ML20134M371
| ML20134M371 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/31/1995 |
| From: | May T BOSTON EDISON CO. |
| To: | |
| Shared Package | |
| ML20134M348 | List: |
| References | |
| NUDOCS 9611250062 | |
| Download: ML20134M371 (48) | |
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1995 j Annual Report To Shareholders I
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Financial Highlights ,
t years ended December 31, y 1995 1994 j
.3 Operating revenues (000) 51,628,503 $ 1,544,735 l[~~ kg Income available for common stock (000) $96,739 $109,257 g Common shares outstanding -
f n .-*% weighted average (000) 46,592 45,338 aw-c- Common stock data:
(g) Earnings per share (excluding restructuring charge) $2.52 Dividends declared per share $1.835 (a) $2.41
$1.775 Payout ratio (excluding restructuring charge) 72 % (a) 73 %
( Book value per share $20.61 $20.11 Return on average common equity
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( (excluding restructuring charge) 12.2 % (a) 12.1 %
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(% e/ g Fixed charge coverage (SEC) 2.38 2.46 VU hf[ j Certain reclassifications and recalculations were made to the data reported in the prior
[ year to conform to the method of presentation used in 1995 (a) The company incurred a 50.44 per share restructuring charge in 1995.
About The Company Boston Edison is a public utility engaged principally in the gen-eration, purchase, transmission, dis-
, y Eh tribution and sale of electnc energy. y It was incorporated in 1886. We sup- l ply electricity at retail to an area of approximately 590 square miles
.w within 30 miles of Boston, encom- # *" '
passing the City of Boston and 39 surrounding cities and towns. The population of the territory served at y retail is approximately 1,500,000.
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 percent 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 11 percent from wholesale sales and Mayor's educational initiative.
2 percent from other sources.
On The Cover: Crossing the bridge to competition. Boston Edison will continue to focus on its customers and its commu-nities as it helps drive and shape industry reform.
I j 1995 Annual Report To Shareholders
l 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-l tinue to balance the interests of consumers and shareholders, steadily navigating the choppy waters of j industry reform from a position of financial strength. Customer relationships are being forged in this l new environment, and new opportunities in two-way customer communications are being pursued.
We continue as a full-service utility while offering many nontraditional products and services.
l This past year was a transition year, by all accounts, as the move to restructure gained momen-
{ tum. Key issues were addressed by regulators, utilities, communities, consumers, environmentalists '
j and independent power producers alike. In last year's Annual Report, your company described the l issues surrounding industry reform and Boston Edison's strategic direction to address them. I
! The clear direction of public policy is to unbundle utility l operations. Boston Edison is moving in parallel with this trend, reshaping and redefining 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 earnings 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 well operationally. Average service restoration times improved by 15 per-cent and more than 90 percent of all new services were installed within a tnree-day turnaround. The company's aging distribution system. including the downtown network, is being upgraded for increased reliability. Additionally, the company's fossil generating units achieved the second best per-formance in history for unit availability. In nuclear generation, Pilgrim Station surpassed all previous capacity factors during a refueling outage year and recently set a new record for continuous operation.
INDUSTRY PICTURE - THE MASSACHUSETTS DEBATE Customers will benefit from the forces of competition as the electric utility industry moves to restructure. Under the regulatory model, Bostor. Edison, like most utihties, was fully integrated, f
manufacturing the product of electricity, and handling the transmission and distribution of that prod-
- uct to its customers.
l l Boston Edison's vision of a restructured industry is one in which j educated consumers choose freely among competitors for their energy l supply and services. In the new environment, the three major components of the business i will be separated. Electricity generation wol become totally deregulated over time. Kilowatts will i
! become a commodity, sold at the marke: 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 electricitv delivery, will still be highly regulated, but distobution com-l panies will have opportunities to offer new product lines and expanded services. Over time, our l own distribution 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 l energy more efficiently.
