecu.ve annual income tax rate for 1995 was 37.1% i

. A new annual conservation charge for recovery of demand vs. 31.4% for 1994. The higher rate is the result of a $10 mil-side management program costs was implemented in February  ;

h.

1995. Under th.is charge all 1995 program costs were recovered . on adjustment to deferred income tax expense made .m 1994 2D '

m accordance wn. h the 1992 settlement agreement.

m 1995. Th.is resulted in higher DShi revenues and expenses '

than in prior years when certain program costs were deferred Other income and recovered over a six-year period.

The net decrease in other income is primarily due to a $5.7 Short-term sales increased as a result of higher generating million gain recognized in 1994 from a court ruling on a 1989 '

availability in 1995. Revenues from short-term sales result in eminent domain taking of certain of our property.

a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, have no net effect Interest charges on earnings. Interest on long-term debt increased / n s $125 Gion l Op; rating expenses debenture issuance in hiay 1995, partery orTset by interest sav-ings from first mongage bond and debenture redempnons m 1 Fuel and purchased power expenses increased $22 million pri-1994. Other interest charges increased slightly due to higher l marily due to the timing effect of fuel and purchased power short-term interest rates panially offset by a lower average short-

~

cost collection. Excluding the timing effect, fuel expense term debt level. AFUDC decreased due to a lower construction increased due to an 8% increase in fossil generation while pur-work-in-progress balance and shorter construction periods, par-chased power expense was substantially unchanged. Fuel and I tially offset by higher shon-term interest rates.

purchased power expenses are substantially recoverable through fuel and purchased power revenues. Electric Sales and Revenues Operations and maintenance expense increased 3.3% over Electric sales i 1994. This was primarily due to an $11 million increase in the arnonization of deferred nuclear outage costs. In the third Retail kWh sales increased 2.8% in 1996. The major contribu-quaner of 1995 we made a retroactive change to the amoniza. trt this increase was the positive effect on commercial cus-tion period of deferred nuclear outage costs from five years to t men of a continued strong economy in our retail service terri-two years as discussed in Note B to the Consolidated Financial t ry. The strong economy's impact in greater Boston is illus-Statements. In addition, employee benefit expenses increased trated by the highest commercial office occupancy rate in 15 primarily due to higher postretirement benefit expenses record- years. In addition, hotel occupancy rates and non-manufactur-ed in accordance with the 1992 settlement agreement. We also ing employment increased over 1995. The commercial sector incurred higher administrative costs in positioning the company represents approximately 50% of our electric operating rev-for changes in the industry, which were offset by lower operat. enues. Residential sales, which represent approximately 27% of i l-

1 electric operating revenacs, decreased slightly primarily due to performed during the shutdown. The power needs usually met 4

overall milder than normal weather conditions. Industrial sales by the station were met by other generating plants or purchased remained relatively flat. This sector represents approximately from other suppliers as necessary. We do not believe that the

. 9% of electric operating revenues. Total kWh sales, including generator damage resulted from actions within our control.

wholesale, increased 3.3%. The increase in wholesale sales was Our recovery of the incremental purchased power costs during

, primarily due to higher sales to our Pilgdm contract customers the outage through fuel and purchased power revenues, howev- I I

as the plant was operating for substantially all of 1996. In addi- er, remains subject to review by the hiDPU under a generating tion, sales to our municipal customers increased due to a reduc- unit performance program.

tion in available energy supply in New England. .

Liquidity A 1.2% increase in retail kWh sales in 1995 was primarily due to a stror.ger economy, partially offset by the impact of We ordinarily meet most of our cash requirements for plant demand side management programs. Total kWh sales expenditures with internally generated funds. These funds are

increased 3.8% primarily due to an increase in Pilgrim contract cash flows from operating activities, adjusted for changes in i i

customer sales. working capital and the payment of dividends. During 1996, 1995 and 1994 our internal generation of cash provided 170%, i Ebetric revenues 102% and 109%, respectively of our plant expenditures. The  ;

Our retail electric rates are subject to the jurisdiction of the capital spending level, excluding nuclear fuel, forecasted for i

hiDPU. As discussed in the Positioning in the Industry sec- 1997 is $144 million which includes amounts for utility plant

! tion, we reached a settlement agreement in December 1996 and our new business ventures. The capital spending level over that, if approved, resolves certain necessary issues surrounding the next five years is forecasted to be approximately $750 mil-electric industry restructuring. As part of the settlement agree- tion. In addition to capital expenditures, we have long-term l ment our electric d: livery business will provide " Standard debt and preferred stock payment requirements of $103.6 mil- l Offer" customers service at rates designed to give a 10% savings lion per year in 1997 and 1998, $3.6 million in 1999, $168.6 in electric prices. Under the agreement, our base rates will million in 2000 and $53.6 million in 2001.

remain frozen until the Retail Access Date (the later of External financings continue to be necessary to supplement January 1,1998 or the date when retail access is made available our internally generated funds, primarily through the issuance to all customers of Massachusetts investor-owned utilities). We of short-term commercial paper and bank borrewings. We have do not expect that maintaining base rates at their current level authority from the FERC to issue up to $350 million of short- a until the Retail Access Date will have a material adverse effect term debt. We also have a $200 million revolving credit agree-on our financial condition or results of operations. After the ment and arrangements with several banks to provide additional Retail Access Date, the retum on equity on our electric delivery short-term credit on a committed as well as on an uncommitted business will be subject to an 11.75% ceiling which is lower and as available basis. At December 31,1996, we had approxi-than has been experienced in the recent past, mately $201 million of short-term debt outstanding, none of The annual performance adjustment charge from our 1992 which was incurred under the revolving credit agreement. In settlement agreement with the MDPU remains in effect 1994 the MDPU approved our financing plan to issue up to through the year 2000 and provides us with opportunities to $500 million of equity and long. term securities through 1996.

improve our financial results. The most significant potential In 1996 the MDPU approved our request to extend this financ-impact of this performance incentive is based on Pilgrim ing plan through 1998. Authority to issue approximately $322 Station's annual capacity factor. An annual capacity factor million remains under this plan. Proceeds from issuances under between 60% and 68% would provide us with approximately this plan are to be used to refimance short and long-term securi-

$54.5 million of revenues in the performance year ended ties and to fund capital expenditures and working capital October 1997. For each percentage point increase in capacity requirements. Refer to Notes H and I to the Consolidated factor above 68%, annual revenues will increase by approxi- Financial Statements for additional information relating to our mately $800,000. For each percentage point decrease in capaci. financing activities. We intend to issue $100 million of two-ty factor below 60% (to a minimum of 35%), annual revenues year debt in March 1997.

will decrease by approximately $900,000. We are currentiy

, Outlook for the Future billing customers based on an 85% capacity factor. This is a decrease from the capacity factor of 90.9% achieved in the per. Competitive forces within the electric utility industry continued formance year ended October 1996 due to the scheduled rou. to increase in 1996. Changes in the industry include ongoing tine refueling outage that began in February 1997. We earned competition in wholesale power markets and increased pressure

$67.6 million in revenues related to Pilgrim's capacity factor in for retail customer choice. These forces are due to a variety of the performance year ended October 31,1996. factors, including legislative and regulatory proceedings at both Pilgrim Station was shut down for approximately three federal and state levels designed to foster competition and months in 1994 due to a non-nuclear problem with its electri. changes in customer expectations. The trend continues toward cal generator. Regularly scheduled maintenance work was also increased competition through modified regulation of the

-. - - - -- ~ .- - -- -- .

industry. In Massachusetts, open access to generation markets try have afTected utilities

• ability to continue to apply regulatory ,

l for retail customers is approaching rapidly, accounting. The final rules issued by the MDPU or the enact- l l The effects of competition have been evident in the whole- ment oflegislation in Massachusetts could,in the near term, i

l sale energy market.' In response to the competition from other cause us to no longer meet the criteria for application of SFAS electric utilities and nonutility generators to sell electricity for 71 for some ofour operations. Should this occur, we would be resale, we secured long-term power supply agreements with our required to take an immediate noncash charge to income for all seven wholesale customers that set rates through 2002 and of our affected regulatory assets and the above-market portion beyond. This segment represents 3% of our operating revenues. of purchased power contracts. In addition, a write-down of in January 1997, we filed an open access tariff with the utility plant assets would be required under Statement of FERC that incorporates our transmission rates into a New Financial Accounting Standards No.121, Accounting for the England regional transmission tariff. This filing, which is sub- Impairment oflong. Lived Assets and for long-Lived Assets to

! ject to approval, was made in response to the FERC's open be Disposed Of, if competitive or regulatory change results in a j access transmission order that was issued in April 1996. The probability that future cash flows will not be sufficient to recov-l order requires all utilities with transmission systems to file open er our investment in those assets. Based on our settlement  ;

l access tariffs, to provide service under those tariffs to transmis- agreement we expect to recover all strandable costs through a l sion customers comparable to service provided to their electric non-bypassable access charge to be paid by customers of our energy customers and to take service under the tariffs for whole- electric delivery business. Urider our settlement agreement, our ,

sale purchases and sales. The order also supports the full recov- delivery business will remain subject to rate-regulation and, i ery oflegit matei and verifiable costs previously incurred under therefore, will continue to meet the criteria of these accounting l

, federal and state regulation. The provisions in the order pro- standards. As noted cadier, under our settlement agreement we  ;

j vide a framework for significant changes in the electric utility expect to continue to operate Pilgrim Station with the ability to l l_ industry. We do not expect the FERC order to significantly collect stranded costs related to the unit. Although not antici- 1 l impact the results of our operations, which are primarily regu- pated based on our settlement agreement, the nonrecovery of lated by the MDPU, strandable costs could have a material impact on our results of j Additional competition exists with alternative fuel suppliers operations and financial condition. However, iflaws are enact- '

l as customers are able to substitute natural gas, steam or oil for ed or regulatory decisions are made that do not offer electricity for heating or cooling purposes. In addition, indus- Massachusetts electric utilities an opportunity to recover previ- l 22 trial and large commercial customers may pursue options to ously reviewed, prudently incurred commitments to provide i generate their own electric power or factor the cost of electricity service to our customers, we believe we have strong legal argu-  ;

into their decisions to relocate to new service territories. ments to challenge such laws or decisions. We will actively pur-  ;

l In addition to our involvement in the MDPU's restructur- sue the full recovery of stranded costs and are prepared to take l ing proceeding, we have actively responded to the changing the action necessary to protect the interests of our shareholders.

i electric utility industry in other ways. In 1995 we reorganized Other Matters the company into separate business units in order to strengthen

(

l our competitiveness. The Customer, Fossil Generation, Nuclear Connecticut Yankee Generation and Corporate Services business units were designed '

to sharpen management focus along our significant lines of On December 4,1996, the board of directors of Connecticut operation while maintaining company-wide strategic goals. The Yankee Atomic Power Company (CYAPC), which owns and l . restructuring reduced our workforce which resulted in a signifi- per tes the Connecticut Yankee nuclear electric generating unit l

i . cant increase in labor efficiencies and cost savings. We also con- (Connecticut Yankee), unanimously voted to retire the IIaddam )

Neck, Connecticut unit. The decision was imed on an eco- l tinued to develop customer alliances and provided economic

- development rates to some customers. These actions all illus, n mic analysis of the costs of operating the unit through 2007,

! trate our commitment to be a competitively priced, reliable the period ofits operating license, compared to the costs of provider of energy. cl sing the unit and incurring replacement power costs for the in the traditional revenue requirements model, our electric same period. We have a 9.5% equity investment in CYAPC of  ;

revenues have been based on the cost of providing electric ser- appmximately $10 million. Refer to Note L4. to the j vice. As such, we are subject to certain accounting standards Conwlidated Financial Statements for more information regard-that are not applicable to other businesses and industries in gen- ing Connecticut Yankee.

emli We believe that we currently meet the criteria of these Environmental I J

standards. Statement of Financial Accounting Standards No.

. . W,e are subj.ect to numerous federal, state and local standards w.ah 71, Accountmg for the Effects of Certam Types of Regulan. on respect to waste dn.posal, a.ir and water quality and other environ- )

(SFAS 71) requires us to defer recognition of certain costs when mental considerations. These standards can require that we mod-mcurred when we expect to receive future rate recovery of these . .

.. i our existing facih. .nes or mcur increased operating costs.

.fy costs. The Secun. .nes and Exchange Commission has recently

. . . W.e own or operate approximately 40 properties where o.d begun to focus on how the changes .m the elecute unh.ty mdus-i Wh ials N or aled. V'e

sion reductions by 1999 or years d ereafter. The extent of any also continue to face possible liability as a potentially responsi-additional emission restrictions and the cost of any further mod-ble party in the cleanup of approximately ten multi-party haz-ifications is uncertain at this time.

ardous waste sites in Massachusetts and other states where we Public concern continues regarding electromagrietic fields are alleged to have generated, transported or disposed of haz-ardous waste at the sites. Refer to Note L.6. to the (EMF) associated with electric transmission and distribution Consolidated Financial Statements for more information regard- facilities and appliances and wiring in buildings and homes.

Such concerns have included the possibility of adverse health ing hazardous waste issues.

effects caused by EMF as well as perceived effects on property In October 1996, the Accounting Standards Executive vdues. Some scientific reviews conducted to date have suggest-Committee of the American Institute of Certified Public ed usociations between EMF and potential health effects, while Accountants issued Statement of Position 96-1, Environmental Remediation Liabilities, effective in 1997. This statement con- other studies have not substantiated such associations. The National Research Council recently reported that there is no tains authoritative guidance on specific accounting issues that conclusive evidence that exposure to EMF from power lines and are present in the recognition, measurement, display and disclo-appliances presents a heahh hazard. The panel of scientists, sure of environmental remediation liabilities We do not believe working with the National Academy of Sciences, report that that this statement will have a material effect on our financial more than 500 studies over the last several years have produced position or results of operations.

Uncertainties continue to exist with respect to the disposal no proof that EMF causes leukemia or other cancers or harms human health in other ways. We continue to support research of both spent nuclear fuel and low-level radioactive waste into the subject and are participating in the funding ofindus-(LLW) resulting from the operation of Pilgrim Station.The try-sponsored studies. We are aware that public concern regard-United States Department of Energy (DOE) is responsible for ing EMF in some cases has resulted in litigation, in opposition the ultimate disposas of spent nuclear fuel; however, there are to existing or proposed facilities in proceedings before regulators uncertainties regarding the DOE's schedule of acceptance of or in requests for legislation or regulatory standards concerning spent fuel for disposal. In 1995 we regained access to the LLW EMF levels. We have addressed issues relative to EMF in vari-disposal facility located in Barnwell, South Carolina. Refer to ous legal and regulatory proceedings and in discussions with Note E to the Consolidated Fimcial Statements for further customers and other concerned persons; however, to date we discussion regarding spent nuclear fuel and LLW disposal.

Tne 1990 Clean Air Act Amendments require a significant have not been significantly affected by these developments. We 23 continue to closely monitor all aspects of the EMF issue.

reduction in nationwide emissions of sulfur dioxide from fmni fuel-fired generating units. Sulfur dioxide emissions will be Litigation restricted through a market-based system of allowances. In 1996 We were named as a party in lawsuits by Subaru of New we sold sulfur dioxide allowances related to the years 2000 to England, Inc. and Subaru Distributors Corporation. The plain-2010 that are cxpected to be in excess of our needs. Proceeds tiffs claimed certain automobiles stored on lots in South Boston from the sale of these allowances were recorded as a regulatory suffered pitting damage caused by emissions from our New liability as it is probable that we will be required to refund the Boston Station generating unit. In February 1997, we settled proceeds to customers. We have the option to repurchase certain the lawsuit brought by Subaru Distributors Corporation. The of these allowances at specified prices from 2000 to 2010. We settlement did not have a material impact on our financial posi-currently do not anticipate exercising these options; however, tion or resuhs of operations. The Subaru of New England, Inc.

their potential exercise will be based on numerous factors, lawsuit is still pending.

including the timing of the Retail Access Date. As discussed in Refer to Note L.7. to the Consolidated Financial the Positioning in the Industry section, under our settlement Statements for more information on these lawsuits and other agreement we have agreed to the divestiture of our fossil generat.

legal matters in which we are involved.

ing plants no later than six months after the Retail Access Date (the later of January 1,1998 or the date when retail access is Safe harbor cautionary statement made evailable to all customers of Massachusetts investor-owned We ccasionally make forward-looking statements such as fore-utilities). If regulatory approval is not obtained or is delayed, it casts and projections of expected future performance or state-is possible that we could continue to operate these units. Other mms f ur plans and objectives. These forward-looking state-provisions of the 1990 Clean Air Act Amendments involve limi- ments may be contained in filings with the Securities and tations on emissions of nitrogen oxides from existing generating Exchange Commission, press releases and oral statements.

units. Combustion system modifications made to New Boston Actual results could potentially differ materially from these and Mystic Stations, including the installation oflow nitrogen statements. Therefore, no assurances can be given that the out-oxides burners at New Boston, have allowed the units to meet c mes stated in such forward-looking statements and estimates the provisions of the 1995 standards. Depending upon the out, wdl be achieved.

come of certain Massachusetts Department of Environmental The preceding sections include certain forward-locking Protection air quality modeling studies currently in progress, the st rements about the effects of the mdustry restructuring continued operation of these units could require additional emis-

-' ' ~ '

process and our related settlement agreement, our joint ven-tures, operating results, Pilgrim Station's performance, rates, technology and the prices and availability of operating supplies could materially affect our projected operating results.

Connecticut Yankee and environmental and legal issues.

Pilgrim Station's performance could differ from our expec-The efTects of the industry restructuring process currently tations. The station's capacity factor could be impacted by underway at the MDPU and our related settlement agreement changes in regulations or by unplanned eutages resuhing from could differ from our expectations. This could occur as regula- certain operating conditions.

tory decisions and negotiated setdements between utilities and The ultimate liability related to the shutdown of intervenors are finalized. In addition, the development of a competitive electric generation market, the impacts of actual Connecticut Yankee could difTer from the current estimate. In addition, although not anticipated, it is possible that some por-electric supply and demand in New Engir.a and legislative tion of our share of post-operation costs may not be recoverable action may affect the ultimate results of the industry restructur-from ultimate customers.

ing and our serdement agreement.

The timing and activities of our joint ventures as well as The impacts of various environmental and legal issues our actual investments may differ from our expectations. could differ from our expectations. New regulations or changes to existing regulations could impose additional operating This could occur if required regulatory approvals are delayed or not obtained. requirements or liabilities other than expected. The efTects of The impacts of our continued cost control procedures on changes in specific hazardous waste site conditions and Jeanup technology could affect our estimated cleanup liabilities. The our operating results could difTer from our expectations. The impacts of changes in available information and circumstances effects of changes in economic conditions, tax rates, interest regarding legal issues could affect our estimated litigation costs.

?4

Consolidated Statements ofIncome years ended December 31, (in thousands, except earnings per share) 1996 1995 1994 Operating mvenues 5 1,666,303 $ 1,628,503 $ 1,544,735 Operating expenses:

Fuel and purchased power 588,893 535,806 513,825 Operations and maintenance 417,372 458,196 443,545 Restructuring costr 0 34,000 0 Depreciation and amortization 185,494 153,339 148,845 Amortization of deferred costs of cancelled nuclear unit 0 0 19,791 Demand side management programs 30,825 45,125 35,438 Taxes-property and other 107,086 106,361 100,015 Income taxes 88,703 66,276 54,798 Total operating expenses 1,418,373 1,401,103 1,316,257 Operating income 247,930 227,400 228,478 Other income (expense), net 698 (575) 3,979 Operating and other income 248,628 226,825 232,457 Interest charges:

Long-term debt 94,823 106,640 102,570 Other 14,551 12,642 12,343 Allowance for borrowed funds used during construction (2,292) (4,767) (7,478)

Total interest charges 107,082 114,515 107,435 Net income 141,546 112,310 125,022 Preferred stock dividends 15,365 15,571 15,765 Earnings available for common shareholders $ 126,181 5 96,739 $ 109,257 25 Weighted average common shares outstanding 48,265 46,592 45,338 s

Earnings per share of common stock $ 2.61 $ 2.08 $ 2.41 Consolidated Statements of Retained Earnings years ended December 31, (in thousands) 1996 1995 1994 Balance at the beginning of the year $ 257,344 $ 247,004 $ 218,292 Net income 141,546 112,310 125,022 Subtotal 398,890 359,314 343,314 Cash dividends declared:

Preferred stock 15,365 15,571 15,765 Common stock 90,834 86,399 80,545 Subtotal 106,199 101,970 96,310 Provision for preferred stock redemption and issuance costs (a) 905 0 0 Balance at the end of the year $ 291,786 5 257,344 5 247,004 (a) Refer to Note B.7. to the Consolidated Financial Statements.

The accompanying notes are an integral part of the consolidated financial statements.

1 l

Consolidated Balance Sheets December 31, (in thousands) 1996 1995 Assets Utility plant in service, at original cost $ 4,393,585 $ 4,315,422 Less: accumulated depreciation 1,550,317 $ 2,843,268 1,439,996 $ 2,875,426 Nuclear fuel 351,453 302,594 Less: accumulated amortization 268,509 82,944 251,951 50,643 Construction work in progress 30,376 29,573 Net utility plant 2,956,588 2,955,642 Investments in electric companies, at equity 23,054 23,620 Nuclear decommissioning trust 132,076 102,894 Current assets:

Cash and cash equivalents 5,651 5,841 Accounts receivable 233,024 219,114 Accrued unbilled revenues 34,922 37,113 Fuel, materials and supplies, at average cost 57,075 59,631 Other 45,146 375,818 23,607 345,306 Deferred debits:

Regulatory assets-power contracts 88,963 21,396 Other regulatory assets 113,063 128,699 Other 39,729 59,613 Total assets $ 3,729,291 $ 3,637,170 g Capitalization and Liabilities Common stock equity $ 1,036,424 $ 989,438 Cumulative preferred stock:

Nonmandatory redeemable series 119,954 119,677 Mandatory redeemable series 81,465 84,837 Long-term debt 1,058,644 1,160,223 Current liabilities:

Long term debt / preferred stock due within one year $ 102,667 $ 102,667 Notes payable 201,454 126,441 Accounts payable 134,083 133,474 Accrued interest 24,378 25,113 Dividends payable 25,343 25,351 Other 115,812 603,737 138,044 551,090 Deferred credits:

Power contracts 88,963 21,396 Accumulated deferred income taxes 498,718 497,282 Accumulated deferred investment tax credits 58,899 62,970 Nuclear decommissioning liability 133,388 113,288 Other 49,099 36,969 Commitments and contingencies Total capitalization and liabilities $ 3,729,291 $ 3,637,170 The accompanying notes are an integral part of the consolidated financial statements.

