BECO-LTR-96-031, Beco 1995 Annual Rept & Securities & Exchange Commission (Sec) Form 10-K Rept
| ML20106J810 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/31/1995 |
| From: | May T, Oheim H BOSTON EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| BECO-LTR-96-031, BECO-LTR-96-31, NUDOCS 9604110292 | |
| Download: ML20106J810 (119) | |
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10CFR50.71(b) 10CFR140.15(b)(1)
Boston Edison Pilgrim Nuclear Power Station Rocky Hill Road Plymouth, Massachusetts 02360 April 10, 1996 Henry V Oheim- BECo Ltr. #96-031 General Manager - Techn6 cal section U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Docket No. 50-293 License No. DPR-35 l
Annual Financial Statement for 1995 i in accordance with 10CFR 50.71(b) and 10CFR 140.15(b)(1), Boston Edison submits the enclosed 1995 annual report and the Securities and Exchange Commission (SEC) Form 10-K which 1 corresponds to the 1995 annual report. !
i If you have any questions on this documentation, please contact Mr. Robert Cannon at (508) 830- l 8321.
H. V. Oheim RLC/ Rap 95/10K-94 Attachment cc: Mr. R. Eaton, Project Manager Division of Reactor Projects - l/11 Mail Stop: 14D1 U. S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike Rockville, MD 20852 '
U.S. Nuclear Regulatory Commission Region 1 475 Allendale Road King of Prussia, PA 19406 Senior Resident inspector Pilgrim Nuclear Power Station 7
m h 9604110292 951231 PDR ADOCK 05000293 g' I PDR l
1995 Annual Report To Shareholders pp '
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) Financial Highlights
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years ended December 31,
, 1995 1994
'["g% Operating revenues (000) $1,628,503 $1,544,735
, %g, Income available for common stock (000) $96,739 $109,257 jI Common shares outstanding -
weighted average (000) 46,592 45,338 .I i [P m~~
a% Common stock data: ;
! Earnings per share (excluding restructuring charge) $2.52 $2A1 *
.4) (a)
{ ( T Dividends declared per share $1.835 $1.775
} ,% Payout ratio (excluding .estructuring charge) 72 % (a) 73 %
!_ YN Book value per share $20.61 $20.11 l % Return on average common equity l ( (excluding restructuring charge) 12.2 % (a) 12.1 %
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, d Fixed charge coverage (SEC) 2.38 2.46
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Certain reclassifications and recalculations were made to the data reported in the prior i
1 f year to conform to the method of presentation used in 1995.
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(a) The company incurred a 50.44 per share restructuring charge in 1995.
About The Company Boston Edison is a public i utility engaged principally in the gen-
+ .y eration, purchase, transmission, dis-Eats' wr tribution and sale of electric energy. A lt was incorporated in 1886. We sup- j j ply electricity at retail to an area of
- approximately 590 square miles l within 30 miles of Boston, encom- dW passing the City of Boston and 39 l '
l surrounding cities and towns. The !
population of the territory served at f. I ,
retailis approximately 1.500,000.
i We also supply electricity to ,
other utilities and municipal electric departments at wholesale for resale.
Above, Boston Mayor Tom Menino and Tom May announce the
- About 87 parcent of our revenues company's contribution of money, computer hardware and vol-are derived from retail electric sales, unteers to the Boston School Department in support of the 4
j 11 percent from wholesale sales and Mayor's educational initiative.
j 2 percent from other sources.
5 On The Cover: Crossing the bridge to competition. Boston f Edison will continue to focus on its customers and its commu-l nities as it helps drive and shape industry reform.
Nineteen ninety-five was an eventful, historic year in the electric utility industry, with at least 40 states looking at various aspects of deregulation. Here in Massachusetts, Boston Edison has been among the leaders in shaping industry reform and will continue as a powerful influence. As we help shape the future of the industry, Boston Edison will con-tinue to balance the interests of consumers and shareholders, stead"y navigating the choppy waters of industry reform from a position of financial strength. Customer relationships are being forged in this j new environment, and new opportunities in tvw-way customer communications are being pursued.
We continue as a full-service utikty wh;le offering many nontraditional products and services.
This past year was a transition year, by all accounts, as the move to restocture gained momen-tum. Key issues were addressed by regulators, utikties, communities, consumert environmentalists and independent power producers ahke. In last year's Annual Report, your company described the issues surrounding industry reform and Boston Edison's strategic direction to address them.
The clear direction of public policy is to unbundle utility operations. Boston edison is moving in pareiiei witn inis trend. resneping end reeefining the company as well. Internally, we continue to cut costs, streamline the company and increase overall services to the customer. Because of these efforts, we delivered another strong year of financial performance.
Our dividend growth for 1995 was within the top 15 percent of the industry. We declared a six-cent dividend increase in December 1995, bringing the annual rate to $1.88 per share, a 3.3 per-cent increase. This is at a time when more than half of the nation's electric utilities are decreasing or levelizing their dividends. Our camings for 1995 were $2.52, not including a $0.44 accounting charge related to our corporate restructuring. This represents a 4.6 percent increase over last year.
Return on equity remains strong at 12.2 percent versus last year's 12.1 percent (again excluding the restructuring charge). Our three-year total return on investment is the highest of the major New England utilities.
) The strength of our stock price steadily improved throughout 1995, trending up from $24 per share at the beginning of the year, and closing at $29-1/2 at year-end. Our equity ratio also
, improved in 1995 to its strongest level in a decade, primarily due to new common stock issued during the year.
We also performed wel1 operationally. Average service restoration times improved by 15 per-cent and more than 90 percent of all new services were ir. stalled within a three-day turnaround. The company's aging distribution system, including the downtown network, is being upgraded for increased reliabikty Additionally, the company's fossil generating units achieved the second best per-formance in history or unit availabikty. In nuclear generation, Pilgrim Station surpassed all previous capacity factors during a refuehng outage year and recently set a new record for continuous op0 ration.
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INDUSTRY PICTURE - THE MASSACHUSETTS DEBATE Customers will benefit from the forces of competition as the electric utility i..Sistry moves to restructure. Under the regulatory model, Boston Edison, like most utilities, was fully integated, manufacturing the product of electricity, and handling the transmission and distribution of that prod-uct to its customers,
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Boston Edison's vision of a restructured industry is one in which educated consumers choose freely among competitors for their energy ,
supply and services, in the new environment, the three majcr components of the business will be separated. Electricity generation will become totally deregulated over time. Kilowatts will become a commodity, sold at the market price. All generators and users will have equal access to the transmission system and will pay the same charge to move their products along this "transmis-sion highway." Distribution, or electricity delivery, will still be highly regulated, but distribution com-panies vill have opportunities to offer new product lines and expanded services. Over time, our own distnbution business will develop into a full client / service network. It will offer interactive com-munications with customers that will help them get the best price for their energy and use that energy more efficiently.
Clearly, the industry is moving toward direct access and lower energy costs. Customors wiii first see their bills simplified, showing production and delivery charges separately. These bills will have fewer components and an easier-to-understand format that will help clarify energy usage. As customers learn about the market through these new pncing signals, they will increasingly look for the best encigy market price and related products and ser-vices. Boston Edison will be there to package those retail services for customers.
But there are many issues requiring joint resolution by interested parties before total dereg-ulation can occur. One major issue is stranded cost recovery. Those costs represent investments made to meet regulatory obligations. There are several positive signs that indicate stranded costs will be handled in a fair and equitable way. The Federal Energy
_, Regulatory Commission's actions on transmission access provide for a reasonable opportunity to recover investments, as did the Massachusetts Department of Public Utilities in its August 16,1995, order. In terms ,
3 of Boston Edison's own stranded cost exposure, we
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g utilities. we are not waiting. however, for a final rulin9 on stranded
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the E-Plan, which is the quickest path to <
lower prices and customer choice. Under j
the E-Plan, all customers could choose their energy sup-pliers as early as 1998. However, the E-Plan includes an invaluable transition element. It unbundles utility costs, sets performance incentives for pricing delivery, simu-lates market prices for production, and, perhaps more -
- importantly, educ. 3 consumers. All of this can begin Professor William Hogan is Research in 1997, at least one full year earlier than the start of Director of the Harvard Electricity Policy most other restructuring plans.
Group at the Kennedy school of Beyond all this debate, customers, both large Government, Harvard University. Professor and small, want to know when tangible results will be Hogan, a leading national authority on seen, when prices will drop substantially. Boston industry restructuring. has been a supporter Edison believes competitive prices benefit everyone. It of the company's E-Plan approach.
is important to note that the tread toward lower costs has already begun. In inflation-adjusted terms, Boston Edison customers are paying 25 percent less per kilowatt-hour today than they did in 1981. More significant price changes will be seen in the coming years.
CROSSING THE BRIDGE - BOSTON EDISON'S COMPETITIVE STRATEGY In anticipation of the new competitive model, Boston Edison announced last July the for-mation of Business Units, one month before the DPU announced its plan to restructure the indt'o-try. This is an intemal alignment to the unbundling concept, giving profit and service resporoibilities as well as operational accountabilities to various segments of our business. These segments include Fossil, Nuclear, Customer and Corporate Services.
The company's Organization Future Project, which led to the formation of these Business Units, focused on reducing staffing and management layers, as well as speeding decision making and
, providing quicker customer response. By year-end 1996, we will have 3,400 employees. This is the lowest employment level since 1950, yet we now service twice the customer base and carry more than five times the load we had 45 years ago. Boston Edison's commitment, as with all successfully deregulated companies, is to reduce costs, increase revenues and enhance service simultaneously. Through redefining practices and procedures as well as using new technology, we are meeting this aggressive challenge. We reduced management ranks by nearly 40 percent in 1995, eliminating two management layers, redefining the remaining management positions and reselecting managers based on new skills and competencies.
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l This restructuring will reduce our costs by approximately $30 million a year, and these sav-ings can be applied to reduce our stranded investment exposure while continuing our strong finan-cial performance. Additionally, the restructuring has resulted in an even stronger, more dynamic leadership team.
Boston Edison employees dealt effectively with these dramatic changes. This was the most significant staffing reduction in the company's history. Throughout the process, employees
- demonstrated professionalism, business savvy and concern for the company's future. New work processes, enhanced teamwork and innovative thinking will continue to help us stay ahead of indus-
- try developments.
THE CUSTOMER STORY There is much more to the company's success than just cutting costs. Boston Edison is protecting and growing revenues through enhanced customer focus. We already face competition in several forms, vying with power marketers and other utilities to retain and attract customers.
One way Boston Edison will succeed is to help customers succeed in their respective businesses. We offer much more than a mere commodity to our Customers. We are providing total energy solutions, not only quality energy but value-added services and customized approaches to a customer's individual energy needs.
For example, Boston Edison recently signed a long-term agreement with one of its largest wholesale customers, the Massachusetts Port Authonty (Massport). During the life of this contract, the Authority's electricity use will more than double. Boston Edison provided Massport with a com-petitive orice and services to meet its growing demand. It is this kind of integrated approach that will position us as one of the most responsive, service-oriented energy suppliers in the region -
and the one with the best overall value.
Our track record is impressive. There have been some half dozen major competitive situa-tions in the last few years. We squared off with our competitors - including major utilities in the region - and won every bid.
NEW BUSINESS OPPORTUNITIES e
In addition to retaining and growing a strong customer base, we are also looking at new revenue. Boston Edison already offers an array of new products and services, including power sys-
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tems services, power quality consulting and conservation services. Through the company's unregu-lated subsidiary, Boston Energy Technology Group (BETG), we have had success in the energy ser-vices business with clients in Florida, the Midwest and New England. Coneco, the subsidiary's energy services management company, saw 1995 revenues of $6.2 million, with annual growth pro-jected at more than 50 percent.
BETG also announced recently the formation of a joint venture for district cooling in downtown Boston. The joint venture, Northwind-Boston, with Unicom Thermal Technologies, 4
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CLEAR VISION OF THE FUTURE Boston Edison will continue to help shape the evolving, competitive market and will pursue a leadership role in the development of a cohesive industry restructunng plan for Massachusetts.
Competitors in this new arena will require a different set of skills and attitudes to survive and thrive.
Your company's leadership and employees have what is necessary to succeed end. as yo. ii see throughout the balance of this report, are exercising those skills daily for the benefit of shareholders, customers and the communities we serve.
Our financial performance relative to the rest of the industry is strong. Our internal struc-ture, dedicated employees and external influence will guide our success in the restructured industry.
Boston Edison is crossing the threshold, not with misgivings but rather with complete confidence.
Thomas J. May
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Chairman, President and Chief Executive Officer 8
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i Industrial and Manufacturing Whde Boston Edison's industrial base is relatively small, amounting to about 12 percent of retad sales, its associated manufactunng jobs are valuable to the region Despite the manufacturing decline in recent years, there are success stones and your company has played a part in many of them.
In tandem with substantial State efforts to provide incentives for manufactunng in Massachusetts, Boston Edison's own economic development etforts resulted in 28 megawatts of new and retained load, representing more than $6 million in annual base rev- .g, enue. These results were recently recognized when Chairman, President and CEO Tom May .
was named Chairman of the Governor's Councd on Economic Growth and Technology. s .
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EMC Corporation l
As a manufacturer of data storage devices, Hopkinton-based EMC Corporation has enjoyed record sales and has been the fastest growing company in Massachusetts two years running. EMC recently sur-
. passed IBM for the No.1 position in the mainframe storage market, just five years after they entered that market, making it a challenge to keep pace with burgeoning demand.
EMC also is an industry leader in quality control. Every unit they produce undergoes rigorous testing before it is shipped to a client.
EMC's rapid growth and demand for product quahty are where Boston Edison enters the picture. Sensitive testing equipment requires much more than just an on/off switch for electricity. Even a small power dip is a serious power quality irue at EMC because their product is continuously tested in a 21-day cycle. That means EMC sets very high expectations for their energy supplier.
The EMC/ Boston Edison partnership goes back to 1990. We have installed ice storage, lighting and cooling equipment at EMC as part of our Energy Efficiency Partnership. EMC also benefited from an Economic Development Rate for load expansion within our service territory.
Working in tandem with EMC, we ensure that the quality of our product enhances the quality of theirS. To do that, we had to first under-stand the specific needs of this fast-growing, highly-successful company.
Currently a 9-megawatt customer EMC's rapid expansion will increase their load by 100 percent over the next five years. Both Boston Edison and EMC recognized that, to meet this growth, the delivery system in the area needed to be upgraded. To that end, Boston Edison, EMC and the town of Hopkinton are cooperating to fast-track construction of a new substation.
Instead of the normal four to five years from concept to operation, this new substation will be completed in just two years. Additionally, dedicated circuits were run to EMC's main facility to ensure greater reliabikty and better overall power quality for this valued customer.
" Boston Edison has been committed to making all improve-ments necessary to supply EMC reliably," said EMC's Director of Corporate Facilities Dan Fitzgerald. " Boston Edison's electric customer service and engineering staff undertook a remarkable effort in constructing dedicated and back-up supplies to our main manu-facturing facility. This will solidify our partnership and ensure our mutual success."
As EMC's business continues to grow and evolve, Boston Edison will be there, listen-ing and responding. We will work to understand this customer's changing needs, to apply our l expertise in solving their energy problems and to offer innovative energy-related services that will enhance their business operations 7
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Commercial and Governmen? The commercial sector, which includes government customers, remains the comerstone of the company's business, representing over 59 per-cent of retail sales. The area's economy showed slow but sustained growth in 1995. That was especially noticeable in the improving occupancy rates of commercial buildings. For the first time in several years, new commercialprojects were announced. High technology and financial services companies continued to add employees despite cutbacks in the health and banking sectors.
The company works with commercial /govemment customers to tailor solutions and meet their unique needs.
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l Massport's Steve Tocco at Logan international Airport.
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Massport l
The Massachusetts Port Authority (Massport) is one of Boston Edison's largest and most valued wholesale customers. As the operator of Boston's Logan Airport and four other locations, Massport has vast electrical energy needs, with a current load of 25 megawatts that is expected to more than double over the next decade. Massport decided last year to test the competitive waters for suppliers. Boston Edison was involved with each new option Massport explored, providing innovative ideas to meet their energy issues.
Boston Edison recently reached a ten-year agreement with Massport after fierce competition with ten other suppliers. The long-term agreement between Boston Edison and Massport will bring the Port Authority into the 21st century, with energy efficiency measures and operational improvements. More pre-dictable, stable energy prices were negotiated in recognition of the significant growth Massport will experience.
With increased competition in the electric power industry. Massport anticipated that this was the proper time to lock in savings through a long-term contract. The agreernent is an acknowledgment of the Authority's huge demand for electricity and Boston Edison's desire to forge a relationship that will endure in the emerging energy marketplace.
"We selected Boston Edison from a pool of 11 proposals from major utilities - some as far away as Texas," said Massport Executive Director Stephen P. Tocco. "But when Massport evaluated the proposals according to price, experience in the power generating market and quakty of generating capacity, Boston Edison's proposal was determined to be the best fc: the Authority. We are ecstatic to be staying with Boston Edison, a local company which has served the Authority's needs hr many years."
Also under this agreement, Massport and Boston Edison VHil expand their pilot program for using electric vehicles (EVs) at Logan, with plans to make the airprt an EV showcase.
Boston Edison also will provide a comprehensive package of energy efficiency mea-sures at Massport, including switchgear maintenance services and the installation of efficient electric chillers to replace existing steam absorbers throughout the Massport system.
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A source of great pride to the City of Boston, FleetCenter opened in grand style last September. This 775,000-square-foot sports and enter-tainment complex puts an emphasis on spectator comfort and overall efficiency. Boston Edison played a key role in FleetCenter's design by installing energy-efficient technologies expected to cut energy costs by about $60,000 a year.
3 High-efficiency chillers, motors and lighting along with variable speed drives on all major air handling equipment will reduce the facility's annual consumption by over 620,000 kilowatt-hours. All these measures contribute greatly to the comfort and enjoyment of spectators.
While the Boston Garden was an historic landmark, it was the oldest operating facility of its kind in the country. No longer will fans have to endure sweltering temperatures at a Celtics game or fog on the ice at a Bruins game.
The new FleetCenter arena is a year-round facihty that can attract summer sporting and enter-tainment events as well as large conventions and corporate meetings. Its appeal is due, in large part, to proper cooling systems.
Edison engineers worked with developers to incorporate upgrades into the overall design and worked with an aggressive schedule, completing the work on time and within budget. With a 4- to 5-megawatt load at the arena, the upgrades will go a long way toward keeping costs under control.
"The quality of the relationship with Boston Edison is first-rate," says FleetCenter Vice President of Operations Chris Maher. "I can call our Edison representative anytime to get help with cost estimating and budget preparation. They are introducing new ideas for better cost control all the time. Boston Eaison is a resource for any energy problem we encounter and we look to them for professional solutions."
FleetCenter is indeed a showplace with superior acoustics, unobstructed views, a state-of-the-art Jumt<oTro 1 scoreboard and, of course, cutting-edge lighting and chmate control.
Add to that a host of other amenities, and you have a world-class facility.
. U. S. Olympic Gymnastic Trials are coming to FleetCenter in June, an event that was made possible by having a four-season facility. While the Boston Garden will hold fond memories of such legends as Bill Russell, Bobby Orr, Larry Bird and Johnny Most, FleetCenter will soon have its own legends. Boston Edison is proud to be part of it.
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! Residential / Community Residential customers are clearly stakeholders, i
} but so, too, are the communities we serve and in which we operate. Boston l Ed: son will continue to have a very large stake in the communities. The atti-tudes of residential customers, who account for about 28 percent of retail sales, and the company's relationship with communities are equally important to us.
Listening, understanding and responsiveness are the attnbutes which allow a company to meet the needs of residentral customers and community leaders To this group, we add our small commercial customers, especially those who work and live in the neighborhoods we service.
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pp"' Mary Muhey Jacobson represents the con-([asN y? , cerns of the West Rosbury business commu-j 7 p 4 .g Il t the West Roxbury Pub and U ',h Restaurant, a cornerstone establishment in
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lohn O'Neill of the Consumer Adsisory Panel visits Boston Edison's Meter Test Lab. *
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Consumer Advisory Panel l
Boston Edison's Consumer Advisory Panel serves as a focus group for customer-related ideas and concerns. John O'Neill serves in his fourth year on the panel and is currently co-chair.
"It's a great feeling to know you're having meaningfulinput on behalf of hundreds of thousands of customers," he said. "The panel can talk to Boston Edison man-agement at the top levels and get results."
The Consumer Advisory Panel provides feedback and guidance from a consumer stand-point on several key issues, including industry deregulation, system modernization, energy effi-ciency and environmental concerns. Additionally, the panel has monitored calls in Boston Edison's Customer Call Center. "The panel is impressed with the response to customer inquiries," O'Neilladded. " Edison representatives use a concerned and caring approach with customers and work to thoroughly resolve problems."
But the single largest issue for the Consumer Advisory Panel has been accurate meter reading. " Meter reading is, by far, the issue of most importance to residential customers,"
O'Neill stressed, and he should know. Aside from serving as the panel's co-chair, he is also CEO/ Executive Director for Somerville-Cambridge Elder Services.
" Clarity and accuracy of bills is important, not only to residential customers in general, but, in particular, to elderly customers. Some of my constituents would go without a meal in order to pay all their bills."
Boston Edison took that feedback seriously and is accelerating its automated meter reading strategy. Within the next 18 months, 260,000, or ove.r one-third of Boston Edison's l meters, will be replaced with automated meter devices, providing eformation from previously inaccessible meters. Soon to follow will be sophisticated customer devices capable of interac-tive, two-way communications.
These new technologies will result in more predictable, accurate bills. More importantly, they will improve energy management and create opportunities for new products and services.
West Roxbury l
The center of West Roxbury is a booming commercial area with a full spectrum of small businesses operating there. As President of the West Roxbury Business and Professional Association, Mary Mulvey Jacobson represents the concerns of more than 250 small businesses and commercial property owners. Mulvey Jacobson helped Boston Edison enhance its relation-ship with the business community to ensure greater reliability for this growing commercial area.
Chief among these efforts was the development of a system upgrade plan that coordi-nated planned outages in the area for minimum impact on business owners.
"I was bowled over by the sensitivity of Edison's plan," said Mulvey Jacobson. "It showed that they were listening."
Boston Edison recently joined the West Roxbury Business and Professional Association, adding to its involvement in civic and business groups.
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Marie Theodat (left) and Marie-Rose Romain Murphy of Codman Square Main Street join Boston Mayor Thomas Menino to survey the restoration of some spectacular neighborhood architecture. Formerly a public library, the building houses the Codman Square Health Center's executive offices as well as an event center and community youth program.
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Main Street Boston Edison is an active participant in the City of Boston's Main Street program, an effort to improve Boston's neighborhood commercial districts.
This $4.2 million initiative is the largest, most all-encompassing of its kind in the country, offer-l
. ing assistance to more than 20 Boston communities. Boston Main Street is an innovative pro-gram that brings together resources from the Federal government, the City of Boston and local corporations to assist neighborhood commercial areas in their revitalization efforts. As a
" Corporate Buddy," Boston Edison is working with Codman Square Main Street on the growth and economic development of that community.
Nationally, the concept has been implemented in more than 1,000 small communi-ties and city neighborhoods What differentiates Boston's initiative is its city-wide implementation in a large urban area - a national first.
As a city councilor, Boston Mayor Thomas Menino was instrumental in bringing the program into his own Roslindale neighborhood a decade ago and has worked to expand the concept into a signature revitalization project. "As the neighborhood business goes, so goes the neighborhood," he said.
Boston Edison is one of several corporations awarding a $40,000 grant to its sponsor area. With that money, Codman Square Main Street hired an executive director and began a comprehensive marketing and economic improvement strategy.
" Boston Edison's commitment goes above and beyond financial support," says Marie-Rose Romain Murphy, executive director for Codman Square Main Street Inc. "We are thrilled with their willingness to provide us access to their resources such as technical assistance and in-kind services. Working with Edison will be key to the success of our organization and, ultimately, to Codman Square's growth and development."
Individuals representing the different sectors of the community comprise the Main Street Board, including merchants, residents, commercial property owners and local non-profit organizations. This group controls resources provided by the city and has helped to recruit 35 new businesses into the area. They also plan aggressive retail promotion as well as community
. festivals and events to draw potential customers to the area.
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Financial Section Contents Company Highlights ------------------------------------17 Management's Discussion and Analysis - - - - - - - - - - - - - - - - -----18 ,
Consolidated Statements of Income - - - - - - - - - - - - - - - - - - - -----25 Consolidated Statements of Retained Earnings ---- -- -------- - - 25 Consolidated Balance Sheets - - - - - - - - - - - - - - - - - - - -- - - - -----26 Consolidated Statements of Cash Flows - - - - - - - - - - - - - - - - - - - - - 27 Notes to Consolidated Financial Statements - - - - - - - - - - - - - -----28 Report of Independent Accountants - - - - - - - - - - - - - - - - - - - -----42 Selected Consolidated Quarterly Financial Data (Unaudited) - -----43 Selected Quarterly Stock Data - - - - - - - - - - - - - - - - - - - - - - -----43 Selected Consolidated Operating Statistics (Unaudited) ---------- 44 Selected Consolidated Sales Statistics (Unaudited) - - - - - - - - -----45 Selected Consolidated Financial Statistics (Unaudited) ----------- 46 O f ficers and Directors - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 47 Important Shareholder Information - - - - - - - - - - - - - - - - - -- - -----48 muunnammsm_
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Company Highlights Dividends Paid Per Share Earnings Per Share Excluding Restructuring Increased on a percentage basis by more Continues to show steady increase.1995 than industry average in each of the past amount excludes a $0.44 restructuring charge.
five years.