l Clearly, the industry is moving toward direct access and lower
- energy costs. Customers wiii first see their bills simplified, showing production and delivery charges separately. These bills will have fewer components and an easier-to-understand format j that will help clarify energy usage. As customers learn about the market through these new pricing signals, they will increasingly look for the best energy market price and related products and ser-t
- vices. Boston Edison will be there to package those retail services for customers.
l But there are many issues requiring joint resolution by interested panies before total dereg-ulation can occur. One major issue is stranded cost recovery. Those costs represent investments f
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 l ,l , Regulatory Commission's actions on transmission access provide for a reasonable opportunity to recover investments, as did the Massachusetts Department of Pubhc Utilities in its August 16,1995, order. In terms l @- 3 i
, of Boston Edison's own stranded cost exposure, we i N P % are positioned well in relation to other New England utilities, we are not wa.11ng. however, for a final ruiing on stranded
) " Q+ wkh x cost recovery to clean up our balance g;3 sheet. Cost savings are already being O
A' rechanneled to mitigate the potential for
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l In the meantime, we were the first v .. .
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to submit our own restructuring plan, the E-Plan, which is the quickest path to f
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! lower prices and customer choice. Under '
1 j the E-Plan, all customers could choose their energy sup-phers as early as 1998. However, the E-Plan includes an j invaluable transition element. It unbundles utility costs, j sets performance incentives for pricing delivery, simu-
! lates market prices for production, and, perhaps more - '"
j importantly, educates 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 j 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 trend toward lower costs
- has already begun. In inflation-adjusted j terms, Boston Edison customers are paying 25 percent less per kilowatt-l hour today than they did in 1981. More significant price changes will be seen in the coming years.
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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 indus-try. This is an internal alignment to the unbundling concept, giving profit and service responsibilities 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 lea to the formation of these Business j 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 l 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.
3
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 dea!: 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 ut stay ahead of indus-try developments.
THE CUSTOMER STORY i l
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 i 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 wholesele customers, the Massachusetts Port Authority (Massport). During the life of this contract, the Authority's electricity use will more than double. Boston Edison provided Massport with a com-petitive price 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 I major utilities in the region - and won every bid.
NEW BUSINESS OPPORTUNITIES 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-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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is attractive because it provides commercial customers with a clean and efficient alternative for cooling buildings. Over the next five years, this project is expected to generate about $15 million in annual revenue. It will be an important value-added service for customer retention and also will help us gain marketshare.
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 restructuring 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 and, as you'll see throughout the balance of this report, are exercising those skills daily for the benefit of shareholders, customers and the communities we serve.
Our financia! 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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8 Chairman, President and Chief Executive Officer J
,n b W" Industrial and Manufacturing While Boston Edison's industrial base is relatively sma!I, amounting to about 12 percent of retail sales, its associated manufacturing jobs are valuable
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to the region. Despite the manufactunng dochne in recent years, there are success stones and your company has played a part in many of them.
l In tandem with substantial State elforts to provide incentives for manufacturing in Massachusetts. Boston Edison's own economic develooment efforts resulted in 28 i megawatts of new and retained load, representing more than $6 milhon in annual base rev- 4.
enue. These results were recently recognized when Chairman, President and CEO Tom May was named Chairman of the Govemor's Council on Economic Growth and Technology. s
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EMC% Dan Fitigerald at the Hopkinton manufacturing facility.
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EMC Corporation 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 quality are where Boston Edison enters i 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 issue at EMC because their l
I product is continuously tested in a 21-day cycle. That means EMC sets very high expectations I for thc;r energy supplier.
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- The EMC/ Boston Edison partnership goes back to 1990. We have installed ice storage, f 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 reliability 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 expertise in solving their energy problems and to offer innovative energy-related services that will enhance their business operations.
7
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1 Commercial and Government The commercial sector, which includes government customers, remains the cornerstone of the company's business, representing over 59 per-cent of retad sales. The area's economy showed slow but sustained growth in 1995. That was especially noticeable on the improving occupancy rates of commercial buildings. For the first time in several years, new commercialprojects were announced. High technology and hnancial services companies continued to add employees despite cutbacks in the health and banking sectors.
l The company works with commercial / government customers to tailor solutions and meet their unique needs.