Consolidated Statements of Cash Flows years ended December 31, (in thousands) 1996 1995 1994 Operating activities:

Net income $ 141,546 $ 112,310 $ 125,022 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization 228,259 202,294 203,222 Deferred income taxes and investment tax credits (4,057) (25,193) (8,276)

Allowance for borrowed funds used during construction (2,292) (4,767) (7,478)

Net changes in:

Accounts receivable and accrued unbilled revenues (11,719) (34,626) (20,701)

Fuel, materials and supplies (2,171) 7,202 3,093 Accounts payable 609 2,978 23,196 Other current assets and liabilities (44,514) 26,485 35,217 Other, net 50,921 23,975 14,847 Net cash provided by operating activities 356,582 310,658 368,142 Investing activities:

Plant expenditures (excluding AFUDC) (151,045) (180,822) (198,771)

Nuclear fuel expenditures (52,967) (13,621) (21,934)

Demand side management expenditures 0 0 (37,007)

Sale of plant assets, net (106) 3,018 15,972 Nuclear decommissioning trust investments (29,182) (20,063) (16,771)

Electric company investments 566 1,058 (386)

Net cash used in investing activities (232,734) (210,430) (258,897) 77 Financing activities: ,,

Issuances:

Common stock 12,559 64,888 10,634 Long-term debt 0 125,000 15,000 Redemptions:

Preferred stock (4,000) (2,000) (2,000)

Long-term debt (101,600) (100,600) (50,000)

Net change in notes payable 75,013 (88,345) 10,635 Dividends paid (176,010) (100,152) (95,460)

Net cash used in financing activities (12 t,038) (101,209) (111,191)

Net decrease in cash and cash equivalents (190) (981) (1,946)

Cash and cash equivalents at the beginning of the year 5,841 6,822 8,768 Cash and cash equivalents at the end of the year 5 5,651 $ 5,841 5 6,822 Supplemental disclosures of cash flow information: ,

Cash paid during the year for Interest, net of amounts capitalized $ 100,810 $ 104,011 $ 99,287 Income taxes $ 98,668 $ 96,180 $ 46,074 The accompanying notes are an integral part of the consolidated financial statements.

Notes to Consolidated Financial Statements Note A. Nature of Operations We are an investor-owned regulated public utility operating in the energy and energy services business. This includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. A portion of our generation is produced by our wholly owned nuclear generating unit, Pilgrim Nuclear Power Station. We supply electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues were 88% retail and 12% wholesale in 1996. We also conduct unregulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG).

Through BETG and its subsidiaries, we are engaged in certain nonutility businesses, including energy utilization and conserva-tion, construction management and district energy. In December 1996, BETG signed a joint venture agreement with Residential Communications Network, Inc., currently known as RCN Telecom Services, Inc. (RCN), to form a limited liability company to pro-vide local and long-distance telephone service, video, high-speed Internet access and other telecommunications-related services (the

" Telecommunications Venture"). The unregulated entiry will be owned up to 49% by BETG, with RCN having the day-to-day man-agement responsibility. The joim venture agreement is subject to a number of conditions which must be satis 6ed before formal oper-ations begin, including the obtaining of certain regulatory approvals. In January 1997, BETG, through one ofits wholly owned sub-sidiaries, signed de6nitive agreements with Williams Energy Services Company (WESCO), a subsidiary ofThe Williams Companies, Inc., to form EnergyVision, LLC, an unregulated limited liability company. This " Energy Marketing Venture" will market electricity, natural gas and energy-related services to retail customers in the six New England states. BETG, through its subsidiary, and WESCO each own 50% of the new company which began operations in February 1997.

In January 1997, we announced a plan to form a holding company structuce. The holding company structure, which is subject to shareholder and regulatory approvals, is intended to provide increased financial, managerial and organizational flexibility in order to better position us to operate in the changing electric utility industry. It will permit us to take advantage of nonutility business opportunities in a more timely manner. In addition, the holding company structure will clearly separate our regulated and unregular-ed lines of business enabling us to pursue nonutility business ventures in a manner consistent with the electric utility industry restruc-turing principles outlined by the Massachusetts Department of Public Utilities (MDPU). The holding company structure is a well-28 established form of organization for companies conducting muhiple lines of business, particularly entities engaging in both regulated and unregulated acri ities. All investor-owned Massachusetts electric utilities, other than Boston Edison, are currently organized in a holding company structure.

Refer also to Note C to these C(msolidated Financial Statements for potential changer in the nature of our operations as a resuh of the electric utility industry restructuring.

Note B. 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 (HEEC) and BETG. All signi6 cant intercompany transactions have been climinated. Certain reclassiGcations have been made to the prior year data to conform with the current presentation.

We follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the MDPU. We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The consolidated financial state-ments conform with generally accepted accounting principles (GAAP). As a rate-regulated company we are subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 resuhs in difTerences in the timing of recognition of certain expenses from that of other businesses and indus-tries. The preparation of financial statements in conformiry with GAAP requires us to make estimates and assumptions that afTect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the fmancial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

2. Revenues We record estimates of revenues for electricity used by our customers but not yet billed at the end of each accounting period.

3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate. The difference between actual costs and the amounts billed to cus-tomers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated

balance sheer until subsequent rates are adjusted. The MDPU has the right to reduce our subsequent fuel and purchased power rates if they fmd that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.

4. Utility Plant Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance an repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value related costs of removal are charged to accumulated depreciation.

5. D:pr:ciation and Nuclear Fuel Amortization Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful live various classes of property. Excluding the adjustment discussed below, the overall composite depreciation rates were 3.26%,3.28%

and 3.31% in 1996,1995 and 1994, respectively.

Upon the completion of a review of our electric generating units, we determined that our oldest and least ef6cient fossil units (Mystic 4,5 and 6) are unlikely to provide competitively priced power beyond the year 2000. Therefore, during the second quarter of 1996, we revised the estimated remaining economic lives of these units to five years retroactive to the beginning of the year. The effect of this change in estimate is an annual increase to depreciation expense of $22 million.

The cost of decommissioning Pilgrim Station is excluded from our depreciation rates. Refer to Note E to these Consolidated Financial Statements for a discussion of nuclear decommissioning. 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 spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy enrichment facilities. These costs are recovered from our customers through fuel rates.

6. D:fsrred Nuclear Outage Costs We defer the incremental costs associated with nuclear refueling outages when incurred and amortize them over future periods. In 1995 we changed the amortization period from fve years to two years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station.

7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemp-tion and issuance oflong-term debt and preferred stock. The costs related to long-term debt are recognized as an addition to interest expense over the life of the debt or replacement debt. Ileginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock redemptions and issuances as a direct reduction to retained earnings over the average life of the replacement preferred stock series.

8. Allowance for Borrowed Funds Used During Construction (AFUDC)

AFUDC represents the estimated costs to fmance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form ofincreased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1996,1995 and 1994 were 5.87%,6.35% and 4.45%, respectively, and represented ontv the cost of short-term debt.

9. Cash and Cash Equivalents Cash and cash equivalents are compriad of highly liquid securities with maturities of 90 days or less when purchased. Outstanding checks are included in cash and accounts payable until they are presented for payment.

10. Allowance for Doubtful Accounts Our accounts receivable are substantially recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.

11. R:gulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accord with agreements with our regulators. These costs are expensed when the corresponding revenues are received in order to appropri ly match revenues and expenses. The majotity of these costs is currently being recovered from customers over varying time p 1 No return on investment is being earned on the regulatory assets.

Regulatory assets consisted of the following:

December 31, 1996 1995 Power contracts

$ 88,963 $ 21,396 Redemption premiums 31,052 36,832 income taxes, net 47,483 46,121 Postretirement benefits costs 15,009 15,009 Decontamination and decommissioning 13,190 13,968 Nuclear outage costs 3,432 13,471 Other 2,897 3,298 5 202,026 $ 150,095

12. Earnings Per Share of Common Stock Earnings per share of common stock is calculated by dividing net income, after the payment of preferred stoc weighted average common shares outstanding during the year.

Note C. Electric Utility Industry in December 1996, we reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Energy Resources that, if approved by the MDPU, allows all retail electric customers in our service area to c supplier (referred to as retail access) beginning as early as January 1,1998. As part of the settlement, we have agre fossil generating plants no later than six months after the commencement of retail access. Accordingly, other t Power Station, we will no longer own any electricity generating facilities. The rates of our retained electric delivery bu tinue to be regulated by the MDPU and will include a non-bypassable access charge for the collection of our stranded costs

. These costs include the above-market commitments under existing purchased power contracts, our net generation plant investm decommissioning commitments and regulatory assets related to our generation business. Implementation of the settle 30 subject to enactment of enabling legislation by the Massachusetts legislature and rulings by the FERC.

in the traditional revenue requirements model, our electric revenues have been based on the cost of providing ele such, we are subject to certain accounting standards that are not applicable to other businesses and industries in ge that we currently meet the criteria of these standards. SFAS 71 requires us to defer recognition of certain costs when inc we expect to receive future rate recovery of these costs. The Securities and Exchange Commission has recently begun to the changes in the electric utility industry have affected utilities' ability to continue to apply regulatory accounting issued by the MDPU or the enactment oflegislation in Massachusetts could, in the near term, cause us to no longe for application of SFAS 71 for some of our operations. Should this occur, we would be required to take an immediate non charge to income for all of our affected regulatory assets and the above-market portion of purchased power contracts write-down of utility plant assets would be required under Statement of Financial Accounting Standards No.1 impairment oflong-Lived Assets and for Long-Lived Assets to be Disposed Of, if competitive or regulatory ch ability that fature cash flows will not be sufficient to recover our investment in those assets. Based on our settle expect to recover all strandable costs through a non-bypassable access charge to be paid by our delivery business customers. Un our settlement agreement, our delivery business will remain subject to rate regulation and, therefore, will continue to mee of these accounting standards. As noted earlier, under our settlement agreement we expect to continue to ope with the ability to collect stranded costs related to the unit. Although not anticipated based on our settlement agreem covery of strandable costs could have a material impact on our results of operations and financial condition. However, iflaws enacted or regulatory decisions are made that do not offer Massachusetts electric utilities an opportunity to reco reviewed, prudently inc ed commitments to provide service to our customers, we believe we have strong legal argum lenge such laws or decisbns. Te will actively pursue the full recovery of stranded cc,sts and are prepared to protect the interests of our shareholders.

Our 1992 settlement agrement provided us with two annual retail base rate increases of $29 million effective in Nove and November 1994 and an eight-year annual performance adjustment charge. We did not make a base rate tion of the settlement agreement in 1995, therefore base rates have remained in effect at their 1995 levels.

Note D. Income Taxes income taxes are accounted for in accordance with Statement of Financial Accounting Standards No.109, Accounting for Incame Taxes (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differ-ences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory assets of $47.5 million and $46.1 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1996, and December 31,1995, respectively. The regulatory assets represent the additional future revenues to be collected from cus-tomers for deferred incorne taxes.

Accumulated deferred income taxes consisted of the following: ,

December 31, (in thousands) 1996 1995 Deferred tax liabilities:

Plant-related $532,390 $521,280 Other 95,642 95,148 628,032 616,428 Deferred tax assets:

Plant-related 8,406 12,590 Investment tax credits 38,005 40,632 Other 82,903 65,924 129,314 119,146 Net accumulated deferred income taxes $498,718 $497,282 No valuation allowances for deferred tax assets are deemed necessary.

Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits.

Components ofincome tax expense were as follows: 3,

, years ended December 31, (in thousands) 1996 1995 1994 Current income tax expense $92,760 $93,469 $63,358 Deferred income tax expense 14 (21,115) (4,468)

Investment tax credits (4,071) (4,078) (4,092)

Income taxes charged to operations 88,703 68,276 54,798 Taxes on other income:

• Current (721) (1,729) 2,550 Deferred 0 0 264 (721) (1,729) 2,834 Total income tax expense $87,982 $66,547 $57,632 The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:

1996 1995 1994 Statutory tax rate 35.0% 35.0% 35.0 %

State income tax, net of federal income tax benefit 4.3 4.3 4.3 investment tax credits (1.8) (2.3) (2.3)

Reversal of deferred taxes - settlement agreement - -

(5.5)

Other 0.7 0.1 (0.1)

Effective tax rate 38.2% 37.1 % 31.4 %

Note E. Nuclear Decommissioning and Nuclear Waste Disposal

1. Nuclear Decommissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We record an estimate of decommissioning costs in depreciation expense on the consolidated statements ofincome over Pilgrim's expected service life.

Decommissioning expense was $12 million, $14 million and $15 million in 1996,1995 and 1994, respectively. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the " green field" method, which provides for the plant site to be completely restored to its original state. The cost esti-mate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a contracted amount of Pilgrim's clectric genera-tion. The funds we collect from decommissioning charges are deposited in an external trust and are restricted to use for decommis-sioning and related expenses. The net earnings on the trust funds, which are also restricted, increast the nuclear decommissioning trust balance, thus reducing the amount to be collected from customers.

The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact oflong-term spent fuel storage options resulting from delays in the United States Department of Energy (DOE) spent fuel removal program. Refer to part 2 below for a discussion of spent fuel removal. The partial update indicates an estimated decommissioning cost of $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage tech-nology. No further update is currently available; however, we will continue to monitor DOE spent fuel removal schedules and devel-opments in spent fuel storage technology along with their impact on the decommissioning estimate. We anticipate that we will be permitted to recover our actual ultimate decommissioning costs from our retail and contract customers.

In February 1996, the Financial Accounting Standards Board (FASB) issued proposed new rules for accounting for liabilities related to closure and removal oflong-lived assets, which include decommissioning of nuclear generating facilities. If these proposed rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the bal-ance sheet, offset by an addition to utility plant. The plant addition would be depreciated over Pilgrim's remaining expected service j life. The liability would be measured based on the present value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in the recognition of a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation 32 expense previously recognized for decommissioning. In addition, trust fund earnings would be reported on the income statement.

Depending on the resuhs of the FASB's redeliberation of certain issues regarding these proposed rules, it plans to issue either a final statement or revised proposed rules in the second quarter of 1997.

2. Spent Nuclear Fuel The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the Nuclear Regulatory Commission to modify the facility to provide suflicient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the MDPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies, including proposed participa-tion in a limited liability company (L1 C) which would undertake construction of a private spent fuel storage facility in the state of Utah or other locations. Our participation in this LLC requires approval by the MDPU and is currently the subject of a petition seeking such approval.

In July 1996, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the DOE is obligated to begin taking spent nuclear fuel for disposa! in 1998. The decision was in response to petitions filed by us and other interested parties in 1994 seeking declaratory ruhnn concerning this obligation. In December 1996, the DOE notified us and other nuclear plant owners that it would be unable to begin acceptance of spent nuclear fuel for disposal in 1998. Along with other interested parties, we again fded a petition with the U.S. Court of Appeals for the Disuict of Columbia Circuit seeking declaratory rulings concerning enforcement and remedies for DOE's failure to accept spent fuel for disposal in a timely manner. Under the Nuclear Waste Policy Act of 1982 it is the uhimate responsibility of the DOE to permaw.tly dispose of spent nuclear fuel. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. The DOE has been conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political opposition and the DOE has publicly stated that it will be unable to begin acceptance of spent nuclear fuel for disposal by the date specified in the Nuclear Waste Policy Act. We cannot predict at this time whether or on what schedule the DOE will eventually construct a spent fuel repository or what the effect will be of any delays in such construction.

3. Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) dispc, sal facilities located in Barnwell, South Carolina, in 1995. This site is j

currently the only disposal facility available to us. Leg Gation has been enacted in Massachusetts establishing a regulatory process for managing the state's LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternative-ly, an agreement with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other 11W management procedure, we will continue to monitor the situation and investigate other available options.

Note F. Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separat- business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement pro-grams and implemented a special severance program to reduce employee staffing levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employees whose positions were climinated became eligible for benefas under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million c.-t of tax) over the third and fourth quarters of 1995. The charge consisted of $24 milPon for the retirement programs and $10 mihion for the severance program. The enhanced retirement programs were offered to all employees at least 55 years old, with difTerent years of service requirements for management and union employees. The programs provided for supplemental salary payments and waivers of the early retirement pension reduction and the medical and life insurance benefits years of service requirement. The special severance program, which applied to management and support personnel, was pnwided for all employees whose positions were eliminated in the reorganization. Severance benefits pro-vided included salary payments, medical insurance and outplacement services. As of December 31,1996, there was no material obliga-tion remaining for these programs.

Note G. Pensions and Other Postretirement Benefits

1. Pensions We have a defined benefit ftmded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employ-ment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market funds, 33 insurance contracts and real estate funds.

We also have a supplemental retirement plan for certain management employees. Benefits under this plan are based on final com-pensation upon retirement. The plan is not funded. The plan's cost and benefit obligation amounts are induded in the following pen-sion information for 1995 and 1996. Amounts related to the plan prior to 1995 were not material to out total pension costs.

Net pension cost consisted of the following components:

years ended December 31, (in thousands) 1996 1995 1994 Errent service cost - benefits earned $13,452 $11,339 $15,057 Int 3 rest cost on projected benefit obligation 32,325 31,789 33,961 A tus set (return)/ loss on plan assets (40,335) (72,192) 214 Nt t amort:stion and deferral 17,064 49,557 (32,169)

Net pensit. ' cost $22,506 $20.493 $17,063 In accorda ice with our 1992 settlement agreement we deferred the difference between the net pension cost of the retirement plan and its annual funding amount through 1995. Net pension costs recognized in 1995 and 1994 were $28.2 million and $25.0 million, respectively.

We used the following assumptions for calculating pension cost:

1996 199E 1994 Discount rate 7.25% 8.2f6 7.00 %

Expected long-term rate of return on assets 10.00% 10D0ro 10.00 %

Compensation increase rate 3.90% 3.90% 4.50 %

The plans' funded status were as follows:

December 31, (in thousands) 1996 1995 Supplemental Supplemental Retirement Retirement Retirement Retirement Plan Plan Plan Plan Actuarial present value of accumulated benefit obligation:

Vested $ 316,101 $ 7,576 $ 377,272 $ 8,748 Non-vested 10,867 943 13,902 1,409 Total (a) $ 326,968 $ 8,519 $ 391,174 5 10,157 Plan assets at fair value $ 331,299 $ 0 $ 358,572 5 0 Projected obligation for service rendered to date (400,561) (9,199) (476,666) (11,036)

Projected benefit obligation in excess of plan assets (69,262) (9,199) (118,094) (11,036)

Unrecognized prior service cost 11,238 9,436 12,283 10,223 Unrecognized net loss /(gain) 78,853 (1,141) 82,935 252 Unrecognized net obligation 7,130 0 8,064 0 Additional minimum liability (b) 0 (7,615) (17,790) (9,596)

Net pension prepayment /(liability) $ 27,959 $ (8,519) $ (32,602) $ (10,157)

(a) The accumulated benefit obligation at December 31,1995, includes $13.5 million related to the enhanced retirement programs offered in 1995 as discussed in Note F to these Consolidated Financial Statements.

(b) Statement of Financial Accounting Standards No. 87. Employers' Accounting for Pensions (SFAS 87), requires the recognition of g an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SFAS 87 we recorded additional minimum liabilities and corresponding intangible assets of 57.6 million and $27.4 million on our consolidated balance sheets at December 31,1996 and 1995, respectively.

We used the following assumptions for calculating the plans' year-end funded status:

1996 1995 Discount rate 7.75% 7.25 %

Compensation increase rate 3.90% 3.90 %

We also provide defined contribution 401(k) plans for substantially all our employees. We match a percentage of employees' sol-untary contributions to the plans. We made matching contributions of 58 million in 1996, $9 million in 1995 and 58 million in 1994.

2. Other Postretirement Benefits in addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting Standards No.106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). Out 1992 settlement agreement provided us with a phase-in to full expense of the PBOP costs incurred under SFAS 106. The 1992 settlement agreement allowed us to defer any costs in excess of the specified phase-in amounts to the extent that we funded an external trust. Our funding policy is to generally contribute 100% of PBOP costs to external trusts. Therefore, we recorded $23 mil-tion and $17 million of PBOP costs in 1995 and 1994, respectively in accordance with the 1992 settlement agreement. In 1996 we recorded the full PBOP costs incurred under SFAS 106 of $26 million. The net deferred PBOP costs of $15 million resulting from the delayed phase-in are included in regulatory assets as these costs are expected to be recovered from customers in future periods.

Net postretirement benefits cost consisted of the following components:

years ended December 31, (in thousands) 1996 1995 1994 Current service cost - benefits earned S 4,616 $ 3,408 5 4,978 Interest cost on accumulated benefit obligation 16,815 13,521 13,632 Actual return on plan assets (9,584) (7,151) (187)

Amortization of transition obligation 9,151 9,151 9,151 Net amortization and deferral 5,209 3,017 (2,581)

Net postretirement benefits cost 5 26,207 $ 21,946 5 24,993 We used the following assumptions for calculating postretirement benefits cost:

1996 1995 1994 Discount rate 7.25% 8.25 % 7.00 %

Expected long-term rate of return on assets 9.00% 9.00 % 9.00 %

Health care cost trend rate 7.00 % 7.00% 9.00 %

The health care cost trend rate is assumed to decrease by one percent in 1997 and 1998 and to remain at 5% in years thereafter.

Changes in the heahh care cost trend rate will affect our cost and obligation amounts. A one percent increase in the assumed health care cost trend rate would increase the total service and interest cost components by 7.6% and would increase the accumulated benefit obligation at December 31,1996, by 6.7%.

The PBOP program's funded status was as follows:

December 31, (in thousands) 1996 1995 35 Trust assets at fair value $ 72,702 5 51,064 Accumulated obligation for service rendered to date from:

Retirees $ (156,694) $ (110,877)

Active employees eligible to retire (12,644) (31,980)

Active employees not eligible to retire (61,567) (230,905) (53,514) (196,371)

Accumulated benefit obligation in excess of trust assets (158,203) (145,307)

Unrecognized prior service cost (16,274) (17,889)

Ur. recognized net loss 26,663 5,612 Urrecognized transition obligation 146,413 155,564 Net postretirement benefits liability $ (1,401) $ (2,020)

The weighted average discount rates used to measure the accumulated benefit obligation were 7.75% in 1996 and 7.25% in 1995.

The trust assets consist of equitics, bonds and money market funds.

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Note H. Capital Stock December 31, (dollars in thousands, except per share amounts) 1996 1995 Common stock equity:

Common stock, par value $1 per share, 100,000,000 shares authorized; 48,509,537 and 48,003,178 shares issued and outstanding: $ 48,510 $ 48,003 Premium on common stock 695,723 683,686 Retained earnings 2M,786 257,344 Surplus invested in plant 405 405 Total common stock equity $1,036,424 5 989,438 Dividends declared per share of common stock were $1.88, $1.835 ai,J 51.775 in 1996,1995 and 1994, respectively.