$2.00 $2.60
$2.40 _ y
$2.20 5
?
=
$2.00 2;
$1.60 8 h $1.80 I
$1.40
$1.40
$1.20 $1.20 1991 1992 1993 1994 1995 1996 proforma l1991 19"2 1993 1994 1995 l Number of Employees Retail Sales Mix Decreased 10.8%, in line with our plans Stabilized by the commercial and residential to pare down to 3,400 employees by sectors that help minimize effects of regional year-end 1996. economic swings.
4800 AMH)
Commercial Residential 4400 59.2 % _ 27.8 %
~
E 4200 Industrial
& Other 13.0%
3600
?
~
3400 1991 1992 1993 1994 1995 17 I
retail base rate increase effective November 1994, the ending !
Man gement's Discussion and Analysis of amonization of deferred cancelled nuclear costs in 19c4, a 1.2% increase in retail kWh sales and lower revenue reserve !
Rate Regulation provisions. These positive impacts were partially offset by higher income tax, property tax, nuclear outage amortization The rates we charge our retail customers are regulated by our and employee benefit expenses, and an award received on an nate regulators, the Massachusetts Depanment of Pubh.c .
eminent doma.m case m 1994.
Utilities (DPU). In 1992 the DPU approved a three-year set- l tlement agreement effective November 1992. This agreement Operating revenues provided us with retail rate increases, allowed for the recovery Operaung revenues increased 5.4% over 1994 as follows: .
of demand side management (DSM) conservation program costs, specified certain accounting adjustments and clarified fi" 'h "'*"d')
Retail electric revenues $59,419 the timing and recognition of certain expenses. The agree- ,
Demand side management revenues 8,783 ment also set a limit on our ra:e of return on common equity Wholesale and other revenues 11,126 of 11.75% for 1993 through 1995, excluding any penalties or Short-term sales revenues 4,440 rewards from performance incentives.
Increase in operating revenues $83,768 The retail rate increases consisted of two annual base rate increasts of $29 million effective November 1993 and Retail electric revenues increased $59 milh.on.
November c_N4 and an annual performance adjustment .
. Approximately $28 milh.on of the m. creased revenues was due charge efTectiv.: November 1992 through October 2000. The to the November 1994 base rate increase and approximately performance adjustment charge varies annually based on the
. . . $11 m.dlion was due to the increase in retail kWh sales. Fuel performance of Pilgn.m Nuclear Power Stanon. This charge is
. and purchased power revenues m. creased $11 m.d lion as a funher descn. bed .m the Electnc Sales and Revenues section. .
In addm. .on to the retail rate increases, our results of result of the a.rmng effect of fuel and purchased power cost recovery. Honver, these higher revenues are offset by higher operations were afTected by the recovery of D. SM program
. fuel and purchased power expenses and have no net efTect on costs, accounting adjustments and the n.mmg and recognition earnings. Performance revenues, which vary annually based of certain expenses as further descn. bed m. the follow.mg . .
on the operating performance of Pilgrim Stanon, mcreased $9 Results of Operations section. . .
md. lion primarily due to a higher performance rate effective m We did not make a base rate fding upon the exp.ira-
. 1995 and a 17% increase in generation.
non of the 1992 settlement agreement, therefore base rates A new annual conservation charge for recovery of currendy remain in effect at the.ir 1995 levels.
demand side management program costs was implemented m.
in February 1996 we filed an m. dustry restructuring .
February 1995. Under this charge all 1995 program costs plan wn. h the DPU in response to its August 1995 order on
. . . were recovered .m 1995. Th.is resulted in higher DSM rev-restructuring the electnc unh.ty mdustry. 'I.h.is plan is expect-enues and expenses than in prior years when certain program ed to lead to negotiations with intervening parties that wd. l costs were capitalized for recovery over six years.
result in an unbundling of our currendy integrated monopoly
. The net increase in wholesale and other revenurs .is business imo a separate competitive electnc production bus.i- . .
. . pnmanly due to a $10 million decrease in revenue reserve pra-ness and a regulated electnc d.istnbun.on business. Refer to ..
visions, which are primarily related to wholesale customer con-Outlook for the F.uture for further m. forman.on regard.mg the
. . . . tract issues.
restructuring of the electnc unh.ty mdustry m Massachusetts.
The increase in short-term sales revenues is due to higher short-term sales resulting from higher generating avail-Results of Operations
- ability in 1995. Revenues from short-term sales serve to 1995 versus 1994 reduce fuel and purchased power billings to retail customers and therefore have no net effect on earnings. . I Earnings per common share were $2.08 in 1995 and $2.41 in 1994. Earnings in 1995 reflect a one-time charge of $34 mil- .
l lion ($20.7 million net of tax, or 50.44 per share) associated
""" N ""
with our corporate restructuring. The charge reflects the costs Total fuel and purchased power expenses increased $22 mil-of early retirement and severance programs implemented as lion primarily due to the timing effect of fuel and purchased part of our organizational nreamlining and reorganization p wer cost collection. Excluding the timing effect, fuel into business units. Exctding the one-time charge, carnings expense increased 5% due to an 8% increase in fossil station per common share we;c $2.52 in 1995, an increase of 4.6% generation while purchased power expense was unchanged.
over 1994. This iocreas:is due to the $29 million annual Fuel and purchased power expenses are substantially all recov. )
etable through fuel and purchased power revenues.
18 l
Other operatior s and maintenance expense increased Intervir charges 0.9% over 1994. Employee benefit expenses increased pri- Interest charges on long-term debt increased due to a $125 marily due to higher pestretirement benefit expenses recorded million debentures issuance in May 1995, partially offset by in accordance with the 1992 settlement agreement. We also interest savings from first mortgage bond and debenture incurred higher administrative costs in positioning the com- redemptions in 1994. Other interest charges increased slightly pany for changes in the industry, which were offset by lower due to higher short-term interest rates partially offset by a operating costs in the electric delivery business. Electric gen- lower average short-term debt level. Allowance for borrowed eration costs increased only 1% in 1995, primarily due to a funds used during construction (AFUDC), which represents refueling and maintenance outage at Pilgrim Station. the financing costs of construction, decreased due to a lower
. The $34 million one-time restructuring charge was construction work in progress balance and shorter construction incurred over the third and fourth quarters of 1995 as a result periods, partially offset by a higher AFUDC rate related to the of our corporate reorganization announced in July 1995. As higher short-term interest rates.
part of the reorganization 330 employees elected to retire imder enhanced retirement programs and 149 employees 1994 versus 1993 whose positions were eliminated became eligible for benefits Earnings per common share were $2.41 in 1994 and $2.28 under a special severance program. See Note F to the in 1993. The increase in earnings was primarily the result Consolidated Financial Statements for additional information.
of the expiration of a long-term purchased power contract in We expect to achieve ongoing savings as a result of the restruc-October 1993, a $29 million annual retail base rate increase turing, with a payback period of appmximately one year.
effective November 1993, a 2.0% increase in retail kWh Depreciation and amortization expense increased due sales and an award relating to an eminent domain case, to a higher average depreciable plant balance.
These positive changes were partially offset by higher opera-In 1994 we fully expensed the remaining deferred tions and maintenance, depreciation and amortization and costs of the cancelled Pi(dm 2 nuclear unit. income tax expenses.
In the third quarter of 1995 we changed the amorti-zation period ofdeferred nuclear outage costs to two years Operating revenues from five years as discussed in Note B to the Consolidated Operating revenues increased 4.2% over 1993 as follows:
F.mancial Statements. The remaining $9 milh.on of deferred (in thousands) costs allocable to retail customers for refueling outages per- .
Retad electric revenues $62,945 formed m . 1991 and 1993 was written off. Approx.imately $15 Demand side management revenues 5,056 mdlion of deferred costs from the 1995 refueling outage is Wholesale and other revenues (6,644) be.ing amomzed over two years.
Short-term sales revenues 1,219
,The increase in demand side management programs increase in operating revenues $62,576 expense is related to the increase in DSM revenues.
Beginning with the annual conservation charge implemented Retail electric revenues increased $63 million. The in February 1995, DSM costs are recovered and expensed pri-November 1993 and 1994 base rate increases resulted in $29 marily in the year incurred. The 1995 expense includes $31 million of the increased revenues, and approximately $6 mil-million of 1995 program costs and $14 million of amortiza-lion was due to the 2% increase in retail kWh sales. Fuel and tion of costs capitalized in 1992 through 1994.
purchased power revenues increased $28 million primarily Property and other taxes increased primarily due r due to the recovery of certain new purchased power expenses.
higher Boston property taxes resulung from capital addmons.
In accordance with the 1992 settlement agreement, specific Our effective annual income tax rate for 1995 was revenues related to the purchased power contract that expired 37.1% vs. 31.4% for 1994. The higher rate is the result of a in October 1993 were not affected.
$10 million adjustment to deferred income taxes made in Wholesale and other revenues decreased primarily 1994 in accordance with the 1992 settlement agreement.
due to an $8.5 million increase ir. revenue reserve provisions Other s,ncome in 1994 related to certain wholesale customer contract issues.
The net decrease in other income is primarily due to a $5.7 Operating ,xpen,,,
million gain recognized in 1994 from a court ruling on a Total fuel and purchased power expenses decreased $27 mil-1989 eminent domain taking of certain of our property.
lion. Fuel expense decreased partly due to lower fossil fuel prices and a 12% decrease in nuclear output. Purchased power expense reflects lower costs associated with the long-term contract that expired in October 1993, partially offset by the costs of new contracts. The timing effect of fuel and pur-19
chased power cost collection also contributed to the decrease Electric Sales and Revenues in fuel and purchased power expenses.
Other operations and maintenance expense increased 11ectric sales 7.4% primarily due to higher employee benefit expenses. Retail kWh sales increased 1.2% in 1995 primarily due to Pension expense increased $20 million due to a higher contri- the positive effects of a stronger economy on commercial ;
bution made to the pension plan for the year. In accordance customers. This sector represents approximately 50% of our with the 1992 settlement agreement, we recorded pension electric operating revenues.
expense in the amount of the contribution to the plan. Demand side management conservation programs are Depreciation and amortization expense increased pri- designed to assist customers in reducing electricity use and, marily due to a higher depreciable plant balance. therefme, result in lower growth in electricity sales. We receive .
In 1994 we fully expensed the remaining deferred approval from our state regulators for DShi spending levels costs o' the cancelled Pilgrim 2 nuclear unit. In accordance and recovery amounts through an annual conservation charge.
with .ne 1992 settlement agreement we did not expense any Through 1994 we collected from customers certain DShi pro-of these costs in 1993. gram costs primarily in the year incurred and other DShi pro-Amortization of deferred nuclear outage costs in gram costs over a six-year period. In 1995 a new annual con-1994 and 1993 consists of amounts related to the 1993 and servation charge was implemented under which all 1995 pro-1991 refueling outages at Pilgrim Station. In 1993 we gram costs were recovered in 1995. We are also provided with deferred approximately $14 million of refueling outage costs. incentives and recovery oflost revenues based on the actual We began to amortize these costs in June 1993 over Ove years reduction in customer electricity usage from these programs as approved in the 1992 settlement agreement. and a return on the costs that we are recovering over six years.
The $2 million decrease in demand side manage-ment programs expense was due to the timing of recovery of Electric revenues program costs. DShi expense includes some program costs As discussed in the Rate Regulation section, our 1992 settle-recovered over twelve months and other program costs recov- ment agreement provided us with two annual retail base rate cred over six years. The 1994 expense consists of $22 million increases of $29 million efTective in 1993 and 1994 and an of costs primarily related to 1994 expenditures and $13 mil- eight-year annual performance adjustment charge. We did lion of costs capitalized in 1992 through 1994. not make a base rate filing upon the expiration of the settle-hiunicipal property and other taxes increased primar- ment agreement in 1995, therefore base rates currently remain ily as a result of higher Boston property taxes due to a tax rate in effect at their 1995 levels. Due to our continued commit-increase and capital additions. ment to controlling costs and increasing operating ef6ciencies.
Our elTective annual income tax rate for 1994 was maintaining these rate levels in our current regulatory envi-31.4% vs. 23.4% for 1993. Both rates were reduced from the ronment is not expected to signiAcantly affect our Gnancial statutory rate by adjustments to deferred income taxes of $10 condition or results of operations.
million in 1994 and $20 million in 1993 made in accordance The annual performance adjustment charge provides with the 1992 settlement agreement. us with opportunities to improve our Gnancial results. The most significant potemial impact of this performance incen-Othe s,nuinn-tive is based on Pilgrim Station's annual capacity factor. An In November 1994 a court ruling became effective providing annual capacity factor between 60% and 68% would provide us with an additional $5.7 million gain on a 1989 cminent us with approximately $51 million of revenues in the perfor-domain taking of certain of our property. mance year ended October 1996. For each percentage point increase in capacity factor above 68%, annual reven aes will Interns chargn increase by approximately $750,000. For each percentage Totalinterest charges did not change significantly. Interest point decrease in capacity factor below 60% (to a minimum charges on long-term debt decreased due to the first mortgage of 35%), annual revenues will decrease by approximately -
bond and debenture redemptions in 1994 and the significant $840,000. Pilgrim's capacity factor for the performance year first mortgage bond refinancing in 1993 at lower interest ending October 1996 is currently expected to be approxi-rates. This decrease was partially offset by higher amortiza- mately 91%, an increase from the 67% capacity factor tion of redemption premiums. Other interest charges achieved in the performance year ended October 1995.
increased due to higher short-term interest rates partially off. There are no major outages scheduled for the current perfor-set by a lower average short-term debt level. AFUDC mance year. Pilgrim was out of service in November 1994 increased as a result of a higher AFUDC rate related to the and for a 73-day refueling and maintenance outage in 1995.
higher short-term interest rates. We earned approximately $49 million in revenues related to Pilgrim's capacity factor in the performance year ended October 31,1995.
- o
Pilgrim Station was shut dawn for three months in increased competition from other electric utilities and nonu-1994 due to a non-nuclear problem with its electrical genera- tility generators to sell electricity for resale, we secured long-tor. Regularly scheduled maintenance work was also per- term power supply agreements with our six wholesale cus-formed during the shutdown. The power needs usually met romers that ser rates through 2002 and beyond. In 1995, our by the station were met by other generating plants or pur- largest retail customer, the hiassachusetts Port Authority chased from other suppliers as necessary. W- do not believe (hiassport), issued a request for proposals for a wholesale sup-that the generator damage resulted fmm actions within our plier of electricity. We successfully retained Massport as a cus-control. Our recovery of the incremental purchased power tomer through a ten-year wholesale power supply agreement costs during the outage through fuel and purchased power rev- effective November 1995. We are awaiting approval of this enues, however, is subject to review by the DPU under a gen- agreement from the FERC.
crating unit performance program. In March 1995 the FERC issued a Notice of Proposed Rulemaking (NOPR) addressing open transmission Liquidity access and recovery of previously incurred costs. If approved, We meet our capital expenditure cash requirements primarily the NOPR would require all utilities with transmission sys-with internally generated funds. These funds provided for tems to fde open access tariffs at the FERC, to provide service 95%,98% and 77% of our plant and nuclear fuel expenditures under those tariffs to transmission customers comparable to in 1995,1994 and 1993, respectively. Our current estimate of service provided to their electric energy customers and to take plant expenditures for 1996 is $160 million. These expendi. service under the tariffs for wholesale purchases and sales. The tures will be used primarily to maintain and improve existing NOPR also supports the full recovery oflegitimate and verifi-transmission and distribution facilities. We expect plant expen. able costs previously incurred under federal and state regula-ditures to remain level or decline slightly from the 1996 tion. The provisions in the NOPR provide a framework for amount in the four years thereafter. In addition to capital significant changes in the electric utility industry.
expenditures we have long-term debt and preferred stock pay. We have also been experiencing increased competition ment requirements of $103.6 million per year in 1996 through in the retail electric market. Competition currently exists with 1998, $3.6 million in 1999 and $168.6 million in 2000, ahernative fuel suppliers as customers are able to substitute nat-External financings continue to be necessary to sup. ural gas, steam or oil for electricity for heating or cooling pur-plement our internally generated funds, primarily through the poses. In addition, industrial and large commercial customers issuance of short-term commercial paper and bank borrow. may pursue options to generate their own electric power or fac-ings. We currently have authority from our federal regulators, tor the cost of electricity into their decisions to relocate to new the Federal Energy Regulatory Commission (FERC), to issue service territories. Electric utilities are thus under increasing up to $350 million of short-term debt. We have a $200 mil- Pressure from these customers to discount rates.
lion revolving credit agreement and arrangements with several in August 1995 the DPU issued an order on restruc-banks to provide additional short-term credit on a committed turing of the electric utility industry. The order provides for as well as on an uncommitted and as available basis. At Massachusetts-based electric utilities to restructure their opera-December 31,1995, we had $126 million of short-term debt tions to encourage more competition for customers. It also outstanding, none of which was incurred under the revolving includes the following principles for a restructured electric credit agreement. In 1994 the DPU approved our financing industry:
plan to issue up to $500 million of securities through 1996 provide the broadest possible customer choice a
using the proceeds to refinance short and long-term securities provide all customers with an opportunity to share in and for capital expenditures. Refer to Notes J and K to the the benefits ofincreased competition Consolidated Financial Statements for specific information ensure full and fair competition in generation markets relating to our recent financing activities.
functionally separate generation, transmission and dis-tribution services a
Outlook for the Future provide universal service a
support and further the goals of environmental Competition regulation Competitive pressures on the electric utility industry have rely on incentive regulation where a fully competitive increased due to a variety of factors, including legislative and market cannot exist, or does not yet exist regulatory proceedings at both federal and state levels and The DPU order also set the following principles to guide the changes in customer expectations. The trend is toward promo- transition from a regulated to a competitive industry structure:
tion ofincreased competition through modified regulation of honor existing commitments
- unbundle rates for generation, transmission and the industry.
L date the effects of competition have been most distribution prominent in the wholesale electric market. In response to
- reduce rates in the near term 21
maintain demand side management programs the economic development rates, the lower manufacturing cus-ensure an orderly and quick transition that minimizes tomer rates or the pilot program to have a significant impact on customer confusion our fmancial condition or results of operations.
The order provides a reasonable opportunity for the in the rate-regulated environment based on cost recovery of net, nonmitigatable potentially strandable costs recovery that we have traditionally operated in, we are subject (strandable costs), over a period of up to ten years. These to certain accounting standards that are not applicable to costs include investments in plant that might not be recover- other businesses and industries. The standards allow us to able in a competitive market, liabilities for future decommis- record certain costs as regulatory assets instead of as expenses sioning of nuclear plants, the amounts by which certain pur- when incurred when we expect to receive future rate recovery chase power contracts exceed the competitive price for genera- of the costs. We believe that we currently meet the criteria of ,
tion, and prudently incurred regulatory assets. We are look- these standards. In addition to the specifically identified reg-ing at possibilities for mitigating our potentially strandable ulatory assets on our consolidated balance sheets, there may ;
costs, including potential revisions to depreciation and amor- be differences in the carrying value of our net utility plant tization periods. compared to what the amount would have been if we were The order establishes only general principles for the not subject to rate regulation. These potential differences l transition to a competitive market and does not establish a would be due to differing plant depreciable lives for regulato- I particular model for the new industry structure. Each of the ry and non-regulatory accounting standards. We have not yet Massachusetts-based electric utilities is required to develop a fully determined to what extent such differences may exist.
plan for moving toward competition consistent with the The effects of competition and modified regulation could, in DPU's order and encouraged to negotiate with all interested the near term, cause us to no longer meet the criteria for parties while doing so. We were one of three companies application of the regulatory accounting standards for some of required to file a restructuring plan in February 1996. Our our operations. Should this occur we would have to take a ,
plan is consistent with the general principles outlined in the noncash write-off of our affected regulatory assets and adjust j order, including unbundled rates for generation, transmission our affected plant balances if necessary by recording an addi- l and di>tribution, it provides for and is based upon full recov- tion to depreciation expense at that time. However, the DPU ery of strandable costs through a nonbypassable access charge. order on industry restructuring provides a reasonable oppor-This charge is to be paid by customers as a condition of tunity for recovery of these previously incurred costs, which receiving service over our distribution system, wn' ich remains are also provided for in our related plan. We expect to recov-a monopoly ftmetion. We expect to enter into negotiations er all strandable costs through our distribution system, which with intervening parties that will result in new rates and per- we expect will remain rate-regulated, and therefore will contin- I formance incentives to be implemented in the new industry ue to nieet the criteria of these accounting standards. Ifit does structure. not continue to bc likely that we will recover all our regulatory In addition to our involvement in the DPU's restruc- assets and generating plant costs as our restructuring plan is
- turing proceedings, we are actively responding to the current ultimately finalized, we would have to write off such portions and anticipated changes in the industry in several ways. In 1995 that are no longer probable of recovery in accordance with we reorganized the company into separate business units in Financial Accounting Standards No.121, Accounting for the order to strengthen our competitiveness. These business units, impairment of Long-Lived Assets and for long-Lived Assets to l Customer, Generating-Fossil, Generating-Nuclear and be Disposed Of. See Note M to the Consolidated Financial Corporate Services, were designed to sharpen management focus Statements for information on this new accounting standard.
- along our significant lines of operation while maintaining com- The nonrecovery of specifically identified and other embedded I pany-wide strategic goals. As a result of enhanced retirement regulatory assets or plant costs could have a material impact on programs and a special severance program offered during this our results of operations and financial condition.
corporate restructuring, we reduced our workforce by 12% We expect to achieve ongoing savings as a result of the restructuring, Resource regulation ,
with a payback period of approximately one year. We also con- In this period of transition in the electric utility industry we tinued to develop customer alliances and provided economic remain subject to current regulatory requirements. The DPU development rates to some customers. In addition, we currently requires utilities to purchase power from qualifying nonutility i have a special lower rate available for a small number oflarge generators at prices set through a bidding process. In a con-manufacturing customers on a limited basis and we recently tinuation of a dispute which originated in 1991, the DPU is implemented a one-year pilot program that uses a competitive currently investigating whether we should again be ordered to market index to set electric rates for a limited number of cus- negotiate a contract to purchase power from an independent tomers. These actions all signify our commitment to be a com- power producer, JMC Altresco, Inc. We have consistently petitively priced, reliable provider ofenergy. We do not expect opposed this order since we do not believe we need any new 22
, A.,L-- - ..- 1 A.> 1 --
power for several years and the proposed contract would also continue to face possible liability as a potentially respun-impose excessive costs on our customers. In 1995 we fded a sible party in the cleanup of approximately ten multi-party motion to dismiss the matter, which is pending. We also filed hazardous waste sites in Massachusetts and other states where testimony comparing the cost of Altresco to projected market we are alleged to have generated, transported or disposed of costs and hearings are currently ongoing. In a separate but relat. hazardous waste at the sites. At the majority of these sites we ed matter, we appealed the Massachusetts Energy Facilities are one of many potentially responsible parties and we cur.
Siting Board's (EFSB) approval of construction of Altresco's pro- rently expect to have only a small percentage of the potential
- posed generating station based partly on the EFSB's failure to liability. Through December 31,1995, we have accrued
! consider market information and forecasts. approximately $7 million related to our cleanup liabilities.
. We also currently remain subject to the DPU's inte- We are unable to fully determine a range of reasonably possi-grated resource management (IRM) process in which electric ble cleanup costs in excess of the accrued amount, although utilities forecast their future energy needs and propose how based on our assessments of the specific site circumstances, we l they will meet those needs by balancing conservation pro- do not expect any such additional costs to have a material grams with all other supplies of energy. As a result of our impact on our Gnancial condition. However, additional pro-19941RM filing, the DPU found that we did not have a need visions for cleanup costs that may result from a change in esti-for additional generating capacity through 2001 and therefore mates could have a material impact on the results of a report-( were not required to issue a competitive request for proposals ing period in the near term.
! for new generating capacity. Required updates to our IRM Uncertainties continue to exist with respect to the fding have been postponed due to the current industry disposal of both spent nuclear fuel and low-level radioactive
! restructuring proceedings ongoing at the DPU. waste (LLW) resulting from the operation of Pilgrim Station.
The United States Department of Energy (DOE) is responsi-Nonutility business ble for the ultimate disposal of spent nuclear fueh however, We have an unregulated subsidiary, Boston Energy there are uncertainties regarding the DOE's schedule of l Technology Group (BETG), in which we have authority from acceptance of spent fuel for disposal. In 1995 we regained the DPU to invest up to $45 million. This wholly owned access to the LLW disposal facility located in Barnwell, South !
l subsidiary engages primarily in energy conservation services Carolina. Refer to Note E to the Consolidated Financial l and the production of water treatment systems. In 1996 Statements for further discussion regarding spent nuclear fuel j BETG entered into a joint venture to build a series ofice. and LLW disposal. !
based cooling systems as an alternative to costly chemical sys- As part of a 1991 DEP consent order, we are cur-tems. BETG's investment in this joint venture, Northwind rently required to fuel New Boston Station exclusively by i Boston, is not material. natural gas, except in certain emergency circumstances. The We do not currently have a substantial investment in station has the ability to burn natural gas, oil or both. We l BETG and do not anticipate it signiGcantly impacting our have arrangements for a firm supply of natural gas to run results of operations in the next several years. the station at a minimum level and are developing a least-cost plan for operating beyond this minimum level which Oth:r Matters principally utilizes interruptible gas supplies or short-term capacity purchases.