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Massport's Stege Tocco at Logan International Airport.
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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 l 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.
l Boston Edison recently reached a ten-year agreement with Massport after fierce competition with ten other suppliers. The long-term agreement between l Boston Edison and Massport will bring the Port Authority into the I 21st century, with energy efficiency measures and operationalimprovements. 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 agreement 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 quality of generating capacity, Boston Edison's proposal was determined to be the best for the Authority. We are ecstatic to be staying with Boston Edison, a local company which has served the Authority's needs for many years."
Also under this agreement, Massport and Boston Edison will expand their pilot program for using electric vehicles (EVs) at Logan, with plans to make the airport 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.
9
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\ " \ 4, \ \ \ v i ~ \ l' ggeetCent,, Chris M*h*' gns thousand5 , omtortable SP"I" ,,, , traay nish' S***' \ w
FleetCenter A source of great pride to the City of Boston, FleetCenter opened in grand style last september. Tnis 77s.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. 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 facility 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 4
are introducing new ideas for better cost control all the time. Boston Edison 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 JumboTron scoreboard and, of course, cutting-edge lighting and climate control. I 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, i Bobby Orr, Larry Bird and Johnny Most. FleetCenter will soon have its own legends. Boston Edison is proud to be part of it. 11
Residential / Community Residentialcustomers are clearly stakeholders, but so, too, are the cominunities we serve and in which we operate. Boston Edison 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 eaually important to us. Listening, understanding and responsiveness are the attributes which allow a company to meet the needs of residential customers and community leaders. To this group, we add our small commercial customers, especially those who work and hve in the neighborhoods we service. g Aa
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y9$Gh-O $ 4 ,w Rw 3 hy'*. l r h ,..- y le$$ ih Mary Mutwy Jacobson represents the con-cerns of the West Roxbury business commu-J s ieh , - q:d;j. "8 J 1 nity,i;te the west Roxbu,y Pub and
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Restaurant, a cornerstone establishment in [ ,-, i " ^ " the neighborhood. John O'Neill of the Consumer Adnisory Panel sisits Boston Edison's Meter Test Lab. L$ 4 a: r n
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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 meaningful input 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 l 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," i O'Neill stressed, and he should know. Aside from serving as the panel's co-chair, he is also j 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 l order to pay all their bills." l Boston Edison took that feedback seriously and is accelerating its automated meter reading strategy. Within the next 18 months, 260,000, or over one-third of Boston Edison's i meters, will be replaced with automated meter devices, providing information from previously inacce;sible meters. Soon to follow will be sophisticated customer devices capable of interac-tive, two-way communications. l These new technologies will result in more predictable, accurate bins. 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 commercie' procerty 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 Ed: son recently joined the West Roxbury Business and Professional Association, adding to its involvement in civic and business groups. Il
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Y. 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. 14
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. l This $4.2 million initiative is the largest, most all-encompassing of its kind in the country, offer- l l ing assistance to more than 20 Boston communities. Boston Main Street is an innovative pro- i 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 comnluni-ties and city neighborhoods. What differentiates Boston's initiative is its : 1 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 l 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. l 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 comp voensive 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 thnlled 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 l Street Board, including merchants, residents, commercial property owners and local non-profit l organizations This group controls resources provided by the city and has helped to recruit 35 f 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. 1 1;