Cumulative preferred stock:

Par value $100 per share,2,890,000 shares authorized; issued and outstanding:

Nonmandatoy redeemable series:

Current Shares Redemption Series Outstanding Price / Share 4.25% 180,000 $103.625 5 18,000 $ 18,000 4.78 % 250,000 $102.800 25,000 25,000 7.75 % 400,000 -

40,000 40,000 8.25% 400,000 40,000 40,000 123,000 123,000 Less: redemption and issuance costs (3,046) (3,323) 36 Total nonmandatory redeemable series $ 119,954 $ 119,677 Mandatory redeemable series:

Current Shares Redemption Series Outstanding Price / Share 7.27% 400,000 $102.910 $ 40,000 $ 44,000 8.00% 500,000 50,000 50,000 90,000 94,000 Less: redemption and issuance costs (6,535) (7,163) due within one year (2,000) (2,000)

Total mandatory redeemable series $ 84,837 5 81.465

1. Common Stock Common stock issuances in 1994 through 1996 were as follows:

Number Total Premium on (in thousands) of Shares Par Value Common Stock Balance at December 31,1993 45,129 5 45,129 $ 612,653 Dividend reinvestment plan 406 406 10,150 Balance at December 31,1994 45,535 45,535 622,803 Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 Balance at December 31,1995 48,003 48,003 683,686 Dividend reinvestment plan 507 507 12,037 Balance at December 31,1996 48,510 $ 48,510 $ 695,723

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2. Cumulttiva Mandatory Radamable Preferred Stock The 400,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $102.910.

The redemption price declines annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each Aiay to redeem additional shares, not to exceed 20,000, through the sinking fimd at 5100 per share plus accrued dividends. In 1996,1995 and 1994, we redeemed, at par value,40,000 shares,20,000 shares and 20,000 shares, respectively. The redemptions in 1996 include 20,000 shares of optional redemptions.

We are not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at 5100 per share, plus accrued dividends.

Nots 1. Indebtedness December 31, (in thousands) 1996 1995 Long-term debt:

Debentures:

5.125%, due March 1996 $ 0 $ 100,000 5.700%, due March 1997 100,000 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentures 1,115,000 1,215,000 37 Less: due within one year (100,000) (100,000)

Net long-term debentures 1,015,000 1,115,000 Sewage facility revenue bonds 34,100 35,700 Less: due within one year (667) (667)

Less: funds held by trustee (4,789) (4,810)

Net long-term sewage facility revenue bonds 28,644 30,223 Massachusetts Industrial Finance Agency bonds:

5.750%, due February 2014 15,000 15,000 Total long-term debt $ 1,058,644 $ 1,160,223 Short-term debt:

Notes payable:

Bank loans $ 129,631 $ 75,941 Commercial paper 71,823 50,500 Total notes payable $ 201,454 5 126,441 1, Long-Term Debt The 9 7/8% debentures due 2020 are Grst redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are Grst redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are Grst redeemable in September 2002 at 103.780%

and the 7.80% series due 2023 are Srst redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity.

There is no sinking fund requirement for any series of our debentures.

Sewage facility revenue bonds were issued by FIEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund l redemption requirements and mature through 2015. In May 1995 and 1996, we redeemed $0.6 million and $1.6 million, respec-

tively, as scheduled. The weighted average interest rate of the bonds is 7.3% A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insuf6cient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of 51 million.

The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%

The redemption price decreases to 101% in February 2005 and to par in February 2006.

The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2001 are

$101.6 million per year in 1997 and 1998,51.6 million in 1999,5166.6 million in 2000 and 51.6 million in 2001.

2. 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 regulatory authority to issue up to 5350 million of short-term debt.

We have a 5200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equiry ratio of not less than 30% at all times. 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:

(dollars in thousands) 1996 1995 1994 Maximum short-term borrowings 5 272,500 $ 327,769 $ 268,100 Weighted average amount outstanding $ 208,914 $ 165,720 $ 214,640 Weighted average interest rates excluding commitment fees 5.65% 6.21 % 4.47 %

Note J. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of securitics for which it is practicable to estimate the value:

38 Nuclear decommissioning trust:

The cost of $132.1 million approximates fair value based on quoted market prices of securities held.

Cash and cash equivalents:

The carrying amount of $5.7 million approximates fair value due to the short-term nature of these securities.

Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt:

The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31,1996, are as follows:

Carrying Fair (in thousands) Amount Value Mandatory redeemable cumulative preferred stock $ 83,465 $ 93,900 Sewage facility revenue bonds S 34,100 $ 35,082 Unsecured debt $ 1,130,000 $ 1,131,363 Note K. New Accounting Pronouncement in October 1996, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 96-1, Environmental Remediation Liabilities, effective in 1997. This statement contains authoritative guidance on specific accounting issues that are present in the recognition, measurement, display and disclosure of environmental remediation liabilities. We do not believe this statement will have a material effect on our financial posioon or results of operations.

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Not2 L. Commitm:nts and Conting:nci:s

1. Contractual Commitments At December 31,1996, we had estimated contractual obligations for plant and equipment of approximately 58 million.

We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1996 are as follows:

(in thousanda 1997 $ 22,842 1998 20,042 1999 17,568 2000 16,684 2001 12,067 Years thereafter 98,945 Total $ 188,148 The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $455,117.

We will capitalize a portion of these lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $26.3 million in 1996,524.5 million in 1995 and $28.6 million in 1994, net of capitalized expenses of $2.9 million in 1996, $2.7 million in 1995 and $2.4 million in 1994.

We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply our New Boston generating station with natural gas. The fixed and determinable portions of the obligations are 519.5 million in 1997,1998 and 1999 and $14.6 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $49.5 million in 1995, $13.9 million in 1995, and $6.5 million in 1994.

2. Hydro-Quebec We have an approximately 11% equiry ownership interest in two companies which own and operate transmission facilities te import 39 '

electricity from the Hydro-Quebec system in Canada. 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. At December 31,1996, our portion of these guarantees was approximately $18 million.

3. Yrnkee Atomic We have a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and decommission the facility.

Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 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 $16.5 million as of December 31,1996. This estimate is recorded on our consolidated halance sheet as a power con-tract liability and an offsetting regulatory asser as we continue to collect these costs from our customers in accordance with our 1992  :

settlement agreement.

4. Connecticut Yankee On December 4,1996, the board of directors of Connecticut Yankee Atomic Power Company (CYAPC), which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the Haddam Neck, Connecticut unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period ofits operating license, compared to the costs of closing the unit and incurring replacement power costs for the same period. We have a  !

9.5% equity investment in CYAPC of approximately 510 million.

I The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee is approximately 5763 million. Our share of these remaining estimated costs is $72.5 million.

On December 24,1996, CYAPC filed its cost estimate along with certain amendments to its power contracts with the FERC.

The power contract amendments are designed to clarify the obligations of CYAPC's power purchasers, including Boston Edison, fol-lowing the decision to cease power production. Based upon regulatory precedent, CYAPC believes it will continue to collect from its

power purchasers its decommissioning costs, the owners' unrecovered investments in CYAPC and other costs associated with the per-l manent closure of the unit over the remaining period of the unit's operating license. We expect that we will continue to be allowed to

recover our share of such costs from our customers and, therefore, have recorded our share of these costs on our consolidated balance sheet as a regulatory asset with a corresponding power contract liability.

5. Nuclear Insurance '

The federal Price-Anderson Act currently provides approximately 58.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insur-ance. Additional nuclear liability insurance up to approximately $8.7 billion is provided by a retrospective assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a max- i imum assessment of $10 million per reactor per accident in any year.  ;

We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replace-  !

ment power during a prolonged accidental outage and the cost of repair, replacement, decontamination or decommissioning of our l l

utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur  !

during current policy years is $10.4 million under both the replacement power and excess property damage, decontamination and f decommissioning policies.

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6. Hazardous Waste l We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required  ;

i to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection i l ~ and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the i

complexities of cleanup technology, regulatory requirements and the particular characteristics of the difTerent sites. We also continue  ;

l to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in l Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the  ;

majority of these sites we are one o' nany potentially responsible parties and currently expect to have only a small percentage of the potentialliability. Through Decenu 31,1996, we have accrued approximately $7 million related to our cleanup liabilities. We are .

unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assess-  !

l ments of the specific site circumstances, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.

7. Litigation  !

40 We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs claimed {

certain automobiles stored on lots in South Boston sufTered pitting damage caused by emissions from our New Boston Station gener-  ;

ating unit. In February 1997, we settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a i material impact on our financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending.  ;

In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning employees affected by our 1988 reduction in force. In December 1996, we reached a settlement of this law-suit under which there is no finding or admission of discriminatory employment practices. We anticipate full recovery from our insurance carrier for this settlement.

In the normal course of our business we are also involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. riowever, it is reason-ably possible that additional litigation costs that may result from a change in estimates could have a material impact on the results of

, a re}mrting period in the near term.

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Note M. Long-Tarm Pow 2r Contrsets

1. Long-Term Contracts for the Purchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of the generating unit's ca ating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense o solidated income statements. Information relating to these contracts as of December 31,1996, is as follows:

proportionate share (in thousands)

Units of Debt Contract Capacity Minimum Outstanding Expiration Purchased (a) Debt Through Cont. Annual Generating Unit Date  % MW 5ervice Exp. Date t

Cost [

Canal Unit 1 2002 25.0 141 $ 1,415 $ 5,373 $ 24,399 i Mass. Bay Transportation Authority - 1 2005 100.0 34 - -

1,999 i Connecticut Yankee Atomic 2007 9.5 - 2,427 12,519 (b)

Ocean State Power - Unit 1 2010 23.5 68 4,487 20,447 23,689 Ocean State Power - Unit 2 2011 23.5 67 3,538 16,529 24,091 1 Northeast Energy Associates (c) (c) 219 - -

124,730 L'Energia (d) 2013 73.0 63 - - 30,920

]

MassPower 2013 44.3 117 11,738 76,524 50,322 .

Mass. Bay Transportation Authority - 2 2019 100.0 34 - -

371 Total 743 $ 23,605 $131,392 $ 280,521 l

r (a) The Northeast Energy Associates contract represents 6% of our total system generation capability. The remaining units listed j above represent 14.5% in total. i

! (b) Connecticut Yankee permanently ceased operation in 1996. Refer to Note L4. to these Consolidated Financial Statements for l

more details. #'

l (c) We purchase approximately 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and I 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.

(d) We pay for this energy based on a price per kWh actually received.

Our total fixed and variable costs for these contracts in 1996,1995 and 1994 were approximately $281 million (excluding Connecticut Yankee Atomic), $283 mil %n and $286 million, respectively. Our minimum fixed payments under these contracts for the years after 1996 are as foliew,.

i

(;n thousands) 1997 $ 85,429 1998 87,540 1999 88,401 2000 88,927 2001 91,089 Years thereafter 1,047,479

' Total $ 1,488,865

! Total present value $ 797,683 h

2. Long-T rm Pow:r Sil:s in addition to wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts.

Information relating to these contracts is as follows:

Contract Expiration Units of Capacity Sold Date  % MW Contract Customer 2012 11.0 7 3.',_

Commonwealth Electric Company Montaup Electric Company 2012 11.0 73.)

2000 (a) 3.7 25.0 Various municipalit:es 25.7 172.4 Total (a) Subject to certain adjustments.

Under these contracts, the utilities pay their pmportionate sha e of the costs of operating Pilgrim Station and associated transmis-sion facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decommissioning and a return on capital.

42 R: port ofIndependent Accountants To the Stockholders and Directors of Boston Edison Company We have audited the accompanying consolidated balancc sheets of Boston Edison Company and subsidiaries (the Company) as of December 31,1996 and 1995, and the related consolidated statements ofincome, retained earnings and cash flows for each of the three years in the period ended December 31,1996. These financial statements are the responsibility of the Company's management.

Our responsibility is to express an opinion on these fmancial statenients based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the fmancial statements are free of material misstatement. An audit indudes examining, on a test basis, evidence supporting the amounts and disdosures in the fmancial statements. An audit also indudes 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 211 material respects, the fmancial posi-tion of the Company as of December 31,1996 and 1995, and the consolidated results ofits operations and its cash flows for each of the three years in the period ended December 31,1996, in conformity with generally accepted accounting principles.

< M.

Boston, Massachusetts January 23,1997

5tct:d C:nsclid::ted Qu:rt:rly Fin nci I D:ta (Unzudit:d)

(in thousands, except earnings per share)

Balance Available Earnings Operating Operating Net for Common Per Average Revenues income Income Stock Common Share (a) 1996 First quarter $ 387,849 $ 52,093 $ 25,203 $ 21,313 $ 0.44 Second quarter 389,756 55,232 27,926 24,066 0.50 Third quarter 497,968 105,353 80,011 76,194 1.58 Fourth quarter 390,730 35,252 8,406 4,588 0.09 1995 First quarter $ 379,678 $ 47,610 $ 20,202 $ 16,300 $ 0.36 Second quarter 380,828 55,683 26,137 22,247 0.48 Th;rd quarter 498,554 102,695 (b) 72,368 (b) 68,478 (b) 1.46 (b)

Fourth quarter 369,443 21,412 (b) (6,397) (b) (10,286)(b) (0.21) (b)

(a) Based on the weighted aserage number of common shares outstanding during each quarter.

(b) As discussed in Note F to the Consolidated Financial Statements, we incurred a $34 million nonrecurring pre-tax charge related to our corporate restructuring over the third and fourth quarters of 1995. Amounts excluding the restructuring charge were as follows:

Balance Available Earnings Operating Net for Common Per Average Income income Stock Common Share 1995 Third quarter $ 107,779 $ 77,452 $ 73,562 $ 1.57 Fourth quarter 36,991 9,182 5,293 0.11 Selected Quarterly Common Stock Data Following is the reported high and low market value per share of our common stock as reported in the El/StrutJournaland the divi-dends declared per share for each of the quarters in 1996 and 1995:

1996 1995 High Low Dividends High Low Dividends First quarter $301/8 $261/4 $0.470 $251/2 $231/8 $0.455 Second quarter 27 1/8 23 5/8 0.470 27 23 3/8 0.455 Third quarter 25 3/8 21 3/4 0.470 27 1/2 24 1/2 0.455

' Fourth quarter 27 21 3/4 0.470 29 1/2 26 3/4 0.470 l

S:l:cted Cons: lid:tzd Op:r;; ting St:tistics (Unrudit:d)

M 1996 1995 1994 1993 1992 Capacity - MW:

730 760 760 760 760 New Boston Station 670 669 669 670 670 Pilgrim Station 1,005 1,006 1,006 1,005 Mystic Station 994 36 36 36 6 W.F. Wyman Unit 4 37 278 284 287 283 281 Jet turbines 2,709 2,754 2,758 2,755 2,752 Total (a) 1,237 1,274 1,035 938 1,157 Contract purchases (333) (340) (373) (283) (303)

Contract sales 3,613 3,688 3,420 3,410 3,606 Net capability at year-end 3,385 3,466 3,484 3,663 3,587 Net capability at peak - MW Capability responsibility 3,256 3,306 3,306 3,190 3,396 to NEPOOL at peak - MW Company territory:

2,703 2,785 2,798 2,662 2,545 Hourly peak - MW 63.4 % 60.0 % 58.9 % 60.5 % 62.5 %

Load factor Generating station economy 10,568 10,348 10,408 10,345 10,234 (BTU / net kWh)

Capability (net kW):

86 % 85 % 84 % 84 % 81 %

Fossil y 16 % 19 %

14 % 15 % 16 %

Nuclear Generatic,n (system kWh excluding interchange):

69 % 73 % 75 % 68 % 69 %

Fossil 31 % 27 % 25 % 32 % 31 %

Nuclear Utility plant ($ in 000's):

$ 151,045 $ 180,822 $ 198,771 $ 246,774 $ 213,827 Expenditures 68,688 48,111 45,673 34,147 34,036 Retirements 1,550,317 1,439,996 1,344,452 1,258,359 1,177,294 Accumulated depreciation 4,317,028 4,235,347 3,994,212 3,841,752  ?,567,t 60 Depreciable plant Number of utility employees 3,362 3,812(b) 4,026 4,397 4,540 at year-end (a) Winter capability audit results (b) 3,590 at January 1,1996

Stcted Ccnsolid:ted Sxlzs Statistics (Unruditzd) 1996 1995 1994 1993 1992 Electric energy (kWh in thousands):

Sources (system output):

Generated 10,531,745 10,537,114 9,428,931 9,787,092 11,679,824 Purchased 5,680,194 5,446,542 5,920,065 5,326,224 5,449,225 New England Power Pool 1,842,732 1,513,467 1,535,335 1,575,310 932,121 Total 18,054,671 17,497,123 16,884,331 16,688,626- 18,061,170 Disposition:

Commercial 7,821,371 7,454,684 7,478,631 7,263,358 7,178,281 Residential 3,549,899 3,563,626 3,534,372 3,477,870 3,413,252 Industrial 1,547,630 1,538,218 1,539,385 1,580,969 1,671,564 Other (a) 130,678 131,626 130,721 145,242 292,510 Total retail sales 13,049,578 12,688,154 12,683,109 12,467,439 12,555,607 Wholesale and -

contract sales (a) 3,127,087 2,805,777 2,367,589 2,272,669 2,517,247 New England Power Pool 741,390 884,336 725,439 877,978 1,898,059 Total system 16,918,055 16,378,267 15,776,137 15,618,086 16,970,913 Miscellaneous usage 1,136M 6 1,118,856 1,108,194 1,070,540 1,090,257 Total 15,054,671 17,497,123 16,884,331 16,688,626 18,061,170

'Kilowatthour sales - annual growth:

Commercial - 4.9 % (0.3)% 3.0 % 1.2 % 0.5 %

Residential (0.4) 0.8 1.6 1.9 0.8 Industrial 0.6 (0.1) (2.6) (5.4) (0.8) 45 Other. (0.7) 0.7 (10.0) (50.3) 4.6 Total retail sales (a) 2.8 -

1.7 (0.7) 0.5 Wholesale and contract sales 11.5 18.5 4.2 (9.7) 51.6 New England Power Pool (16.2) 21.9 (17.4) (53.7) 51.5 Total system 3.3 % 3.8 % 1.0 % (8.0) % 10.1 %

Electric operating revenues by class:

Commercial 50 % 50 % 50 % 49 % 48 %

Residential 27 % 28 % 28 % 28 % 27 %

Industrial 9% 9% 9% 10 % 10 %

Wholesale and contract 12 % 11 % 11 % 12 % 13 %

Other . 2% 2% 2% 1% 2%

$etail revenue per kWh 11.11 e 11.12 e 10.68 e 10.33 e 9.55 e

$verage number of customers 657,487 653,757 655,707 651,141 646,215 Ka) EfTective in both November 1995 and February 1993, a former retail customer became a wholesale customer as allowed under l Massachusetts state law.

rtain reclassifications and recalculations were made to the data reported in prior years to conform with the method of presentation aed in 1996.

a

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S&ct:d Cens:lidst:d Fintnci:l St tistics (Unruditsd) 1996 1995 1994 1993- 1992 Operating revenues (000) $ 1,666,303 $ 1,628,503 $ 1,544,735 $ 1,482,159 $ 1,411,753 '

Bil:nce for common (000) $ 126,181 $ 96,739 (a) $ 109,257 $ 102,513 $ 90,748 Psr common share:

Earnings $ 2.61 $ 2.08 (a) $ 2.41 $ 2.28 $ 2.10 Dividends declared $ 1.880 $ 1.835 $ 1.775 $ 1.715 $ 1.655 Dividends paid $ 1.88 $ 1.82 $ 1.76 $ 1.70 $ 1.64 Book value $ 21.37 5 20.61 $ 20.11 $ 19.42 $ 18.77 Payout ratio 72 % 88 %(a) 73 % 75 % 78 %

Return on average common equity 12.4 % 10.0 %(a) 12.1 % 11.9 % 11.5 %

Year-end dividend yield 7.0 % 6.4 % 7.6 % 5.9 % 6.2 %

Fixed charge coverage (SEC) 2.91 2.38 2.46 2.22 1.89 Capitalization:

Total debt 52 % 54 % 56 % 57 % 56 % '

Preferred equity 8% 8% 9% 9% 9%

Common equity 40 % 38 % 35 % 34 % 35 %

Long-term debt (000) $ 1,058,644 5 1,160,223 $ 1,136,617 $ 1,272,497 $ 1,091,073 1 Mandatory redeemable prsferred stock (000) $ 83,465 $ 86,837- $ 88,837 $ 90,837 $ 90,837 Total assets (000) $ 3,729,291 $ 3,637,170 $ 3,608,699 $ 3,468,724 $ 3,286,335 Internal generation after dividends (000) $ 257,446 $ 184,492 $ 217,030 $ 194,209 $ 204,248 Plant expenditures (000) $ 151,045 $ 180,822 $ 198,771 $ 246,774 $ 213,838 g

Internal generation 170 % 102 % 109 % 79 % 96 % i Common shares outstanding:

Weighted average 48,264,734 46,591,662 45,337,661 44,959,050 43,143,953 Year-end 48,509,537 48,003,178 45,535,477 45,129,227 44,763,055 5tock price:

High 30 1/8 29 1/2 29 7/8 32 5/8 28 1/4 Low 21 3/4 23 1/8 21 1/2 26 3/8 22 1/8  !

Year-end 26 7/8 29 1/2 24 29 3/4 27 1/2 Year-end market value (000) $ 1,303,694 $ 1,416,094 $ 1,092,851 $ 1,342,595 $ 1,230,984 Trading volume (shares) 41,105,700 23,078,500 25,095,100 18,729,400 26,460,900 Market / book ratio (year +nd) 1.26 1.43 1.19 1.53 1.47 Price / earnings ratio (year-end) 10.3 14.2 (a) 10.0 13.0 13.1 (a) Amounts excluding $34 million pre-tax restructuring charge are as follows:

Balance for common (000) $ 117,403 Earnings per share $ 2.52 Payout ratio 72 %

Return on average common equity 12.2 %

Price / earnings ratio 11.7 %

Certain reclassifications and recalculations were made to the data reported in prior years to conform with the method of presentation used in 1996.