Environmental The 1990 Clean Air Act Amendments require a sig-We are subject to numerous federal, state and local standards ni6 cant reduction in nationwide emissions of sulfur dioxide with respect to waste disposal, air and water quality and other from fossil fuel-Gred generating units. The reduction will be
, , environmental considerations. These standards can require accomplished by restricting sulfur dioxide emissions through a that we modify our existing facilities or incur increased oper- market-based system of allowances. We currently have ating costs. allowances that are in excess of our needs and which may be l- We own or operate approximately 40 properties marketable. Any gain from the sale of these allowances may where oil or hazardous materials were previously spilled or be subject to future regulatory treatment. Other provisions of released. We are required to clean up these properties in the 1990 Clean Air Act Amendments involve limitations on l
! accordance with a timetable developed by the Massachusetts emissions of nitrogen oxides from existing generating units.
Department of Environmental Protection (DEP) and are con- Combustion system modiGcations made to New Boston and l
tinuing to evaluate the costs associated with their cleanup. Mystic Stations, including the installation oflow nitrogen There are uncertainties associated with these costs due to the oxides burners at New Boston, have allowed the units to meet complexities of cleanup technology, regulatory requirements the provisions of the 1995 standards. Depending upon the 4
and the particular characteristics of the different sites. We outcome of certain DEP air quality modeling studies current-l n
ly in pmgress, additional emission reductions may also be Safe harbor cautionary statement required by 1999 or years thereafter. The extent of any addi- We occasionally make forward-looking statements such as fore-tional emission restrictions and the cost of any further modi- casts and projections of expected future performance or state-fications is uncertain at this time. ments of our plans and objectives. These forward-looking Public concern continues regarding electromagnetic statements may be contained in fdings with the Securities and .
fields (EMF) associated with electric transmission and distrib- Exchange Commission, press releases and oral statements. l ution facilities and appliances and wiring in buildings and Actual results could potentially differ materially from these I homes. Such concerns have included the imssibility of adverse statements. Therefore, no assurances can be given that the !
heahh effects caused by EMF as well as perceived efTects on outcomes stated in such forward-looking statements and esti- l property values. Some scientific reviews conducted to date mates will be achieved. . '
have suggested associations between EMF and potential heahh The above sections include certain forward-looking efTects, while other studies have not substantiated such associa-statements about the effects of the industry restructuring tions. We support further research into the subject and are process and our related plan, operating results, Pilgrim
~
participating in the funding ofindustry-sponsored studies. Station's performance and environmental and legal issues.
We are aware that public concern regarding EMF in some The effects of the industry restructuring process cur-cases has resulted in litigation, in opposition to existing or rently underway at the DPU and our related plan could difTer proposed facilities in proceedings before regulators or in from our expectations. This could occur as regulatory deci-requests for legislation or regulatory standards concerning sions and negotiated settlements between utilities and inter-EMF levels. We have addressed issues relative to EMF in vari- venors are finalized during the restructuring process. In addi-ous legal and regulatory proceedings and in discussions with tion, the development of a competitive electric generation customers and other concerned persons; however, to date we market and the impacts of actual electric supply and demand have not been significandy afTected by these developments. in New England may afTect the uhimate results of the industry We continue to closely monitor all aspects of the EMF issue. restructuring and our plan.
The impacts of our continued cost control proce-Litigation dures on our operating results could differ from our expecta-in 1991 we were named in a lawsuit alleging discriminatory tions. The effects of changes in economic conditions, tax employment practices under the Age Discrimination in rates, interest rates, technology and the prices and availability Employment Act of 1967 concerning 46 employees afTected by of operating supplies could ma.erially afTect our projected our 1988 reduction in force. lxgal counsel continues to vigor- operating results.
ously defend this case. We have also been named as a party in Pilgrim Stauon's performance could difTer from our a lawsuit by Subaru of New England, Inc. and Subaru expectations. The station's capacity factor could be impacted Distributors Corporation. The plaintiffs are claiming certain by changes in regulations or by unplanned outages resulting automobiles stored on lots in South Boston suffered pitting from certain operating conditions.
damage caused by emissions from New Boston Station. We The impacts of various environmental and legal believe that we have a strong defense in this case. We are also issues could differ from our expectations. New regulations or involved in certain other legal matters. We are unable to ftdly changes to existing regulations could impose additional oper-determine a range of reasonably possible litigation costs in ating requirements or liabilities. The effects of changes in excess of amounts presiously accrued, although based on the specific hazardous waste site conditions and cleanup technolo-information currently available, we do not expect that any such gy could affect our estimated cleanup liabilities. The impacts additional costs will have a material impact on our financial of changes in available information and circumstances regard-condition. However, additional litigation costs that may result ing legal issues could afTect our estimated litigation costs. ,
from a change in estimates could have a material impact on the resuhs of a reporting period in the near term.
New accounting pronouncement Statement of Financial Accounting Standards No.121, Accounting for the impairment oflong-Lived Assets and fbr Long-Lived Assets to be Disposed Of, is effective in 1996.
This statement establishes accounting standards for recogniz- ;
ing and measuring asset impairment losses. Refer to Note M l to the Consolidated Financial Statements for more informa-tion regarding this statement and its potential effects.
1 1
24 I
Consolidated Statements of income years ended December 31, On thouunds, except earnings per share) 1995 1994 1993 Operating revenues $ 1,628,503 51,544,735 $ 1,482,159 Operating expenses:
Fuel 170,337 156,951 170,799 Purchased power 365,469 356,874 370,049
- Other operations and maintenance 439,263 435,824 405,609 Restructuring costs 34,000 0 0 Depreciation and amortization 153,339 148,845 137,710 Amortization of deferred cost of cancelled nuclear unit 0 19,791 0 Amortization of deferred nuclear outage costs 18,933 7,721 6,546 Demand side managemer.t programs 45,125 35,438 37,504 Taxes - property and other 106,361 100,015 93,102 income taxes 68,276 54,798 35,143-Total operating expenses 1,401,103 1,316,257 1,256,462 Operating income 227,400 228,478 225,697 Other income (expense), net (575) 3,979 211 Operating and other income 226,825 232,457 225,908 Interest charges:
Long-term debt 106,640 102,570 104,375 Other 12,642 12,343 9,778 Allowance for borrowed funds used during construction (4,767) (7,478) (6,463)
Total interest charges 114,515 107,435 107,690 l 125,022 118,218 l Net income 112,310 Preferred dividends provided 15,571 15.765 15,705 Balance available for common stock $ 96,739 $ 109,257 $ 102,513 I Weighted average common shares outstanding 46,592 45,338 44,959 Earnings per share of common stock $ 2.08 $ 2.41 $ 2.28 i l
l Consolidated Statements of Retained Earnings years ended December 31, a
(in thousands) 1995 1994 1993
$ 247,004 $ 218,292 $ 192,948
~ Balance at beginning of year Net income 112,310 125,022 118,218 Subtotal 359,314 343,314 311,166 Cash dividends declared:
Preferred stock 15,571 15,765 15,705 Common stock 86,399 80,545 77,169 Subtotal 101,970 96,310 92,874 Balance at end of year $ 257,344 5 247,004 $ 218,292 i
I
! The accompanying notes are an integral part of the consolidated financial statements.
25
Consolidated Balance Sheets December 31, On thousana) 1995 1994 Assets Utility plant in service, at original cost $ 4,315,422 $ 4,074,810 Less: accumulated depreciation 1,439,996 $2,875,426 1,344,452 $ 2,730,358 Nuclear fuel 302,594 291,836 Less: accumulated amortization 251,951 50,643 236,239 55,597 -
Construction work in progress 29,573 144,048 Net utility plant 2,955,642 2,930,003 ,
Investments in electric companies, at equity 23,620 24,678 Nuclear decommissioning trust 102,894 82,831 Current assets:
Cash and cash equivalents 5,841 6,822 Accounts receivable 219,114 189,361 Accrued unbilled revenues 37,113 32,240 Fuel, materials and supplies, at average cost 59,631 71,560 Prepaid expenses and other 23,607 345,306 26,693 326,676 Deferred debits:
Regulatory assets 156,774 198,148 Intangible asset - pension 27,386 22,849 Other 32,227 216,387 31,391 252,388 Total assets $3,643,849 $ 3,616,576 Capitalization and Liabilities Common stock equity $ 989,438 $ 915,747 Cumulative preferred stock:
Nonmandatory redeemable series 123,000 123,000 Mandatory redeemable series 92,000 94,000 Long-term debt 1,160,223 1,136,617 Current liabilities:
long-term debr/ preferred stock due within one year $ 102,667 $ 102,250 Notes payable 126,441 214,786 Accounts payable 133,474 130,496 Accrued interest 25,113 24,464 Dividends payable 25,351 23,533 Pension benefits 32,602 31,908 Other 105,442 551,090 85,204 612,641 Deferred credits:
Power contracts 21,396 40,277 Accumulated deferred income ta :es 497,282 515,454 Accumulated deferred investmert tax credits 62,970 67,048 Nuclear decommissioning reserve 113,288 92,404 Other 33,162 728,098 19,382 734,571 Commitments and contingencies - -
'Ibtal capitalization and liabilities $3,643,849 $ 3,616,576 The accompanying notes are an integral part of the consolidated financial statements.
a
Consolidited Stat:m:nts of Cash Flows years ended December 31, On shousana) 1995 1994 1993 Operating activities:
Net income $ 112,310 $ 125,022 5118,218 Adjustments to reconcile net income to net cash provided by operating activities:
. Depreciation 148,630 142,932 130,074 Amortization of nuclear fuel 19,029 18,810 21,816 Amortization of deferred cost of cancelled nuclear unit, net 0 19,067 0 Amortization of deferred nuclear outage costs 18,933 7,721 6,546 Other amortization 15,702 14,692 10,158 Deferred income taxes (21,115) (4,184) 10,303
/ Investment tax credits (4,078) (4,092) (4,073)
Allowance for borrowed funds used during construction (4,767) (7,478) (6,463)
Net changes in:
Accounts receivable and accrued unbilled revenues (34,626) (20,701) 13,206 Fuel, materials and supplies 7,202 3,093 9,722 Accounts payable 2,978 23,196 (18,916)
Other current assets and liabilities 26,485 35,217 25,660 Other, net 23,975 14,847 (20,437)
Net cash provided by operating activities 310,658 368,142 295,814 Investing activities:
Plant expenditures (excluding AFUDC) (180,822) (198,771) (246,774)
Nuclear fuel expenditures (13,621) (21,934) (6,491)
Capitalized demand side management expenditures 0 (37,007) (37,156)
Sale of plant assets, net 3,018 15,972 0 Nuclear decommissioning trust investments (20,063) (16,771) (15,189)
Electric company investments 1,058 (386) 1,106 Net cash used by investing activities (210,430) (258,897) (304,504)
Financing activities:
Issuances:
Common stock 64,888 10,634 10,055 Preferred stock 0 0 40,000 Long-term debt 125,000 15,000 815,000 Redemptions:
Preferred stock (2,000) (2,000) (40,000) long-term debt (100,600) (50,000) (648,625)
Net change in notes payable (88,345) 10,635 (71,349)
Dividends paid (100,152) (95,460) (92,370)
Net cash prmided (used) by financing activities (101,209) (111,191) 13,511 Net increase (decrease) in cash and c.uh equivalents (981) (1,946) 4,821 Cash and cash equivalents at the beginning of the year 6,822 8,768 3,947 Cash and cash equivalents at the end of the year $ 5,841 5 6,822 5 8.768 Cash paid during the year for:
Interest, net of amounts capitalized $ 113,945 $ 108,462 5103,720
- Inccme taxes $ 96,180 $ 46,074 5 30,305 The accompanying notes are an integral part of the consolidated financial statements. v
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 indudes the genera-tion, 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 a nudear unit Pilgrim Station. We supply electricity at retail to an area of 590 square miles, induding the City of150ston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric depanments. Electric operating revenues were 89% retail and 11%
wholesale in 1995.
- Note B Significant Accounting Policies .
- 1. Basis of Consolidation and Accounting The consolidated financial statements indude the activities of our wholly owned subsidiaries, Harbor Electric Energy Company and 150ston Energy Technology Group. All significant intercompany transaaions have been climinated. Certain prior period amounts on the Gnancial statements were redassified to conform with the current presentation.
We follow accouming policies prescribed by our federal and state regulators, the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Public Utilities (DPU). We are also subject to the accounting and reporting require-ments of the Securities and Exchange Commission. The financial statements conform with generally accepted accounting princi-ples (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 GAAl! The application of SFAS 71 results in difTerences in the timing of recognition of certain expenses from that of other businesses and industries. The preparation of financial statements in confor-mity with GAAP requires us to make estimates and assumptions that afTect the reponed amounts of assets and liabilities and disdo-sures 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 ditTer from these estimates.
2 Re enues We record 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 some purchased power costs to be billed to customers using a forecasted rate. The difference between actual and estimated costs is recorded as an adjustment to fuel and pur-chased power expenses and is included in accounts receivable until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.
- 4. Depreciation and Nudear Fuel Amortization Our physical property was depreciated on a straight-line basis in 1995,1994 and 1993 at composite rates of 3.10%,3.11% and 3.09% per year, respectivdy, based on estimated useful lives of the various dasses of property. The cost of decommissioning Pilgrim Station is exduded fmm these depreciation rates. When property units are retired, their cost, net of salvage value, is charged to accumulated depreciatior;.
The cost of nucl;ar fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also indudes an amount,fm he estimated costs of ultimatdy disposing of the spent nuclear fuel and for assessments for the decontami-nation and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates.
- 5. Amortiration of Deferred Nudear Outage Costs We defet the incremental costs associated with nudcar refueling outages and amonize them over future periods. In 1995 we changed the amoninnion period to two years from five years. The two-year amortization period is consistent with the two-year cyde between nudear refueling outages at Pilgrim Station. The change fmm the prior five-year amonization period appmved in the 1992 seulement agreement was made following the DPU's August 1995 order on electric industry restructuring, which is dis-
.6
cussed further in the Outlook for the Future section of Management's Discussion and Analysis. This order requires utilities to miti-gate potentially strandable costs by available and reasonable means. The prior regulatory treatment of recovery over a 6ve year peri-od resu! red in a signi6 cant lag between the expenditure and recovery of outage costs. We decided not to request recovery of the buildup of costs resulting from this regulatory lag. Accordingly, the remaining 59 million of deferred costs allocable to retail cus-tomers for refueling outages performed in 1991 and 1993 was written oft. Approximately $15 million of deferred costs from the 1995 refueling outage is being amortized over two years.
- 6. Amortization of Discounts and Redemption Premiums on L)ebt We expense dismunts, redemption premiums and related costs associated with issuances or redemptions oflong-term debt or the
. refmancing of existing debt over the life of the debt or the replacement debt subject to regulatory approval.
- 7. Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to 6 nance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction ofinterest charges. Although AFUDC is not a current source of cash income, the costs are 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 1995,1994 and 1993 were 6.35%,4.45% and 3.62%, respectively, and repre-sented only the cost of short-term debt.
- 8. Cash and Cash Fx1uivalents Cash and cash equivalents are comprised of highly liquid securitics with maturities of three months or less when purchased.
Outstanding checks are included in cash and account 3 payable until presented for payment.
- 9. Allowance for Doubtful Accounts Our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordmgly, we do not maintain a signi6 cant allowance for doubtful accounts balance.
- 10. Regulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with agreements with the DPU. These costs are to be expensed when the corresponding revenues are received in order to appropri-ately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time peri-ods. No return on investment was carned on the regulatory assets.
Regulatory assets consisted of the following:
December 31, 1995 1994 Redemption premiums $ 44,709 5 52,859 Income taxes, net 46,121 44,745 Power contracts 21,396 40,277 Pension and postretirement costs 13,811 22,761 Nuclear outage costs 13,471 17,804 Other 17,266 19,702
$ 156,774 $ 198,148 Note C. Rate Regulation in 1992 the DPU approved a three-year settlement agreement relating to our rate case proceedings. The agreement provided for retail rate increases, accounting adjustments and demand side management program expenditures, clarified the timing and recognition of cer-tain expenses and set limits on our rate of return on common equity through 1995.
In February 1996 we Gled an industry restructuring plan with the DPU in response to its August 1995 order on restruc-turing the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in new rates and performance incentives to be implemented in a new industry structure with a competitive generation market and incentive-reg-ulated transmission and distribution systems. Refer to Management's Discussion and Analysis for further information regarding the restructuring of the electric utility industry in Massachusetts and our proposed plan. State regulatory proceedings do not affect our contract or wholesale power rates, which are regulated by the FERC.
n
Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No.109, Accounting for Income Taxes (SFAS 109), which requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary difTerences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory assets of $46.1 million and $44.7 million and corresponding net increases in accumulated deferred income taxes as of December 31,1995, and December 31,1994, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31, On thousands) 1995 1994 .
Deferred tax liabilities:
Plant-related $ 521,280 $511.572 ,
Other 95,148 105,786 616,428 617,358 Deferred tax assets:
Plant-related 12,590 13,216 Investment tax credits 40,632 43,273 Alternative minimum tax 0 1,332 Other 65,924 44,083 119,146 101,904 Net accumulated deferred income taxes $ 497,282 5515,454 No valuation allowances for deferred tax assets are deemed necessary.
Components ofincome tax expense were as follows:
years ended December 31, (in thousands) 1995 1994 1993 Current income tax expense $ 93,469 5 63,358 $ 28,913 Deferred tax expense (21,115) (4,468) 10,303 Investment tax credits (4,078) (4,092) (4,073)
Income taxes charged to operations 68,276 54,798 35,143 Taxes on other income:
Current (1,729)- 2,550 1,205 Deferred 0 284 0 (1,729) 2,834 1,205 Total income tax expense $ 66,547 $ 57,632 5 36,348 The effective income tax rates reflected in the consolidated financial statements and the reasons for their difTenences from the statutory federal income tax rate were as follows:
1995 1994 1993 Statutory tax rate 35.0 % 35.0 % 35.0 % .
State income tax, net of federal income tax benefit 4.3 4.3 4.2 Investment tax credits (2.3) (2.3) (2.6)
Municipal property tax adjustment - -
(0.6)
Reversal of deferred taxes - settlement agreement -
(5.5) (13.0)
Other 0.1 (0,1) 0.4 Effective tax rate 37.1 % 31.4 % 23.4 %
30
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 are currently expens-ing an estimate of the decommissioning costs over Pilgrim's expected service life. The 1995 expense of approximately $14 million is included in depreciation expense on the consolidated income statement. The estimate used to determine our annual expense is based on a 1991 study 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 r: stored to its original state. The cost estimate, which involves many uncertainties, was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense from 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 collect from decommissioning charges are deposited in an external trust and are restricted so that they
. may only be used for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning fund balance and nuclear decommissioning reserve, thus reducing the amount to be collected from customers.
The 1991 decommissioning study 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. (See part 2 below for a discussion of spent fuel removal.) The partial update indicates an estimated decommis-sioning cost of $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel stor-age technology. No further update is currently available; however, we will continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate.
J In February 1996 the Financial Accounting Standards lloard (FASB) issued proposed new rules for accounting for liabili-ined to closure and removal oflong-lived assets, which includes decommissioning. If these draft rules are adopted we would k required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to nuclear plant. The plant addition would be depreciated over Pilgrim's expected service life. The liability would be mea-suted based on the present value of estimated future cash flows. The cumulative efTect of adoption of these proposed rules could result in a regulatory asset to be recc.vered from customers to the extent that the present value difTerence in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for decom-missioning. Ifit is not probable that we could recover these costs from customers, we would have to charge the cumulative effect of the difference to income instead of recording a regulatory asset. In addition, trust fund earnings would be reported on the income statement.
- 2. Spent Nuclear Fuel The spent fuel storage facility at Pilgrim Station provides storage capacity through approximately 2003. We have a license amend-ment 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 DPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies.
It is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. 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 is conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca hiountain, Nevada. The potential site, however, has
- encountered substantial public and political opposition and the DOE has publicly stated that it may be unable to construct such a repository in a timely manner. In 1994 we and other interested parties filed petitions in the U.S. Court of Appeals for the D.C.
, Circuit seeking declaratory rulings that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. The DOE has sought to dismiss those petitions and a court ruling is awaited. It is unknown at this time whether and on what schedule the DOE will esentually construct a spent fuel repository and what the efTect on us will be of any delays in such construction.
- 3. Low-Ixvel Radioactive Waste We regained access to low-level radioactive waste (IlW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us. I.egislation has been enacted in hiassachusetts establishing a regulatory process for managing the state's 1.lW, 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 11W management procedure, we will continue to monitor the situs. ion and investigate other available options.
n
- 4. Other Nuclear Units We are an investor in and cusmmer of two other domestic nuclear units. Both of these units receive, through the rates charged to their customers, an amount to cover the estimated costs to dispose of their spent nuclear fuel and to decommission the t nits at the end of their useful lives.
i Note F. Corporate Restructuring in 1995 we streamlined the corporate organization and reorgani ed the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retire-ment programs 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 eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million net of tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 million 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 supplementai 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 was provided for all employees whose positions were eliminated in the reorganization, who were all management and administrative support personnel. Severance benefits provided were salary payments, medical insurance and outplacement services.
The retirement programs' pension and medical and life insurance benefits, totalling $16 million, will be paid from pension and employee benefit trusts. The liabilities to the trusts are included on the consolidated balance sheet at December 31,1995,in pen-sion benefits and other current liabilities. All other benefits are being paid from general corporate funds. As of December 31, 1995, $10 million had been paid and $8 million remained in other current liabilities.
Note G. Pensions and Other Postretirement Benefits
- 1. Pensions 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 credit-ed employment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribu-tion 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 pension 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 fol-lowing pension information for 1995. Amounts related to the plan prior to 1995 were not material to our total pension costs and obligations.
Net pension cost consisted of the following components:
yects ended December 31, (in thousands) 1995 1994 1993 Current service cost - benefits carned $ 11,339 $ 15,057 $ 11,734 .
Interest cost on projected benefit obligation 31,789 33,961 33,181 Actual net loss /(return) on plan assets (72,192) 214 (44,470) ,
Net amortization and deferral 49,557 (32,169) 8,528 Net pension cost (a) $ 20,493 $ 17,063 $ 8,973 (a)In accordante with our 1992 settlement agreement we deferred the ddTerente in the net pension cost of the retirement plan and its annual funding amount. Net deferred wsts amoumed to ($1.2) million and $6.5 million at December 31,1995 and 1994. respectively. Lal net pension costs recorded as expense in 1995,1994 and 1993 were 528 million. 525 million and 55 million. respectisely.
/
U 6
We used the following assumptions for calculating pension cost:
1995 1994 1993 Discount rate 8.25 % 7.00 % 8.25 %
Expected long-term rate of return on assets 10.00 % 10.00 % 10.00 %
Compensation increase rate 3.90 % 4.50 % 4.50 %
The pension plans' funded status was as follows:
December 31, (in thousands) 1995 1994
, Actuarial present value of benent obligations:
Accumulated benefit obligation, including vested benefits of $386,020 and $305,632 (b) $ 401,329 5321,072 Plan assets at fair value $ 358,572 5289,164 Projected obligation for service rendered to date (487,702) (387,910)
Projected benefit obligation in excess of plan assets (129,130) (98,746)
Unrecognized prior service cost 22,506 13,328 Unrecognized net loss 83,187 67,361 Unrecognized net obligation 8,064 8,998 Minimum liability adjustment (c) (27,386) (22,849)
Net pension liability (d) $ (42,759) $(31,908)
(b) 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.
(c) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SFAS 87), requires the recognition of an additional mini-mum 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 $27 million and $23 million on our consolidated balance sheets at December 31,1995 and 1994, respectively.
(d)Nei pension liability included on the consolidated balance sheets in current liabilities is $33 million and $32 million, and in deferred credits is $10 million and 50 at December 31,1995 and 1994, respectively.
We used the following assumptions for calculating the plans' year-end funded status:
1995 1994 Discount rate 7.25 % 8.25 %
Compensation increase rate 3.90 % 3.90 %
We also provide defmed contribution 401(k) pbns for substantially all our employees. We match a percentage of employees' voluntary contributions to the plans, which amounted to 59 million in 1995,58 million in 1994 and 57 million in 1993.
- 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 eligibil;ty requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accor-dance with Statement of Financial Accounting Standards No.106 Employers' Accounting for Postretirement Benefits Other Than
, Pensions (SFAS 106). Our 1992 settlement agreement provides us with a five-year expense phase-in of the PBOP costs incurred under SFAS 106 and allows us to defer any costs in excess of the phase-in amounts to the extent that we fund an external trust.
Our funding policy is to contribute 100% of postretirement benefits costs to external trusts. Accordingly, we recorded expenses of
$23 million in 1995,517 million in 1994 and $15 million in 1993, reflecting the amount of current cost recovery from customers.
Net deferred costs amounted to $15 million and $16 million at December 31,1995 and 1994, respectively.
33
Net postretirement benefits cost consisted of the following components:
years ended December 31, On thousands) 1995 1994 1993 Current service cost - benefits earned $ 3,408 5 4,978 5 4,351 Interest cost on accumulated benefit obligation 13,521 13,632 14,286 Actual return on plan assets (7,151) (187) 0 Amortization of transition obligation 9,151 9,151 9,151 Net amortization and deferral 3,017 (2,581) 0 Net postretirement benefits cost $ 21,946 5 24,993 $ 27,788 .
We used the following assumptions for calculating postretirement benefits cost:
1995 1994 1993 Discount rate 8.25 % 7.00 % 8.00 %
Expected long-term rate of return on assets 9.00 % 9.00 % 9.00 %
Health care cost trend rate 7.00 % 9.00 % 12.50 %
The health care cost trend rate is assumed to decrease by one percent in 1996 and 1997 and to remain at 5% in years thereafter. Changes in the health 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 8% and would increase the accumulated benefit obligation at December 31,1995, by 7.5%.
The postretirement benefits program's funded status was as follows:
December 31, On thousands) 1995 1994 Trust assets at fair value $ 51,064 $ 33,300 Accumulated obligation for serCce rendered to date from:
Retirees $ (110,877) $ (93,960)
Active employees eligible to retire (31,980) (31,159)
Active employees not eligible to retire (53,514) (196,371) (51,545) (176,664)
Accumulated benefit obligation in excess of trust assets (145,307) (143,364)
Unrecognized prior service cost (17,889) (19,502)
Unrecognized net (gain)/ loss 5,612 (1,849)
Unrecognized transition obligation 155,564 164,715 Net postretirement benefits liability $ (2,020) 5 0 The net postretirement benefits liability at December 31,1995, represents the additional PBOP obligation from the enhanced retirement programs offered in 1995 (see Note F). This additional amount was not funded as part of the 1995 PBOP cost.
TI.e weighted average discount rates used to measure the accumulated benefit obligation were 7.25% in 1995 and 8.25%
in 1994. The trust assets consist of equities, bonds and money market funds.
Note H. Eminent Domain Taking In November 1994 a Norfolk Superior Court ruling against the hiassachusetts hierropolitan District Commission (h1DC) became -
effective, providing us with an additional $5.7 million gain on an eminent domain land-taking case. We had filed suit against the h1DC in 1992 related to the eminent domain taking of certain of our property in 1989.
Note 1. Cancelled Nuclear Unit In 1982 we began expensing the cost of our cancelled Pilgrim 2 nuclear unit over approximately eleven and one-half years in accor-dance with an order received from the DPU. We did not expense any of these costs in 1993. The remaining balance of $19 mil-lion was fully expensed in 1994 as allowed by our 1992 settlement agreement.
, u l
Note J. Capital Stock December 31, (dollars in thousands, except per share amounts) 1995 1994 1993 Con mon stock equity:
Cenimon stock, par value $1 per share, 100,000,000 shares authorized: 48,003,178, 45,535,477 and 45,129.227 shares issued and outstanding: $ 48,003 $ 45,535 $ 45,129 Premium on common stock 683,686 622,803 612,653 Retained earnings 257,344 247,004 218,292 Surplus invested in platst 405 405 405 Total common stock equiry $ 989,438 $ 915,747 $876,479 Cumulative preferred stock: ,
Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption Series Outstanding Price / Share 4.25 % 180,000 $103.625 $ 18,000 $ 18,000 $ 18,000 4.78 % 250,000 $102.800 25,000 25,000 25,000 7.75 % 400,000 -
40,000 40,000 40,000 8.259o 400,000 - 40,000 40,000 40,000 Total nonmandatory redeemable series $ 123,000 $ 123,000 $ 123,000 Mandatory redeemable series:
Current Shares Redemption Series Outstanding Price / Share 7.27 % 440,000 $103.390 $ 44,000 $ 46,000 $ 48,000 8.00 % 500,000 -
50,000 50,000 50,000 Total mandatory redeemable series 94,000 96,000 98,000 Less: due within one year 2,000 2,000 2,000 Total mandatory redeemable series, net $ 92,000 $ 94,000 $ 96,000 Dividends Declared per Share ,
Common stock $ 1.835 $ 1.775 $ 1.715 Preferred stock:
4.25% series $ 4.250 $ 4.250 $ 4.253 4.78% series 4.780 4.780 4.785 6 7.27% series 7.270 7.270 7.270 7.75% series 7.750 7.750 5.707 8.00% series 8.000 8.000 8.000 8.25% series 8.250 8.250 8.250 8.88% series 0 0 2.220 35
l
- 1. Common Stock Common stock issuances in 1993 through 1995 were as follows:
Number Total Premium on (in thousands) ofShares Par Value Common Stock llalance December 31,1992 44,763 544,763 $602,196 Dividend reinvestment plan 366 366 10,457 Balance I)ecember 31,1993 45,129 45,129 612,653 Dividend reinvestment plan 406 406 10,150 Balance December 31,1994- 45,535 45,535 622,803 Dividend reinvestment plan (a) 468 468 11,404 -
New issuances (b) 2,000 2,000 49,479 Balance December 31,1995 48,003 $48,003 $683,686 .
(a) At December 31,1995, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plar were 1,941,219 Shares.
(b)We used the net proceeds of the 1995 common stak issuances to reduce short-term debt.
- 2. Cumulative Nonmandatory Redeemable Preferred Stock In 1993 we issued 400.000 shares of 7.75% cumulative nonmandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in hiay 1998. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulative nonmandatory redeemable preferred stock.
- 3. Cumulative Mandatory Redeemable Preferred Stock The 440,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $103.390.
The redemption price declines annually each hiay to par value in hiay 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 redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends.
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 $100 per share, plus accrued dividends.
Note K. Indebtedness December 31, (in thousands) 1995 1994 fong-term debt:
Debentures:
8.875% due December 1995 $ 0 $ 100,000 5.125% due March 1996 100,000 100,000 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 0 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 1,215,000 1,190,000 Less: due within one year 100,000 100,000 Net long-term debentures 1,115,000 1,090,000 h
Note K. Indebtedness cont.
December 31, (in thousands) 1995 1994 Sewage facility revenue bonds $ 35,700 $ 36,300 less: due within one year 1,600 600 Irss: funds held by trustee 3,877 4,083 Net long-term sewage facility revenue b<mds 30,223 31,617 Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000 Total long-term debt $1,160,223 $ 1,136,617 Short-term debt:
Notes payable:
Bank loans $ 75,941 $ 80,786 Commercial paper 50,500 134,000 Thral notes payable $ 126,441 $ 214,786
- 1. Long. Term Debt in 1994 the Massachusetts Industrial Finance Agency, on our behalf, issued $15 million of 5.75% tax-exempt unsecured bonds due in 2014. The bonds are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 10l% in February 2005 and to par in February 2006. The proceeds from this issuance together with sufGcient other funds were used to fully redeem the Series U first mortgage bonds.
In 1994 we redeemed at par the $25 million of variable rate Series S Hrst mortgage bonds. As a result of the redemption of all outstanding first mortgage bonds, the Indenture ofTrust and First Mortgage that had mortgaged substantially all our property since 1940 was terminated in November 1994.
In May 1995 we issued $125 million of 7.80% debentures due in 2010. We used the net proceeds from this issuance to reduce short-term debt.
The 9 7/8% debentures due 2020 are Grst redeemable in June 2000 at a redemption price af 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 first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first 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 Harbor Electric Energy Company (HEEC), a wholly owned subsidiary. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In May 1995 $0.6 million was redeemed as scheduled. The weighted sverage inteest 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 insufGcient 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 $1 million.
The aggregate principal amounts co our long-term debt (including HEEC sinking fund requirements) due through 2000 a are $101.6 million per year in 1996 through 1998,51.6 million in 1999 and $166.6 million in 2000.
- 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 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 stand-by source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.
Information regarding our short-term borrowings, comprised of bank loans and commercial paper, is as follows:
(dottars in thousands) 1995 1994 1993 Maximum short-term borrowings $ 327,769 $ 268,100 $ 320,000 Weighted average amount outstanding $ 165,720 $ 214,640 $ 220,149 Weighted average interest rate, excluding commitment fees 6.2 % 4.5% 3.4%
37
Note L. Fair Value of Securitics The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:
Nuclear decommissioning trust:
The cost of $102.9 million approximates fair value based on quoted market prices of securities held.
Cash and cash equivalents:
The carrying amount of $5.8 million approximates fair value due to the short-term nature of these securities.
hiandatory 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 31,1995, are as follows:
Carrying Fair un thouunds) Amount Value hiandatory redeemable cumulative preferred stock $ 94,000 $ 98,005 Sewage facility revenue bonds 35,700 38,446 Unsecured debt 1,230,000 1,276,213 Note M. New Accounting Pronouncement in 1995 the FASil issued Statement of Financial Accounting Standards No.121, Accounting for the Impairment of Long-Lived Assets and for Long-1.ived Assets to be Disposed Of(SFAS 121), efTective in 1996. This statement clarifies when and how to rec-ognize asser impairments. In addition, SFAS 121 requires that all regulatory assets, which must have a high probability of recovery to be initially established, continue to meet that high probability standard or be written oft. However, if written oft, a regulatory asset can be restored ifit regains a high probability of recovery. The impact of this standard on our plant and regulatory assets will be determined by regulamry changes implemented by the DPU and FERC. Ilased on the transition principles of the DPU's order on industry restructuring and our related plan, which are discussed in the Outlook for the Future section of hianagement's Discussion and Analysis, we do not expect SFAS 121 to have an adverse impact on our financial position or results of operations in the near term. Our conclusion may change as the actual shape of restructuring of the industry in hiassachusetts develops. If recovery of our plant and regulatory assets is not provided, SFAS 121 could require a write-down of these assets.
Note N Commitments and Contingencies
- 1. Contractual Commitments At December 31,1995, we had estimated contractual obligations for plant and equipment of approximately $35 million.
We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmis-sion agreements and noncancellable leases for the years after 1995 are as follows:
6 Gn thousands) 1996 $ 24,908 1997 22,109 -
1998 19,002 1999 17,408 2000 16,656 Years thereafter 108,417 Total $208,500 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 $24.5 million in 1995. $28.6 million in 1994 and $29.8 million in 1993, net of cap-italized expenses of $2.7 million in 1995, $2.4 million in 1994 and $5.2 million in 1993.
38
We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply New Iloston Station with natural gas. The fixed and determinable portions of the obligations are $16.1 million in 1996,1997 and 1998, $24.8 million in 1999 and $13.8 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $13.9 million in 1995, and $6.5 million in 1994 and 1993.
- 2. Ilydro-Quebec We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included on our consolidated financial statements. As an equiry participant we are required to guarantee, in addition :o our own share, the total obligations of those participants who do not
. meet certain credit criteria and are compensated accordingly. At December 31,1995, our portion of these guarantees was approxi-mately $19 million.
- 3. Yankee Atomic Electric Company We have a 9.5% stock investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the lloard of Directors of Yankee Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generat-ing station and decommission the facility. We relied on Yankee Atomic for less than one percent ofour system capacity under a long-term purchased power contract.
Yankee Atomic received approval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $21 million as of December 31,1995. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement.
- 4. Nuclear Insurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclea, related accident. The first $200 million of nuclear liability is covered by commercial insur-ance. Additional nuclear liability insurance up to approximately $8.3 billion is provided by a retrospective assessment of up to
$75.5 milhon per incident levied on each of the 110 units licensed to operate in the United States, with a maximum assessment of
$10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an addi-tional five percent of the maximum retrospective assessment.
We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a pmlonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assess-ment for losses which occur during current policy years is $15 million under both the replacement power and excess property dam-age, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses are in excess of the total funds available to NEIL While additional assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in any such assessment.
, 5. Litigation In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees afTected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. We have also been named as a party in a lawsuit by Subam of New England, Inc. and Subaru Distributors Corporation. The plaintifTs are claiming certain automobiles stored on lots in South Iloston sufTered pitting damage caused by emissions from New Iloston Station. We believe that we have a strong defense in this case. 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 previously accrued, although based on the information currently available, we do not expect that any such additional costs will have a material impact on our financial condition.110 wever, 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, n
i
- 6. Ilazardous Waste We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required to dean up these properties in accordance with a timetable developed by the hiassachusetts Department of Environmental Protection (DEP) and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the diffeent 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 hiassachusetts and other states where we are alleged to have generated, transported or disposed of haz-ardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability. Through December 31,1995, 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, ahhough based on our assessments of the specific site circumstances, we do not expect any such additional costs -
to have a material impact on our financial condition. However, 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.
Note O. Long-Term Power Contracts
- 1. long-Term C<mtracts for the Purchase of Electricity We purchase electric power under several long-term contrac:s for which we pay a share of the generating unit's capital and fixed one.:ing costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidned income statements. Information relating to these contracts as of December 31,1995, is as follows:
proportionate share (in thousands)
Units of 1995 1995 Interest Debt Contract Capacity hiinimum Portion of Outstanding Expiration Purchased (a) Debt hiinimum Through Cont.
Generating Unit Date % htW Senice Debt Service Exp. Date
~
Canal Unit 1 2001 25.0 139 5 1,122 5 349 5 3,400 hiass. Hay Transportation Authority - 1 2005 100.0 34 (b) (b) (b)
Connecticut Yankee Atomic 2007 9.5 55 2,646 ' 786 13,857 Ocean State Power - Unit 1 2010 23.5 67 4,819 3,318 20,749 Ocean State Power - Unit 2 2011 23.5 66 4,090 3,049 17.228 Northeast Energy Associates (c) (c) 219 (c) (c) (c)
UEnergia 2013 73.0 64 (d) (d) (d) hiassPower (c) 2013 44.3 117 12,217 7,662 81,983 Alass. Bay Transportation Authority - 2 2019 100.0 34 (f) (f) (f)
'Ibral 795 5 24,894 5 16,164 5 137,217 (a) The Northeast l'nergy Awociates contract represents 5.9% of our total system generation capability. The remaining units listed alue represent 15.6% in total.
(b)We are required to pay the greater of $22.00 per Lilowatt-year or 90% of the New 1:ngland Power Pool capability responsibility adjustment tharge up to $63.On per kilowan-year times the quahtied capacity (currendy rated at 34A1W), plus inuemental operating maintenance and fuel costs. The total thargn for this contratt in 1995 were approximately $2 million. 8 (c) We purchaw approximately 75.5% of the energy output of this unit under two contracts. One wntract represents 13sN1T and expires in the year 2015. The other contrast is for 84N1W and expires in 2010. We pay for this energy based on a price per kWh actually reteived. We do not pay a proponionate share of the unit's capital and thed operating costs. The total charges for these contracts in 1995 were approximately $127 million.
(d)We pay for this energy bawd on a price per L Wh actually retcived. The total charges under this wntract for 1995 were approximately $25 million.
(e) Payments for this contratt are based on a stipulated price per MW rating of the unit subjett to the unit maintaining a twelve month average availabd.
icy of at least 90%. Payments are adjusted proportionately if the twehe-month aserage is below 9n%. If the twelve-month average is less than 10%
no payment is required. 'lotal charges for this contract in 1995 were approximately $49 million.
(f) The second Massachusetts llay Transportation Authority wntract staned in June 1995. Capacity payments under this mntract do not begin until 2003.
At that time we wdl be required to pay $84.57 per kilowau-year times the qualified capacity plus incremental operating maintenance and fuel wsts.
ao
Our total 6xed and variable costs for these contracts in 1995,1994 and 1993 were approximately $283 million, $286 mil-lion and $225 million, respectively. Our minimum fixed payments under these contracts for the years after 1995 are as follows:
(in thousands) 1996 $ 106,649 1997 103,682 1998 105,778 1999 105,258 2000 103,676
. Years thereafter 1,187,672
'Ibtal $ 1,712,715
'Ibtal present value $ 883,409
- 2. long Term Power Sales in addition to wholesale power sales, we sell a percentage of Pilgrim S,ation'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 adjustments.
Under these contracts, the utilities pay their proportional share of the costs of openaing Pilgrim Station and associated transmission facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decommis-sioning and a return on capital.
4 41
'k Rcport of Independent Accountants To the Stockholders and Directors of Boston Edison Company We have audited the accompanying consolidated balance sheets of Boston Edison Company and subsidiaries (the Company) as of
, December 31,1995 and 1994, and the related wnsolidated statements ofincome, retained earnings and cash flows for each of the three years in the period ended December 31,1995. These financial statements are the responsibility of the Company's manage-ment. Our responsibility is to express an opinion on these financial 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 financial position of the Company as of December 31,1995 and 1994, and the consolidated results ofits operations and its cash flows for each of the three years in the period ended December 31,1995, in conformity with generally accepted accounting principles.
4 A ,
Boston, Massachusetts January 25.1996 4
42
Selectcd Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Balance Available Earnings Operating Operating Net for Common Per Average Revenues Income Income Stock Common Share (a) 1995 First quarter $379,678 $ 47,610 $ 20,202 516,300 $ 0.36
. Second quarter 380,828 55,683 26,137 22,247 0.48 Third 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) 1994 First quarter $376,935 $ 45,891 519,812 515,850 $ 0.35 Second quarter 368,245 50,812 23,o82 20,031 0.44 Third quarter 448,179 96,88'O 70,;82 66,256 1.46 Fourth quarter 351,376 34,895 11,046 7,120 0.16 (a) Based on the weighted average number of common shares outstanding during the quarter.
(h) As discussed in Note F to the Consolidated Financial Statements, we incurred a $34 million pre-tax charge related to our corporate restructuring over the third and fourth quarters of 1995. Amounts excluding the restructuring charge are as follows:
Balance Available Earnings Operating Net for Common Per Average l Income Income Stock Common Share 1995 Third quarter 5 107.779 $ 77,452 $73,562 $ 1.57 Fourth quarter 36,991 9,182 5,293 0.11 Certain reclassifications were made to the data reported in prior periods to conform with the current method of presentation.
Selected Quarterly Stock Data Following are the reported high and low sales prices of our common stock on the New York Stock Exchange as reported daily in the a MTd/Strutfournalfor each of the quarters in 1995 and 1994 and the dividends declared per share during each of those quarters:
! 1995 1994
. High Low Dividends High Low Dividends First quarter $251/2 $231/8 $0.455 $29 7/8 $26 $0.440 Second quarter 27 23 3/8 0.455 29 1/8 25 1/4 0.440 Third quarter 27 1/2 24 1/2 0.455 27 5/8 22 3/4 0.440 Fourth quarter 29 1/2 26 3/4 0.470 24 1/4 21 1/2 0.455 43
Selected Consolidated Operating Statistics (Unaudited) 1995 1994 1993 1992 1991 Capacity - hiW:
New Boston Station 760 760 760 760 760 Pilgrim Station 669 669 670 670 670 hiystic Station 1,005 1,006 1,006 1,005 1,015 W.E Wyman Unit 4 36 36 36 36 36 ,
Jet turbines 284 287 283 281 281
%tal (a) 2,754 2,758 2,755 2,752 2,762 Contract purchases 1,274 1,035 938 1,157 1,293 Contract sales (340) (373) (283) (303) (293)
Net capability at year-end 3,688 3,420 3,410 3,606 3,762 Net capability at peak - htW 3,466 3,484 3,663 3,587 3,695 Capability responsibility to NEPOOL at peak - hiW 3,306 3,306 3,190 3,396 3,311 Edison territory:
Hourly peak - hiW 2,785 2,798 2,662 2,545 2,652 Load factor 60.0 % 58.9 % 60.5 % 62.5 % 60.0 %
Generating station economy (B FU/ net kWh) 10,348 10,408 10,345 10,234 10,331 Average cost of fuel (Company) -
$ per million BTU:
Fossil 2.358 2.321 2.504 2.467 2.402 Nuclear 0.432 0.501 0.507 0.522 0.562 l Composite 1.581 1.613 1.620 1.669 1.805 l Capability (net kW):
Fossil 85 % 84 % 84 % 81 % 81 %
Nuclear 15 % 16 % 16 % 19 % 19%
Generation (system kWh excluding interchange):
Fossil 73 % 75 % 68 % 69 % 70 %
Nuclear 27 % 25% 32 % 31 % 30 %
Utility plant ($ in 000's):
Expenditures $ 180,822 5 198,771 $ 246,774 $ 213,827 $ 202,589 Retirements 48,111 45,673 34,147 34,036 30,333 Accumulated depreciation 1,439,996 1,344,452 1,258,359 1,177,294 1,097,991 +
Depreciable plant 4,235,347 3,994,212 3,841,752 3,567,160 3,488,269 .
Number of utility employees at year-end 3,590 (b) 4,026 4,397 4,540 4,637 (a) Tinter ca;ubility audit results (b) At January 1,1996 Certain reclassifications were made to the data reported in prior years to conform with the method of presenution used in 1995.
44
Selected Consolidated Sales Statistics (Unaudited) 1995 1994 1993 1992 1991 Electric energy (kWh in thousands):
Sources (system output):
Generated 10,537,114 9,428,931 9,787,092 11,679,824 10,602,110 Purchased 5,446,542 5,920,065 5,326,224 5,449,225 4,651,101
, New England Power Pool 1,513,467 1,535,335 1,575.310 932,121 1,274,522 Tbtal 17,497,123 16,884,331 16,6F'd,626 18,061,170 16,527,733 Disposition:
Commercial 7,604,841 7,478,631 7,203,358 7,178,281 7,143,484 Residential 3,563,626 3,534,372 3,477,870 3,413,252 3,386,681 Industrial 1,538,218 1,539,385 1,580,969 1,671,564 1,685,184 Other (a) 131,626 130,721 145,242 292,510 279,540
'lbtal retail sales 12,838,311 12,683,109 12,467,439 12,555,607 12,494,889 Wholesale and contract sales (a) 2,655,620 2,367,589 2,272.669 2,517,247 1,660,082 New England Power Pool 884,336 725,439 877,978 1,898,059 1,252,797 Total system 16,3711,267 15,776,137 15,618,086 16,970,913 15,407,768 Miscellaneous usage 1,118,856 1,108,194 1,070,540 1,090,257 1,119,965 j
'Ibral 17,497,123 16,884,331 16,688,626 18,061,170 16,527,733 Eilowarthours - annual growth:
Commercial 1.7 % 3.0 % 1.2 % 0.5 % (0.5)%
Residential 0.8 1.6 1.9 0.8 (1.2)
Industrial (0.1) (2.6) (5.4) (0.8) (3.4)
Other 0.7 (10.0) (50.3) 4.6 1.6
'Ibral retail sales (a) 1.2 1.7 (0.7) 0.5 (1.0)
Wholesale and contract sales 12,2 4.2 (9.7) 51.6 (0.8)
New England Power Pool 21.9 (17.4) (53.7) 51.5 (33.5)
Total system 3.8 % 1.0 % (8.0)96 10.1 % (4.8)%
Electric operating revenues by class:
Commercial 50 % 50 % 49% 48% 48 %
Residential 28 % 28 % 28% 27% 27 %
Industrial 9% 9% 10 % 10 % 10 %
Wholesale and contract 11 % 119o 12 % 13 % 13 %
Other 2% 2% 1% 2% 2%
e Retail revenue per kWh 11.08 e 10.68 e 10.33 e 9.55 e 9.27 e Average number of customers 653,757 655,707 651,141 646,215 642,967 (a) IEcctive l'ebruary 1993 a former retail customer became a wholesale customer as allowed under Massachuscus state law. Excluding the efTect of this customer's change in status, total retail sales increased 2.0% in 1994 and 1.2% in 1993.
45
Selected Consolidated Financial Statistics (Unaudited) 1995 1994 1993 1992 1991 Operating revenues (000) $1,628,503 $ 1,544,735 $ 1,482,159 $ 1,411,753 $1,354,501 Balance for common (000) $ 96,739 $ 109,257 $ 102,513 $ 90,748 $ 77,059 Per common share:
Earnings $ 2.52 (a) $ 2.41 $ 2.28 $ 2.10 $ 1.96 Dividends declared $ 1.835 $ 1.775 $ 1.715 $ 1.655 $ 1.595 .
Dividends paid $ 1.82 $ 1.76 $ 1.70 $ 1.64 5 1.58 Book value $ 20.61 $ 20.11 $ 19.42 $ 18.77 $ 17.92 ,
Operating cash Cow $ 6.81 5 8.12 $ 6.58 5 6.80(b) $ 5.50 (b)
Payout ratio 72% (a) 73 % 75 % 78 % 81 %
Return on average common equiry 12.2% (a) 12.1 % 11.9 % 11.5 % 11.3%
Year-end dividend yield 6.4% 7.6% 5.9% 6.2% 6.6 %
Fixed charge coverage (SEC) 2.38 2.46 2.22 1.89 1.83 Capitalization:
Total debt 54 % 56 % 57 % 56 % 58 %
Preferred equity 8% 9% 9% 9% 10 %
Common equity 38 % 35% 34 % 35 % 32 %
long-term debt (000) $1,160,223 $ 1, u6.617 $ 1,272,497 $ 1,091,073 $ 1,136,765 Mandatory redeemable preferred stock (000) $ 94,000 $ 96,000 $ 98,000 $ 98,000 $ 100,000 Total assets (000) $ 3,643,849 $3,616,576 $ 3,476,601 $ 3,294,212 $3,098,742 Internal generation after dividends (000) $ 184,492 $ 217,030 $ 194,209 $ 204,248 5 193,019 Plant and nuclear fuel expenditures (000) $ 194,443 $ 220,705 $ 253,265 $ 231,025 $ 214,213 Internal generation 95 % 98 % 77 % 88 % 90 %
Common shares outstanding:
Weighted average 46,5 R 662 45,337,661 44,959,050 43,143,953 39,347,824 Year-end 48,001,178 45.535,477 45.129,227 44,763,055 42,047,356 Stock price:
High 29 1/2 29 7/8 32 5/8 28 1/4 24 7/8 low 23 1/8 21 1/2 26 3/8 22 1/8 18 1/4 Year-end 29 1/2 24 29 3/4 27 1/2 24 3/4 Year-end market value (000) $1,416,094 $ 1,092,851 $ 1,342,595 $ 1,230,984 $ 1,040,672 Trading volume (shares) 23,078,900 25,095,100 18,729,400 26,460,900 17,464,300 Market / book ratio (year-end) 1.43 1.19 1.53 1.47 1.38 Price /carnings ratio (year-end) 11.7 (a) 10.0 13.0 13.1 12.6 s
(a) Amounts including $34 million pre-tax restructuring charge: .