Offic:rs l Dir:ctors Thomas J. May, Chairman of the Board, President and Chief Executive Omcer ad William E Connell, Chairman and Chief Executive Alison Alden, Senior Vice President - Sales, Services and Omcer, Connell Limited Partnership (metals recycling Human Resources and processing and industrial production) a,d.f Gary L. Countryman, Chairman of the Board and Chief E. Thomas Boulette, Senior Vice President - Nuclear Executive Officer, Liberty Mutual Insurance Company L Carl Gustin, Senior Vice President - Corporate Relations a,e f Thomas G. Dignan, Jr., Partner, Ropes & Gray John J. Higgins, Jr., Senior Vice President ** #*

Douglas S. Horan, Sem.or Vice I, resident and General Counsel i b,c,d Charles K. Gifford, Chairman, l resident and Chief Execun.ve Omcer, Bank of Boston Corporation (bank James J. Judge, Senior Vice President and Treasurer holding company) and The First National Bank of Ronald A. Ledgett, Senior Vice President - Fossil, Field Service and Electric Delivery b,f Nelson S. Gifford, Principal, Fleerwing Capital (venture William N. Dimoulas, Vice President - Information Systems a,b,c Matina S. Horner, Executive Vice President, Teachers Philippe A. Frangules, Vice President - Strategic &nning/New Businesses Insurance and Annuity Association and College Retirement Equities Fund Richard S. Hahn, Vice President - Technology Research &

a,c Thomas J. May, Chairman of the Board, President and Development )

Chief Executive Officer, Boston Edison Company Leon J. Olivier, Vice President - Nuclear Operations and Statmn Director b,d Sherry H. Penney, Chancellor, University of Massachusetts at Boston Robert J. Weafer, Jr., Vice President - Finance, Controller and e,f Herbert Roth, Jr., Former Chairman of the Board and # l Chief Accounting Officer Chief Executive Omcer, LFE Corporation (traffic and Theodora S. Convisser, Clerk of the Corporation industrial process control systems)

Donald Anastasia, Assistant Treasurer e,f Stephen J. Sweeney, Former Chairman of the Board and I Chief Executive Omcer, Boston Edison Company

. Wayne R. Frigard, Assistant Clerk of the Corporation ,

a Member of Executive Committee b Member of Audit, Finance and Risk Management l Committee c Member of Pricing Committee Paul E. Tsongas - d Member of Executive Personnel Committee 1941-1997 e Member of Nuclear Oversight Committee With the death of Paul E. Tsongas on ,, f Member of Capital Investment Committee January 18,1997, the board of directors lost a valuable member. Thmughout his career as an elected omcial, including United States Senator, and as a member of the Boston Edison board, he consistently demonstrated personal courage, a strong sense of decency and a voice of reason.

He combined those attributes with '

insight, judgment and a sense of humor in becoming one of the nation's most articulate and respected political leaders.

Paul Tsongas brought those same attributes to board deliberations, and his presence will be missed.

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the shares transferred to your own name.

Imp rt:nt Sh rchrldarinf:rm tion If you are interested in receiving a prospectus to learn more Shireholder Inquiries about this plan, or if you have questions on an existing account, contact our stock transfer agent.

If you have questions concerning your dividend payments, the Dividend Reinvestment and Common Stock Purcha.se Plan, direct Automatic Monthly Investment Program (New) deposit service, transfer procedures or other stock account matters.

Shareholders who are participants in the Dividend please contact our stock transfer agent at the following address: Reinvestment and Common Stock Purchase Plan m.; e The First National Bank of Boston make automatic monthly investments of a specified amount c/o Boston EquiServe (not less than 550 per month) through an Automated Clearing Shareholder Services Division House ("ACH") withdrawal from their savings or checking Mail Stop: 45-02-09 account. Once automatic monthly deductions are initiated, P.O. Box 644 funds will be drawn from your designated bank account on the Boston, MA 02102-0644 25th of each month and will be invested in common stock on Toll Free Phone: 1-800-736-3001 the next investment date. For more information on the l If you are submhting documents requesting a transfer, address Aummanc Monthly Investment Program, or an enrollment change or account consolidation, please use this same address f nn, c ntact our st ck transfer agent.

with Mail Stop: 45-01-05.

Safekeeping Program Dividend Payments Dates Sharelmlders who are participants in the Dividend Reinvestment Common and Preferred and C,ommon Stock Purchase Plan can transfer their common 1st of February, May, August and November stock certificates into their plan account for safekeepmg.

Dividends on those shares will be reinvested automatically like T x Status of 1996 Dividends any other shares held in the plan. To continue receiving cash Generally, unless you are subject to certain exemptions, all divi. dividends, you must hold your shares in certificate form. For dends on our common or preferred stock are to be considered additional information, contact our stock transfer agent.

100% taxable.

SEC Form 10-K Stock Symbol and Exchange Listings St ckholders may obtain a copy of our annual report to the Ticker Symboh BSE Securities and Exchange Commission on Form 10-K, by con-48 New York (NYSE) and Boston stock exchanges tacting our Investor Relations Department.

1997 Annual Shareholders Meeting Quarterly Report to Shareholders All shareholders are invited to attend our Annual Meeting on Beneficial owners of our stock whose shares are registered in Thursday, May 15,1997, at 11:00 A.M. at the First National names other than their own may obtain copies of our Quarterly Bank of Boston, Auditorium. Lobby lxvel,100 Federal Street, Reports to Shareholders by contacting our Investor Relations Boston, Massachusetts.

Department. Note that the Annual Report will continue to be Dividend Payments - Direct Deposit Service mai!cd to beneficial owners directly by their bank or broker.

Shareholders receiving dividend checks can arrange for electron- Company Contact ic direct deposit. Transfers are made on the dividend payment Theodora S. Convisser dates and confirmation statements are mailed to shareholders. Clerk of the Corporation To take advantage of this com'enient program, contact our stock transfer agent is noted above. Investor & Shareholder Contacts Dividend Reinvestment and Common Stock Philip J. Lembo Director, investor Relations Purchase Plan (617) 424-3562 Our Dividend Reinvestment and Common Stock Purchase Plan '

(the plan) is available to our common and preferred shareholders, our residential electric customers and empk>yees. Participants do Jean M. Carella Investor Relations Specialist not pay brokerage fees or commissions related to the purchase of (617) 424-2658 shares. Some important features of the plan are as follows:

- Optional cash payments invested monthly Email Address

- 550 per month minimum not to exceed 540,000 ;r@bedison.com per calendar year

- Safekeeping of common stock certificates Internet Address Beneficial owners of our stock whose shares are registered in wv.wbostonedison.com names other than their own (e.g., a broker or bank nominee) must arrange participation with the record holder. If for any General Offices reason you are unable to arrange participation with your broker 800 Boylston Street {

or bank nominee, you must become a record holder by having Boston, MA 02199-8003 i.

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& Boston Edison 800 Boylston Street ,

1 Boston, Massachusatts 02199-8003

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, , , UNITED STATES SECURITIES AND EXCHANGE COMMISSION

., - Washirgttn, D.C. 20549 FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31,1996 OR l

[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT i

OF 1934 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 1 (State or otherjurisdiction of (1.R.S. Employer incorporation or organization) Identification No.)

800 Boylston Street, Boston, Massachusetts 02199 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 617-424-2000 Securities registered pu suant to Section 12(b) of the Aet:

Name of each exchange i Title of ead class on which registered Common stock, par value $1 per share New York Stock Exchange i Boston Stock Exchange Cumulative preferred stock: l 7.75% Series, par value $100 per share New York Stock Exchange (represented by depositary shares-cach repr sents one-fourth interest in par value) 8.25% Series, par value $100 per share 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 l

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 J 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 fcr the past 90 days. YES ,N_ NO _

indicate by check 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 Pan 111 of this Form 10-K or any amendment to this Form 10-K. (X]

The aggregate market value of the voting stock held by non-affiliates of the registrant as of March 21,1997 computed as the average of the 1 high and low market price of the common stock as reported in the listing of composite transactions for New York Stock Exchange listed )

securities in the WallStreetJournal: $1,261,389,298. i Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

Class Outstanding at March 21,1997 Common Stock, $1 par value 48,514,973 shares DOCUMENTS INCORPORATED BY REFERENCE ha Document 111 Portions of definitive proxy statement dated March 26,1997 for Annual Meeting of Stockholders to be held May 15,1997.

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.L Boston Edison Company i

Form 10-K Annual Report December 31, 1996 i

Part I Page Item 1. Business 2 Item 2. Properties and Power Supply 7 Item 3. Legal Proceedings 9 Item 4. Submission of Matters to a Vote of Security Holders 9 l

Part II Item 5. Market for the Registrant's Common Stock and Related f Stockholder Matters 13 Item 6. Selected Financial Data 14 Item 7. Management's Discussion and Analysis 15 Item 8. Financial Statements and Supplementary Financial Information 28 Item 9. Changes in and Disagreements with Accountants on Accountiag and Financial Disclosure 51 Part III Item 10. Directors and Executive Officers of the Registrant 52 Item 11. Executive Compensation 52 Item 12. Security Ownership of Certain Beneficial owners and Management 53 Item 13. Certain Relationships and Related Transactions 53 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 54 1

J Part 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 electric demand side management programs.

Refer to the Positioning in the Industry section of Item 7 for information regarding the restructuring of the electric utility industry process currently underway and its potential impacts on the Company.

The Company also conducts unregulated activities through its wholly owned subsidiary, Boston Energy Technology Group (BETG). Through BETG and its subsidiaries, the Company is engaged in certain nonutility businesses, including energy utilization and conservation, construction management and district energy. Refer to Note A to the Consolidated Financial Statements in Item 8 for more information regarding the Company's nonutility business ventures.

In January 1997, the Company announced a plan to form a holding company structure. The holding company structure, which is subject to shazeholder and regulatory approvals, is further described in Note A to the Consolidated Financial Statements in Item 8.

(b) Financial Information about Industry Segments The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable.

(c) Narrative Description of Business Principal Products and Services The Company supplies electricity at retail to an area of 590 square ndles, including the city of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 ndllion. In 1996 the Company served an average of 657,487 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues by class for the last three years consisted of the following:

1996 1995 1994 Retail electric revenues:

Commercial 50% S n's 50%

Residential 27% 2b% 28%

Industrial 9% 9% 9% i Other 2% 2% 2%

Wholesale and contra.ct revenues 12% 11% 111 1

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l Sources and Availability of Fuel l i The Company owns two stations whose g-nerating units have the ability to burn oil, natural gas or both, one nuclear power station and ten combustion turbine generators. The Company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:

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_ercentage of Company Average Cost of Fuel Generation by Source (%) (S per Million BTU) 1996 1995 1994 1993 1992 1996 1995 1994 1993 1992 Oil 16.1 17.5 27.8 31.3 33.7 3.04 2.66 2.35 2.38 2.40 Gas 33.3 39.9 31.6 24.3 25.7 3.11 2.20 2.28 2.67 2.55 Nuclear 50.6 42.6 40.6 44.4 40.6 0.41 0.43 0.50 0.51 0.52 The majority of the Company's residual oil purchases consists of imported oil acquired primarily from 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.

A portion of the Company's natural gas is supplied on an interruptible basis by contract. These contracts permit interruptions in deliveries by the supplier when natural gas supplies or pipeline capacity is unavailable. The Company is currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances, as part of a 1991 consent order with the Massachusetts Department of Environmental Protection.

The Company has arrangements for a firm supply of natural gas to run the station at a minimum level and has a least-cost plan for operating beyond this minin.um level which principally utilizes interruptible gas supplies or short-term capacity purchases.

In order to obtain fuel for use at its nuclear generating unit, 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 1 for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 2002, 2000, 2004 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 the Contany's electr4 c transndssion and distribution lines are obtained from 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 Massachusetts Department of Public Utilities (MDFU).

The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature.

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Seasonal Nature of Business The Company's kWh sales and revenues are typically higher in the winter and j summer than in the spring and fall as sales tend to vary with weather conditions. In addition, the Company currently bills higher base rates to commercial and industrial customers during the billing months of June chrough September as mandated by the MDFU. Accordingly, greater than half of the Company's annual earnings typicalt y occurs in the third quarter. As part of the Company's settlement agreement which is discussed in the Positioning in the Industry section of Item 7, it is expected that the seasonal variances of the Company's rates will be discontinued. Refer also to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8.

Competitive Conditions The Company is operating in an increasingly competitive environment. Changes in the industry include ongoing competition in wholesale power markets and increased pressure for retail customer choir.e. These forces are due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels designed to foster competition and changes in customers expectations. Refer to the Positioning in the Industry and Outlook for the Future sections of Item 7 for information regarding electric utility industry restructuring and the Company's response to the competitive environment.

Environmental Matters The Company is subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and 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.

Environmental-related capital expenditures for the years 1996 and 1995 were

$2.7 million and $2.9 million, respectively. These expenditures are forecasted to be approximately S2 million in each of the years 1997 and 1998.

The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur.

Refer to the Environmental section of Item 7 for more information.

Number of Employees .

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As of March 22, 1997, the company had 3,323 full-time and 44 part-time utility employees including 2,260 represented by two locals of the Utility Workers Union of America, AFL-CIO. The locals' labor contracts are effective through May of the year 2000. Subsidiary operations had 54 full-time employees.

Employee relations are considered satisfactory by the Company.

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a (d) Financial Information about Foreign and Domestic Operations and Export i Sales l

Refer to Principal Products and Services of this item for information regarding the geographical area served by the Company and revenues by class for the last three years. -

(e) Additional Information ,

Regulation l

The Company and its wholly owned subsidiary, Harbor Electric Energy Company

,- (HEEC), operate primarily under the authority of the MDPU, whose jurisdiction j includes supervision over retail rates for electricity and financing and -

1 investing activities. 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  !

l the transmission or sale of that power, certain issuances of short-term debt l and regulation of the system of accounts. The Company's subsidiary BETG and i j- its subsidiaries are not subject to such regulation.

The Company is required to submit annual performance standards to the MDPU applicable to its generating units and other units from which the Company purchases power through long-term contracts. Under this generating unit performance program, the Company provides quarterly progress reports to the ,

MDPU. The MDPU has the right to reduce subsequent fuel and purchased power j 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. The Company believes that its current provision for refunds is sufficient to cover i potential refunds.

The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the i siting, construction and operation of nuclear reactors with respect to public

,. health'and safety,. environmental matters and-antitrust considerations. A l' 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 expires in  !

2012. Continuing NRC review of existing regulations and certain operating ,

occurrences at other nuclear plants have periodically resulted in the l imposition of additional requirements for all nuclear plants in the United States, including Pilgrim Station. NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the I

imposition of monetary civil penalties. In January 1997, the Company submitted a request for NRC review regarding the calculation of Pilgrim's emergency core cooling system net postive su: tion head. NRC practice will not allow the plant to restart until this review is performed. The Company anticipates that the review will be completed prior to the completion of Pilgrim's current refueling and maintenance outage. The unit is currently expected to return to service in late April.

In addition, the Company could undertake certain actions regarding Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations, 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  :

controtersy and public debate manifested from time to time in the form of .

requests for various kinds of federal, state and local legislative or i regulatory action, direct voter initiatives or referenda or litigation. The j l

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i Company cannot predict the extent, cost or timing of any modifications to -

1 Pilgrim Station which could be:necessary in the future sa 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 coritinuously evaluates the operation of the station from the '

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standpoint of siatety, reliability and economics and believes that such

, continued operation is in the best inter ste of the company and its customers.  ;

1 i Capital Expenditures and Financings The Company's most recent estimates of capital and nuclear fuel expenditures, allowance for funds used during construction (ATUDC), long-term debt a maturities and sinking fund requirements for the years 1997 through 2001 are E as.follows: <

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, (in thousands) 1997 1998 '1999 2000 2001 i< Capital  !

j expenditures. (1) $140,000 $150,000 $160,000 $160,000 $140,000 Nuclear fuel

!. expendituren 'O $ 29,500 $ 14,000 $ 33,000 $ 16,000 l l~ AFUDC (2) $ 2,000 $ 2,000 $ 2,000 $ 2,000 $ 2,000'

' Long-term de:ot $101,600 $101,600 $ 1,600 $166,600 $ 1,600

• l Preferred stock l' sinkina fund S 2,000 $ 2,000 $ 2,000 $ 2,000- $ 52,000 i

[ (1) . Includes unregulated business ventures.

(2) Excludes AFUDC on nuclear fuel, i

t The Company continuously reviews its capital expenditure and fin. .ng  ;

! programs. These programs and, therefore, the eatimates shown abos are .

subject to revision due to changes in regulatory requirements an. he effects 1 of the induntry restructuring process, environmental standards, as2ilability'  ;

, and cost of capital, interest rates and other assumptions.

j Utility plant expenditures in 1996 were $151 ndllion and consisted primarily

of additions to the Company's transmission and distribution' systems and

nuclear generation facility.-

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' Refer to the Liquidity section of Item 7 for more information regarding the j Company's capital resources.

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.. o Item 2. Properties and Power Supply j i

' The Company's total electric generation capacity f rom company-owned facilities -

consisted of the following:

- Year j Unit Location Capacity"' Type Installed ,

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i l Pilgrim Nuclear Plymouth, Mass. 670 Nuclear 1972  :

Power Station i New Boston Station South Boston, Mass. 730 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, Mass.

Units 4-5-6 388 Fossil 1957-1961

-Unit 7 592 Fossil 1975 t Combustion turbine 14 Fossil 1969 l generator l

l Combustion turbine Various 278 Fossil 1966-1971  :

t _aenerators (nine)  !

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I (a)-In megawatts (t@l) based on winter capability audit results.

t The Company also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil-  :

l fired unit located in Yarmouth, Maine, began operations in 1978 and is  ;

I operated by Central Maine Power Company. Additional electric generation .

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capacity is available to the Company through its contractual arrangements with j other utilities and nonutilities and its participation in the New England Power Pool as further described in this item.  !

l The Company's significant items of property consist of electric generating  ;

j stations, substations and service centers, and are generally located on j Company-owned land. The Company's high-tension transmission lines are  ;

generally located on land either owned or subject to easements in its favor.  !

l The Company's low-tension dist11bution lines and fossil fuel pipelines are l located principally on public property under permission granted by municipal l and other state authorities.

As of December 31, 1996, the company's transmission system consisted of 362 ndles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 156 miles of underground circuits operating at 115 and 345 kV, The l substations supported by these lines are 45 transudssion or combined i transmission and distribution substations with transformer capacity of 10,281 megavoit amperes (MVA), 63 4 kV distribution substations with transformer capacity of 1,205 MVA and 18 primary network units with 88 MVA capacity. In  ;

l Laddition, high tension service was delivered to 242 customers' substations.

The overhead and underground distribution systems cover approximate 3y 4,700 l and 900 ndles of streets, respectively. HEEC, the Company's regulated l subsidiary, has;a distribution system that consists principally of a 4.1 mile  !

115 kV submarine distribution line and a substation which j- located on Deer Island in Boston,. Massachusetts. HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water:

Resources Authority, at this location.

t I 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

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policies. The Company currently has one proceeding before the EFSB, which -

concerns proposed transmission and station facilities in Hopkinton and Milford, Massachusetts. l Purchased Power Contracts

! Information regarding long-term contracts for the purchase of electricity is included in Note M to the Consolidated Financial Statements in Item 8.

Under the Company's two long-term purchased power contracts with the Massachusetts Bay Transportation Authority (MBTA), the MBTA retains the right  ;

to utilize the combustion turbines for its own emergency use and for testing purposes while the Company retaino New England Power Pool credit for their capacity and output.

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! Sales contracts The Company has agreements with. commonwealth Electric Company and Montaup l Electric Company under which each purchase 11% of the capacity and '

corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and l

operating costs plus an annual return on investment. The Company has sindlar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station.

j New England Power Pool

!. The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities and other electricity suppliers in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region.

To obtain maximum benefits of power pooling, the electric facilities of all member companies are operated by NEPOOL as if they were a single power system.

This is accomplished through the use of a central dispatching system that uses the lowest cost generation and transmission equipment available at any given time. This operation is the responsibility of NEPOOL's central dispatch ,

center, the New' England Power Exchange (NEPEX). As a result of its  !

participation in NEPOOL, the Company's operating ~ revenues and costs are ,

affected to some extent by the operations of the other members. The dispatching of Ccmpany-owned generating facilities by NEPEX may be affected by minimally increasing energy requirements and any additions to New England t generation capacity.

In December 1996, NEPOOL filed with the FERC to restructure the power pool to comply with recent FERC orders requiring open access to transmission and changes to the membership and governance provisions of the power pooling agreement. The filing also proposed changes which would transfer operating responsibility of the integrated transmission and generation system in New England to an Independent. System Operator and establish a bid-based market for unbundled energy services in lieu of the current cost-based pricing mechanism.

The.FERC has allowed the transmission and governance changes to become

. effective March 1, 1997, subject to refund and further orders. NEPOOL proposed that the changes in operations responsibility and market-based pricing would become effective in'the second half of 1997. These changes were proposed in anticipation of the restructuring of the electric utility industry and the entrance of new providers in the energy market.

l l The Company's net capacity was 3,613 MW at its winter peak and 3,385 MW at its l summer peak. Its corresponding NEPOOL capacity obligations were estimated to l be 3,399 MW and 3,256 MW, respectively.

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Item 3. Legal Proceedings The Company was named as a party in lawsuits filed in both the US District Court and the Massachusetts Norfolk Superior Court by Subaru of New England, Inc. and Subaru Distributors Corporation in 1992. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions f rom the Company's New Boston generating station. In February 195~, the Company settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a naterial impact on the Company's financial position or results of operations. The Subaru of New England, Inc.

lawsuit is still pending.

In 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts (US District Court) alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning employees affected by the Company's 1988 workforce reduction. In December 1996, the company reached a settlement of this lawsuit under which there is no finding or admission of discriminatory employment practices. The company anticipates full recovery from its insurance carrier for this settlement.

Also refer to Note L.6. to the Consolidated Financial Statements in Item 8 for a discussion of legal issues involving hazardous waste sites.

Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the fourth quarter of 1996.

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r E:cecutive Of ficers of the Registrant -

The names, ages, positions and business experience during the past five years of all the executive officers of Boston Edison Company and its subsidiaries as

! of March 1, 1997 are listed below. There are no family relationships between

! any of the officers of the company, nor any arrangement or understanding between any Ceanpany of ficer and another person pursuant to which the position as officer is held. 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, Age and Position During Past Five Years Thomas J. May, 49 Chairman of the Board, President Chairman of the Board, President and Chief Executive Officer (since and Chief Executive Officer 1995), Chairman of the Board and I Chief Executive Officer (1994-1995), President and Chief Operating Officer (1993-1994) and Executive Vice President (1990-1993); Director (since 1991)

Chairman of the Board and Chief Executive Officer and Director, i Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp. and Boston Edison Services, Inc.;

Chairman of the Board and Director, Rez-Tek International Corp. and Coneco Corp.; Director, BecoCom, Inc. and Northwind Boston, LLC Alison Alden, 48 Senior Vice President - Sales,  ;

Senior Vice President - Sales, Services Services and Human Resources '

and Human Resources (since 1996), Vice President -

Sales & Service (1993-1996) and Director - Organizational Development (1990-1993)

Director, Harbor Electric Energy Company, Boston Energy Technology Group and Coneco Corp. )

E. Thomas Boulette, 54 Senior Vice President - Nuclear Senior Vice President - Nuclear (since 1993), Vice President -

Nuclear Operations and Station Director (1992-1993) and Vice President - Operations (1989-1992) of Maine Yankee Atomic Power Company ,

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, Business Experience i Name, Age and Position During Past Five Years l

L. Carl Gustin, 53 Senior Vice President - Corporate Senior Vice President - Corporate Relations (since 1995), Senior Relations V3ce President - Marketing &

Corporate Relations (1989-1995)

John J. Higgins, Jr., 64 Senior Vice President (since 1990)

Senior Vice President Douglas S. Horan, 47 Senior Vice President and General i i Senior Vice President and Counsel (since 1995), Vice l General Counsel President and General Counsel (1994-1995) and Deputy General Counsel (1991-1994) 1 Director and General Counsel, Harbor Electric Energy Company; Director, Boston Energy Technology Group and BecoCom, Inc. ]

James J. Judge, 41 Senior Vice President and Senior Vice President and Treasurer (since 1995), Assistant 1 Treasurer Treasurer (1989-1995) and )

Director - Corporate Planning (1993-1995) i Senior Vice President, Treasurer and Director, Harbor Electric ,

Energy Company and Boston Energy i Technology Group; Director, l TravElectric Services Corp., l Boston Edison Services, Inc.,  !