Earnings $ 2,08 Payout ratio 88 %
Return on average common equity 10.0 %
Price / earnings ratio 14.2 (b) I'.uludes clini of rate and comract seulemems.
Certain redassi6 cations and recalculations were made to the data reported in prior years to conform with the method of presentation used in 1995, c.
Officers Directors Thomas J. hiay, Chairman of the Board, President and Chief Executive OGcer a,d William E Connell, Chairman and Chief Executive Omcer, Connell Limited Partne. ship (metals E. Thonus Boulette, Senior Vice President - Nuclear recycling and processing and :ndustrial production)
L. Carl Gustin, Senior Vice President - Corporate Relations d,f Gary L. Countryman, Chairman of the Board and Chief Executive Omcer, Liberty hiutual John J. liiggins, Jr., Senior Vice President - Human Resources Insurance Company a,e,f Thomas G. Dignan, Jr., Partner, Ropes & Gray Douglas S. lloran, Senior Vice President and General (law firm)
Counsel b,c,d Charles K. Gifford, Chairman, President and Chief Executive Officer, Bank of Boston Corporation James J. Judge, Sem. or Vice Pres.i dent and'I,reasurer (bank holding company) and The First National Bank of Boston Ronaki A. Ledgett, Senior Vice President - Fossil b,f Nelson S. Gifford, Principal, Fleetwing Capital Alison Alden Vice President - Sales & Service ("'"'"'" I " "*5 ' * *" )
a,e Kenneth L Guscott, General Partner, Long Bay s William N. Dimoulas, Vice President - Information Systems hianagement Company (real estate development) a,b,c hiatina S. Horner, Executive Vice President, Teachers <
Richard S.11ahn, Vice President - Technology Insurance and Annuity Association and College Research & Development Retirement Equities Fund a,c Thomas J. hiay, Chairman of the Board, President I con J. Olis ier, Vice President - Nuclear Operations and and Chief Executive Omcer, Boston Edison Station Director Company Robert A. Ruscitto, Vice President - Field Service and b,d Sherry H. Penney, Chancellor, University of Electric Delivery hiassachusetts at Boston e,f Bernard W. Reznicek, Dean, College of Business Robert J. Weafer, Jr., Vice President - Finance, Controller and Administration, Creighton University and fornnr Chief Accounting Omccr Chairman of the Board and Chief Executive .
Omcer, Boston Edison Company Theodora S. Convisser, Clerk of the Corporation e,f Herbert Roth, Jr., F.ormer Chairman of the Board and Chief Executive Omcer, LFE Corporation Donald Anastasia, Assistant Treasurer (trame and industrial control systems) e,f Stephen J. Sweeney, Former Chairman of the Board o Wayne R. Frigard, Assistant Clerk of the Corporation and Chief Executive Omcer, Boston Edison Company
, b,c,d Paul E. Tsongas, Partner, Foley Hoag & Eliot (law firm) a hiember of Executive Committee i
b hiember of Audit, Finance and Risk hianagemen't Committee g3 c
d hiember of Pricing Committee
/
hiember of Executive Personnel Committee /
e hiember of Nuclear Oversight Committee f hiember of Capital Investment Committee 47
i
- 550 per month minimum not to exceed $40,000 important Shareholder Information per calendar year
- Safekeeping of common stock certificates Shareholder Inquiries Beneficial owners of our stock whose shares are registered in names mher than their own (e.g., a broker or bank nominee) ifyou have questions concerning your dividend payments, the Dividend Reinvestment and Common Stock Purchase Plan, must arrange participati n with the rec rd holder. If for any direct deposit service, transfer procedures or other stock re s n y u are un ble to arrange participation with your bro-account matters, please contact our stock transfer agent at the ker or bank nominee, you must become a record holder by ,
following address: having the shares transferred to your own name. j The First National llank of Boston If you are interested in receiving a prospectus to learn c/o Boston EquiServe more about this plan, or if you have questions on an existing ',
Shareholder Services Division account, contact our stock transfer agent. -
Mail Stop: 45-02-09 .
P.0, Box 644 Safekeeping Program (New)
Boston, MA 02102-0644 Shareholders who are participants in the Dividend l Toll Free Phone: 1-800-736-3001 Reinvestment and Common Stock Purchase Plan can transfer If you aie submitting documents requesting a transfer, their common stock certificates into their plan account for address change or account consolidation, please use this same s fckeeping. Dividends on those shares will be reinvested I address whh Mail Stop: 45-01-05. If you would like to automatically like any other shares held in the plan. Tb con-contact the bank by relephone call 617-575-3100. tinue receiving cash dividends, you must hold your shares in certificate form. For additional information, contact our Dividend Payments Dates stock transfer agent. )
l Common and Preferred SEC Form 10 K l 1st of February, May, August and November Stockholders may obtain a copy of our annual report to the Tax Status of 1995 Dividends Securities and Exchange Commission on Form 10-K, Generally, unless you are subject to certain exemptions, all by contacting our Investor Relations Department.
dividends on our common or preferred stock are to be consid-Quarterly Report to Shareholders cred 100% taxable.
l Beneficial owners of our stock whose shares are registered in Stock Symbol and Exchange Listings names other than their own may obtain copies of our Ticker Symbol: BSE Quarterly Reports to Shareholders by contacting our Investor
! ii.v York and Boston stock exchanges Relations Department. Note that the Annual Report will ,
continue to be mailed to beneficial owners directly by their l 1996 Annual Shareholders Meeting bank or broker.
All shareholders are invited to attend our Annual Meeting on mPany Gntact Wednesday, May 8,1996, at 11:00 A.M. at the Sheraton Boston Ilotel and 'Ibwers. Theodora S. Convisser Clerk of the Corporation Dividend Payments - Direct Deposit Service Investor Relations Contacts l Shareholders rece. .ivmg dividend checks can arrange for elec-
, tronic direct deposit. Transfers are made on the dividend pay. Philip J. I.embo ,
l ment dates and confirmation statements are mailed to share. Director, investor Relations ,
holders. Tb take advantage of this convenient program, con. (617) 424-3562 tact our stock transfer agent as noted above. or '
Jean M. Carella Dividend Reinvestment and Common Stock Investor Relations Specialist Purchase Plan (617) 424-2658 in 1995, we modified and improved our Dividend Email Address Reinvestment and Common Stock Purchase Plan (the plan).
l It is available to our common and preferred shareholders, our irFbedison.com residential electric customers and employees. Participants do General Offices not pay brokerage fees or commissions related to the purchase of shares. Sc.me important features of the plan are as follows: 800 Boylston Street
- Optional cash payments invested monthly Boston, MA 02199-8003 j
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& Boston Edison 800 Boylston Street Boston, Massachusetts 02199-8003 l
1 l
' , SECURITIES AND EXCHANGE COMMISSION Washirgt:n, D.C. 20549 y FORM 10-K
! [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1 l 1934 [ FEE REQUIRED] l For the fiscal year ended December 31,1995 l
[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 1 OF 1934 [NO FEE REQUIRED] )
! For the transition period from to l'
Commission file number 1-2301 <
BOSTON EDISON COMPANY l (Exact name of registrant as specified in its charter)
Massachusetts 04-1278810 !
(Stateorotherjurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)
800 Boylston Street. Boston. Massachusetts 02199 l (Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000 l Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange i
Title of each class on which recistered Common stock, par value $1 per share New York Stock Exchange Boston Stock Exchange
! Cumulative preferred stock:
l 7.75% Series, par value $100 per share New York Stock Exchange l
(represented by depositary shares-each ,
! represents one-fourth interest in par value) 8.25% Series, par value $100 per share New York Stock Exchange ,
(represented by depositary shares-each l
l represents one fourth interest in par value)
Securities registered pursuant to Section 12(g) of the Act: None l 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 Part III of this l Form 10-K or any amendment to this Form 10-K. 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 Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES .X_ NO ._,
The aggregate market value of the voting stock held by non-afIlliates of the registrant as of February 29,1996 computed by reference to the last reported sale price of the common stock, $1 par value, of the registrant of the New York Stock Exchange composite tape on that date: $1,328,730,345.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Outstandine at February 29.1996 Class Common Stock, $1 par value 48,098,836 shares DOCUMENTS INCORPORATED BY REFERENCE III Portions of definitive proxy statement dated March 28,1996 for Annual Meeting of Stockholders to be held May 8,1996.
9 i'
8-Boston Edison Company i
Form 10-K Annual Report December 31, 1995 Part'I Page Item 1. Business 2 Item 2. Properties and Power Supply 9 i
Item 3 3. Legal Proceedings 11 Item 4. Submission of Matters to a Vote of Security Holders 12 Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 16 Item 6. Selected Financial Data 17 Item, 7. Management's Discussion and Analysis 18 Item 8. Financial Statements and Supplementary Financial Information 30 Item 9. Changes in and Disagreements with Accountants on
, Accounting and Financial Disclosure 52 l
'1
[ Part III Item 10. Directors and Executive officers of the Registrant 53 l
Item 11. Executive Compensation 53 q
)
Item 12. Security ownership of Certain Beneficial owners and i Management 54 l
Item 13. Certain Relationships and Related Transactions 54 l l
Part f/ l
. I Item 14. Exhibits, Financial Statement Schedules and Reports on l Form 8-K- 55 c
1
S Part I Item 1. Business ,
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(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.
The Company has an unregulated subsidiary, Boston Energy Technology Group (BETG), in which it has authority from the Massachusetts Department of Public Utilities (DPU) to invest up to S45 million. This wholly owned subsidiary engages primarily in energy conservation services and the production of water i treatment systems. In 1996 BETG entered into a joint venture to build a i series of ice-based cooling systems. BETG's investment in this joint venture, Northwind Boston, is not material. The Company does not currently have a substantial investment in BETG and does not expect the subsidiary to significantly impact the results of operations in the next several years.
(b) Financial Information about Industry 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 miles, 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 million. In 1995 the Company served an average of 654,000 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:
1995 1994 1993 Retail electric revenues:
Commercial 50% 50% 49%
Residential 28% 28% 28%
Industrial 9% 9% 10%
other 2% 2% 1%
Wholesale and contract revenues 11% 11% 12%
2
O l
t Sources and Availability of Fuel The Company owns two stations whose_ generating units have the ability to burn oil, natural gas or both, one nuc.nar-power station and ten combustion. turbine generators. Refer also to the company-owned Facilities section of Item 2.
The Company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:
I
_ Percentage of Company Average Cost of Fuel 'i Generation by Source (%) ($ per Million BTU) 1995 1994 1993 1992 1991 1995 1994 1993 1992 i
1991 l
[ 011 17.5 27.8 31.3 33.7 42.8 2.66 2.35 2.38 2.40 2.60 Gas 39.9 31.6 24.3 25.7 24.9 2.20 2.28 2.67 2.55 2.08 Nuclear 42.6 40.6 44.4 40.6 '32.3 0.43 0.50 0.51 0.52 -0.56 The majority of the Company's residual oil purchases consists of imported oil acquired primarily from international suppliers. The Company has contracts j l with major oil companies that can supply most of its estimated requirements, '
i assuming no major disruptions in oil producing regions. Within contract l provisions, the company has the ability to purchase significant amounts of oil i
{ in the spot market when it is economical to do so.
]
A portion of the Company's natural gas is supplied on an interrupt.ible basis '
by contract. These contracts. permit. interruptions in deliveries by the !
supplier when natural gas pipeline capacity is unavailable. The Company is l 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 (DEP). The l Company has arrangements for a firm supply of natural gas to run the station I at a minimum level and is developing a least-cost plan for operating beyond {
this minimum level which principally utilizes interruptible gas supplies or ;
short-term capacity purchases. I In order to obtain nuclear fuel for use at Pilgrim Station, the Company must obtain supplies of uranium concentrates and secure contracts for these
, concentrates to go through the processes of conversion, enrichment and l fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 1998, 2000, 1998 and 2012,'respectively.
~ Franchises Through its charter, which is unlindted 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 Company's electric transmission 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 DPU. The rights to these locations are-not limited in time, but are. net vested and are subject to the action of these authorities
.and the legislature, b ,
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. _ - _. . =. ----__. - ----__ ~
f Seasonal Nature of Business I i
The Conpany's kWh sales and revenues are typically higher in the winter and l summer than in the spring and fall as sales tend to vary with weather conditions. In addition, the Company bills higher base rates to commercial !
and industrial customers during the billing months of June.through September i as mandated by the DPU. Accordingly, greater than half of the Company's ,
annual earnings typically occurs in the third quarter. Refer also to the <
Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8.
l Working Capital Practices h The Company has no special practices with respect to working capital that would be considered unusual for the electric utility industry or significant 3
for the understanding of the Company's business. t i
Customer Dependence l
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No material portion of the Company's business is dependent upon one or a few customers. !
Government Contracts l
No material portion of the Company's business is subject to renegotiation or .;
termination of government contracts or subcontracts. r Conpetitive conditions The Company is operating in an increasingly competitive environment.
Competitive pressures on the electric utility industry have increased due oa variety of factors, including legislative and regulatory proceedings at both federal and state levels and changes in customer expectations. The trend is '
toward prbmetion of increased competition through modified regulation of the industry.
To date the effects of competition have been most prominent in the wholesale !
electric market. In response to increased competition from other electric :
utilities and nonutility generators to sell electricity for resale, the l Company secured long-term power supply agreements with its six wholesale ;
customers that set rates through 2002 and beyond, t
As discussed in the Competition section of Item 7, the Federal Energy ,
Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) in !
March 1995 addressing open transmission access and recovery of previously ~
incurred costs. The provisions in the NOPR provide a framework for significant changes in the electric utility industry. ;
4 Direct competition with other electric utilities and other energy suppliers [
for retail electricity sales is still subject to certain limitations. The ;
company and other Massachusetts electric utilities are currently protected in i several ways by the DPU and municipal statutes against other utilities ,
offering service to retail customers in their service areas. Another electric i utility may not extend its service area to include municipalities other than those named in its agreement of association or charter without DPU ,
authorization granted after notice and public hearing. Also, another company l may not obtain an initial location for its lines in a municipality served by !
the Company without the approval of municipal authorities, subject to the '
right of appeal to the DPU. Additionally, a municipality may not engage in ,
the electric utility business without complying with statutes requiring '
l 4
s specific city or town approval and the purchase of Company property within municipality limits.
Despite the limitations on direct competition, the Company has been i experiencing some forms of increased competition in the retail electric market. Competition currently 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, current legislation allows industrial and large commercial customers to own and operate their own electric generating units. Large facilities may also factor the cost of electricity into their decisions to relocate to new service territories. ;
Electric utilities are thus under increasing pressure to discount rates. '
In August 1995 the DPU issued an order on restructuring of the electric utility industry. The order provides for Massachusetts-based electric ,
l utilities to restructure their operations to encourage more competition for ;
customers. Refer to the Competition section of Item 7 for a discussion of the DPU order and the Company's involvement in the restructuring proceedings.
In addition to its involvement in the DPU's restructuring proceedings, the company is actively responding to the current and anticipated' changes in the l industry in several ways. In 1995 the Company reorganized into separate business units and reduced its workforce in order to strengthen its competitiveness as discussed in Note F to the Consolidated Financial Statements. It also continued to develop customer alliances and provided economic development rates to some customers. In addition, the Company currently has a special lower rate available for a small number of large nanufacturing customers on a lindted basis and recently implemented a _ one-year pilot program that uses a competitive market index to set electric rates for a limited number of customers. These actions all signify the Company's commitment to be a competitively priced, reliable provider of energy.
Research Activities The Company actively participates in several industry sponsored research activities. Related expenditures, included in other operations and naintenance expense on the consolidated income statement in Item 8, were not material in 1995.
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 can require modification of existing' facilities or curtailment or termination of operations at these facilities, 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. The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements.
The Company's environmental-related capital expenditures for the years 1996 through 2000 are currently expected to total $17 million, including $4.5 ndllion in 1996 and $3.5 ndllion in 1997. Additional expenditures could be required as changes in environmental requirements occur.
The Company is required by the DEP to clean up approximately 40 properties that it owns or operates in which hazardous materials were previously spilled 5
or released. In addition, the company has exposure to potential joint and several liability for the cleanup of approximately ten multi-party hazardous d waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites.
Litigation or negotiations among the parties and with regulatory authorities is in process concerning the scope and cost of cleanup and the sharing of costs among the potentially responsible parties for several of these sites.
The Company's potential hazardous waste liabilities are described further in the Environmental section of Item 7.
Spent nuclear fuel and low-level radioactive waste (LLW) result from the operations of Pilgrim Station. Uncertainties continue to exist regarding the ultimate disposal of both the spent nuclear fuel and LLW. Refer to Note E to the Consolidated Financial Statements in Item 8 for further discussion regarding spent nuclear fuel and LLW disposal.
As a facility which treats and stores hazardous wastes, Pilgrim Station is required to be licensed by the United States Environmental Protection Agency (EPA). Pilgrim has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive.
The Company is subject to regulation by the EPA and the DEP relative to emissions from its fossil fuel-fired generating units under federal and l Massachusetts clean air laws, including the 1990 Clean Air Act Amendments.
l These regulations require the installation of various emissions controls and, I
in certain cases, the use of low sulfur content fuels. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section of Item 7.
The Company is also. subject to regulation by the EPA and the DEP with respect to discharges of effluent from its generating stations into receiving waters.
The federal Clean Water Act and the Massachusetts Clean Waters Act require the Company to receive permits that limit discharges in accordance with applicable water quality standards and are subject to renewal. The Company has the required discharge permits for each of its electric generating stations.
Public concern continues regarding electromagnetic fields ( EMF) associated with electric transudssion and distribution facilities and appliances and wiring in buildings and homes. These concerns include the possibility of adverse health effects as well as perceived effects on property values. Refer to the Environmental section of Item 7 for a discussion of the EMF issue.
Number of Employees The Company had 3,518 full-time and 26 part-time utility employees as of January 1, 1996, 2,342 of which are represented by two Aocals of the Utility Workers Union of America, AFL-CIO. The locals' labor contracts are effective through 2000. BETG had 46 full-time employees.
(d) Financial Information about Foreign and Domestic Operations and Export Sales 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.
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l (e) Additional Information i
Regulation l
The Company and its wholly owned subsidiary, Harbor Electric Energy Company !
(HEEC), operate primarily under the authority of the DPU, whose jurisdiction !
includes supervision over retail rates for electricity, financing, investing i and accounting. In addition, the FERC has jurisdiction over various phases of the Company's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of that power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation.
The company is required to submit to the DPU annual performance standards l applicable to its generating units and other units from which the company purchases power through long-term contracts. Under this generating unit i performance program, the Company provides quarterly progress reports to the DPU. The DPU has the right to reduce subsequent fuel and purchased power !
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 ,
i company has not yet received orders from the DPU for the performance years i ended October 1994 and October 1995. The Company believes that its current .
provision for refunds is sufficient to cover pot =ntl.1 refunds, i
The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A i license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which was issued in 1972 and expires in 2012.
Continuing NRC review of existing regulations and certain operating l occurrences at other nuclear plants have periodically resulted in the t
imposition of additional requirements for all domestic nuclear plants, 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 imposition of monetary civil penalties. In addition, tne 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.
l Nuclear power continues to be a subject of political controversy and public ,
debate manifested from time to time in the form of requests for various kinds !
of federal, state and local legislative or regulatory action, direct voter initiatives or referenda or litigation. The Company cannot predict the extent, cost or timing of any modifications to Pilgrim Station which could be necessary in the future as a result of additional regulatory or other requirements, nor can it determine the effect of such future requirements on i
the continued operation of Pilgrim Station. The Company continues to evaluate the operation of the station from the standpoint of safety, reliability and economics and believes that such continued operation is in the best interests of the Company and its customers.
l l The Company also owns 9.5% of the common stock of Connec't'icut Yankee Atomic l
Power Company, which owns a nuclear generating unit. ' Northeast Utilities, the majority owner of Connecticut Yankee, operates the unit. In March 1996 the n
c 1 ,
l NRC ordered Northeast Utilities to submit a plan within 30 days verifying operational! compliance with licensing documentation at the Connecticut Yankee '
unit and another unit owned and operated by Northeast Utilities, or risk .
l having the plants shut down. This order follows noncompliances discovered at
[
two of Northeast Utilities' other nuclear units. The Company is unable to -
determine at this time what the results of the NRC order will be on the operations of the Connecticut Yankee unit, or what the impact would be on the ,
Company if the unit were to be shut down.
e i
Capital Expenditures and Financings !
The Company's most recent estimates of capital expenditures, allowance for i funds used during construction ( AFUDC) , long-term debt maturities and sinking !
fund requirements for the years 1996 through 2000 are as follows: !
(in thousands) 1996 1997 1998 1999 2000 Plant !
expenditures $160,000 $140,000 $130,000' $120,000 $110,000 [
Nuclear fuel expenditures 48,000
(
0 27,000 13,000 29,000 AFUDC (1) 2,000 2,000 2,000 2,000 2,000 Long-term debt 101,600 101,600 101,600 1,600 166,600 Preferred stock ,
sinkina fund 2,000 2,000 2,000 2,000 2,000 (1) Excludes AFUDC on nuclear fuel. 6 The Company conducts a continuing review of its capital expenditure and financing programs. These programs and, therefore, the estimates shown above l are subject to revision due to changes in regulatory requirements,
- environmental standards, availability and cost of capital, interest rates and ;
other assumptions.
Plant expenditures in 1995 were $181 ndllion and consisted primarily of ;
additions to the Company's transmission and distribution systems and nuclear generation ficility. Significant projects included spending of $20 million for the replacement of the main turbine rotors at Pilgrim Station and $17 million for the replacement of electric system property. !
In 1994 the DPU approved the Company's financing plan to issue up to $500 t million of securities through 1996 using the proceeds to refinance short and long-term securities and for capital expenditures. Refer to Notes J and K to '
the Consolidated Financial Statements in Item 8 for specific information relating to the Company's financing activities.
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Item 2. Properties and Power Supply Company-owned Eacilities The Company's total electric generation capacity consisted of the followino: '
Year Unit Location Capacity
- Type Installed Pilgrim Nuclear Plymouth, Mass. 669 Nuclear 1972 Power Station New Boston Station South Boston, Mass. 760 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, Mass.
Units 4-5-6 399 Fossil 1957-1961 Unit 7 592 Fossil 1975 Combustion turbine 14 Fossil 1969 ;
generator Combustion turbine Various 284 Fossil 1966-1971 cenerators (nine)
(a) In MW based on winter capability audit results.
All of the Company's steam fossil fuel-fired generating units are located at tide water and have access to fuel oil storage and/or natural gas or oil pipelines from nearoy suppliers.
The Company also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil-fired unit located in Yarmouth, Maine, began operations in 1978 and is operated by Central Maine Power Company.
Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and non-utilities and its participation in the New England Power Pool as further described in this item.
The Company's significant items of property consist of electric generating stations, substations and service centers, and are generally located on Company-owned land. The Company's high-tension transmission lines are generally located on land either owned by the Company or subject to easements in its favor. The Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under perndssion granted by municipal and other state authorities.
As of December 31, 1995, the Company's transmission system consisted of 362 ndles of overhead circuits operating at 115, 230 and 345 kV and 156 ndles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 46 transmission or combined transmission and distribution substations with transformer capacity of 10,612 megavolt amperes (16 01), 69 distribution substations with transformer capacity of 1,143 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 237 customers' substations. The overhead and underground j distribution systems cover 4,652 and 892 miles of streets, respectively.
HEEC, the company's regulated subsidiary, has a distribution system that I consists principally of a 4.1 mile 115kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts.
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. _ _ - _ - . .-. - - _ . ~ - - - - - - --. -- _ __ - - _ .
9 I i The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company
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plans for the construction of certain new generation or transmission facilities based upon findings that such facilities are consistent with state r public health, environmental protection and resource use and development '
policies. The company currently has one proceeding before the EFSB, which concerns proposed transmission and station facilities in Hopkinton and Milford, Massachusetts.
Long-Term Power Contracts f
i Refer to Note o to the Consolidated Financial Statements in Item 8 for further
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information regarding the following contracts. The Company also has short-term agreements with several other utilities for varying periods for purchases of system and unit power, for sales of Company system and unit power and for i transmission services.
Utility Purchase Contracts:
The Company has a long-term contract with a subsidiary of Commonwealth Energy i System in which it receives 25% of the output of an oil-fired electric generating unit. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return on investment.
The Company has two long-term purchased power contracts with the Massachusetts ,
Bay Transportation Authority (.BTA)M for the availability of two of the MBTA's '
jet turbines. The MBTA retains the right to utilize the jets for its own emergency use and for testing purposes while the Company retains New England .
Power Pool credit for their capacity and output.
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The Company has a contract to purchase 9.5% of Connecticut Yankee's nuclear l generating unit's output and is obligated to pay Connecticut Yankee 9.5% of (
its fixed and operating costs plus an annual return on investment.
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Non-Utility Generator Purchase Contracts: :
The Company currently purchases 533 MW of capacity and associated energy from non-utility generators. These purchases are from Ocean State Power, Northeast Energy Associates, L'Energia and MassPower. The company also purchases power -
from two small hydro-electric facilities. ,
Sales Contracts:
1 The company has agreements with Commonwealth Electric Company, a subsidiary of i Commonwealth Energy System, and with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, under which Commonwealth and Montaup each purchase 11% of the capacity and corresponding energy of Pilgrim Station and 1 pay 11% of the unit's fixed and operating costs plus an annual return on >
investment. Commonwealth and Montaup have also agreed to indemnify the Company to the extent of 11% each of all losses, liability or damage not covered by insurance resulting from the operation, condemnation, shutdown or retirement of the unit. In addition, the Company has similar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station.