BecoCom, Inc., Northwind Boston, l LLC and EnergyVision, LLC l Ronald A. Ledgett, 58 Senior Vice President - Fossil, Senior Vice President - Fossil, Field Service and Electric Field Service and Electric Delivery (since 1996), Senior Vice Delivery President - Power Delivery (1991-1995)

I Robert J. Weafer, Jr., 50 Vice President - Finance, Vice President - Finance, Controller and Chief Accounting Controller and Chief Officer (since 1991)

Accounting Officer i

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I Business Experience

! Name, Age and Position During Past Five Years Theodora S. Convisser, 49 Clerk of the Corporation (since Clerk of the Corporation 1986) and Assistant General l Counsel (since 1984)

Clerk, Harbor Electric Energy Company, Boston Energy Technology ,

Group, TravElectric Services

! Corp., Boston Edison Services, l Inc., Rez-Tek International Corp.,

Coneco Corp., BecoCom, Inc. and Northwind Boston, LLC I

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. o Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters (a) Market Information The Company's common stock is listed on the New York and Boston Stock Exchanges.

Following is the high and low market value per share of the Company's common stock as reported in the Wall Street Journal for each of the quarters in 1996 and 1995:

1996 1995 High Low High Low First quarter $30 1/8 $26 1/4 $25 1/2 $23 1/8 Second quarter $27 1/8 $23 5/8 $27 $23 3/8 Third quarter $25 3/8 $21 3/4 $27 1/2 $24 1/2 Fourth ouarter $27 $21 3/4 $29 1/2 $26 3/4 (b) Holders As of March 21, 1997, the Company had 35,630 holders of record of its common stock.

(c) Dividends Following are the dividends declared per share of common stock for each of the quarters in 1996 and 1995:

1996 1995 First quarter $0.470 $0.455 Second quarter $0.470 $0.455 Third quarter $0.470 $0.455 Fourth ouarter $0.470 $0.470 (d) Other Information Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements for the year ended December 31, 1996:

Ratio of earnings to fixed charges 2.91 Ratio of earnings to fixed charges and preferred stock dividend requirements 2.41 i

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l Item 6. Selected Financial Data -

The following table summarizes five years of selected consolidated financial data of the Company (in thousands, except per shara data).

I 1996 1995 1994 1993 1992 Operating revenues $1,666,303 $1,628,503 $1,544,735 $1,482,159 $1,411,753 Net income $ 141,546 $ 112,310 $ 125,022 $ 118,218 $ 107,298 1 Earnings per share of common stock $ 2.61 $ 2.00(a) $ 2.41 $ 2.28 $ 2.10 Totc1 ,

assets $3,729,291 $3,637,170 $3,608,699 $3,468,724 $3,286,335 '

Long-term debt $1,058,644 $1,160,223 $1,136,617 $1,272,497 $1,091,073 Redeemable preferred stock $ 203,419 $ 206,524 6 208,514 $ 210,514 $ 210,514 Cash dividends declared per common share $ 1.800 $ 1.835 $ 1.775 $ 1.715 $ 1.655 +

(a) Includes $0.44 per share restructuring charge. Excluding the restructuring charge, 1995 earnings per share were $2.52.

Certain reclassifications were made to the data reported in prior years to conform with the current method of presentation.

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i Item 7. Management's Discussion and Analysis l

Positioning in the Industry

Background

Electric utilities have traditionally operated under a monopolistic regulatory framework. Under this framework customers have been restricted to a single electricity provider, typically a vertically integrated electric utility engaged in the generation, transndssion and distribution of electricity.

However, since the 1970's, the electric energy business has become increasingly competitive. With the enactment of the Public Utility Regulatory Policies Act of 1978, a new independent power producer industry commenced, competing with traditional electric utilities for opportunities to generate electric power. In recent years many state utility commissions, including the Massachusetts Department of Public Utilities (MDPU), have initiated inquiries into restructuring the electric utility industry with a goal of promoting competition and extending to all customers the option of choosing their own electricity suppliers. In 1996, Massachusetts electric utilities and other interested parties participated in the industry restructuring proceeding before the MDPU. This process culminated in the latter part of the year with a series of settlement agreements and the issuance by the MDPU of its formal electric industry restructuring plan.

Electric utility industry restructuring ,

In December 1996, we reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Division of Energy Resources that resolves certain necessary issues surrounding electric industry restructuring.

This agreement must be filed with and approved by the MDPU. If approved, the settlement agreement allows retail electric customers the ability to choose their electricity supplier (referred to as retail access). Retail access would occur at the later of January 1, 1998 or the date when retail access is made available to all customers of Massachusetts investor-owned utilities (the Retail Access Date). The settlement agreement provides us with the ability to fully recover our stranded costs incurred under the traditional electric ratemaking structure.

Under the settlement agreement, all retail customers will have the opportunity to select their electricity provider starting on the Retail Access Date.

Retail customers will continue to receive electric delivery service under regulated rates. Customers who choose not to participate in the competitive market will have the option of continuing to buy power from our electric delivery business at "Standarc Cffer" price; for =even years. The " Standard Offer" will provide customers with electric service at rates designed to give a 10% savings in electric prices. Our electric delivery business will purchase power for " Standard Offer" service from suppliers through a competitive bidding process.

Commencing with the Retail Access Date, the retail delivery rates of our distribution business will include a non-bypassable access charge designed to recover all of our stranded costs which are currently estimated to be approximately $3 billion. These costs include the above-market commitments under existing purchased power contracts, our net generation plant investment, nuclear decommissioning commitments and regulatory assets related to our generation business. l l

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l As part of the settlement we have agreed to divest our fossil generating -

plants no later than six months after the Retail Access Date. We expect to continue operation of Pilgrim Nuclear Power Station with a new revenue ,

mechanism for recovery of Pilgrim's future costs and have agreed to estinate '

the market value of the station by December 31, 2002.

l l Regulatory assets related to our generation business and our net generation

! plant investment will be recovered with a return over a twelve-year period.

As an incentive to mitigate stranded costs, our returr. on equity will be increased for mitigation prior to the Retail Access Date and as the transition access charge declines thereafter. The aggregate amount of the access charge will be reduced by the net proceeds from the fossil divestiture and the market  ;

valuation of Pilgrim Station. Nuclear decommissioning commitments and 1

} above-market commitments under existing purchased power contracts will be '

i collected over the lives of the underlying obligations which are expected to l

exceed twelve years. Certain severance, employee training and community-related transitional payments are also recoverable through the access charge.

j Our electric delivery business will remain fully subject to rate regulation.

As part of the agreement, while there will be some rate design changes, our l

bere rate revenue level (non-fuel) will be frozen until the Retail Access Date ,

when customer choice begins. l l l l Effective with the commencement of retail choice and pursuant to the

! settlement agreement, our electric delivery business will annua 11v file with the MDPU a computation supporting our return on average common equity associated with distribution system operations. The return on equity would be subject to a floor of 6% and a ceiling of 11.75%. If the return on equity is i l below 6%, we would be authorized to add a surchargo to customer rates in order )

to reach the 6% floor. If the return on equity is above 11%, we would be required to adjust customer rates by an amount necessary to reduce the  ;

calculated return on equity between 11% and 12.5% by 50%, and a return above j 12.5% by 100%. No adjustment would be made if the return on equity falls j l ,

between 6% and 11%.

The settlement also provides for the continued protection of the environment through stringent emissions standards, a continued commitment to energy l conservation and renewable resource programs and protections for low-income customers.

In October 1996, another major electric utility in Massachusetts, along with the Massachusetts Attorney General, the Massachusetts Division of Energy Resources and other parties filed a settlement agreement with the MDPU. Their settlement agreement provides for retail choice, full compensation for potential stranded costs and the divestiture of its fossil and hydroelectric generating business. In addition, customers that do not choose an alternative supplier would receive :andard Offer" service that would provide a 10%

savings in electric prices upon the Retail Access Date. On February 26, 1997,

the MDPU issued an order accepting this utility's settlement agreement.

We anticipate tiat the MDPU will issue a decision on our settlement agreement i in the second c. third quarter of 1997. Implementation of the settlement will

[ also be subject to enactment of enabling legislation by the Massachusetts

! legislature and rulings by the Federal Energy Regulatory Commission (FERC).

t In the first quarter of 1997, both tne Massachusetts Governor and a Joint Committee of the Massachusetts legislature filed separate bills on restructuring the electric utili ty industry. The major principles of these bills are substanLially consistent with those of the MDPU restructuring plan, including the opportunity for stranded cost recovery and reduced electricity 16 r

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prices. The bills clarify the MDPU's authority to create the opportunity for retail customer choice by January 1, 1998.

In December 1996, the MDPU issued its formal electric industry restructuring plan. The stated goal of the plan is to reduce costs, over time, for all consumers of electricity. Under the MDPU's proposal, the current monopoly regulatory framework will evolve into a competitive market system featuring consumer choice among providers of generation services. The transmission and distribution of electricity will remain monopolies subject to rate regulation.' 1 Joint ventures We currently conduct unregulated activities through our wholly owned j subsidiary, Boston Energy Technology Group (BETG). In December 1996, BETG signed a joint venture agreement with Residential Communications Networ!:,

Inc., currently known as RCN Telecom Services, Inc. (RCN), to form a limited liability company to provide local and long-distar.ce telephone service, video, !

high-speed Internet access and other telecommunications-related services (the

• Telecommunications Venture"). The unregulated entity will be owned up to 49%

by BETG, with RCN having the day-to-day management responsibility. The projected costs of creating the " Telecommunications Venture", which is planned to serve 1.6 million customers in the greater Boston area, is approximately

$300 million over several years. The joint venture agreement is subject to a number of conditions which must be satisfied before formal operations begin, including the o'taining of certain regulatory approvals.

In January 1997, BETG, through one of its wholly owned subsidiaries, signed definitive agreements with Williams Energy Services Company (WESCO), a subsidiary of The Williams companies, Inc., to form EnergyVision, LLC, an unregulated limited liability company. This " Energy Marketing Venture" will market electricity, natural gas and energy-related services to retail customers in the six New England states. EnergyVision began operations in February 1997. BETG, through its subsidiary, and WESCO each own 50% of the new company, with an expected combined initial investment of less than $10 million.

Holding Conpany In January 1997, we announced a plan to form a holding company structure. The holding company structure, which is subject to shareholder and regulatory approvals, is intended to provide increased financial, managerial and organizational flexibility in order to better position us to operate in the changing electric utility industry. It will permit us to take advantage of nonutility business opportunities in a more timely manner. In addition, the holding company structure will clearly separate our regulated and unregulated lines of business enabling us to pursue nonutility business ventures in a manner consistent with the electric utility industry restructuring principles outlined by the MDPU. The holding company structure is a well-established form of organization for companies conducting multiple lines of business, particularly entities engaging in both regulated and unregulated activities.

All investor-owned Massachusetts electric utilities, other than Boston Edison, are currently organized in a holding company structure.

1992 Rate Settlement As referred to in the following Results of Operations, the MDPU had previously approved our three-year settlement agreement effective November 1992. This agreement provided us with retail rate increases, allowed for the recovery of demand side management conservation program costs, specified certain 17

accounting adjustments and clarified the timing and recognition of certain expenses. The agreenient also set a limit of 11.75% on our rate of return on common equity for each of the calendar years 1993, 1994 and 1995, excluding any penalties or rewards from performance incentives. The retail rate increases consisted of two annual retail base rate increases of $29 million effective November 1993 and November 1994 and an annual performance adjustment ,

charge effective November 1992 through October 2000. The performance adjustment charge varies annually based on the performance of Pilgrim Nuclear Power Station. This charge is further described in the Electric Sales and Revenues section. We did not make a base rate filing upon the expiration of the 1992 settlement agreement, therefore base rates have remained in effect at their 1995 levels.

Results of operations 1996 versus 1995 Earnings per share of common stock were $2.61 in 1996 compared to $2.08 in 1995. Earnings in 1995 reflected a nonrecurring before tax charge of $34 million ($20.7 million net of tax, or $0.44 per share) associated with our corporate restructuring. The restructuring is discussed further in Note F to the Consolidated Financial Statements. Excluding the nonrecurring restructuring charge, earnings per common share increased 3.6% over 1995 primarily due to lower operations and maintenance and interest expenses and l higher Pilgrim performance revenues. These positive changes were partially offset by an increase in depreciation expense.

Operating revenues Operating revenues increased 2.3% over 1995 as follows:

(in thousands)

Retail electric revenues $48,649 Demand side nanagement revenues (20,545)

Wholesale revenues (2,072)

Short-term sales and other revenues 11,768

! Increase in operatino revenues $37.800 i Retail electric revenues increased $48.6 million. Fuel and purchased power revenuer increased approximately $36 million. These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect on earnings. Performance revenues, which vary annually based on the operating performance of Pilgrim Station, increased $14.5 million as Pilgrim l Station operated at a higher capacity in 1996. Pilgrim's annual performance j adjustment charge is discussed further in the Electric Sales and Revenues section. Retail kWh sales increased 2.8% in 1996, primarily due to the positive economic impacts on our commercial customers.

Demand side management (DSM) revenues decreased primarily due to a decline in current DSM program expenditures.

The primary reason for the decrease in wholesale revenues is due to a decrease ,

in Pilgrim contract customer revenues. These revenues decreased despite ]

increased kWh sales due to lower operations and maintenance expense related to ,

Pilgrim Station. Pilgrim contract customers are billed for their l proportionate share of the unit's costs.

Net short-term sales and other revenues increased $11.8 ndllion. Despite i lower kWh sales, short-term sales revenues increased approximately $6 million

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due to higher fuel prices. Revenues from short-term sales result in a corresponding reduction to future fuel and purchased power billings to retail i customers and, therefore, have no net effect on earnings. This increase also reflects an increase in revenue from non-electric sources in 1996.

qperating expenses ruel and purchased power expenses increased $53 ndllion. Fuel expense increased, despite a slight decrease in company generation, due to significantly higher oil and natural gas prices. Purchased power expense reflects a higher volume of energy purchases and en overall increase in energy a

prices. These increases were partially offset by the timing effect of fuel and purchased power cost collection. Fuel and purchased power expenses are substantially recoverable through fuel and purchased power revenues.

Operations and maintenance expense decreased $41 million primarily due to

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lower labor costs resulting from our 1995 restructuring and the continuing cost control efforts of each of our business units. In addition, the amortization of deferred nuclear outage costs decreased $9 million. As discussed in Note B to the Consolidated Financial Statements, in the third quarter of 1995 we made a retroactive change to the amortization period of these deferred costs from five years to two years, consistent with the two-year cycle between refueling outags; at Pilgrim Station.

The 1995 operating expenses reflect a $34 nillion nonrecurring charge related to our corporate restructuring. Refer to the Results of Operations for 1995 versus 1994 and Note F to the Consolidated Financial Statenents for additional information regarding our 1995 restructuring. l Depreciation and amortization increased $32 million. The increase is primarily the result of a change in the estimated remaining economic lives of 4 our Mystic 4, 5 and 6 fossil generating units in the second quarter of 1996, i retroactive to the beginning of the year, and an increase in tae depreciable plant balance. The change in estimated economic lives of Mystic 4, 5 and 6 4 resulted in a $22 million increase in depreciation expense for the year.

Refer to Note B to the Consolidated Financial Statements for more information l on depreciation expense. 1 The decrease in DSM programs expense reflects the decline in current DSM program expenditures.

The increase in income taxes is due to higher net income and a higher l effective tax rate in 1996. Our effective tax rate in 1996 is 38.2% versus 37.1% in 1995.

4 Interest charges Interest on long-term debt decreased due to the maturity of $100 million 8 7/8% debentures in December 1995 and $100 million 5 1/8% debentures in March 1996. These decreases were partially of fset by the issuance of $125 ndllion a

7.80% debentures in May 1995 which were outstanding for all of 1996. Other 4 interest charges increased due to an increase in interest on short-term debt caused by the higher average short-term debt level partially offset by a lower i average short-term borrowing rate. The short-term debt balance increased as a result of the debenture maturities and the redemption of $4 ndllion of l preferred stock in 1996. Allowance for borrowed funds used during ,

I construction (AFUDO) , which represents the financing costs of construction, decreased due to lower overall construction activity during 1996, shorter  ;

construction periods, and lower short-term interest rates.

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2 1995 versus 1994  !

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!- Earnings per share of common stock were $2.08 in 1995 compared to $2.41 in i J 1994. Earnings in 1995 reflect the nonrecurring before tax charge of $34 J million ($20.7 udllion net of tax, or $0.44 per share) associated with our y corporate restructuring. The charge reflects the costs of early retirement  !

and severance programs implemented as part of our organizational streamlining i and reorganization into business units. Excluding the restructuring charge, (

earnings per common share were $2.52 in 1995, an increase of 4.6% over 1994.  ;

This increase is due to the $29 million annual retail base rate increase j effective November 1994, the ending of amortization of deferred cancelled  ;

L . nuclear costs in 1994, a 1.2% increase in retail kWh sales and lower revenue f

, reserve provisions. These positive impacts were partially offset by higher

j. income and property taxes, nuclear outage amortization and employee benefit expenses in 1995 over 1994 levels, and a gain recorded in 1994 related to a i favorable court ruling on an eminent domain case. i l

j. Qperating revenues l 3 i

! Operating revenues increased 5.4% over 1994 as follows:

3 (in thousands)  ;

Retail electric revenues $69,851  !

i- Demand side management revenues 8,783 l Wholesale revenues (1,799) 1 j Short-term sales and other revenues 6,933, i Increase in operatina revenues $83.768 ).

i Retail. electric revenues increased $69.9 million. Approximately $28 ndllion l

, of the increase was due to the November 1994 base rate increase while )

approximately $11 million was due to the increase in retail kWh sales. Fuel I and purchased power revenues increased $11 ndllion as a result of the timing ,

effect of fuel and purchased power cost recovery. These higher revenues are l offset by higher fuel and purchased power expenses and, therefore, have no net '

j. effect on earnings. Pilgrim performance revenues increased $9 million  ;

. primarily due to a higher performance rate effective in 1995 and a 17% )

j increase in generation.  ;

A new annual conrervation charge for. recovery of demand side management program costs was implemented in February 1995. Under this charge all 1995  ;

program costs were recovered in 1995. This resulted in higher DSM revenues  :

and expenses than in prior years when certain program costs were deferred and j

! recovered over a six-year period. l l l 4

Short-term sales increased as a result of higher generating availability in j 4

1995. Revenues from short-term sales result in a corresponding reduction to i future fuel and purchased power billings to retail customers and, therefore, '

3 have no net effect on earnings.

i- Qperating expenses Puel and purchased power expenses increased $22 ndllion primarily due to the timing effect of fuel and purchased power cost collection. Excluding the

[

timing effect, fuel expense increased due to an 8% increase in fossil generation while purchased power expense was substantially unchanged. Fuel

-and purchased power expenses are substantially recoverable through fuel and purchased power revenues.

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i Operations and maintenance expense increased 3.3% over 1994 This was 4

primarily due to an $11 million increase in the amortization of deferred l nuclear outage costs. In the third quarter of 1995 we made a retroactive i

1 change to the amortization period of deferred nuclear outage costs from five years to two years as discussed in Note B to the Consolidated Financial

. Statements. In addition, employee benefit expenses increased primarily due to higher postretirement benefit expenses recorded in accordance with the 1992 settlement agreement. We alsc incurred higher administrative costs in i . positioning the company for charges in the industry, which were offset by i lower operating costs in the electric delivery business. Electric generation

costs increased only 1% in 1995, primarily due to a refueling and maintenance

! outage at Pilgrim Station.

l The $34 million nonrecurring restructuring charge was incurred over the third and fourth quarters of 1995 as a result of our corporate reorganization announced in July 1995. As part of the reorganization, 330 employees elected

to retire under enhanced retirement programs and 149 employees whose positions

. were eliminated became eligible for benefits under a special severance

, program. Refer to Note F to the Consolidated Financial Statements for additional information.

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!. Depreciation and amortization expense increased due to a higher average j depreciable plant balance.

I In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit.

, The increase in demand side management programs expense is related to the i increase in DSM revenues. Beginning with the annual conservation charge j implemented in February 1995, DSM costs are recovered and expensed primarily

in the year incurred. The 1995 expense includes $31 million of 1995 program j costs and $14 million of amortization of costs capitalized in 1992 through l 1994.

j Property and other taxes increased primarily due to higher Boston property 4 taxes resulting from capital additions.

f Our effective annual income tax rate for 1995 was 37.1% vs. 31.4% for 1994.

The higher rate is the result of a $10 million adjustment to deferred income tax expense made in 1994 in accordance with the 1992 settlement agreement.

i Other income The net decrease in other income is primarily due to a $5.7 million gain i recognized in 1994 from a court ruling on a 1989 eminent domain taking of certain of our property.

Interest charges l

Interest on long-term debt increased due to a $125 ndllion debenture issuance in May 1995, partially offset by interest savings from first mortgage bond and

' debenture redemptions in 1994. Other interest charges increased slightly due to higher short-term interest rates partially offset by a lower average short-term debt level. -AFUDC decreased due to a lower construction work-in-progress balance and shorter construction periods, partially offset by higher short-term interest rates.

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Electric Sales and Revenues Electric sales Retail kWh sales increased 2.8% in 1996. The major contributor to this increase was the positive effect on commercial customers of a continued strong economy in our retail service territory. The strong economy's impact in greater Boston is illustrated by the highest commercial office occupancy rate -

in 15 years. In addition, hotel c< upancy rates and non-manufacturing employment increased over 1995. The commercial sector represents approximately 50% of our electric operating revenues. Residential sales, which represent approximately 27% of electric operating revenues, decreased slightly primarily due to overall allder than normal weather conditions.

Industrial sales remained relatively flat. This sector represents approximately 9% of electric operating revenues. Total kWh sales, including  !

wholesale, increased 3.3%. The increase in wholesale sales was primarily due to higher sales ta our Pilgrim contract customers as the plant was operating for substantially all of 1996. In addition, sales to our municipal customers increased due to a reduction in available energy supply in Nsk England.

A 1.2% increase in retail kWh sales in 1995 was primarily due to a stronger economy, partially offset by the impact of demand side management programs.

Total kWh sales increased 3.8% primarily due to an increase in Pilgrim contract customer sales.

Electric revenues Our retail electric rates are subject to the jurisdiction of the MDPU. As discussed in the Positioning in the Industry section, we reached a settlement agreement in December 1996 that, if approved, resolves certain necessary issues surrounding electric industry restructuring. As part of the settlement agreement our electric delivery business will provide " Standard Offer" customers service at rates designed to give a 10% savings in electric prices.

Under the agreement, our base ratet will remain frozen until the Retail Access Date (the later of January 1, 1998 of the date when retail access is made available to all customers of Massachusetts investor-owned utilities). We do not expect that maintaining base rates at their current level until the Retail Access Date will have a material adverse effect on our financial condition or results of operations. After the Retail Access Date, the return on equity on our electric delivery business will be subject to an 11.75% ceiling which is lower than has been experienced in the recent past.

The annual performance adjustment charge fro.n our 1992 settlement agreement

• with the MDPU remains in effect through the year 2000 and provides us with opportunities to improve our financial results. The most significant potential impact of this performance incentive is based on Pilgrim Station's annual capacity factor. An annual capacity factor between 60% and 68% would provide us with approximately $54.5 ndllion of revenues in the performance year ended October 1997. For each percentage point increase in capacity factor above 68%, annual revenues will increase by approximately $800,000.

For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease by approximately $900,000. We are '

currently billing customets F-sed on an 85% capacity factor. This is a decrease from the capacity factor of 90.9% achieved in the performance year ended October 1996 due to the scheduled routine refueling outage that began in February 1997. We earned $67.6 million in revenues related to Pilgrim's capacity factor in the performance year ended October 31, 1996.

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Pilgrim Station was shut down for approximately three months in 1994 due to a non-nuclear problem with its electrical generator. Regularly scheduled maintenance work was also performed during the shutdown. The power needs usually met by the station were met by other generating plants or purchased from other suppliers as necessary. We do not believe that the generator damage resulted from actions within our control. Our recovery of the incremental purchased power costs during the outage through fuel and purchased power revenues, however, remains subject to review by the MDPU under a generating unit performance program.

Liquidity We ordinarily meet most of our cash requirements for plant expenditures with internally generated funds. These funds are cash flows from operating activities, adjusted for changes in working capital and the payment of dividends. During 1996, 1995 and 1994 our internal generation of cash provided 170%, 102% and 109%, respectively of our plant expenditures. The capital spending level, excluding nuclear fuel, forecasted for 1997 is $144 1dllion which includes amounts for utility plant and our new business

. ventures. The capital spending level over the next five years is forecasted I to be approximately $750 million. In addition to capital expenditures, we have long-term debt and preferred stock payment requirements of $103.6 million pex year in 1997 and 1998, $3.6 ndllion in 1999, $168.6 million in 2000 and

$53,6 million in 2001.

External financings continue to be necessary to supplement our internally generated funds, primarily through the issuance of short-term commercial paper and bank borrowings. We have authority from the FERC to issue up to $350 million of short-term debt. We also have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-team credit on a committed as well as on an uncommitted and as available basis. At December 31, 1996, we had approximately $201 ndllion of short-term debt outstanding, none of which was incurred under the revolving credit agreement.

4 In 1994 the MDPU approved our financing plan to issue up to $500 ndllion of equity and long-term securities through 1996. In 1996 the MDPU approved our request to extend this financing plan through 1998. Authority to issue approximately $322 million remains under this plan. Proceeds from issuances .

under this plan are to be used to refinance short and long-term securities and l to fund capital expenditures and working capital requirements. Refer to Notes i H and I to the Consolidated Financial Statements for additional information relating to our financing activities. We intend to issue $100 million of two-year debt in March 1997.

l Outlook for the Future '

Competitive forces within the electric utility industry continued to increase in 1996. Changes in the industry include ongoing competition in wholesale power markets and increased pressure for retail customer choice. These forces are due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels designed to foster competition and changes in customer expectations. The trend continues toward increased competition through modified regulation of the industry. In Massachusetts, open access to generation markets for retail customers is approaching rapidly.

The effects of competition have been evident in the wholesale energy market.

In response to the competition from other electric utilities and nonutility generators to sell electricity for resale, we secured long-term power supply agreements with our seven wholesale customers that set rates through 2002 and beyond. This segment represents 3% of our operating revenues.

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o In January 1997, we filed an open access tariff with the FERC that incorporates our transmission rates into a New England regional transmission tariff. This filing, which is subject to approval, was made in response to the FERC's open access transmission order that was issued in April 1996. The order requires all utilities with transmission systems to file open access tariffs, to provide service under those tariffs to transmission customers comparable to service provided to their electric energy customers and to take service under the tariffs for wholesale purchaser and sales. Tr.e order also

• supports the full recovery of legitimate and verifiable costs previously incurred under federal and state regulation. The provisions in the order provide a framework for significant changes in the electric utility industry.

We do not expect the FERC order to significantly impact the results of our operations, which are primarily regulated by the MDPU.

Additional competition exists with alternative fuel suppliers as customers are able to substitute natural gas, steam or oil for electricity for heating or cooling purposes. In addition, industrial and large commercial customers may pursue options to generate their own electric power or factor the cost of electricity into their decisions to relocate to new service territories.

In addition to our involvement in the MDPU's restructuring proceeding, we have actively responded to the changing electric utility industry in other ways.

In 1995 we reorganized the company into separate business units in order to strengthen our competitiveness. The Customer, Fossil Generation, Nuclear Generation and Corporate Services business units were designed to sharpen management focus along our significant lines of operation while maintaining company-wide strategic goals. The restructuring reduced our workforce which resulted in a significant increase in labor ef ficiencies and cost savings. We also continued to develop customer alliances and provided economic development rates to some customers. These actions all illustrate our commitment to be a competitively priced, reliable provider of energy.

In the traditional revenue requirements model, our electric revenues have been based on the cost of providing electric service. As such, we are subject to certain accounting standards that are not applicable to other businesses and  !

industries in general. We believe that we currently meet the criteria of these standards. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71) requires us to defer recognition of certain costs when incurred when we expect to receive future rate recovery of these costs. The Securities and Exchange Commission has recently begun to focus on how the changes in the electric utility industry have affected utilities' ability to continue to apply regulatory accounting. The final rules issued by the MDPU or the enactment of legislation in Massachusetts could, in the near term, cause us to no longer meet the criteria for application of SFAS 71 for some of our operations.

l Should this occur, we would be required to take an immediate noncash charge to l income for all of our affected regulatory assets and the above-market portion l'

of purchased power contracts. In addition, a write-down of utility plant assets would be required under Statement of Financial Accounting Standards No.

121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, if competitive or regulatory change results in a l probability that future cash flows will not be sufficient to recover our investment in those assets. Based on our settlement agreement we expect to recover all strandable costs through a non-bypassable access charge to be paid by customers of our electric delivery business. Under our settlement agreement, our delivery business will remain subject to rate-regulation and, therefore, will continue to meet the criteria of these accounting standards.

As noted earlier, under our settlement agreement we expect to continue to operate Pilgrim Station with the ability to collect stranded costs related to 24

t i  !

.,. . a i  !

) i the unit. Although not anticipated based on our settlement agreement, the {

nonrecovery of strandable costs could have a material impact on our results of operations and financial condition. However, if laws are enacted or e

regulatory decisions are made that do not offer Massachusetts electric  ;

utilities an opportunity to recover previously reviewed, prudently incurred  ;

commitments to provide service to our customers, we believe we have strong }

j legal arguments to challenge such laws or decisions. .We will actively pursue the full recovery of stranded costs and are prepared to take the action i necessary to protect the interests of our shareholders.

l Other Matters [

Connecticut Yankee  ;

l *

On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power l

^

Company (CYAPC', , which owns and operates the connecticut Yankee nuclear j electric generating unit (Connecticut Yankee), unanimously voted to retire the Haddam Neck, Connecticut unit. The decision was based on an economic analysis ,

of the costs of operating the unit through 2007, the period of its operating j

license, compared to the costs of closing the unit and incurring replacement  ;

i power costs for the same period. We have a 9.5% equity investment in CYAPC of j approximately $10 million. Refer to Note L.4. to the ConsL11 dated Financial  ;

Statements for more information regarding Connecticut Yankee.  ;

)

Environmen tal . l f

We are subject to numerous federal, state and local standards with respect to waste disposal, air and water quality and other environmental considerations.

These standards can require that we modify our existing facilities or incur increased operating costs.

l We own or operate approximately 40 properties where oil or hazardous materials l were previously spilled or released. We also continue to face possible  :

liability as a potentially responsible party in the cleanup of approximately i ten multi-party hazardous waste sites in Massachusetts and other states where q we are alleged to have generated, transported or disposed of hazardous waste  ;

at the sites. Refer to Note L.6. to the Consolidated Financial Statements for more information regarding hazardous waste issues.

I In October 1996, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 96-1, )

Environmental Remediation Liabilities, effective in 1997. This statement contains authoritative guidance on specific accounting issues that are present in the recognition, measurement, display and disclosure of environmental remediation liabilities. We do not believe that this statement will have a material effect on our financial position or results of operations.

Uncertainties continue to exist with respect to the disposal of both spent nuclear fuel and low-level radioactive waste (LLW) resulting from the operation of Pilgrim Station. The United States Department of Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel; however, there are uncertainties regarding the DOE's schedule of acceptance of spent fuel for -

disposal. In 1995 we regained access to the LLW disposal facility located in Barnwell, South Carolina. Refer to Note E to the Consolidated Financial i Statements for further discussion regarding spent nuclear fuel and LLW j disposal.

]

The 1990 Clean Air Act Amendments require a significant reduction in ,

nationwide emissions of sulfur dioxide from fossil fuel-fired generating l 1

25 j h .- w _-+r a ~* e e a't es-r- yw-- --iT M e w--..pgio -

-r + - #

,- --. - -- ^

units. Sulfur dioxide emissions will be restricted through a market-based system of allowances. In 1996 we sold sulfur dioxide allowances rclated to l the years 2000 to 2010 that are expected to be in excess of our needs.

Proceeds from the sale of these allowances were recorded as a regulatory liability as it is probable that we will be required to refund the proceeds to customers. We have the option to repurchase certain of these allowances at specified prices from 2000 to 2010. We currently do not anticipate exercising these op dons; however, their potential exercise will be based on numerous factors, including the timing of the Retail Access Date. As discussed in the Positioning in the Industry section, under our settlement agreement we have agreed to the divestiture of our fossil generating plants no later than six months after the Retail Access Date (the later of January 1, 1998 or the date when retail access is made available to all customers of Massachusetts investor-owned utilities). If regulatory approval is not obtained or is delayed, it is possible that we could continue to operate these units. 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 low nitrogen oxides burners at New Boston, have allowed the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain Massachusetts Department of Environmental Protection air quality modeling studies currently in progress, the continued operation of these units could require additional emission reductions by 1999 or years thereafter. The extent of any additional emission restrictions and the cost of any further modifications is uncertain at this time.

Public concern continues regarding electromagnetic fields ( EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Such concerns have included the possibility of adverse health effects caused by EMF as well as perceived effects on property values. Some scientific reviews conducted to date have suggested associations between EMF and potential health effects, while other studies have not  !

substantiated such associations. The National Research Council recently reported that there is no conclusive evidence that exposure to EHF from power lines and appliances presents a health hazard. The panel of scientists, working with the National Academy of Sciences, report that more than 500 studies over the last several years have produced no proof that EMF causes  ;

leukemia or other cancers or harms human health in other ways. We continue to l support research into the subject and are participating in the funding of industry-sponsored studies. We are aware that public concern regarding EMF in ,

some cases has resulted in litigation, in opposition to existing or proposed l facilities in proceedings before regulators or in requests for legislation or ,

regulatory standards concerning EMF levels. We have addressed issues relative i to EMF in various legal and regulatory proceedings and in discussions with customers and other concerned persons; however, to date we have not been significantly affected by these developments. We continue to closely monitor j all aspects of the EMF issue. i Litigation We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from our New Boston Station generating unit. In February 1997, we settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a material impact on our financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending, i

l l

l 26

= _ _ . - _. ~ . - . _

1 Refer to Note L.7. to the Consolidated Financial Statements for more information on these lawsuits and other legal matters in which we are involved.

Safe harbor cautionary statement We occasionally make forward-looking statements such as forecasts and projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements.

Actual results could potentially differ naterially from these statements.  ;

Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.

The preceding sections include certain forward-looking statements about the effects of the industry restructuring process and our related settlement agreement, our joint ventures, operating results, Pilgrim Station's performance, Connecticut Yankee and environmental and legal issues.

The effects of the industry restructuring process currently underway at the MDPU and our related settlement agreement could differ from our expectations.

, This could occur as regulatory decisions and negotiated settlements between utilities and intervenors are finalized. In addition, the development of a competitive electric generation market, the impacts of actual electric supply and demand in New England and legislative action may affect the ultimate results of the industry restructuring and our settlement agreement.

The timing and activities of our joint ventures as well as our actual l 9

investments may differ from our expectations. This could occur if required regulatory approvals are delayed or not obtained. l The impacts of our continued cost control procedures on our operating results could differ from our expectations. The effects of changes in economic  !

conditions, tax rates, interest rates, technology and the prices and j availability of operating supplies could materially affect our projected i

operating results. l Pilgrim Station's performance could dif fer from our expectations. The station's capacity factor could be impacted by changes in regulations or by unplanned outages resulting from certain operating conditions.

! The ultimate liability related to the shutdown of Connecticut Yankee could differ from the current estimate. In addition, although not anticipated, it is possible that some portion of our share of post-operation costs may not be recoverable from ultimate customers.

The impacts of various environmental and legal issues could differ from our

, expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect our estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect our estimated litigation costs.

27

l l

.. , . 1 i

l Item 8. Financial Statements and Supplementary Financial Information l l

4 Consolidated Statements of Income  !

years ended December 31, (in thousands, except earnings per share) 1996 1995 1994 j Aperating revenues $1,666,303 $1,628,503 $1,544.735

,, Operating expenses:

Fuel and purchased power 588,893 535,806 513.825 ,

'. Operations and maintenance 417,372 458,196 443,545 j Restructuring costs -0 34,000 0 '

185;494 Depreciation and amortization 153,339 148,845

' Amortization of deferred costs of ,

cancelled nuclear unit 0 0 19,791

• Demand side management programs 30,825 45,125 35,438 I

I ~ Taxes-property and other 107,086 106,361 100,015 Income taxes 88,703 68,276 54,798 -

Total operating expenses 1,418,373 1,401,103 1,316,257

Qperating income 247,930 227,400 228,478

. Other income (expense), net 698 (575) 3,979 Operating and other income 248,628 226,825 232,457 ,

Interest charges: -

l Long-term debt 94,823 106,640 102,570 Other 14,551 12,642 12,343-

. Allowance for borrowed funds used i during construction (2,292) (4,767) (7,478)

Total interest charges 107,082 11/.,515 107,435 I Net income 141,546 112,310 125,022 l Preferred stock dividends 15,365 15,571 15,765 1 Earnings available for common shareholders S 126,181 S 96,739 $ 109,257

{ ,

Weighted average common shares outstanding 48,265 46,592 45,338 .

Earninas ner share of common stock $ 2.61 $ 2.08 $ 2.41 -

)

Consolidated Statements of Retained Earnings years ended December 31, ',

(in thousands) 1996 1995 1994

-Balance at the beginning of the year S 257,344 $ 247,004 $ 218,292 j Net income 141,546 112,310 125,022 Subtotal 398,890 359,314 343,314 Cash dividends. declared:

Preferred stock 15,365 15,571 15,765 Common stock 90,854 86,399 80,545 Subtotal 106,199 101,970 96,310 Provision for preferred stock redemption and issuance costs (a) 905 0 0 Balance at the end of the year S 291,786 S 257,344 S 247,004 (a) Refer to Note B.7. to the Consolidated Financial Statements.

The accompanying notes are an integral part of the consolidated financial statements.

I 28 I

- - ._- - - -. . _ _ . - . - _ _ . _ . . . . . _ - . _ _ _ . . . . ~. - .... - - .- .-

i 5

~

Consolidated Balance Sheets 4 December 31,

[ (in thousands) 1996 1995 I Assets

• l Utility plant in service, at l original cost $4,393,585 $4,315,422 Less: accumulated depreciation 1,550,317 S2,843,268 1,439,996 S2,875,426 ,

Nuclear fuel 351,453 302,594 Less accumulated amortization 268,509 82,944 251,951 '50,643 .

Construction work in progress 30,376 29,573  !

Net utility plant 2,956,588 2,955,642 Investments in electric companies, at equity . _

23,054 23,620 ,

Nuclear decomnissioning trust 132,076 102,894 Current assets: .

Cash and cash equivalents 5,651 5,841 Accounts receivable 233,024 219,114

-Accrued unbilled revenues 34,922 37,113 ,

Fuel, materials and supplies, at average cost 57,075 59,631 Other 45,146 375,818 23,607 345,306 Deferred debits:

Regulatory assets-power contracts 88,963 21,396 other regulatory assets 113,063 128,699 other 39,729 59,613 Total assets $3,729,291 S3,637,170 Capitalization and Liabilities l Cousnon stock equity $1,036,424 S 989,438 i Cumulative preferred stock:

Nonmandatory redeemable series 119,954 119,677 Mandatory redeemable series 81,465 84,837 Long-term debt 1,058,644 1,160,223  !

-Current liabilities: i Long-term debt / preferred l stock due within one year S 102,667 $ 102,667

• Notes payable 201,454 126,441 l Accounts payable 134,083 133,474 Accrued interest 24,378 25,113 ,

Dividends payable 25,343 25,351  !

Other 115,812 603,737 138,044 551,090 Deferred credits:  ;

Power contracts 88,963 21,396 Accumulated deferred income taxes 498,718 497,282 Accumulated deferred investment )

tax credits 58,899 62,970 Nuclear decommissioning liability 133,388 113,288 Other '49,099 36,969 Commitments and contingencies Total capitalization and liabilities $3,729,291 S3,637,170 The accompanying notes are an integral part of the consolidated financial statements.

29

)

Consolidated Statements of Cash Flows years ended December 31, (in thousands) 1996 1995 1994 Operating detivities:

l Net income $141,546 $112,310 $125,022 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization 228,259 202,294 203,222 i

Deferred income taxes and investment tax credits (4,057) (25,193) (8,276)

Allowance for borrowed funds used during construction (2,292) (4,767) (7,478)  ;

Net changes in: ,

Accounts receivable and accrued i unbilled revenues (11,719) (34,626) (20,701)

Fuel, materials and supplies (2,171) 7,202 3,093  ;

Accounts payable 609 2,978 23,196 Other current assets and liabilities (44,514) 26,485 35,217 Other, net 50,921 23,975 14,847 Net cash provided by operating activities 356,582 310,658 368,142 Investing activities:

Plant expenditures (excluding AFUDC) (151,045) (180,822) (198,771)

Nuclear fuel expenditures (52,967) (13,621) (21,934)  !

Demand side management expenditures 0 0 (37,007) ,

Sale of plant assets, net (106) 3,018 15,972 )

Nuclear decommissioning trust investments (29,182) (20,063) (16,771) l Electric company investments 566 1,058 (386)

Net cash used in investing activities (232,734) (21'0,430) (258,897)

Financing activities:

Issuances: )

Common stock 12,559 64,888 10,634 l Long-term debt 0 125,000 15,000 Redemptions:

Preferred stock (4,000) (2,000) (2,000) 4 Long-term debt (101,600) (100,600) (50,000) l Net change in notes payable 75,013 (88,345) 10,635 l Dividends paid (106,010) (100,152) (95,460) l Net cash used in financing activities (124,038) (101,209) (111,191)

Net decrease in cash and cash equivalents (190) (981) (1,946) ,

cash and cash equivalents at the )

i beginning of the year 5,841 6,822 8,768 Cash and cash equivalents at t.he end of the year S 5,651 S 5,841 S 6,822 Supplemental disclosures of cash flow information:

l Cash paid during the year for:

l Interest, net of amounts capitalized $100,810 $104,011 S 99,287 Income taxes S 98,668 $ 96,180 S 46,074 The accompanying notes are an integral part of the consolidated financial statements.

30

. .. - ~ --- ._ - - - - - _ . - - ~ _ _ - - . - . .-. . - . . .- .

i

, a b

l.

4 Notes to Consolidated Financial Statements Note A. Nature of Oc cations

j. We are an investor-owned regulated public utility operating in the energy and energy services business. This includes the generation, purchase, l transmission, distribution and sale of electric energy and the development and

implementation of electric demand side management programs. A portion of our

, generation is produced by our wholly owned nuclear generating unit, Pilgrim i Nuclear Power Station. We supply electricity at retail to an area of 590 g square miles, including the city of Boston and 39 surrounding cities and i towns. We also supply electricity at wholesale for resale to other utilities j l and municipal electric departments. Electric operating revenues were 88% -

, retail and 12% wholesale in 1996. We also conduct unregulated activities l

l through our wholly owned subsidiary, Boston Energy Technology Group (BETG).  ;

Through BETG and its subsidiaries, we are engaged in certain nonutility 5

businesses, including energy utilization and conservation, construction ,

management and district energy. In December 1996, BETG signed a joint venture j agreement with Residential Communications Network, Inc., currently known as t

) RCN Telecom Services, Inc. (RCN), to form a limited liability company to i

! provide local and long-distance telephone service, video, high-speed Internet access and other telecommunications-related services (the " Telecommunications 4 i

Venture"). The unregulated entity will be owned up to 49% by SETG, with RCN  !

having the day-to-day management responsibility. The joint venture agreement  !

is subject to a number of conditions which must be satisfied before formal i i operations begin, including the obtaining of certain regulatory approvals. In  ;

January 1997, BETG, through one of its wholly owned subsidiaries, signed  ;

definitive agreements with Williams Energy Services Company (WESCO), a i

] subsidiary of The Williams Companies, Inc., to form EnergyVision, LLC, an  !

unregulated limited liability company. This

• Energy Marketing Venture" will market electricity, natural gas and energy-related services to retail  !

customers in the six New England states. BETG, through its subsidiary, and ,

WESCO each own 50% of the new company which began operations in February 1997. ,

4 j- In January 1997, we announced a plan to form a holding company structure. The  !