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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 najor generating and transmission facilities in the region.
To obtain maximum benefits of power pooling, the electric facAlities 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 Company-owned generating f acilities by NEPEX may be affected by minimally increasing energy requirements and any additions to New England generation capacity.
The table below sets forth certain information as of the date of the Company's 1995-1996 winter and 1995 summer peak loads:
December 11, 1995 August 16, 1995 (winter 1995-96) (summer 1995)
NEPEX utilities installed capacity:
Seasonal maximum rating 27,187 MW 25,637 MW Seasonal normal rating 26,839 MW 25,353 MW NEPEX peak load 19,167 MW 20,486 MW Company territory peak load 2.458 MW 2.785 MW The Company's net capacity was 3,667 MW at its winter peak and 3,445 MW at its summer peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,341 MW and 3,306 MW, respectively.
NEPOOL participants have two agreements with Hydro-Quebec of Canada for hydro-electric power. The first agreement, Phase I, provides up to three million MWH of hydro-electric power to NEPOOL annually through 1997. The second agreement, Phase II, is a firm contract that provides seven million MWH of hydro-electric power annually through 2001. The price of the Phase II energy is based on the average cost of fossil fuel in New England for the previous year. The contract price is 80% of that average through 1996 and will be 95%
l of that average in 1997-2001. The Company receives capacity credit through l NEPOOL for approximately 11% of the generation equivalent of the total Hydro-Quebec interconnection, j
The Company has an approximately 11% equity ownership interest in the two companies which own and operate the Phase II transndssion f acilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 1995, the Company's portion of these guarantees was approximately S19 million.
Item 3. Legal Proceedings 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 46 employees affected by the Company's 1988 reduction in force. Legal counsel continues to vigorously defend this case. The 11
Company has also been named as a party in a lawsuit 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 are claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. The Company believes that it has a strong defense in this case. It is also involved in certain other legal matters. The Company is unable to fully determine a range of reasonably possible litigation costs in excess of amounts previously accrued, although based on the information currently available, it does not expect that any such additional costs will have a material impact on its financial condition.
However, 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.
Also refer to the Environmental section in Item 7 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 1995.
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l Executive Officers of the Registrant '
l The names, ages, positions and business experience during the last five years I of all the executive officers of Boston Edison Company and its subsidiaries as of March 1, 1996 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding 4 between any Company officer and another person pursuant to which the officet was elected. Officers of the company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until j their respective successors are chosen and qualified. l l
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Business Experience Name, Age and Position During Past Five Years I
l Thomas J. May, 48 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 Chief Executive Officer (1994-1995), President and Chief I operating Officer (1993-1994) and Executive Vice President (1990- I 1993); Director (since 1991)
Chairman of the Board and Chief l Executive Officer and Director, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp. and Ener-G-Vision, Inc.; Chairman of the Board and Director, REZ-TEK International Corp. and Coneco corp.
E. Thomas Boulette, 53 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 L. Carl Gustin, 52 Senior Vice President - Corporate Senior Vice President - Corporate Relations (since 1995), Senior Relations Vice President - Marketing &
Corporate Relations (1989-1995)
John J. Higgins, Jr., 63 Senior Vice President - Human Senior Vice President - Human Resources (since 1990)
Resources 13
Business Experience Name, Age and Position During Past Five Years Douglas S. Horan, 46 Senior Vice President and General Senior Vice President and Counsel (since 1995), Vice General Counsel President and General Counsel (1994-1995), Deputy General Counsel (1991-1994) and Associate General Counsel (1986-1991)
Director and General Counsel, Harbor Electric Energy Company; Director, Boston Energy Technology Group James J. Judge, 40 Senior Vice President and Senior Vice President and Treasurer (since 1995), Assistant Treasurer Treasurer (1989-1995) and Director - Corporate Planning (1993-1995)
Senior Vice President, Treasurer and Director, Harbor Electric Energy Company and Boston Energy Technology Group; Director, ,
Enar-G-Vision, Inc., TravElectric '
Services Corp. and REZ-TEK International Corp.
Ronald A. Ledgett, 57 Senior Vice President - Fossil Senior Vice President - Fossil (since 1995), Senior Vice President - Power Delivery (1991-1995) and Director, Special Projects (1989-1991)
Alison Alden, 47 Vice President - Sales & Service Vice President - Sales & Service (since 1993) and Director -
Organization Development (1990-1993)
Director, Harbor Electric Energy Company, Boston Energy Tcmhnology Group and Coneco Corp.
Robert A. Ruscitto, 51 Vice President - Field Service and Vice President - Field Service Electric Delivery (since 1995),
and Electric Delivery Vice President - Electric Customer Service (1994-1995), General Manager, Electric Customer Service (1992-1994) and Manager, Metropolitan Transmission &
Distribution Department (1990-1992) 14
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i7 Business Experience Name, Age and Position During Past Five Years Robert J. Weafer, Jr., 49 Vice President - Finance, Vice President - Finance, Controller and Chief Accounting Controller and Chief Officer (since 1991), Controller Accounting Officer (1988-1991) and Chief Accounting Officer (1983-1991)
Theodora S. Convisser, 48 Clerk of the Corporation (since clerk of the Corporation 1986) and Assistant General Counsel (since 1984) i
' Clerk, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Ener-G-Vision, Inc.,
REZ-TEK International Corp. and Coneco Corp.
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I' Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters .
r (a) Market Information The Company's common stock is listed on the New York and Boston Stock Exchanges.
Following are the reported high and low sales prices of the company's common stock on the New York Stock Exchange as reported daily in the Wall Street ,
Journal for each of the quarters in 1995 and 1994:
1995 1994 High Low High Low First quarter $25 1/2 $23 1/8 $29 7/8 $26 Second quarter 27 23 3/8 29 1/8 25 1/4 Third quarter 27 1/2 24 1/2 27 5/8 22 3/4 Fourth cuarter 29 1/2 26 3/4 24 1/4 21 1/2 (b) Holders l As of December 31, 1995, the company had 38,205 holders of record of its common stock.
(c) Dividends l Following are the dividends declared per share of common stock for each of the l quarters in 1995 and 1994:
1995 1994 First quarter S0.455 S0.440 l Second quarter 0.455 0.440 l Third quarter 0.455 0.440 l [ourth cuarter 0.470 0.455 (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, 1995:
Ratio of earnings to fixed charges 2.38 Ratio of earnings to fixed charges and preferred stock dividend rec;uirements 2.00 l
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r Item 6. Selected Financial Data i l
i The following table summarizes five years of selected consolidated financial !
data of the Company (in thousands, except per share data). I I
1995 1994 1993 1992 1991 I l
Operating revenues $1,628,503 $1,544,735 $1,482,159 $1,411,753 $1,354,501 ,
l Net income 112,310 125,022 118,218 107,298 94,670 !
Earnings per common share 2.52 (a) 2.41 2.28 2.10 1.96 Total assets 3,643,849 3,616,576 3,476,601 3,294,212 3,098,742 Long-term debt 1,160,223 1,136,617 1,272,497 1,091,073 1,136,765 Redeemable preferred /
preference stock 217,000 219,000 221,000 221,000 221,333 l
Cash dividends declared per common share 1.835 1.775 1.715 1.655 1.595
_(a) Excludes $0.44 per share restructuring charge.
Certain reclassifications were made to the data reported in prior years to conform with the method of presentation used in 1995.
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Item 7. Management's Discussion and Analysis Rate Regulation The rates we charge our retail customers are regulated by our state regulators, the Massachusetts Department of Public Utilities (DPU). In 1992 the DPU approved a three-year settlement agreement effective November 1992.
This agreement provided us with retail rate increases, allowed for the recovery of demand side management (DSM) conservation program costs, specified certain accounting adjustments and clarified the tindng and recognition of
.certain expenses. The agreement also set a limit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any penalties or rewards from performance incentives.
The retail rate increases consisted of two annual base rate increases of $29 ndllion 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.
In addition to the retail rate increases, our results of operations were affected by the recovery of DSM program costs, _ accounting adjustments and the timing and recognition of certain expenses as further described in the following Results of Operations section.
We did not make a base rate filing upon the expiration of the 1992 settlement agreement, therefore base rates currently remain in effect at their 1995 levels.
In February 1996 we filed an industry restructuring plan with the DPU in response to its August 1995 order on restructuring the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in an unbundling of our currently integrated monopoly business into a separate competitive electric production business and a regulated electric distribution business. Refer to Outlook for the Future for further information regarding the restructuring of the electric utility industry in Massachusetts.
Results of' operations 1995 versus 1994 Earnings per common share were $2.08 in 1995 and $2.41 in 1994. Earnings in 1995 reflect a one-time charge of $34 ndllion (S20.7 million net of tax, or
$0.44 per share) associated with our corporate restructuring. The charge reflects the costs of early retirement and severance programs implemented as part of our organizational streamlining and reorganization into business units. Excluding the one-time 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 effective November 1994, the ending of amortization of deferred cancelled nuclear costs in 1994, a 1.2% increase in retail kWh sales and lower revenue reserve provisions. These positive impacts were partially offset by higher income tax, property tax, nuclear outage amortization and employee benefit expenses, and an award received on an eminent domain case in 1994.
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Qperating revenues l
Operating revenues increased 5.4% over 1994 as follows:
(in thousands)
Retail electric revenues $59,419 Demand side management revenues 8,783 >
Wholesale and other revenues 11,126 Short-term sales revenues 4,440 Increase in operatino revenues $83,768 Retail electric revenues increased $59 million. Approximately $28 million of the increased revenues was due to the November 1994 base rate increase and approximately $11 million was due to the increase in retail kWh sales. Fuel and purchased power revanues increased $11 million as a result of the timing effect of fuel and purchased power cost recovery. However, these higher revenues.are offset by higher fuel and purchased power expenses and have no net effect on earnings. Performance revenues, which vary annually based on the operating performance of Pilgrim Station, increased $9 ndllion primarily I
due to a higher performance rate effective in 1995 and a 17% increase in '
generation.
I A new annual conservation charge for recovery of demand side management
- program costs was implemented in February 1995. Under this charge all 1995
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l program costs were recovered in 1995. This resulted in higher DSM revenues and expenses than in prior years when certain program costs were capitalized for recovery over six years.
l The net increase in wholesale and other revenues is primarily due to a $10 l million decrease in revenue reserve provisions, which are primarily related to wholesale customer contract issues.
The increase in short-term sales revenues is due to higher short-term sales resulting from higher generating availability in 1995. Revenues from short-term sales serve to reduce fuel and purchased power billings to retail customers and therefore have no net effect on earnings.
qperating expenses Total fuel and purchased power expenses increased $22 million primarily due to the timing effect of fuel and purchased power cost collection. Excluding the timing effect, fuel expense increased 5% due to an 8% increase in fossil station generation while purchased power expense was unchanged. Fuel and purchased power expenses are substantially all recoverable through fuel and purchased power revenues.
Other operations and maintenance expense increased 0.9% over 1994. Employee benefit expenses increased primarily due to higher postretirement benefit expenses recorded in accordance with the 1992 settlement agreement. We also incurred higher administrative costs in positioning the company for changes in the industry, which were offset by 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.
i The $34 million one-time restructuring charge was incurred over the third and l fourth quarters of 1995 as a result of our corporate reorganization announced j in July 1995. As part of the reorganization 330 employees elected to retire j under enhanced retirement programs and 149 employees whose positions were eliminated became eligible for benefits under a special severance program.
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! See Note F to the Consolidated Financial Statements for additional information. We expect to achieve ongoing savings as a result of the restructuring, with a payback period of approximately one year.
l Depreciation and amortization expense increased due to a higher average depreciable plant balance.
In 1994 we fully expensed the remaining deferred costs of the cancelled l Pilgrim 2 nuclear unit.
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- In the third quarter of 1995 we changed the amortization period of deferred nuclear outage costs to two years from five years as discussed in Note B to the Consolidated Financial Statements. The remaining $9 million of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 was written off. Approximately $15 million of deferred costs from the 1995 refueling outage is being amortized over two years.
The increase in demand side management prograns expense is related to the increase in DSM revenues. Beginning with the annual conservation charge implemented in February 1995, DSM costs are recovered and expensed primarily in the year incurred. The 1995 expense includes $31 million of 1995 program costs and $14 million of amortization of costs capitalized in 1992 through 1994.
Property and other taxes increased primarily due to higher Boston property taxes resulting from capital additions.
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 taxes made in 1994 in accordance with the 1992 settlement agreement.
Other income The net decrease in other income is primarily due to a $5.7 million gain recognized in 1994 from a court ruling on a 1989 eminent domain taking of certain of our property.
Interest charges Interest charges on long-term debt increased due to a $125 million debentures 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. Allowance for borrowed funds used during construction UNFUDC), which represents the financing costs of construction, decreased due to a lower construction work in progress balance and shorter construction periods, partially offset by a higher AFUDC rate related to the higher short-term interest rates.
1994 versus 1993 Earnings per common share were $2.41 in 1994 and $2.28 in 1993. The increase in earnings was primarily the result of the expiration of a long-term purchased power contract in October 1993, a $29 million annual retail base rate increase effective November 1993, a 2.0% increase in retail kWh sales and an award relating to an eminent domain case. These positive changes were partially offset by higher operations and maintenance, depreciation and amortization and income tax expenses.
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Operating revenues Operating revenues increased 4.2% over 1993 as follows:
, (in thousands)
! Retail electric revenues $62,945 Demand side management revenues 5,056 l-Wholesale and other revenues (6,644) I Short-term sales revenues 1,219 !
Increase in operatino revenues $62,576 I l Retail electric revenues increased $63 million. The November 1993 and 1994 :
l base rate increases resulted in $29 million of the increased revenues, and f approximately $6 ndllion was due to the 2% increase in retail kWh sales. Fuel i and purchased power revenues increased $28 million primarily due to the recovery of certain new purchased power expenses. In accordance with the 1992 settlement agreement, specific revenues related to the purchased power contract that expired in October 1993 were not affected.
Wholesale and other revenues decreased primarily due to an $8.5 ndllion increase in revenue reserve provisions in 1994 related to certain wholesale l customer contract issues.
Operating expenses
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Total fuel and purchased power expenses decreased $27 million. Fuel expense decreased partly due to lower fossil fuel prices and a 12% decrease in nuclear ;
output. Purchased power expense reflects lower costs associated with the j l long-term contract that expired in October 1993, partially offset by the costs of new contracts. The timing effect of fuel and purchased power cost collection also contributed to the decrease in fuel and purchased power expenses.
Other operations and naintenance expense increased 7.4% primarily due to higher employee benefit expenses. Pension expense increased $20 million due to a higher contribution made to the pension plan for the year. In accordance l with the 1992 settlement agreement, we recorded pension expense in the amount .
l of the contribution to the plan.
Depreciation and amortization expense increased primarily due to a higher depreciable plant balance.
In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. In accordance with the 1992 settlement agreement we did not expense any of these costs in 1993.
Amortization of deferred nuclear outage costs in 1994 and 1993 consists of amounts related to the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we deferred approximately $14 million of refueling outage costs. We began to amortize these costs in June 1993 over five years as approved in the 1992 settlement agreement.
l The $2 million decrease in demand side management programs expense was due to the timing of recovery of program costs. DSM expense includes some program costs recovered over twelve months and other program costs recovered over six years. The 1994 expense consists of 322 million of costs primarily related to t
1994 expenditures and $13 ndllion of costs capitalized in 1992 through 1994.
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Municipal property and other taxes increased primarily as a result of higher Boston property taxes due to a tax rate increase and capital additions.
Our effective annual income tax rate for 1994 was 31.4% vs. 23.4% for 1993.
Both rates were reduced from the statutory rate by adjustments to deferred income taxes of $10 million in 1994 and $20 ndllion in 1993 made in accordance with the 1992 settlement agreement.
Other income In November 1994 a court ruling became effective providing us with an additional $5.7 million gain on a 1989 eminent domain taking of certain of our property.
Interest charges Total interest charges did not change significantly. Interest charges on long-term debt decreased due to the first mortgage bond and debenture redemptions in 1994 and the significant first mortgage bond refinancing in 1993 at lower interest rates. This decrease was partially offset by higher amortization of redemption premiums, other interest charges increased due to higher short-term interest rates part ally offset by a lower average short-term debt level. AFUDC increased as a result of a higher AFUDC rate related to the higher short-term interest rates.
Electric Sales and Revenues Electric sales Retail kWh sales increased 1.2% in 1995 primarily due to the positive effects of a stronger economy on commercial customers. This sector represents approximately 50% of our electric operating revenues.
Demand side management conservation programs are designed to assist customers in reducing electricity use and, therefore, result in lower growth in electricity sales. We receive approval from our state regulators for DSM spending levels and recovery amounts through an annual conservation charge.
Through 1994 we collected from customers certain DSM program costs primarily in the year incurred and other DSM program costs over a six-year period. In 1995 a new annual conservation charge was implemented under which all 1995 program costs were recovered in 1995. We are also provided with incentives and recovery of lost revenues based on the actual reduction in customer electricity usage from these programs and a return on the costs that we are recovering over six years.
l Electric revenues As discussed in the Rate Regulation section, our 1992 settlement agreement provided us with two annual retail base rate increases of $29 ndllion effective in 1993 and 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 currently remain in effect ,
at their 1995 levels. Due to our continued commitment to controlling costs I and increasing operating efficiencies, maintaining these rate levels in our current regulatory environment is not expected to significantly affect our financial condition or results of operations.
l The annual performance adjustment charge provides us with opportunities to improve our financial results. The most significant potential impact of this I
22
i performance incentive is based on Pilgrim Station's annual capacity factor.
An annual capacity factor between 60% and 68% would provide us with approximately $51 million of revenues in the performance year ended October 1996. For each percentage point increase in capacity factor above 68%, annual revenues will increase by approximately $750,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease by approxinately $840,000. Pilgrim's capacity factor for the performance year ending October 1996 is currently expected to be approximately 91%, an increase from the 67% capacity factor achieved in the performance year ended October 1995. There are no najor outages scheduled for the current performance year. Pilgrim was out of service in November 1994 and for a 73-day refueling and maintenance outage in 1995. We earned approximately $49 ndllion in revenues related to Pilgrim's capacity f actor in the performance year ended October 31, 1995.
Pilgrim Station was shut down for 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, is subject to review by the DPU under a generating unit performance program.
Liquidity We meet our capital expenditure cash requirements primarily with internally generated funds. These funds provided for 95%, 98% and 77% of our plant and l nuclear fuel expenditures in 1995, 1994 and 1993, respectively. Our current estimate of plant expenditures for 1996 is $160 million. These expenditures '
will be used primarily to maintain and improve existing transmission and l distribution facilities. We expect plant expenditures to remain leve1 or decline slightly from the 1996 amount in the four years thereafter. In addition to capital expenditures we have long-term debt and preferred stock ]
j payment requirements of $103.6 million per year in 1996 through 1998, $3.6 l million in 1999 and $168.6 million in 2000.
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 currently have authority from our federal regulators, the Federal Energy Regulatory Commission (FERC), to issue up to $350 ndllion of short-term debt. We have a $200 ndllion revolving credit agreement and arrangements with several banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At l December 31, 1995, we had $126 million of short-term debt outstanding, none of '
which was incurred under the revolving credit agreement. In 1994 the DPU approved our financing plan to issue up to $500 million of securities through 1996 using the proceeds to refinance short and long-term securities and for capital expenditures. Refer to Notes J and K to the Consolidated Financial Statements for specific information relating to our recent financing activities.
Outlook for the Future Competition Competitive pressures on the electric utility industry have increased due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels and changes in customer expectations. The trend is 23
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toward promotion of increased competition through modified regulation of the industry.
To date the effects of competition have been most prominent in the wholesale electric market. In response to increased competition from other electric utilities and nonutility generators to sell electricity for resale, we secured long-term power supply agreements with our six wholesale customers that set rates through 2002 and beyond. In 1995, our largest retail customer, the Massachusetts Port Authority (Massport), issued a request for proposals for a wholesale supplier of electricity. We successfully retained Massport as a customer through a ten-year wholesale power supply agreement effective November 1995. We are awaiting approval of this agreement from the FERC.
In March 1995 the FERC issued a Notice of Proposed Rulemaking (NOPR) addressing open transmission access and recovery of previously incurred costs.
If approved, the NOPR would require all utilities with transmission systens to file open access tariffs at the FERC, to provide service under those tariffs l to transmission customers comparable to service provjded to their electric energy customers and to take service under the taritfs for wholesale purchases and sales. The NOPR also supports the full recovery of legitimate and verifiable costs previously incurred under federal and state regulation. The l
provisions in the NOPR provide a framework for significant changes in the electric utility industry.
1 We have also been experiencing increased competition in the retail electric market. Competition currently 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 nay pursue options to generate their own electric power or factor the cost of electricity into their decisions to relocate to new service territories. Electric utilities are thus under increasing pressure from these customers to discount rates, i In August 1995 the DPU issued an order on restructuring of the electric utility industry. The order provides for Massachusetts-based electric utilities to restructure their operations to encourage more competition for customers. It also includes the following principles for a restructured electric industry:
- provide the broadest possible customer choice
- provide all customers with an opportunity to share in the benefits of increased competition
- ensure full and fair competition in generation markets
- functionally separate generation, transmission and distribution services j
- provide universal service
- support and further the goals of environmental regulation
- rely on incentive regulation where a fully competitive market cannot exist, or does not yet exist i
The DPU order also set the following principles to guide the transition from a l regulated to a competitive industry structure:
- honor existing commitments
- unbundle rates for generation, transmission and distribution
- reduce rates in the near term
- naintain demand side management programs
- ensure an orderly and quick transition that minimizes customer confusion The order provides a reasonable opportunity for the recovery of net, l nonmitigatable potentially strandable costs (strandable costs), over a period 24
of up to ten years. These costs include investments in plant that might not be recoverable in a competitive market, liabilities for future decenadssioning of nuclear plants, the amounts by which certain purchase power contracts exceed the competitive price for generation, and prudently incurred regulatory assets. We are looking at possibilities for mitigating our potentially strandable costs, including potential revisions to depreciation and amortization periods.
The order establishes only general principles for the transition to a competitive market and does not establish a particular model for the new l industry structure. Each of the Massachusetts-based electric utilities is required to develop a plan for moving toward competition consistent with the DPU's order and encouraged to negotiate with all interested parties while doing so. We were one of three companies required to file a restructuring plan in February 1996. Our plan is consistent with the general principles outlined in the order, including unbundled rates for generation, transudssion l and distribution. It provides for and is based upon full recovery of l
strandable costs through a nonbypassable access charge. This charge is to be paid by customers as a condition of receiving service over our distribution system, which remains a monopoly function. We expect to enter into i negotiations with intervening parties that will result in new rates and performance incentives to be implemented in the new industry structure.
In addition to our involvement in the DPU's restructuring proceedings, we are actively responding to the current and anticipated changes in the industry in several ways. In 1995 we reorganized the company into separate business units in order to strengthen our competitiveness. These business units, Customer, Generating-Fossil, Generating-Nuclear and Corporate Services, were designed to sharpen management focus along our significant lines of operation while maintaining company-wide strategic goals. As a result of enhanced retirement programs and a special severance program offered during this corporate restructuring, we reduced our workforce by 12%. We expect to achieve ongoing
. savings as a result of the restructuring, with a payback period of I
approximately one year. We also continued to develop customer alliances and provided economic development rates to some customers. In addition, we currently have a special lower rate available for a small number of large manufacturing customers on a limited basis and we recently implemented a one-year pilot program that uses a competitive market index to set electric rates for a limited number of customers. These actions all signify our commitment to be a competitively priced, reliable provider of energy. We do not expect the economic development rates, the lower manufacturing customer rates or the pilot program to have a significant impact on our financial condition or results of operations.
l In the rate-regulated environment based on cost recovery that we have traditionally operated in, we are subject to certain accounting standards that are not applicabic to other businesses and industries. The standards allow us to record certain costs as regulatory assets instead of as expenses when incurred when we expect to receive future rate recovery of the costs. We believe that we currently meet the criteria of these standards. In addition to the specifically identified regulatory assets on our consolidated balance sheets, there may be differences in the carrying value of our net utility plant compared to what the amount would have been if we were not subject to rate regulation. These potential differences would be due to differing plant depreciable lives for regulatory and non-regulatory accounting standards. We have not yet fully determined-to what extent such differences may exist. The effects of competition and modified regulation could, in the near term, cause us to no longer meet the criteria for application of the regulatory accounting i standards for some of our operations. Should this occur we would have to take
! a noncash write-off of our affected regulatory assets and adjust our affected l
25 l
- . - - . - ~ - . - -. .- . --- - - - _ - . - _ - - . - . _ _ - _ - -.
\
plant balances if necessary by recording an addition to depreciation expense at that time. However,.the DPU order on industry restructuring provides a reasonable opportunity for recovery of these previously incurred costs, which are also provided for in our related plan. We expect to recover all strandable costs through our' distribution system, which we expect will remain rate-regulated, and therefore will continue to meet the criteria of these accounting standards. If it does not continue to be likely that we will recover all our regulatory' assets and generating plant costs as our restructuring plan is ultinately finalized, we would have to write off such portions that are no longer probable of. recovery in accordance with Financial -!
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived ,
Assets and for Long-Lived Assets to be Disposed Of. See Note M to the- '
Consolidated Financial Statements for information on this new accounting i standard. The nonrecovery of specifically identified and other embedded '
l regulatory assets or plant costs could have a naterial impact on our results of operations and financial condition. ,
Resource regulation In this period of transition in the electric utility industry we remain subject to current regulatory requirements. The DPU requires utilities to purchase power from qualifying nonutility generators at prices set through a bidding process. In a continuation of a dispute which originated in 1991, the DPU is currently investigating whether we should again be ordered to negotiate l a contract to purchase power from an independent power producer, JMC Altresco,
! Inc. We have consistently opposed this order since we do~not believe we need ;
, any new power for several years and the proposed contract would impose excessive costs on our customers. In 1995 we filed a motion to dismiss the matter, which is pending. We also filed testimony comparing'the cost of Altresco to projected market costs and hearings are currently ongoing. In a separate but related matter, we appealed the Massachusetts Energy Facilities
!- Siting Board's (EFSB) approval of construction of Altresco's proposed generating station based pr.rtly on the EFSB's failure to consider market information and forecasts.
We also currently remain subject to the DPU's integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs
-with all other supplies of energy. As a result of our 1994 IRM filing, the i DPU found that we did not have a need for additional generating capacity through 2001 and therefore were not required to issue a competitive request ,
for proposals for new generating capacity. Required updates to our IRM filing ,
have been postponed due to the current industry restructuring proceedings l ongoing at the DPU.
Nonutility business
}
, We have an unregulated subsidiary, Boston Energy Technology Group (BETG), in !
which we have authority from the DPU to invest up to $45 million. This wholly owned subsidiary engages primarily in energy conservation services and the l
production of water treatment systems. In 1996 BETG entered into a joint
- venture to build a series of ice-based cooling systene as an alternative to costly chemical systems. BETG's investment in this joint venture, Northwind Boston, is not material.
I We do not currently have a substantial investment in BETG and do not anticipate it significantly impacting our results of operations in the next j several years.
26 i
i Other Matters Environmental We are subject to numerous federal, utate and local standards with respect to waste disposal, air and water m ality and other environmental considerations.
These standards can require that ea modify our existing facilities or incur increased operating costs.
We own or cperate approximately 40 properties where oil or hazardous naterials were previously spilled or released. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability.
Through December 31, 1995, we have accrued approximately $7 ndllion related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any such additional costs to have a material impact on our financial condition. However, 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.
J 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 l disposal. In 1995 we regained access to the LLW disposal facility located in l Barnwell, South Carolina. Refer to Nc+ E to the Consolidated Financial Statements for further discussion rega ig spent nuclear fuel and LLW disposal.
As part of a 1991 DEP consent order, we are currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances. The station has the ability to burn natural gas, oil or both.
We have arrangements for a firm supply of natural gas to run the station at a minimum level and are developing a least-cost plan for operating beyond this minimum level which principally utilizes interruptible gas supplies or short-term capacity purchases.
The 1990 Clean Air Act Amendments require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel-fired generating units. The reduction will be accomplished by restricting sulfur dioxide
! emissions through a market-based system of allowances. We currently have i allouances that are in excess of our needs and which may be marketable. Any gain from the sale of these allowances nay be subject to future regulatory treatment. Other provisions of the 1990 Clean Air Act Amendments involve limitations on endssions of nitrogen oxides from existing generating units.
Combustion system modifications made to New Boston and Mystic Statiens, including the installation of low nitrogen oxides burners at New Boston, have 27
?
allowed the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain DEP air quality modeling studies currently in progress, additional emission reductions may also be required 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 concera continues regarding electromagnetic fields (EMF) associated with electric transmie; ion and distribution facilities and appliances and wiring in buildings and homes. Such concerns have included the possibility of adverse health ef fects caused by EMF as well as perceived ef fects 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. We support further 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 facilities in proceedings before regulators or in requests for legislation or regulatory standards concerning EMF levels. We have addressed issues relative to EMF in various legal and regulatory proceedings and in discussions with customers and other concerned persons; however, to date we have not been significartly affected by these developments. We continue to closely monitor all aspects of the EMF issue.
Litigation In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. We have also been named as a party in a lawsuit by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs are' claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. We believe that we have a strong defense in this case. 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 previously accrued, although based on the information currently available, we do not expect that any such additional costs will have a material impact on our financial condition. However,. 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. I New accounting pronouncement l
Statement of Financial Accounting Standards No. 121, Accounting for the i Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, is effective in 1996. This statement establishes accounting standards for recognizing and measuring asset impairment losses. Refer to Note M to the Consolidated Financial Statements f r,I more information regarding this statement and its potential effects.
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 materially from these statements.
Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.
28 +
1 I
- l The above sections include certain forward-looking statements about the effects of the industry restructuring process and our related plan, operating results, Pilgrim Station's performance and envirommental and legal issues.
The effects of the industry restructuring process currently underway at the DPU and our related plan could differ from our expectations. This could occur as regulatory decisions and negotiated settlements between utilities and intervenors are finalized during the restructuring process. In addition, the development of a competitive electric generation market and the impacts of actual. electric supply and demand in New England may affect the ultimate ;
results of the industry restructuring and our plan.
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 availability of operating supplies could materially affect our projected operating results.
i Pilgrim Station's performance could differ 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 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. 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.
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i Item 8. Financial Statements and Supplementary Financial Information Consolidated Statements of Income years ended December 31, (in thousands, except earnings per sharel__ 1995 1994 1993 Operating revenues 41,628,503 $1,544,735 S1,482,159 Operating expenses:
Fuel 170,337 156,951 170,799 Purchased power 365,469 356,874 370,049 Other operations and maintenance- 439,263 435,824 405,609 Restructuring costs 34,000 0 0 Depreciation and amortization 153,339 148,845 137,710 Amortization of deferred cost of cancelled nuclear unit 0 19,791 0 Amortization of deferred nuclear outage costs 18,933 7,721 6,546 Demand side management programs 45,125 35,438 37,504 ,
Taxes property and other 106,361 100,015 93,102 '
Income taxes 68,276 54,798 35,143 Total operating expenses 1,401,103 1,316,257 1,256,462 qperating income 227,400 228,478 225,697 Other income (expense), net (575) 3,979 211 Operating and other income 226,825 232,457 225,908 Interest charges:
Long-term debt 106,640 102,570 104,375 Other 12,642 12,343 9,778 Allowance for borrowed funds used during construction (4,767) (7,478) (5,463)
Total interest charges 114,515 107,435 107,690 Net income 112,310 125,022 118,218 Preferred dividends provided 15,571 15,765 15,705 Balance available for common stock S 96,739 $ 109,257 S 102.513 Weighted average common shares outstanding 46,592 45,338 44,959 Earninas ver share of common stock $ 2.08 6 2.41 S 2.28 Consolidated Statements of Petained Earnings years ended December 31, (in thousands) 1995 1994 1993 Balance at beginning of year $ 247,004 $ 218,292 $ 192,948 Net income 112,310 125,022 118,218 Subtotal 359,314 343,314 311,166 Cash dividends declared:
Preferred stock 15,571 15,765 15,705 Common stock 86,399 80,545 77,169 subtotal 101,970 96,310 92,874 Balance at end of year S 257,344 $ 247,004 S 218,292-The accompanying notes are an integral part of the consolidated financial statements.
30
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. l l Consolidated Balance Sheets December 31, (in thousands) 1995 1994 Assets. I Utility plant in service, at original cost $4,315,422 $4,074,810 i
l Less: accumulated depreciation 1,439,996 $2,875,426 1,344,452 $2,730,358 Nuclear. fuel 302,594 291,836 ;
Less: accumulated amortization 251,951 50,643 236,239 55,597 '
Construction work in progress 29,573 144,048 l Net utility plant 2,955,642 2,930,003
- Investments in electric companies, at equity 23,620 24,678 Nuclear decommissioning trust 102,894 82,831 Current assets:
! . Cash and cash equivalents 5,841 6,822 l Accounts receivable 219,114 189,361 '
Accrued unbilled revenues 37,113 32,240 i Fuel, materials and supplies, at average cost 59,631 71,560 Prepaid expenses and other 23,607 345,306 26,693 326,676 i Deferred debits:
Regulatory assets 156,774 198,148
- Intangible asset - pension 27,386 22,849 '
other 32,227 216,387 31,391 252,388 l Total assets $3,643,849 $3,616,576 l Capitalization and Liabilities Common stock equity $ 989,438 $ 915,747 ;
Cumulative preferred stock: 1 Nonmandatory redeemable series 123,000 123,000 Mandatory redeemable series 92,000 94,000 ,
Long-term debt 1,160,223 1,136,617 l Current liabilities:
Long-term debt / preferred stock due within one year
$ 102,667 $ 102,250 Notes payable 126,441 214,786
-Accounts payable 133,474 130,496 l Accrued interest 25,113 24,464 1 Dividends payable 25,351 23,533 l l
Pension benefits 32,602 31,908 !
Other 105,442 551,090 85,204 612,641 I Deferred credits: )
Power contracts 21,396 40,277 l I
Accumulated deferred income taxes 497,282 515,454 Accumulated deferred investment tax credits 62,970 67,048 Nuclear decommissioning reserve 113,288 92,404 other 33,162 728,098 19,388 734,571 Commitments and contingencies - -
Total capitalization and liabilities $3,643,849 S3,616,576 l l
The accompanying notes are an integral part of the consolidated financial l- statements.
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- l Consolidated Statements of Cash Flows years ended December 31, (in thousands) 1995 1994 1993 Operating activities: ;
Net income $112,310 $125,022 $118,218 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation 148,630 142,932 130,074 Amortization of nuclear fuel 19,029 18,810 21,816 Amortizatien of deferred cost of cancelled nuclear unit, net 0 19,067 0 Amortization of deferred nucl< r outage ,
costs 18,933 7,721 6,546 Other amortization 15,702 14,692 10,158 Deferred income taxes (21,115) (4,184) 10,303 _'
Investment tax credits (4,078) (4,092) (4,073)
Allowance for borrowed funds used during construction (4,767) (7,478) (6,463) '
Net changes in:
Accounts receivable and accrued unbilled revenues (34,626) (20,701) 13,206 Fuel, materials and supplies 7,202 3,093 9,722 Accounts payable 2,978 23,196 (18,916)
Other current assets and liabilities 26,485 35,217 25,660 Other, net 23,975 14,847 (20,437) .
Net cash provided by operating activities 310,658 368,142 295,814 Investing activities: ;
Plant expenditures (excluding AFUDC) (180,822) (198,771) (246,774) ;
Nuclear fuel expenditures (13,621) (21,934) (6,491)
Capitalized demand side management expenditures 0 (37,007) (37,156)
- Sale of plant assets, net 3,018 15,972 0 Nuclear d_ commissioning trust investments (20,063) (16,771) (15,189)
Electric company investments 1,058 (386) 1,106 Net cash used by investing activities (210,430) (258,897) (304,504)
Financing activities: {
Issuances: i Common stock 64,888 10,634 10,855 Preferred stock 0 0 40,000 Long-term debt 125,000 15,000 815,000 Redemptions: !
Preferred stock (2,000) (2,000) (40,000) :
Long-term debt (100,600) (50,000) (648,625)
Net change in notes payable (88,345) 10,635 (71,349)
Dividends paid (100,152) (95,460) (92,370)
Net cash provided (used) by financing activities (101,209) (111,191) 13,511 Net increase (decrease) in cash and cash equivalents (981) (1,946) 4,821 Cash and cash equivalents at the beginning of the year 6,822 8,768 3,947 Cash and cash eauivalents at the end of the year S 5,841 S 6,822 S 8,768 Cash paid during the year fort j Interest, net of amounts capitalized $113,945 $108,462 $103,720 Income taxes S 96,180 $ 46,074 $ 30,305 The accompanying notes are an integral part of the consolidated financial statements.
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I j Notes to Consolidated Financial Statements Note A. Nature of Operations l We are an investor-owned regulated public utility operating in the energy and j energy services business. This includes the generation, purchase, ;
l transmission, distribution and sale of electric energy and the development and I implementation of electric demand side management programs. A portion of our
! generation.is produced by a nuclear unit, Pilgrim Station. We supply I
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 89% retail and 11% wholesale in 1995.
Note B. Significant Accounting Policies l
- 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company and Boston Energy Technology Group. All significant intercompany transactions have been eliminated. Certain prior period amounts on the financial statements were reclassified to conform with the current presentation.
We follow accounting policies prescribed by our federal and state regulators, the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Public Utilities (DPU). We are also subject to the accounting and reporting requirements of the Securities and Exchange, Commission. The i financial statements 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 (SEAS 71) , under GAAP. The application of SEAS 71 results in I differences in the timing of recognition of certain expenses from that of other businesses and industries. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect 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 l We record revenues for electricity used by our customers but not yet billed at the end of each accounting period.
- 3. - Torecasted Ensel and Purchased Power Bates The rate charged to retail customers for fuel and purchased power allows for fuel and some purchased power costs to be billed to custon.ers using a ;
forecasted rate. The difference between actual and estimated costs is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.
33
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- 4. Depreciation and Nuclear Buel Aamortisation our physical property was depreciates ra a straight-line basis in 1995, 1994 and 1993 at composite rates of 3.10%, 3.11% and 3.^09% per year, respectively, i based on estimated useful lives of the various classes of property. The cost of deconadssioning Pilgrim Station is excluded from these depreciation rates.
When property units are retired, their cost, net of salvage value, is charged to accumulated depreciation.
The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for 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.
- 5. Amortization of Deferred Nuclear outsgre Costs We defer the incremental costs associated with nuclear refueling outages and amortize them over future periods. In 1995 we changed the amortization period to two years from five years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling cutages at Pilgrim Station.
The change from the prior five-year amortization period approved in the 1992 settlement agreement was made following the DPU's August 1995 order on electric industry restructuring, which is discussed further in the outlook for the Future section of Management's Discussion and Analysis. This order requires utilities to mitigate potentially strandable costs by available and reasonable means. The prior regulatory treatment of recovery over a five year period resulted in a significant lag between the expenditure and recovery of outage costs. We decided not to request recovery of the buildup of costs resulting from this regulatory lag. Accordingly, the remaining $9 million of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 was written off. Approximately $15 ndllion of deferred costs from the 1995 refueling outage is being amortized over two years.
- 6. Aamortisation of Discounts and Jtedenption PreaLiums on Debt We expense discounts, redemption premiums and related costs associated with issuances or redemptions of long-term debt or the refinancing of existing debt over the life of the debt or the replacement debt subject to regulatory approval.
- 7. Allowance for Tunds Used Duringr Construction (AEDDC)
AFUDC represents the estimated costs to finance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of 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 1995, 1994 and 1993 I were 6.35%, 4.45B and 3.62%, respectively, and represented only the cost of i
- short-term debt.
i
- 8. Cash and Cash Equivalents I )
Cash and cash equivalents are comprised of highly liquid securities with
- maturities of three months or less when purchased. Outstanding checks are included in cash and accounts payable until presented for payment.
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- 9. Allowance for Doubtful Accounts e
our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customs: charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
- 10. Jtegulatory Assets Regulatory assets represent costs incurred which are expected to be collected from custcmers through future charges in accordance with agreements with the DPU. These costs are to be expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. No return on investment was earned on the regulatory assets.
Regulatory assets consisted of the following:
December 31, 1995 1994 Redemption premiune S 44,709 $52,859 Income taxes, net 46,121 44,745 Power contracts 21,396 40,277 Pension and postretirement costs 13,811 22,761 Nuclear outage costs 13,471 17,804 Other 17,266 19,702
$156,774 S198,148 Note C. Rate Regulation In 1992 the DPU approved a three-year settlement agreement relating to our rate case proceedings. The agreement provided for retail rate increases, accounting adjustments and demand side management program expenditures; clarifjed the timing and recognition of certain expenses and set limits on our rate of return on common equity through 1995.
In February 1996 we filed an industry restructuring plan with the DPU in response to its August 1995 order on restructuring the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in new rates and performance incentives to be implemented in a new industry structure with a competitive generation narket and incentive-regulated transmission and distribution systems. Refer to Management's Discussion and Analysis for further information regarding the restructuring of the electric utility industry in Massachusetts and our proposed plan. State regulatory proceedings do not affect our contract or wholesale power rates, which are regulated by the FERC.
Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ( S EAS 10 9 ) , which 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 recorded net regulatory assets of $46.1 million and $44.7 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1995, and December 31, 1994, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
35
Accumulated deferred income taxes consisted of the following:
December 31, lin thousands) 1995 1994 Deferred tax liabilities:
Plant-related $521,280 $511,572 Other 95,148 105,786 616,428 617,358 Deferred tax assets:
Plant-related 12,590 13,216 Investment tax credits 40,632 43,273 Alternative minimum tax 0 1,332 other 65,924 44,083 119,146 101,904 Net accumulated deferred income taxes $497,282 $515,454 No valuation allowances for deferred tax assets are deemed necessary.
Components of income tax expense were as follows:
years ended December 31, (in thousands) 1995 1994 1993 Current income tax expense $93,469 $63,358 $28,913 Deferred tax expense (21,115) (4,468) 10,303 Investment tax credits (4,078) (4,092) (4,073)
Income taxes charged to operations 68,276 54,798 35,143 Taxes on other income:
Current (1,729) 2,550 1,205 Deferred 0 284 0 (1,729) 2,834 1,205 Total income tax expense $66,547 S57,632 $36,348 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:
1995 1994 1993 Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.3 4.3 4.2 Investment tax credits (2.3) (2.3) (2.6)
Municipal property tax adjustment - -
(0.6) !
Reversal of 6 aferred taxes - settlement agreement -
(5.5) (13.0) i other 0.1 (0.1) 0.4 !
Effective tax rate 37.1% 31.4% 23.4% 1 Note E. Nuclear Deconnissioning and Nuclear Waste Disposal l
- 1. Nuclear Decomnissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We are currently expensing an estimate of the ,
decommissioning costs over Pilgrim's expected service life. The 1995 expense l of approximately $14 ndllion is included in depreciation expense on the consolidated income statement. 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 estimate, which involves many uncertainties, was incorporated in our 36
- . _ _ . . . - -- .- - - - - . - . - . - . - - ~ - - - - -. - ,
e t
. i 1992 reta11 settlement agreement. We receive recovery of the annual expense !
from 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 collect from decommissioning charges are deposited in an external trust and are restricted so that they may only be used for >
decommissioning and related expenses. .The net earnings on the trust funds, '
which are also restricted, increase the nuclear decommissioning fund balance ;
and nuclear decommissioning reserve, thus reducing the amount to be collected i from customers.
i 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 I l
Energy (DOE) spent fuel removal program. (See part 2 below for a. discussion !
! of spent fuel removal.) The partial update indicates an estimated decommissioning cost of $400 ndllion in 1991 dollars based upon a revised '
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 fuel storage technology along with their impact on the decommissioning i
- estinate .
/
In February 1996 the Financial Accounting Standards Board (FASB) issued 1
, proposed new rules for accounting for liabilities related to closure and !
removal of long-lived assets, which includes decommissioning. If these draft i
rules are adopted we would be required to retroactively recognize the entire ;
estimated liability for decommissioning costs on the balance sheet, offset by :
dn addition to nuclear plant. The plant addition would be depreciated over !
! Pilgrim's expected service life. The liability would be measured based on the '
I present value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in 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 l decommissioning. If it is not probable that we could recover these costs from customers, we would have to charge the cumulative effect of the difference to income instead of recording a regulatory asset. In addition, trust fund earnings would be reported.on the income statement.
- 2. . spent Nucle w 1%el l
The spent fuel storage facility at Pilgrim Station provides storage capacity through approximately 2003. We have a license amendment from the Nuclear Regulatory conndssion to modify the facility to provide sufficient room for l spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the DPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies. l It is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. 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 charaes. The DOE is conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered l substantial public and political opposition and the DOE has publicly stated h that it may be unable to construct such a repository in a timely manner. In l 1994 we and other interested parties filed petitions in the U.S. court of l
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- r Appeals for the D.C. Circuit seeking declaratory rulings that the DOE is
- obligated to begin taking spent nuclear fuel for disposal in 1998. The DOE i has sought to dismiss those petitions and a court ruling is awaited. It is i unknown at this time whether and on what schedule the DOE will eventually
- i construct a spent fuel repository and what the effect on us will be of any delays in such construction.
8 3. Low-Zevel Jtadioactive 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 available to us. Legislation 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, alternatively, an agreement with one or more other states. Pending the construction of a disposal facility within the i 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.
, 4. Other RFaclear Dhits i i We are an investor in and customer of two other domestic nuclear units., Both l of these units receive, through the rates charged to their customers, an amount to cover the estimated costs to dispose of their spent nuclear fuel and to decommission the units at the end of their useful lives.
Note F. Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we
- offered enhanced retirement programs and implemented a special severance
- program to reduce employee staffing levels. Under the enhanced retirement prograns 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge'($20.7 million net of tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 million 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 was provided for all employees whose positions were eliminated in the reorganization, who were al] management and administrative support personnel.
Severance benefits provided were salary payments, medical insurance and outplacement services. The retirement programs' pension and medical and life insurance benefits, totr.111ng $16 ndllion, will be paid from pension and employee benefit trusts. The liabilities to the trusts are included on the consolidated balance sheet at December 31, 1995, in pension benefits and other current liabilities. All other benefits are being paid from general corporate funds. As of December 31, 1995, $10 million had been paid and $8 million remained in other current liabilities.
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I Note G. Pensions and Other Postretirement Benefits l
l 1. Pensions 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 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 pension 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. Amounts related to i the plan prior to 1995 were not material to our total pension costs and obligations.
Net pension cost consisted of the following components:
years ended December 31, j (in thousands) 1995 1994 1993 l Current service cost - benefits earned $11,339 $15,057 $ 11,734 Interest cost on projected benefit ,
obligation 31,789 33,961 33,181 l Actual net loss /(return) on plan assets (72,192) 214 (44,470) ,
Net amortization and deferral 49,557 (32,169) 8,528 i Net cension cost (a) $20,4 93 S17,063 $ ,g,973 (a) In accordance with our 1992 settlement agreement we deferred the i
difference in the net pension cost of the retirement plan and its i annual funding amount. Net deferred costs amounted to ($1.2) million i and $6.5 million at December 31, 1995 and 1994, respectively. Total net pension costs recorded as expense in 1995, 1994 and 1993 were $28 million, $25 million and $5 million, respectively.
I We used the following assumptions for calculating pension cost: l 1995 1994 1993 Discount rate 8.25% 7.00% 8.25%
Expected long-term rate of return on assets 10.00% 10.00% 10.00%
Compensation increase rate 3.90% 4.50% 4.50%
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The pension plans' funded status was as follows:
December 31, ,
(in thousands) 1995 1994 Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of $386,020 and $305,632 (b) $401,329 $321,072 Plan assets at fair value $358,572 $289,164 Projected obligation for service rendered to date (487,702) (387,910) '
Projected benefit obligation in excess of plan assets (129,130) (98,746)
Unrecognized prior service cost 22,506 13,328 Unrecognized net loss 83,187 67,361 Unrecognized net obligation 8,064 8,998 Minimum liability adjustment (c) (27,386) (22,849)
Net Dension liability (d) $(42,759) $(31,908)
(b) 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. ;
(c) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SEAS 87), requires the recognition of an additional minimtml liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SEAS 87 we recorded additional ndnimum liabilities and corresponding intangible assets of $27 million and $23 million on our consolidated balance sheets at December 31, 1995 and 1994, respectively.
(d) Net pension liability included on the consolidated balance sheets in current liabilities is $33 million and $32 million, and in deferred credits is $10 ndllion and $0 at December 31, 1995 and 1994, respectively.
We used the following assumptions for calculating the plans' year-end funded status 1995 1994 Discount rate 7.25% 8.25%
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' voluntary contributions to the plans, which amounted to $9 million in 1995, $8 ndllion in 1994 and $7 ndllion in 1993. l l
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- 2. Other Postretirement Benefits In addition to pension benefits, we also provide health care and other 1 benefits to our retired employees who meet certain age and years of service j 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 ( S EAS 106) . Our 1992 settlement agreement provides us with a five-year expense phase-in of the PBOP costs incurred under SEAS 106 and allows us to defer any costs in excess of the phase-in amounts to the extent that we fund an external trust. Our funding policy is to contribute 100% of 40
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! postretirement benefits costs to external trusts. Accordingly, we recorded expenses of $23 million in 1995, $17 million in 1994 and $15 million in 1993, l reflecting the amount of current cost recovery from customers. Net deferred i
costs amounted to $15 million and $16 million at December 31, 1995 and 1994, l respectively.
Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands) 1995 1994 1993 Current service cost - benefits earned S 3,408 $ 4,978 $ 4,351 Interest cost on accumulated benefit obligation 13,511 13,632 14,286 Actual return on plan assets (7,151) (187) 0 Amortization of transition obligation 9,151 9,151 9,151 I Net amortization and deferral 3,017 (2,581) 0 Net oostretirement benefits cost $21,946 $24.993 $27,788 We used the following assumptions for calculating postretirement benefits cost:
1995 1994 1993 Discount rate 8.25% 7.00% 8.00%
E:tpected long-term rate of return on assets 9.00% 9.00% 9.00% l Health care cost trend rate 7.00% 9.00% 12.50% l The health care cost trend rate is assumed to decrease by one percent in 1996 and 1997 and to remain at 5% in years thereafter. Changes in the health 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 8% and would increase the accumulated benefit obligation at December 31, 1995, by 7.5%.