, holding company structure, which is subject to shareholder and regulatory }

] approvals, is intended to provide increased financial, managerial and '

, organizational flexibility in order to better position us to operate in the  :

4 changing electric utility industry. It will permit us to take advantage rf -

i nonutility business opportunities in a more timely manner. In addition, ite j holding company structure will clearly separate our regulated and unregulated ,

lines of business enabling us to pursue nonutility business ventures in a  ;

manner consistent with the electric utility industry restructuring principles j outlined by the Massachusetts Department of Public Utilities (MDPU). The  ;

holding company structure is a well-established form of organization for  !

companies conducting multiple lines of business, particularly entities  !

engaging in both regulated and unregulated activities. All. investor-owned 1 Massachusetts electric utilities, other than Boston Edison, are currently I organized in a holding company structure.

Refer also to Note C to these Consolidated Financial Statements for potential changes in the nature of our operations as a result of the electric utility j industry restructuring. i 31 {

I

- . . . .- . . . ~ _ . - . - - - _ . - - . _ - , _

l  !

. l l 1 L

l Note B. Significant Accounting Policies l

l 1. Basis of conso1Ldation and Accountingr 1 l

The consolidated financial statements include the activities of our wholly )

owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All significant intercompany transactions have been eliminated. Certain )

l reclassifications have been made to the prior year data to conform with the i I current presentation.  !

l l We follow accounting policies prescribed by the Federal Energy Regulatory l Commission (FERC) and the MDPU. We are also subject to the accounting and l reporting requirements of the Securities and Exchange Commission. The l consolidated financial statements conform with generally accepted accounting i principles (GAAP). As a rate-regulated company we are subject to Statement of  ;

Financial Accounting Standards No. 71, Accounting for the Effects of Certain l Types of Regulation (S EAS 71) , under GAAP. The application of SEAS 71-results l in differences in the timing of recognition of certain expenses from that of l other businesses and industries. The preparation of financial statements in  !

conformity with GAAP requires us to make estimates and assumptions that affect j the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

2. Revenues We record estimates of revenues for electricity used by our customers but not ,

yet billed at the end of each accounting period. )

3. Forecasted Ruel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate. The difference between actual costs and the amounts billed to customers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated balance sheet until subsequent rates are adjusted. The MDPU has

)

the right to reduce our subsequent fuel and purchased power rates if they find  !

that we have been unreasonable or imprudent in the operation of our generating i units or in purchasing fuel. l i

4. Utt1Lpy Plant Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and j

replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.

5. Depreciation and 3raclear Tuel Amortisation 1

Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. Excluding the adjustment discussed below, the overall composite depreciation rates were 3.26%, 3.28% and 3.31% in 1996, 1995 and 1994, respectively.

I 32

Upon the completion of a review of our electric generating units, we

' I determined that our oldest and least efficient fossil units (Mystic 4, 5 and  ;

6) are unlikely to provide competitively priced power beyond the year 2000.

Therefore, during the second quarter of 1996, we revised the estimated remaining economic lives of these units to five years retroactive to the beginning of the year. The effect of this change in estimate is an annual increase to depreciation expense of $22 million.

The cost of decommissioning Pilgrim Station is excluded from our depreciation rates. Refer to Note E to these Consolidated Financial Statements for a discussion of nuclear decommissioning. 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 spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates.

6. Deferred Btsclear Outage Costs We defer the incremental costs associated with nuclear refueling outages when incurred and amortize them over future periods. In 1995 we changed the amortization period from five years to two years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station.

7. Costa Associated with Issuance and Redenption of Debt and Preferred Stock l

Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemption and issuance of long-term debt and preferred stock. The costs related to long-term debt are recognized as an addition to interest expense over the life of the debt or replacement debt. Beginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock redemptions and issuances as a direct reduction to retained earnings over the average life of the replacement preferred stock series.

l

8. A.11ovance for Borrowed Funds Used During Construction (AETTDC)

AFUDC represents the estimated costs to finance utility plant construction.

In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1996, 1995 and 1994 were 5.87%, 6.35% and 4.45%, respectively, and represented only the cost of short-term debt.

9. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased. Outstanding checks are included in cash and accounts payable until they are presented for payment.

10. Allowance for Doubtful Accounts Our accounts receivable are substantially recoverable. This recovery occurs 1 both from customer payments and from the portion of customer charges that l provides for the recovery of bad debt expense. Accordingly, we do not j maintain a significant allowance for doubtful accounts balance.

33 i

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__ _ ~ . _ __.-.____m.__ . _ _ _ - . _ _ _ _ _ _ .._

• o . .

l l

12. Jtegulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges.in accordance with agreements with our regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority j of these costs is currently being recovered from customers over varying time i periods. No return on investment is being earned on the regulatory assets. J l

Regul. story assets consisted of the following: {

December 31, j 1996 1995 Power contracts $ 88,963 $ 21,396 Redemption premiums 31,052 36,832 Income taxes, det 47,483 46,121 .

Postr<etirement benefits costs 15,009 15,009 l Decontamination and decommissioning 13,190 13,968  ;

Nuclear outage costs 3,432 13,471 Other- 2,897 3,298

$202.026 $150.095

12. P ~ % Per Share of Ccammon Stock r h Earni:ngs per share of common stock is calculated by dividing net income, after the payment of preferred stock dividends, by the weighted average common shares outstanding during the year.

Note C. Electric Utility Industry  ;

In December 1996, we reached a settlement agreement with-the Massachusetts Attorney General and the Massachusetts Division of Energy Resources that, if .

approved by the MDPU, allows all retail electric customers in our service area  :

to choose their electricity supplier (referred to as retail access) beginning as early as January 1, 1998. As part of the settlement, we have agreed to divest our fossil generating plants no later than six months after the [

commencement of retail access. Accordingly, other than Pilgrim Nuclear Power '

Station, we will no longer own any electricity generating facilities. The rates of our retained electric delivery business will continue to be regulated by the MDPU and will include. a non-bypassable access charge for the collection '

of our stranded costs. These costs include the above-market commitments under existing purchased power contracts, our net generation plant investment, ';

nuclear decommissioning commitments and regulatory assets related to our generation business. Implementation of the settlement will be subject to t enact. ment of enabling legislation by the Massachusetts legislature and rulings >

by the FERC. i In the traditional revenue requirements model, our electric rever.ues have been based on the cost of providing electric service. As such, we are subject to ,

certain accounting standards that are not applicable to other businesses and .

. indu:stries in general. We believe that we currently meet the criteria of these standards. STAS 71 requires us to defer recognition of certain costs ,

when incurred when we expect to receive future rate recovery of these costs.

The Securities and Exchange Commission has recently begun to focus on how the changes in the electric utility industry have affected utilities' ability to i continue to apply regulatory accounting. The final rules issued by the MDPU .

or the enactment of legislation in Massachusetts could, in the near term, '

cause us to no longer meet the criteria for application of SEAS 71 for some of l our operations. Should this occur, we would be required to take an immediate 1

4 34 I

. r

s

.a noncash charge to income for all of our affected regulatory assets and the above-market portion of purchased power contracts. In addition, a write-down of utility plant assets would be required under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, if competitive or regulatory change results in a probability that future cash flows will not be sufficient to recover our investment in those assets. Based on our settlement agreement we expect to recover. all strandable costs through a non-bypassable access charge to be paid by our delivery business customers. Under our settlement agreement, our delivery business will remain subject to rate regulation and, therefore, will continue to meet the criteria of these accounting standards. As noted earlier, under our settlement agreement we expect to continue to operate Pilgrim Station with the ability to collect stranded costs related to the unit. Although not anticipated based on our settlement agreement, the nonrecovery of strandable costs could have a material impact on our results of operations and financial condition.

However, if laws are enacted or regulatory decisions are made that do not offer Massachusetts electric utilities an oppor .nity to recover previously reviewed, prudently incurred commitments to provide service to our customers, we believe we have strong legal arguments to challenge such laws or decisions.

We will actively pursue the full recovery of stranded costs and are prepared to take the action necessary to protect the interests of our shareholders.

Our 1992 settlement agreement provided us with two annual retail base rate increases of $29 million effective in November 1993 and November 1994 and an eight-year annual performance adjustment charge. We did not make a base rate filing upon the expiration of the settlement agreement in 1995, therefore base rates have remained in effect at their 1995 levels.

Note D. Inconne Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SEAS 109). SEAS 109 requires the recognition of deferred tax assets and liabilities for the  ;

future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SEAS 109 we i recorded net regulatory assets of $47.5 million and $46.1 million and  ;

corresponding net increases in accumulated deferred income taxes as of 1 December 31, 1996, and December 31, 1995, respectively. The regulatory assets I represent the additional future revenues to be collected from customers for deferred income taxes.

Accumulated deferred income taxes consisted of the following: ,

1 December 31, l (in thousands) 1996 1995 Deferred tax liabilities:

Plant-related $532,390 $521,280 Other 95,642 95,148 628,032 616,428 Deferred tax assets: l Plant-related 8,406 12,590 Investment tax credits 38,005 40,632 Other 82,903 65,924 129,314 119,146 Net s cc'tmalated def erred income taxe.s $498,'18 S497.282 35

c . .

No valuation allowances for deferred tax assets are deemed necessary.

Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits.

Components of income tax expense were as follows:

years ended December 31, (in thousands) 1996 1995 1994 Current income tax expense $92,760 $93,469 $63,358 Deferred income tax expense 14 (21,115) (4,468)

Investment tax credits (4,071) (4,078) (4,092)

Income taxes charged to operations 88,703 68,276 54,798 Taxes on other incomes l Current (721) (1,729) 2,550 1 Deferred 0 0 284 l (721) (1,729) 2,834 l Total income tax expense $87,982 $66,547 $57,632 The effective income tax rates reflected in the consolidated financial ]

statements and the reasons for their differences from the statutory federal income tax rate were as follows:

1996 1995 1994 Statutory tax rate 35.0% 35.0% 35.0%

State income tax, net of federal income tax benefit 4.3 4.3 4.3 Investment tax credits (1.8) (2.3) (2.3)

Reversal of deferred taxes - settlement agreement - -

(5.51 Other 0.7 0.1 (0.1)

___ Effective tax rate 38.2% 37.1% 31.4%

Note E. Nuclear Decomunissioning and Nuclear Waste Disposal 2.. Wholoar Deccummissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We record an estimate of decommissioning costs in depreciation expense on the consolidated statements of income over Pilgrim's expected service life. Decommissioning expense was $12 million, $24 million and $15 ndllion in 1996, 1995 and 1994, respectively. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 ndllion to decommission the plant using the " green field" method, which provides for the plant site to be completely restored to its original state. The cost estimate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a contracted amount of Pilgrim's electric  ;

generation. The funds we cellect from decommissioning charges are deposited in an external trust and are restricted to use for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, ,

increase the nuclear decommissioning trust balance, thus reducing the amount  !

to be collected from customers.

j The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact of long-term spent fuel storage options resulting from delays in the United States Department of Energy (DOE) spent fuel removal program. Refer to part 2 below for a discussion of spent fuel removal. The partial update indicates an estimated  !

decommissioning cost of $400 million in 1991 dollars based upon a revised 36

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spent fuel removal schedule and utilization of dry spent fuel storage <

l technology. No further update is currently available; however, we will  !

l continue to monitor DOE spent fuel removal schedules and developments in spent  ;

j fuel storage technology along with their impact on the decommissioning j l estimate. We anticipate that we will be permitted to recover our actual ultimate decommissioning costs from our retail and contract customers In February 1996, the Financial Accounting Standards Board (EASB) issued f proposed new rules for accounting for liabilities related to closure and i l removal of long-lived assets, which include decommissioning of nuclear ,

generating' facilities. If these proposed rules are adopted we would be i required to retroactively recognize the entire estimated liability for ,

decommissioning costs on the balance sheet, offset by an addition to utility j plant. The plant addition would be depreciated over Pilgrim's remaining j expected service life. The liability would be measured based on the present  :

value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in the recognition of a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for  !

decommissioning. In addition, trust fund earnings.would be reported on the j income statement. Depending on the results of the EASB's redeliberation of  ;

certain issues regarding these proposed rules, it plans to issue either a final statement or revised proposed rules in the second quarter of 1997. ,

2. Spent Nuclear Phel )i The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the Nuclear Regulatory Commission to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the MDPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies, including proposed participation in a limited liability company (LLC) which would undertake construction of a private spent fuel storage facility in the state-of Utah or other locations.

Our participation in this LLC requires approval by the MDPU and is currently the subject of a petition seeking such approval.

In July 1996, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. .The decision was in response to petitions filed by us and other interested parties in 1994 seeking declaratory rulings concerning this obligation. In December 1996, the DOE notified us and other nuclear plant owners that it would be unable to begin acceptance of spent nuclear fuel for disposal in 1998. Along with other interested parties, we again filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking declaratory rulings concerning enforcement and remedies for DOE's failure to accept spent fuel for disposal in a timely manner. Under the Nuclear Waste Policy Act of 1982 it is the ultimate. responsibility of the DOE to permanently dispose of spent nuclear fuel. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel

- disposal contract with the DOE. The fee is collected from customers through  ;

fuel charges. The DOE has been conducting scientific studies evaluating a i potential. spent nuclear fuel repository site at Yucca Mountain, Nevada. The l potential site, however, has encountered substantial public and political oppositian and the DOE has publicly stated that it will be unable to begin acceptance of spent nuclear fuel for disposal by the date specified in the Nuclear Waste Policy Act. We cannot predict at this time whether or on what 37

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d schedule the DOE will eventually construct a spent fuel repository or what the j effect will be of any delays in such constrection.

3. Low-Level Blad.ioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility availabir to us. Legislation has been enacted in ,

Massachusetts establishing c regulatory process for managing the state's LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agreement with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management procedure, we will continue to monitor the situation and investigate other available options.

Note F. Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separat< business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement prograns and implemented a special severance program to seduce employee staffing levels. Under the enhanced retirement progrrms 330 employees elected to retira, and 149 employees whose positions were e.liminated became eligible for benefits under the special severance program. These programs resulted in a $34 ndllion pre-tax charge ($20.7 ,

million net of tax) over the third and fourth quarters of 1995. The charge ,

consisted of $24 ndllion for the retirement programs and $10 ndllion for the severance program. The enhanced retirement programs were offered to all +

employees at least 55 years old, with different years of service requirements  ;

for management and union employees. The programs provided for supplemental  !

salary payments and waivers of the early retirement pension reduction and the  ;

medical and life insurance benefits years of service requirement. The special  !

severance program, which applied to management and support personnel, was provided for all employees whose positions were eliminated in the reorganization. Severance benefits provided included salary payments, medical i insurance and outplacement services. As of December 31, 1996, there was no i material obligation remaining for these programs.

Note G. Pensions and other Postratirement Benefits-

1. Reasions i We have a defined benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employment. Our funding policy is to l contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market  ;

funds, insurance contracts and real estate funds.

We also have a supplemental retirement plan for certain management employees.

Benefits under this plan are based on final compensation upon retirement. The plan is not funded. The plan's cost and benefit obligation amounts are included in the following pension information for 1995 and 1996. Amounts related to the plan prior to 1995 were not material to our total pension Costs.

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Net pension cost consisted of the following components: I I

years ended December 31,  ;

(in thousands) 1996 1995 1994 I current service cost - benefits earned $13,452 S11,339 $15,057 i Interest cost on projected benefit [

obligation 32,325 31,789 33,961 Actual net (return)/ loss on plan assets (40,335) (72,192) 214 i Net amortization and deferral 17,064 49,557 (32,169)

Net pension cost $22,506 $20,493 $17,063 In accordance with our 1992 settlement agreement we deferred the difference  ;

between the net pension cost of the retirement plan and its annual funding amount through 1995. Net pension costs recognized in 1995 and 1994 were $28.2  ;

ndllion and $25.0 million, respectively. '

We used the following assumptions for calculating pension costs (

1996 1995 1994 Discount rate 7.25% 8.25% 7.00%

Expected long-term rate of return on assets 10.00% 10.00% 10.00%

Compensation increase rate 3.90% 3.90% 4.50%  :

The plans' funded status were as follows:

December 31, (in thousands) 1996 1995  ;

Supplemental Supplemental  !

Retirement Retirement Retirement Retirement j Plan Plan Plan Plan Actuarial present value of  ;

accumulated benefit {

obligation:

Vested $316,101 $ 7,576 $377,272 S 8,748 4 Non-vested 10,867 943 13,902 1,409 Total (a) S326,968 S 8,519 $391,174 S 10,157 >

f Plan assets at fair value $331,299 $ 0 $358,572 $ 0 ,

Projected obligation for  !

service rendered to date (400,561) (9,199) (476,666) (11,036) ,

Projected ben.efit ,

obligation in excess of plan assets (69,262) (9,199) (118,094) (11,036)

Unrecognized prior service cost 11,238 9,436 12,283 10,223 l Unrecognized net loss /(gain) 78,853 (1,141) 82,935 252 Unrecognized net obligation 7,130 0 8,064 0 Additional minimum liability (b) 0 (7,615) (17,790) (9,596)

Net pension prepayment /

_111 ability) S 27.959 S (8,519) $(32,602) S(10,157)

(a) The accumulated benefit obligation at December 31, 1995, includes

$13.5 million related to the enhanced retirement programs offered in 1995 as discussed in Note F to these Consolidated Financial Statements.

(b) Statement of Financial Accounting Standards.No. 87, Employers' Accounting for Pensions (SEAS 87), requires the recognition of an additional minimum liability for.the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SEAS 87 we 39 4

recorded additional minimum liabilities and corresponding intangible .

L assets of $7.6 ndllion and $27.4 million on our consolidated balance sheets at December 31, 1996 and 1995, respectively. ,

We used the following assumptions for calculating the plans' year-end funded status:

1996 1995 l Discount rate .

7.75% 7.25% l l

Compensation increase rate 3.90%- 3.90%

We also provide defined contribution 401(k) plans for substantially all our employees. We match a percentage of employees' voluntary contributions to the j' plans. We made matching contributions of $8 million in 1996, S9 million in 1995 and $8 ndllion in 1994l. e l' '

. 2. Other Pontzetizanaent Benefits .

In addition to pension benefits, we also provide health care and other .;

benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting i Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (S EAS 106) . Our 1992 settlement agreement provided us with a phase-in to full expense of the PBOP costs incurred under SEAS 106. The 1992 settlement agreement allowed us to defer any costs in excess of the specified  !

phase-in amounts to the extent that we funded an external trust. Our funding l policy is to generally contribute 100% of PBOP costs to external trusts.

I Therefore, we recorded $23 million and $17 million of PBOP costs in 1995 and

! 1994, respectively in accordance with the 1992 settlement agreement. In 1996 we recorded the full PBOP costs incurred under SEAS 106 of $26 million. The i net deferred PBOP costs of $15 ndllion resulting from the delayed phase-in are ,

! included in regulatory assets as these costs are expected to be recovered from customers in future periods. <

j Net postretirement benefits cost consisted of the following components:

years ended December 31, l (in thousands) 1996 1995 1994 i Current service cost - benefits earned S 4,616 $ 3,408 S 4,978 ,

Interest cost on accumulated benefit obligation 16,815 13,521 13,632 Actual return on plan assets (9,584) (7,151) (187)

Amortization of transition obligation 9,151 9,151 9,151 [

Net amortization and deferral 5,209 3,017 (2,581)

Net postretirement benefits cost $26,207 S21,946 $24,993 i

? ,

(, We used the following assumptions for-calculating postretirement benefits  ;

cost:

1996 1995 1994 Discount rate 7.25% 8.25% 7.00% l Expected long-term rate of return on assets 9.00% 9.00% 9.00%

Health care cost trend rate- 7.00% 7.00% 9.00%

, The health care cost trend rate is assumed to' decrease by one percent in 1997 and 1998 and to remain at 5% in years thereafter, changes in the health care t

l cost trend rate will affect our cost and obligation amounts. A o.se percent increase in the assumed health care cost trend rate would increast the total 40

> l l

t service and interest cost components by 7.6% and would increase the  !

accumulated benefit obligation at December 31, 1996, by 6.7%.

l The PBOP program's funded status was as follows: l December 31,  ;

(in thousands) 1996 1995 ,

Trust assets at fair value $ 72,702 $ 51,064 Accumulated obligation for service l rendered to date from: .

Retirees $(156,694) $(110,877) i Active employees eligible to retire (12,644) (31,980) )

Active employees not eligible to i retire (61,567) (230,905) (53,514) (196,371) l Accumulated benefit obligation in J excess of trust assets (158,203) (145,307)

Unrecognized prior service cost (16,274) (17,889) ,

Unrecognized net loss 26,663 5,612 I Unrecognized transition obligation 146,413 155,564 Net oostretirement benefits liability S (1.401) $ (2,020)

The weighted average discount rates used to measure the accumulated benefit obligation were 7.75% in 1996 and 7.25% in 1995. The trust assets consist of equities, bonds and money market funds.

I i

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1 4 Nota B. Capital Stock y- l

December 31, (dollars in thousands, except per share amounts) 1996 1995 i Oommon stook equity:-

Cormon stock, par value $1 per share, 6 J 100,000,000 shares authorized; 48,509,537 ,

,< and 48,003,178 shares issued and i 4

outstanding: $ 48,510 $ 48,003 Premium on common stock 695,723 683,686

! Retained earnings 291,786 257,344 ,

Surplus invested in plant 405 405 t j~ Total common stock equitv ,

$1,036,424 $989,438 l

' Dividends declared per share of common stock were $1.88, $1.835 and $1.775 in r

, 1996, 1995 and 1994, respectively. >

l~ ,

cumulative preferred stock

!

Par value $100 per share, 2,890,000 shares .

j. authorized; issued and outstanding:  !

Nonmandatory redeemable series

a Current Shares Redemption Series Outstanding Price / Share

. 4.25% 180,000 $103.625 $ 18,000 $ 18,000 4.78% 250,000 $102.800 25,000 25,000 3 7.75% 400,000 -

40,000 40,000

j. 8.25% 400,000 -

40,000 40,000 -

123,000 123,000 ,

Less: redemption and issuance costs (3,046) (3,323)

Total nonmandatory redeemable series $ 119,954 $119,677 l I

I Mandatory redeemable series l Current Shares Redemption Series Outstanding Price / Share '

7.27% 400,000 $102.910 $ 40,000 $ 44,000 4

8.00% 500,000 -

50,000 50,000 I 90,000 94,000 -

Less: redemption and issuance costs (6,535) (7,163)  ;

j due within one year (2,00C) (2,000)  ;

Total mandatory redeemable series 81,465 $ 84,837  ;

S i i

1. ca==aa stock 1

Common stock issuances in 1994 through 1996 were as follows:  !

Number Total Premium on (in thousands) of Shares Par Value Common Stock Balance at December 31, 1993 45,129 $45,129 $612,653 Dividend reinvestment plan 406 406 10,150 Balance at December 31, 1994 45,535 45,535 622,803 Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 Balance at December 31, 1995 48,003 48,003 683,686 Dividend reinvestment plan 507 507 12,037 gal,ance at December 31, 1996 48,510 $48,510 $695,723 42

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2. Cwintive ManA= tory kadeaannble Preferred Stock The 400,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $102.910. The redemption price declines annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each May to redeen

! addit'onal shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends. In 1996, 1995 and 1994, we redeemed, at par value, 40,000 shares, 20,000 shares and 20,000 shares, respectively. The l redemptions in 1996 include 20,000 shares of optional redemptions.