The postretirement benefits program's funded status was as follows:
I December 31, I (in thousands) 1995 1994 Trust assets at fair valus S 51,064 $ 33,300 Accumulated obligation fcr service rendered to date from:
Retirees $(110,877) $(93,960)
Active employees eligible to retire (31,980) (31,159)
Active employees not eligible to retire (b3 514) (196,371) (51,545) (176,664)
Accumulated benefit obligation in excess of trust assets (145,307) (143,364)
Unrecognized prior service cost (17,889) (19,502)
Unrecognized net (gain)/ loss 5,612 (1,849)
Unrecognized transition obligation It5,564 164,715 Net oostretirement benefits liability S (2.020) $ 0 Tne net postretirement benefits liability at December 31, 1995, represents the additional PBOP obligation from the enhanced retirement prograns offered in 1995 (see Note F). This additional amount was not funded as part of the 1995 j PBOP cost.
l The weighted average discount rates used to measure the accumulated benefit obligation were 7.25% in 1995 and 8.25% in 1994. The trust assets consist of equities, bonds and money market funds.
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Note E. Eminent Domain Taking
-In November 1994 a Norfolk Superior Court ruling against the Massachusetts Metropolitan District Commission (MDC) became effective, providing us with an additional $5.7 million gain on an eminent domain land-taking case. We had filed suit against the MDC in 1992 related to the eminent domain taking of certain of our property in 1989.
- Note I. Cancelled Nuclear Unit ;
In 1982 we began expensing the cost of our cancelJed Pilgrim 2 nuclear unit over approximately eleven and one-half years in accordance with an order ;
received from the DPU. We did not expense any of these costs in 1993. The '
remaining balance of $19 ndllion was fully expensed in 1994 as allowed by our 1992 settlement agreement, i
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Note J. Capital Stock December 31, [
(dollars in thousands, except per share amounts) 1995 1994 1993 Comunon stock equity:
Common stock, par value $1 per share, 100,000,000 shares authorized; 48,003,178, 45,535,477 and 45,129,227 shares issued and outstanding: $ 48,003 $ 45,535 $ 45,129 Premium on common stock 683,686 622,803 612,653 Retained earnings 257,344 247,004 218,292 Surplus invested in plant 405 405 405 Total common stock ecuity $989,438 $915,747 $876,479 Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption Series Outstanding Price / Share L 4.25% 180,000 $103.625 S 18,000 S 18,000 S 18,000 4.78% 250,000 $102.800 25,000 25,000 25,000 7.75% 400,000 -
40,000 40,000 40,000 8.25% 400,000 -
40,000 40,000 40,000 Total nonmandatory redeemable series $123,000 S123,000 $123,000 Mandatory redeemable series:
Current Shares Redemption Series Outstanriing Price / Share 7.27% 440,000 $103.390 S 44,000 $ 46,000 $ 48,000 8.00% 500,000 -
50,000 50,000 50,000 Total nandatory redeemable series 94,000 96,000 98,000 i Less: due within one year 2,000 2,000 2,000 l Total mandatory redeemable series, net S 92,000 $ 94,000 $ 96,000 Diviank Deciated per Share common stock $ 1.835 S 1.775 S 1.715
( Preferred stock l 4.25% series S 4.250 $ 4.250 S 4.253 4.78% series 4.780 4.780 4.785 7.27% series 7.270 7.270 7.270 7.75% series 7.750 7.750 5.707 8.00% series 8.000 8.000 8.000 8.25% series 8.250 8.250 8.250 8.88% series 0 0 2.220 l
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- 1. Commuon Stock Common stock issuances in 1993 through 1995 were as follows:
Number Total Premium on (in thousands) of Shares Par Value Common Stock Balance December 31, 1992 44,763 $44,763 $602,196 Dividend reinvestment plan 366 366 10,457 Balance December 31, 1993 45,129 45,129 612,653 Dividend reinvestment plan 406 406 10,150 Balance December 31, 1994 45,535 45,535 622,803 Dividend reinvestm.'nt plan (a) 468 468 11,404 New issuances (b) 2,000 2,000 49,479 Balance December 31, 1995 48,003 S48,003 $683,686 (a) At December 31, 1995, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 1,941,.19 shares.
(b) We used the net proceeds of the 1995 common stock issuances to reduce short-term debt.
- 2. L%aulative Mon == net = tory Redeemable Preferred Stock In 1993 we issued 400,000 shares of 7.75% cumulative nonmandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in May 1998. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulative nonmandatory redeemable preferred stock.
- 3. Ctanulative Mandatozy Redeemable Preferred Stock The 440,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $103.390. 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 redeem ,
additional shares, not to exceed 20,000, through the sinking fund at $100 per ,
share plus accrued dividends.
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 $100 per share, plus accrued dividends, i
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Note K. Indebtedness December 31, (in thousands) 1995 1994 Long-term debt:
Debentures:
8.875%, due December 1995 $ 0 $ 100,000 5.125%, due March 1996 100,000 100,000 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 0 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 20?? 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentures 1,215,000 1,190,000 Less: due within one year 100,000 100,000 Net long-term debentures 1,115,000 1,090,000 Sewage facility revenue bonds 35,700 36,300 Less: due within one year 1,600 600 Less: funds held by trustee 3,877 4,083 Net long-term sewage facility revenue bonds 30,223 31,617 Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000 Total lonc-term debt $1,160,223 $1,136,617 short-term debt:
Notes payable:
Bank loans $ 75,941 $ 80,786 Commercial paper 50,500 134,000 Total notes payable $ 126,441 S 214,786
- 1. Long-Te2x Debt In 1994 the Massachusetts Industrial Finance Agency, on our behalf, issued $15 million of 5.75% tax-exempt unsecured bonds due in 2014. The bonds 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 proceeds from this issuance together with sufficient other funds were used to fully redeem the Series U first mortgage bonds.
In 1994 we redeemed at par the $25 million of variable rate Series S first mortgage bonds. As a result of the redemption of all outstanding first mortgage bonds, the Indenture of Trust and First Mortgage that had mortgaged substantially all our property since 1940 was terminated in November 1994.
In May 1995 we issued $125 million of 7.80% debentures due in 2010. We used the net proceeds from this issuance to reduce short-term 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 45 l
m _ ____ _ ._ _. ____ _ _ _ _ _ _ . - _ - _ _ . . . _. __. __ _ _
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 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 Harbor Electric Energy Company (HEEC), a-wholly owned subsidiary. The bonds are tax-exempt, subject to ;
annual mandatory sinking fund redemption requirements and nature through 2015.
In May 1995 $0.6 million was redeemed 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 insufficient 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 $1 million. ,
The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2000 are $101.6 ndllion per year in 1996 through 1998, $1.6 million in 1999 and $166.6 million in 2000.
- 2. Short-Tezm Debt .
We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have authority to issue up to $350 ndllion 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 naintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.
Information regarding our short-term borrowings, comprised of bank loans and commercial paper, is as follows:
(dollars in thousands) 1995 1994 1993 Maximum short-term borrowings S327,769 $268,100 $320,000 Weighted average amount outstanding $165,720 $214,640 $220,149 Weighted average interest rates excluding commitment fees 6.2% 4.5% 3.4%
Note L. Fair Value of Securities The following methods and assumptions were used to estimate the fair value of !
each class of securities for which it is practicable to estimate the value:
Nuclear decommissioning trust:
The cost of $102.9 million approximates fair value based on quoted market prices of securities held.
Cash and cash equivalents:
The carrying amount of $5.8 million approximates fair value due to the short-term nature of these securities.
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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, 1995, are '
as follows:
Carrying Fair (in thousands) Amount Value Mandatory redeemable cumulative preferred stock $ 94,000 $ 98,005 Sewage facility revenue bonds 35,700 38,446 Unsecured debt 1,230,000 1,276,213 Note M. New Accounting Pronouncement In 1995 the EASB issued Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of (S EAS 121) , effective in 1996. This statement clarifies when and how to recognize asset impairments. In addition, SEAS 121 requires that all regulatory assets, which must have a high probability of recovery to be initially established, continue to meet that high probability standard or be written off. However, if written off, a regulatory asset can be restored if it regains a high probability of recovery. The impact of this standard on our plant and regulatory assets will be determined by regulatory changes implemented by the DPU and FERC. Based on the transition principles of the DPU's order on industry restructuring and our related plan, which are discussed in the outlook for the Future section of Management's Discussion and ,
Analysis, we do not expect SEAS 121 to have an adverse impact on our financial position or results of operations in the near term. Our conclusion may change as the actual shape of restructuring of the industry in Massachusetts develops. If. recovery of our plant and regulatory assets is not provided, !
SFAS 121 could require a write-down of these assets.
Note N. Commitments and Contingencies
- 1. Contractual Coancitments At December 31, 1995, we had estimated contractual obligations for plant and ;
equipment of approximately $35 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 1995 are as follows:
(in thousands) 1996 $ 24,908 1997 22,109 1998 19,002 1999 17,408 2000 16,656 Years thereafter 108,417 Total $208,500 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 $24.5 million in 1995, $28.6 million in 1994 and
$29.8 million in 1993, net of capitalized expenses of $2.7 ndllion in 1995,
$2.4 million in 1994 and $5.2 million in 1993.
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We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply New Boston Station with natural gas. The fixed and determinable portions of the obligations are S16.1 ndllion in 1996, 1997 and 1998, $24.8 million in 1999 and $13.8 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $13.9 ndllion in 1995, and $6.5 million in 1994 and 1993.
- 2. Rydro-guabec We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included on our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria and are compensated accordingly. At December 31, 1995, our portion of these guarantees was approximately $19 ndllion.
- 3. Yankee Atomic Electric Coxqpany We have a 9.5% stock 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 1 nuclear generating station and decommission the facility. We relied on Yankee i Atomic for less than one percent of our system capacity under a long-term l purchased power contract.
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Yankee Atomic received approval from federal regulators to continue to collect )
its investment and decommissioning costs through July 2000, the period of the l plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $21 ndllion as of December 31, 1995. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset as we ,
continue to collect these costs from our customers in accordance with our 1992 j settlement agreement. l
- 4. Nuclear Insurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 ndllion of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately $8.3 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 110 units licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability clains and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional five percent of the maximum retrospective assessment.
We have purchased insurance frem Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or deconadssioning 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 $15 million under both 48
the replacement power and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses are in excess of the total funds available to NEIL. While additional assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in any such assessment.
- 5. Litiga tion In 1991 we were named in a lawsuit alleging discriminatory employment i practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to l vigorously defend this case. We have also been named as a party in a lawsuit by Subaru of New England, Inc. and Subaru Distributors Corporation. The I plaintiffs are claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. We '
believe that we have a strong defense in this case. 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 previously accrued, i although based on the information currently available, we do not expect that I any such additional costs will have a material impact on our financial I condition. However, 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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- 6. Hazardous Waste We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing to evaluate-the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we l currently expect to have only a small percentage of the potential liability.
l Through December 31, 1995, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of l reasonably possible cleanup costs in excess of the accrued amount, although j based on our assessments of the specific site circumstances, we do not expect ;
- any such additional costs to have a material impact on our financial '
L condition. However, additional provisions for cleanup costs that may result
( from a change in estimates could have a material impact on the results of a l reporting period in the near term.
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Note O. Long-Term Power Contracts 1 1
- 1. Long-Te2x Contracts for the Purchase of Electricity We purchase electric power under several long-team 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 l purchased power expense on our consolidated income statements. Information l relating to these contracts as of December 31, 1995, is as follows: i proportionate share (in thousands)
Units of 1995 1995 Interest Debt Contract Capacity # Minimum Portion of Outstanding Expiration Purchased Debt Minimum Through Cont. -
Generating Unit Date % MW Service Debt Service Exp. Date Canal Unit 1 2001 25.0 139 $ 1,122 $ 349 $ 3,400 Mass. Bay Trans-portation Authority - 1 2005 100.0 34 (b) (b) (b)
Connecticut Yankee Atomic 2007 9.5 55 2,646 1,786 13,857 Ocean State Power -
Unit 1 2010 23.5 67 4,819 3,318 20,749 Ocean State Power -
Unit 2 2011 23.5 66 4,090 3,049 17,228 Northeast Energy Associates (c) (c) 219 (c) (c) (c) '
L'Energia 2013 73.0 64 (d) (d) (d)
MassPower (e) 2013 44.3 117 12,217 7,662 81,983 Mass. Bay Trans-portation Authority - 2 2019 100.0 34 (f) (f) (f)
Total 795 $24,894 $16.164 $137,217 (a) The Northeast Energy Associates contract represents 5.9% of our total system generstion capability. The remaining units listed above represent
- 15. 6% in tota l.
(b) We are required to pay the greater of $22.00 per kilowatt-year or 90% of the New England Power Pool capability responsibility adjustment charge up to $63.00 per kilowatt-year times the qualified capacity (currently rated .
at 34MW), plus incremental operating, maintenance and fuel costs. The '
total' charges for this contract in 1995 were approximately $2 million.
(c) We purchase approximately 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for-this energy based on a price per kWh actually received. We do not pay a proportionate share of the unit's capital and fixed operating costs. The total charges for these contracts in 1995 were approximately $127 ndllion.
(d) We pay for this energy based on a price per kWh actually received. The l total charges under this contract for 1995 were approximately $25 million.
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[ (e) Payments for this contract are based on a stipulated price per MW rating '
of the unit subject to the unit maintaining a twelve-month average '
availability of at least 90%. Payments are adjusted proportionately if the twelve-month average is below 90%. If the twelve-month average is ;
less than 10%, no payment is required. Total charges for this contract '
in 1995 were approximately $49 million.
(f) The second Massachusetts Bay Transportation Authority contract started'in June 1995. Capacity payments under this contract do not begin until 2003. At that time.we will be required to pay $84.57 per kilowatt-year 1 times the qualified capacity plus incremental operating maintenance and fuel costs. ,
our total fixed and variable costs-for these contracts in 1995, 1994 and 1993 I were approximately $283 million, $286 million and $225 million, respectively. !
Our minimum fixed payments under these contracts for the years after 1995 are l as follows:
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(in thousands) 1996 S 106,649 1997 103,682 1998 105,778 1999 105,258 2000 103,676
! Years thereafter 1,187,672
! Total $1,712,715 Total present value 3 883,409 l 2. Long-Te2x 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 adjustments.
Under these contracrs, the utilities pay their proportional 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) i (in thousands, except earnings per share)
Balance Available Earnings operating Operating Net for Common Per Average !
l Revenues Income Income Stock Common Share
l 1995 l
l First quarter $379,678 $ 47,610 $20,202 $16,300 $0.36 i Second quarter 380,828 55,683 26,137 22,247 0.48 l Third quarter -498,554 102,695*' 72,368 *' 68,478 *' 1, 4 6 *' l
, Fourth quarter 369,443 21,412*' (6,397)*' (10,286)*' (0.21)*' i l l 1994 1
First quarter $376,935 $ 45,891 $19,812 $15,850 $0.35 Second quarter 368,245 50,812 23,982 20,031 0.44 Third quarter 448,179 96,880 70,182 66,256 1.46 Fourth quarter 351,376 34,895 11,046 7,120 0.16 !
(a) Based on the weighted average number of common shares outstanding during the quarter.
(b) As discussed in Note F to the Consolidated Financial Statements, we incurred a $34 ndllion pre-tax charge related to our corporate ,
restructuring over the third and fourth quarters of 1995. Amounts s excluding the restructuring charge are as follows: ;
Balance Available Earnings l Operating Net for Common Per Average Income Income Stock Common Share Third quarter $107,779 $77,452 $73,562 $1.57' Fourth quarter 36,991 9,182 5,293 0.11 Certain reclassifications were made to the data reported in prior periods to conform with the current method of presentation.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable.
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Part III Item 10. Directors and Executive Officers of the Registrant (a) Identification of Directors See " Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 28, 1996, 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 Of ficers of the Registrant.
(c) Identification of Certain Significant Employees Not applicable.
(d) Family Relationships 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 1 through 4 of l the definitive proxy statement dated March 28, 1996, incorporated herein by i reference. j 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 1
Not applicable.
(g) Promoters and Control Persons Not applicable.
Item 11. Executive Compensation- j See " Director and Executive Compensation" on pages 6 through 12 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference.
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s 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 See " Stock ownership by Directors and Executive Officers" on page 5 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference.
(c) Changes in Control Not applicable.
Item 13. Certain Relationships and Related Transactions Not applicable.
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9 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:
Page Consolidated Statements of Income for the three years ended December 31, 1995, 1994 and 1993 30 Consolidated Statements of Retained Earnings for the three years ended December 31, 1995, 1994 and 1993 30 Consolidated Balance Sheets as of December 31, 1995 and 1994 31 Consolidated Statements of Cash Flows for the three years ended December 31, 1995, 1994 and 1993 32 Notes to Consolidated Financial Statements 33 Selected consolidated Quarterly Financial Data (Unaudited) 52 Report of Independent Accountants 66 No financial statement schedules are prepared as they are either not required or not applicable.
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Exhibit SEC Docket Exhibit 3 Articles of-Incorporation and By-Laws
)
Incorporated herein by reference:
3.1 Restated Articles of Organization 3.1 1-2301 Form 10-Q for the 1 quarter ended l June 30, 1994 l
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 j l
Exhibit 4 Instruments Defining the Rights of l Security Holders, Including Indentures '
Incorporated herein by reference: i 4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301 !
dated September 1, 1988, between Form 10-Q Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 !
l 4.1.1 First Supplemental Indenture '4.1 1-2301 I dated June 1, 1990 to Form 8-K I' 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, l 1991 l
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Exhibit SEC Docket i
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! 4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K l for the l p year ended 1 December 31, l 1992 1 4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301 Board of Directors of Boston Edison {
Form 10-K :
Company taken September 10, 1992 re for the '
l 8 1/4%' debentures due September 15,.2022 year ended l December 31, 1992 l
4.1.6 Votes of the Pricing Committee of-the 4.1.26 1-2301' Board of Directors of Boston Edison Form 10-X 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
- 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 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 Company taken August 18, 1993 re .for the 6.05% debentures due August 15, 2000 year ended December 31, 1993
' Filed herewith:
4.1.9 Votes of the Pricing Committee of the
. Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 l
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Exhibit SEC Docket 4.1.10 First Amendment to Revolving Credit Agreement :
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-term debt whose authorization does not exceed 10% of the Company's total assets, i I
Exhibit 10 Material Contracts '
Incorporated herein by reference: I 10.1 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, May Form 10-Q 1986 for the quarter ended I June 30, 1986 10.1.1 Key Executive Benefit Plan 10.3.1 1-2301 ,
Standard Form.of Agreement, May Fonm 10-K 1986, with modifications for the ;
year ended i December 31, !
1991 ;
10.2 Executive Annual Incentive 10.5 1-2301 Compensation Plan Form 10-K for the year ended i December 31, 1988
- 10.3 1991 Director Stock Plan 10.1 1-2301 l Form 10-0 !
for the 4 quarter ended !
March 31, 1991 l l
10.4 Boston Edison Company Deferred 10.11 1-2301 ,
Fee Plan dated January 1, 1990 Form 10-K 4 for the year ended i December 31, ;
1992 !
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- f. Exhibit SEC Docket I
10.5 Deferred Compensation Trust 10.10 1-2301 l between Boston Edison Company Form 10-K
! and State Street Bank and for the L Trust Company dated year ended l February 2, 1993 December 31, 1992 l
j 10.5.1 Amendment No. 1 to Deferred 10.5.1 1-2301 i Compensation Trust dated Form 10-K '
March 31, 1994 for the l year ended
[ December 31, i
1994 10.6 Directors Retirement Benefit 10.8.1 1-2301 (1993 Plan) Form 10-K I for the year ended i December 31, 1993 l
10.7 Description of Supplemental Fee 10.7 1-2301 j Arrangement for Certain Directors Form 10-K i for the l year ended December 31, 1994 10.8 Performance Share Plan, Amendment 10.8 1-2301 and Restatement dated October 24, 1994 Form 10-K for the year ended December 31, 1994 10.9 Boston Edison Company Deferred 10.9 1-2301 )
l Compensation Plan, knendment and Form 10-K i Restatement dated January 31, 1995 for the ;
year ended i December 31, !
1994 10.10 Dnployment Agreement applicable to 10.10 1-2301 Ronald A. Ledgett dated April 30, 1987 Form 10-K l for the l year ended l December 31, l 1994 ;
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f Exhibit SEC Docket I
Exhibit 12 Statement re Computation of Ratios !
Filed herewith: i 12.1 Computation.of Ratio.of Earnings I to Fixed Charges for the Year-Ended December 31, 1995 '
i 12.2 Computation of Ratio of Earnings ,
to Fixed Charges and Preferred Stock 1 Dividend Requirements for the Year Ended December 31, 1995 .
l Exhibit 21 Subsidiaries of the Registrant 21.1 Harbor Electric Energy Company. l (incorporated in Massachusetts), ,
a wholly owned subsidiary of Boston !
Edison Company >
21.2 Boston Energy Technology Group, Inc. i (incorporated in Massachusetts),. '
a wholly owned subsidiary of Boston-Edison Company i
l 21.3 Ener-G-Vision, Inc. (incorporated i in Massachusetts), a wholly owned j subsidiary of Boston Energy l Technology Group, Inc. j l
21.4 TravElectric Services Corporation (incorporated in Massachusetts),
a wholly owned subsidiary of Boston Energy Technology Group, Inc.
L 21.5 REZ-TEK International Corporation (incorporated in Massachusetts),
a najority owned subsidiary of Boston Energy Technology Group, Inc. ;
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! 21.6' Coneco Corporation (incorporated l in Massachusetts), a majority owned i subsidiary of Boston Energy !
Technology Group, Inc. j i
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Exhibit SEC Docket !
Exhibit 23 Consent of Independent Accountants f Filed herewith: i 23.1 Consent of Independent Accountants i to incorporate by reference their opinion included with this Form 10-K in the Form S-3 Registration .
Statements filed by the Company on September 14, 1990 (File No. !
33-36824), 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)
Exhibit 27 Financial Data Schedule ,
t Filed herewith:
l 27.1 Schedule UT Exhibit 99 Additional Exhibits Incorporated herein by reference:
99.1 DPU Settlement Agreement with 28.1 1-2301 Boston Edison Company dated ' Form 8-K October 3, 1989 dated October 3, 1989 99.2 Settlement Agreement between Boston 28.1 1-2301 Edison Company and Commonwealth Fonn 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 99.3 Pilgrim Outage Case Settlement between 28.2 1-2301 Boston Edison Company and Reading Form 8-K Municipal Light Department regarding dated contract Demand Rate, dated December December 21, 21, 1989 1989 4
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y V
Exhibit SEC Docket 99.G Settlement Agreement Between Boston 28.2 1-2301 Edison Company and City of Holyoke Form 10-0 Gas and Electric Department et. al., for the dated April 26, 1990 quarter ended March 31, 1990 99.5 Information 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, 1994, 1993 and 1992 Form 10-K for the years ended December 31, 1994 and 1993 and Fonn 8 Amendment to Form 10-K for the year ended December 31, 1992 dated June 29, 1995, June 30, 1994 and June 29, 1993, respectively 99.6 DPU Settlement Agreement with 28.2 1-2301 Boston Edison Company, dated Form 10-Q October 23, 1992 for the quarter ended September 30, 1992 l
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(b) Reports on Form 8-K:
There were no Form 8-K's filed during the fourth quarter of 1995.
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. l SIGNATURES !
I Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange l Act of 1934, the registrant has duly caused this report to be signed on its t behalf by the undersigned, thereunto duly authorized. l BOSTON EDISON COMPANY- f E
[
By: /s/ James J. Judge j James J. Judge (
Senior Vice President and Treasurer !
(Principal Financial Officer) f Date: March 28, 1996 P
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 28th day of March 1996. ;
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/s/ Thomas J. May Chairman of the Board, President i Thomas J. May and Chief Executive Officer j i
/s/ Robert J. Weafer, Jr. Vice President - Finance, J Robert J. Weafer, Jr. Centroller and Chief Accounting Officer :
l 2
/s/ William F. Connell Director f William F. Connell i
/s/ Gary L. Countryman Director
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l Gary L. Countryman i l l 1
/s/ Thomas G. Dignan, Jr. Director Thomas G. Dignan, Jr.
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/s/ Charles K. Gifford Director Charles K. Gifford
/s/ Nelson S. Gifford Directar Nelson S. Gifford j
/s/ Kenneth I. Guscott Director Kenneth I. Guscott I 64
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/s/ Matina S. Horner Director Matina S. Horner
/s/ Sherry H. Penney Director Sherry H. Penney
/s/ Herbert Roth, Jr. Director Herbert Roth, Jr.
~~~
Stephen J. Sweeney Director Paul E. Tsongas i
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I Report of Independent Accountants i f
To the Stockholders and Directors of Boston Edison Company: .
We have audited the consolidated financial statements of Boston Edison Company and subsidiaries (the Company) listed in Item 14(a) of this Form 10-X. These ;
consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial ;
statements based on our audits. !
l 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 I supporting the amounts and disclosures in the financial statements. An audit !
also includes. assessing the accounting principles used and significant I estimates made by manageient, as well as evaluating the overall financial >
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
i In our opinion, the consolidated financial statements referred to above !
present fairly, in all material respects, the consolidated financial position l of the Company as of December 31, 1995 and 1994, and the consolidated results [
of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting f; principles. r i
COOPERS & LYBRAND L.L.P. '
! i k
Boston, Massachusetts January 25, 1996 r i
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