We are not able to redeem any part of the 500,000 shares of 8% series i

cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share, plus i accrued dividends.

l Note I. InJebtedness

, December 31, l (in thousands) 1996 1995 l

Long-term debt:

Debentures:

5.125%, due March 1996 S 0 $ 100,000 5.700%, due March 1997 100,000 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentures 1,115,000 1,215,000 Less: due within one year (100,000) (100,000)

Net long-term debentures 1,015,000 1,115,000 Sewage facility revenue bonds 34,100 35,700 Less due within-one year (667) (667)

Less funds held by trustee (4,789) (4,810)

Net long-term sewage facility revenue bonds 28,644 30,223 Massachusetts Industrial . Finance Agency bonds:

5.750%, due February 2014 15,000 15,000 Total lonc term debt S1,_050,644 $1,160,223 short-term debt:

Notes payable:

Bank loans $ 129,631 $ 75,941 Commercial paper 71,823 50,500 Total notes payable _ _ _ _

$ 201,454 S 126,441 43

1

1. Long-Tem Debt The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeenable in March 2003 at 103.730%. No other series are redeemable prior to maturity.

There is no sinking fund requirement for any series of our debentures.

Sewage facility revenue bonds were issued by dEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In May 1995 and 1996, we redeemed $0.6 million and $1.6 million, respectively, as scheduled. '.'he weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a nsximum of $1 million.

The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in Febremry 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006.

The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2001 are $101.6 million per year in 1997 and 199a, $1.6 million in 1999, $166.6 ndllion in 2000 and $1.6 ndllion in 2001,

2. Short-Tem 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 regulatory authority to issue up to $350 million of short-term debt.

We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings.

Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.

Inf ormation regarding our short-tenn borrowings, comprised of bank loans and commercial paper, is as follows:

(dollars in thousands) 1996 1995 1994 Maximum short-term borrowings $272,500 $327,769 $268,100 W ighted average amount outstanding $208,914 $165,720 $214,640 Weighted average interest rates excluding commitment fees 5.65% 6.21% 4.47%

Note J. Fair Value of Financial Instruments The following methods and assumptions were usen to estimate the fair value of each class of securities for which it is practicable to estimate the v.'ue:

Nuclear decommissioning trust:

The cost of $132.1 million approximates fair value based on quoted market prices of securities held.

44 s

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, Cash and cash equivalents:

1 The carrying amount of $5.7 million approximates fair value due to the short-term nature of these securities.

4 Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values-as of December 31, 1996, are a as follows:

Carrying Fair (in thousands) Amount value

. Mandatory redeemable cumulative preferred stock $ 83,465 $ 93,900 Sewage facility revenue bonds $ 34,100 $ 35,082 Unsecured debt $1,130,000 $1,131,363 I Note K. New Accounting Pronouncement i

l In October 1996, the Accounting Standards Executive Committee of the American i Institute of Certified Public Accavntants issued Statement of Position 96-1,

, Environ 2nental Remediation Liabilities, effective in 1997. This statement i contains authoritative guidance on specific accounting issues that are present

in the recognition, measurement, display and disclosure of environmental remediation liabilities. We do not believe this statement will have a j material effect on our financial position or results of operations.

l

, Note L. Commitments and Contingencies l l

l

1. Contractaal Commitmants i

l At December 31, 1996, we had estimat*d contractual obligations for plant and l equipment of approximately $8 million.

l

[

i j We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable ]

leases for the years after 1996 are as follows:

l (in thousands) f 1997 $ 22,842 1998 20,042 1999 - " 568 2000 is,684 l E001 12,067 4

Years thereafter 98,945 i Total $188,148 0

! The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $455,117.

We will capitalize a portion of these lease rentals as part of plant I expenditures in the future. The total expense for both lease rentals and j transm22sion agreements was $26.3 ndllion in 1996, S24.5 million in 1995 and l

$28.6 million in 1994, net of capitalized expenses of $2.9 ndllion in 1996, j

$2.7 million in 1995 and $2.4 million in 1994. '

We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply our New Boston generating station with natural I

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gas. The fixed and determinable portions of the obligations are $19.5 million

in 1997, 1998 and 1999 and $14.6 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $49.5 million in 1996, $13.9 million in 1995, and $6.5 million

in 1994.

! 2. Rydro-Quebec  :

4 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. As an equity participant we are required to i

y guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 1996, our portion of these guarantees was approximately $18 ndllion.  ;

a h J. Yades Atennic 3-We have a 9.5% equity investment of approximately $2 ndllion in Yankee Atomic

Electric Company - (Yankee Atomic) . In 1992 the board of directors of Yankee i j Atomic decided to permanently discontinue power operation of the Yankee Atomic j

! nuclear generating station and decommission the facility.

.t Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment i and costs of decommissioning is approximately $16.5 ndllion as of December 31,

. 1996. This estimate is recorded on our consolidated balance sheet as a power l contract liability and an offsetting regulatory asset as we continue to i collect these costs from our customers in accordance with our 1992 settlement t agreement. {

4. CoenectLaut Yankee

~

On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power Company (CYAPC), which owns and operates the Connecticut Yankee nuclear  ;

electric generating unit (Connecticut Yankee), unanimously voted to retire the Haddam Neck, Connecticut unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of its operating ,

license, compared to the costs of closing the unit and incurring replacement power costs for the same period. We have a 9.5% equity investment in CYAPc af approximately $10 million.

The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee

• is approximately $763 millic3. Our share of these remaining estimated costs is $72.5 ndllion. ,

On December 24, 1996, CYAPC filed its cost estimate along with certain 6 amendments to its power contracts with the FERC. .The power contract ,

amendments are designed to clarify the obligations of CYAPC's power i purchasers, including Boston Edison, following the decision to cease power

• production. Based upon regulatory precedent, CYAPC believes it will continue to collect from its power purchasers its decommissioning costs, the owners' '

unrecovered investments in CYAPC and other costs associate ' with the permanent closure of the unit over the remaining period of the unit' operating license. .

We expect that we will continue to be allowed to recover our share of nuch  !

- ssts from our customers and, therefore, have recorded our share of these  ;

costs on our consolidated balance sheet as a regulatory asset with a corresponding powe contract liability.  !

i 46  !

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5. Nuclear Zusurnace j i

The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising l from a single nuclear-related accident. The first $200 million of nuclear I liability is covered by commercial insurance. Additional nuclear liability )

insurance up to approximately $8.7 billion is provided by a retrospective l assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 ndliion per reactor per accident in any year.

I We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to I cover some of the costs to purchase replacement power during a prolonged )

accidental outage and the cost of repair, replacement, decontamination or 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 $10.4 million under both the replacement j power and excess property damage, decontamination and decommissioning policies.

6. Essardous Waste l

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We own or operate approximately 40 properties where cil or hazardous materials were previously spilled or released. We are required to clean up these l properties in accordance with a timetable developed by the Massachusetts I Department of Environmental Protection and are continuing to evaluate the i costs associated with their cleanup. There are uncertainties associated with  !

these coe.. due to the complexities of cleanup technology, regulatory i requ3tements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, j transported or disposed of hazardous waste at the sites. At the majority of l these sites we are one of many potentially responsible parties and currently j expect to have only a small percentage of the potential liability. Through i December 31, 1996, we have accrued approximately $7 million related to our j cleanup liabilities. We are unable to fully determine a range of reasonably i possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.

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7. Litiga tion We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from our New Boston Station generating unit. In February 1997, we settled the lawsuit brought by Subaru Distributors Corporation. Tha settlement did not have a material impact on our financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending.

In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning employees affected by our 1988 reduction in force. In December 1996, we reached a settlement of this lawsuit under which there is no finding or admission of discriminatory employment practices. We anticipate full recovery from our insurance carrier for this settlement.

In the normal course of our business we are also involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material inpact on our financial condition. However, it is reasonably possible that additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.

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. Mote M. Long-Tersa Power Contracts J

1. Laag-tessa Contracts for the Purchase of Electricity We 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 pcwer expense on our consolidated income statements. Information relating to these contracts as of December 31, 1996, is as follows:

! proportionate share (in thousands)

, Units of Debt

Contract Capacity Minimum Outstanding l Expiration Purchased Debt Through Cont. Annual Generating Unit Daty  % MW Service Exp. Date Cost Canal Unit 1 2002 25.0 141 $ 1,415 $ 5,373 $ 24,399 -

Mass. Bay Trans-

! portation Authority - 1 2005 100.0 34 - -

1,999 Connecticut Yankee Atomic 2007 9.5 -

2,427 12,519 (b)

Ocean State Power -

. Unit 1 2010 23.5 68 4,487 20,447 23,689 Ocean State Power -

Unit 2 2011 23.5 67 3,538 16,529 24,091 Northeast Energy Associates (c) (c) 219 - -

124,730 L' Ene rgia (d) 2013 73.0 63 - -

30,920 MassPower 2013 44.3 117 11,738 76,524 50,322 Mass. Bay Trans- >

portation Authority - 2 2019 100.0 34 - -

371 Total 743 $23,605 $131.392 S280.521 (a) The Northeast Energy Associates contract represents 6% of our total system generation capability. The remaining units listed above represent 14.5% in total.

(b) Connecticut Yankee permanently ceased operation in 1996. Refer to Note L.4. to these Consolidated Financial Statements for more details.

(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 chare of the unit's capital and fixed operating costs.

(d) We pay for this energy based on a price per kWh actually received.

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Our total fixed and variable costs.for these contracts in 1996, 1995 and 1994 -

were approximately $281 ndllion (excluding Connecticut Yankee Atomic), $283 million and $286 million, respectively. Our minimum fixed payments under these contracts for the years after 1996 are as'follows:

(in thousands) 1997 $ 85,429 1998 67,540 1999 38,401 2000 88,927

-2001 91,089 Years thereafter 1,047,479 Total $1,488,865 Total present value $ 797,683

2. Zomy-roman Power sales

-- In addition to wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts. Information relating to these contracts is as follows:

Contract Expiration Units of Capacity Sold Contract Customer Date  % MW

-Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 various municipalities 2000(a) 3.7 25.0 Total 25.7 172.4 (a) Subject to certain adjuttments.

Under these contracts, the utilities pay their proportionate share of the costs of operating Pilgrim Station and associated transmission facilities.

These costs include operation and maintenance. expenses, insurance, local' taxes, depreciation, decommissioning and a return-on capital.

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selected consolidated Quarterly Financial Data (Unaudited)

(in thousands, except earnings per share)

Balance Available Earnings  ;

Operating Operating Net for Common Per Average 4 Revenues Income Income Stock Common Share '

1996  ;

i First quarter $387,849 $ 52,093 $25,203 $21,313 $0.44-Second quarter 389,756 55,232 27,926 24,086 0.50 -

Third quarter 497,968 105,353 80,011 76,194 1.58 l Fourth quarter 390,730 35,252 8,406 -4,588 0.09 l 1995 l First_ quarter $379,678 $ 47,610 $20,202 $16,300 $0.36 l Second quarter 380,828 55,683 26,137 22,247 0.48 i Third quarter 498,554 102,695'*' 72,368 '6' 68,478 'b'

1. 4 6

'b' Fourth quarter 369,443 21,412'*' (6,397)'b' (10,2 8 6 ) 'b'

( 0. 21 ) j (a) Based on the weighted average number of common shares outstanding during >

each quarter. i (b) As discussed in Note F to the Consolidated Financial Statements, we i

incurred a_S34 million nonrecurring pre-tax charge related to our corporate restructuring over the third and fourth quarters of 1995.  !

Amounts excluding the restructuring charge were as f.'llows:  ;

Balance I

-Available Earnings Operating Net for Common Per Average  !

Income Income Stock Common Share  ;

1995 i

$107,779 $77,452 $1.57 Third quarter $73,562 Fourth quarter 36,991 9,182 5,293 0.11 l Item 9. Changes in and Disagreements with Accountants on Accounting and l Financial Disclosure i Not applicable.

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Part III Item 10. Directors and Executive Officers of the Registrant (a) Identification of Directors j See ' Election of Directors - Information about Nominees and Incumbent Directors" on pages 7 through 9 of the definitive proxy statement dated

' March 26, 1997, 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.

t (c) Identification of Certain Significant Employees Not applicable.

(d) Family Relationships i Not applicable.

(e) 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 7 through 9 of the definitive proxy statement dated March 26, 1997, 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 Legal Proceedings Not applicable.

(g) Promoters and Control Persons I

Not applicable.

Item 11. Executive Compensation  !

l See " Executive Compensation" on pages 2? through 33 of the definitive proxy statement ~ dated March 26, 1997, incorporated herein by reference. 4 1

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i Item 12. Security ownership of Certain Beneficial Owners and Management  ;

(a) Security ownership of Certain Beneficial Owners To the knowledge of~ management, no person owns beneficially more than five ,

percent of the outstanding voting securities of the Company.

(b) ' Security Ownership of Management t

See " Stock Ownership by Directors and Executive Officers" on pages 9 through '

-10 of the definitive proxy statement dated March 26, 1997, incorporated herein :

by reference. j (c) Changes in Control i

Not applicable.

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Item 13. -Certain Relationsh p_: and Related Transactions j Not applicable.

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Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K  ;

(a) The following documents are filed as part of this Form 10-K:

1. Financial Statements: '

Page Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994 28 Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994 28 Consolidated Balance Sheets as of December 31, 1996 and 1995 29 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994 30 Notes to Consolidated Financial Statements 31 Selected Consolidated Quarterly Financial Data (Unaudited) 51 Report of Independent Accountants 65

2. Financial Statement Schedules:

No financial stat.ement schedules are included as they are either not required or not applicable.

3. Exhibits:

Refer to the exhibits listing beginning on the following page.

(b) Reports on Form 8-K:

A Form 8-K dated December 20, 1996, was filed during the fourth quarter of 1996 announcing that the company reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Division of Energy Resources.

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l Exhibit SEC Docket i l

Exhibit 3 Articles of Incorporation and By-Laws Incorporated herein by reference: l l

3.1 Restated Articles of organization 3.1 1-2301 Form 10-Q for the quarter ended June 30, 1994 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 Exhibit 4 Instruments Defining the Rights of Security Holders, including Indentures Incorporated herein by reference:

4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301 dated September 1, 1988, between Form 10-0 Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 ,

4.1.1 First Supplemental Indenture 4.1 1-2301  ;

dated June 1, 1990 to Form 8-K '

Indenture dated September 1, 1988 dated with Bank of Montreal Trust Company - June 28, 1990 9 7/8% debentures due June 1, 2020 4.1.2 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 Harbor Electric Energy Company and December 31, Shawmut Bank, N.A., as Trustee, dated 1991 November 1, 1991 ,

4.1.3 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 55

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Exhibit SEC Docket 4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301 r February 12, 1993 Form 10-K  !

for the year ended December 31, 1992 4.1.4.1 First Amendment to Revolving Credit 4.1.10 1-2301 Agreement dated May 19, 1995 Form 10-K for the year ended December 31,

• 1995 4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301 i Board of Directors of Boston Edison Form 10-K Company taken September 10, 1992 re for the 8 1/4% debentures due September 15, 2022 year ended December 31, 1992 4.1.6 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 ,

6.80% debentures due February 1, 2000 year ended {

December 31, [

1992  ;

4.1.7 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 l

5 1/8% debentures due March 15, 1996, year ended l 5.70% debentures due March 15, 1997, December 31, l

5.95% debentures due March 15, 1998, 1992 4 l

6.80% debentures due March 15, 2003,

! 7.80% debentures due March 15, 2023 4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301 Board of Directors of Boston Edison Form 10-K l Company taken August 18, 1993 re for the 6.05% debentures due August 15, 2000 year ended i

December 31, 1993 4.1.9 Votes of the Pricing Committee of the 4.1.9 1-2301 [

1 Board of Directors of Boston Edison Form 10-K Compsny taken May 10, 1995 re for the  ;

2 7.80% debentures due May 15, 2010 year ended December 31, 1995 i l

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'o The Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long *.erm debt whose authorization does not exceed 10% of the Company's total assets.

Exhibit SEC Docket Exhibit 10 Material Contracts Incorporated herein by reference:

10.1 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, May Form 10-Q 1986 for the quarter ended June 30, 1986 10.1.1 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May Form 10-K 1986, with modifications for the year ended December 31, 1991 10.2 Executive Annual Incentive 10.5 1-2301 Compensation Plan Form 10-K for the year ended December 31, 1988 10.3 1991 Director Stock Plan 10.1 1-2301 Form 10-0 for the "t quarter ended March 31, 1991 10.4 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 14, 1993 Form 10-K for the year ended December 31, 1992 Y

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Exhibit SEC Docket <

10.5 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 l

10.5.1 Amendment No. 1 to Deferred 10.5.1 1-2301  :

Compensation Trust dated Form 10-K

' March 31, 1994 for the  ;

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year ended December 31, 1994 10.6 Directors Retirement Benefit 10.8.1 1-2301  ! '

(1993 Plan) Form 10-K for the )

year ended l December 31,  !

1993 10.7' Performance Share Plan, Amendment 10.8 1-2301 and. Restatement dated October 24, 1994 Form 10-K  !

for the ,j year ended December 31, l 1994  !

1. 10.8 Boston Edison Company Deferred 10.9- 1-2301 Compensation Plan, Amendment and Form 10-K l Restatement dated January 31, 1995 for the .

year ended j December 31,

'1994 i

10.9 Employment Agreement applicable to 10.10 1-2301  !

Ronald A. Ledgett dated April 30, 1987 Form 10-K l for the j year ended i December 31,  ;

1994 10.10 Retention Agreement applicable to 10.1 1-2301 Ronald A. Ledgett dated May 15, 1996 Form 10-Q  !

for the quarter ended June 30, 1996 I

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, j Exhibit SEC Docket 10.11 Change in Control Agreement applicable 10.2 1-2301 to Thomas J. May dated July 8, 1996 Form 10-0 for the quarter ended June 30, 1996 10.12 Form of Change in Control Agreement 10.3 1-2301 applicable to Ronald A. Ledgett, Form 10-Q E. Thomas Boulette, L. Carl Gustin, for the John J. Higgins, Douglas S. Horan quarter ended >

and certain other officers dated June 30, 1996 July 8, 1996 Filed herewith:

10.13 Retention Agreement applicable to Douglas S. Horan dated May 15, 1996 a

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l Exhibit SEC Docket Exhibit 12 Statement te Computation of Ratios Filed herewith:

12.1 Computation of Ratio of Earnings l to Fixed Charges for the Year Ended December 31, 1996 12.2 Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year Ended December 31, 1996 j r

Exhibit 21 Subsidiaries of the Registrant l

21.1 Harbor Electric Energy Company (incorporated in Massachusetts),

a wholly owned subsidiary of Boston ,

Edison Company '

l 21.2 Boston Energy Technology Group, Inc.

(incorporated in Massachusetts),

a wholly owned subsidiary of Boston Edison Company i

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i Exhibit SEC Docket i

Exhibit 23 Consent of Independent Accountants 1

Filed herewith:

23.1 Consent of Independent Accountaats to incorporate by reference their opinic included with this Form 10-K in the Form S-3 Registration Statements filed by the Company on February 3, 1993 (File No. 33-57840),

May 31, 1995 (File No. 33-59693) 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, 1992 (33-48424 and 33-48425),

March 17, 1993 (33-59662 and 33-59682) and April 6, 1995 (33-58457) and in the Form S-4 Registration Statement filed by Boston Edison Holdings, currently known as BEC Energy, on March 17, 1997 (File No. .

333-23439)

Exhibit 27 Financial Data Schedule Filed herewith:

27.1 Schedule UT Exhibit 99 Additional Exhibits Incorporated herein by reference:

99.1 MDFU Settlement Agreement with 28.1 1-2301 Boston Edison Company dated Form 8-K October 3, 1989 dated October 3, 1989 99.2 Settlement Agreement between Boston 28.1 1-2301 Edison Company and Commonwealth Form 8-K Electric Company, Montaup Electric dated Company and the Municipal December 21, Light Department of the Town of 1989 Reading, Massachusetts, dated January 5, 1990 1

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Exhibit SEC Docket l J

99.3 Pilgrim Outage Case Settlement between 28.2 1-2301 Boston Edison Company and Reading Form B-K Municipal Light' Department regarding dated l Contract Demand Rate, dated December December 21, j 21, 1989 1M9 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

' dated April 26, 1990 quarter ended March 31, 1990 99.5 _Informstion required by SEC Form 1-2301 11-K for certain Company' employee Form 10-K/A

-benefit plans for the years ended Amendments to December 31, 1995, 1994 and 1993 Form 10-K for the years ended December 31, 1995, 1994 and 1993 dated June 27,1996, June 29, 1995 i and June 30, 1994, respectively 99.6 MDPU Settlement' Agreement with- 28.2 1-2301 Boston Edison Company, dated Form 10-Q October 23, 1992 for the quarter ended September 30, 1992

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i SIGNATURES j c

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. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its- i behalf by the' undersigned, thereunto duly authorized. j BOSTON EDISON COMPANY f By: /s/ James J. Judge )

James J. Judge Senior Vice President and Treasurer (Principal Financial Of ficer)

• l Date: March 27, 1997 j 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 27th day of March 1997.

I e

/s/ Thomas J. May Chairman of the Board, President  !

Thomas J. May and Chief Executive Officer l

l. /s/ Robert J. Weafer, Jr. Vice President - Finance, j Robert J. Weafer, Jr. Controller and Chief Accounting '

Officer l- /s/ William F. Connell Director .

William F. Connell -!

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/s/ Gary L. Countryman Director Gary L. Countryman t 6

/s/ Thomas G. Dignan, Jr. Director Thomas G. Dignan, Jr.

-f

/s/ Charles K. Gifford Director 4 Charles K. Gifford [

/s/ Nelson S.-Gifford Director 'I Nelson S. Gifford l ./s/ Matina S. Horner Director f l Matina S. Horner i' I

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/s/ Sherry H. Penney l Director '

Sherry H. Penney l I

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/s/ Herbert Roth, Jr. Director l Herbert Roth, Jr.

Director Stephen J. Sweeney l

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• 1 Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company:

We have audited the consolidated financial statements of Boston Edison Company and subs.idiaries (the company) listed in Item 14 (a) of this Form 10-K. These consolidated financial statements are the responsibility of the Company's .

management. Our responsibility is to express an opinion on these financial i statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to '

obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1996 and 1995, and the consolidated results el its operations and its cash flows for each of the three years in the period onded December 31, 1996, in conformity with generally accepted accounting p rinciples .

COOPERS & LYBRAND L.L. P.

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Boston, Massachusetts January 23, 1997 i

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