Financial Section l l 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 Of ficers and Directors - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 47 Important Shareholder Information -------------------------48
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4 i i gn om. m >- ( Co. e 2 .-4 a m we, Highlights i Dividends Paid Per Share Earnings Per Share Excluding Restructuring j Increased on a percentage basis by more Continues to show steady increase.1995 l than industry average in each of the past amount excludes a $0.44 restructuring charge. j five years. l $2.00 $2.60 ( Ti l $2.40 _ ,i I $1.80 m x ' j e $2.20 y t ? + < l o N 2 ! ': $2.00 l ** s. j $1.60 1 ! N $1.80 '- 5
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$1.40
] $1.40 l l $1.20 $1.20 l } 1991 1992 1993 1994 1995 1996 proforma f1991 1992 1993 1994 1995 l 1 i Number of Employees Retail Sales Mix Decreased 10.8%, in line with our plans Stabilized by the commercial and residential to pa e down to 3,400 employees by sectors that help minimize effects of regional year end 1996. economic swings. 4800 4600 , 5 Commercia! Residential 4400 ' 59.2 % 27.8 % k 4200 4000 x industrial k" & Other 13.0 % 3800 3600
~
3400 l1991 1992 1993 1994 1993 l 17
I retail base rate increase effective November 1994, the ending Management's Discussion and Analysis 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 Rate Regulation 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 state regulators, the Massachusetts Department of Pubh.c eminent domain case in 1994. Utih. .nes (DPU). In 1992 the DPU approved a three-year set-dement agreement effective November 1992. This agreement Operating rwenun provided us with retail rate increases, allowed for the recovery Operating revenues increased 5.4% over 1994 as follows: ofdemand side management (DSM1 conservation program On thousands) costs, specified certain accounting adjustments and clarified
"* " 'I'* N "" "*8 $59'4I9 the timing and recognition of certain expenses. The agree-Demand side management revenues 8,783 ment also set a limit on our rate 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.
Inae se in perating revenues $83,768 The retail rate increases consisted of two annual base rate increases of $29 million c&ctive November 1993 and . Retail electric revenues increased $59 milh.o n. November 1994 and an annual performance adjustment Approx.imately $28 milh.on of the .mcreased revenues was due charge c&co.ve November 1992 through October 2000. The to the November 1994 base rate increase and approximately performance adjustment charge varies annually based on the
. $11 million was due to the increase in retail kWh sales. Fuel -
performance of Pilgnm Nuclear Power Stanon. This charge is
. and purchased power revenues m. creased $11 md. lion as a further described m. the Electnc Sales and Revenues section. .
result of the u.mmg effect of fuel and purchased power cost In add. . mon to the retail rate increases, our results of recovery. However, these higher revenues are offset by higher operations were affected by the recovery of DSM program
. fuel and purchased power expenses and have no net effect on costs, accounting adjustments and the u.mmg and recognition earnings. Performance revenues, which vary annually based of certain expenses as further desen. bed m. the followm.g . .
. on the operating performance of Pilgn.m Stanon, mcreased $9 Results of Operan. ons secuon. . . .
mdh.on pnmanly due to a higher performance rate effeco. ve .m We did not make a base rate filing upon the exp.ira-
. 1995 and a 17% increase in generation.
non of the 1992 setdement agreement, therefore base rates A new annual conservation charge for recovery of currently rema.m m effect at their 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 olan with the DPU in response to its August 1995 order on .
. . , , were recovered .m 1995. This resulted in higher DSM rev-restructuring the electnc unh.ty mdustry. Fh.is plan is expect-
. . . . enues and expenses than in prior years when certain program ed to lead to negonanons with intervening parties that wdl
. costs were capitalized for recovery over six years.
result m an unb'undling of our currently m.tegrated monopolv . The net increase in wholesale and other revenues is business into a separate competitive electnc production bus.i- . .
. . . . pnmanly due to a $10 milh.on decrease in revenue reserve pro-ness and a regulated electnc distnbution business. Refer to ..
visions, which are primarily related to wholesale customer con-Outlook for the Future for further m. forman.on regarding 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 efTect on earnings. 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-lion ($20.7 million net of tax, or $0.44 per share) associated
" "W""
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 e&ct of fuel and purchased part of our organizational streamlining and reorganization power cost collection. Excluding the tin.ing e&ct, fuel into business units. Excluding the one-time charge, earnings expense increased 5% due to an 8% increase in fossil station per common share were $2.52 in 1995, an increase of 4.6% generation while purchased power expense was unchanged. Fuel and purchased power expenses are substantially all recov-over 1994. This increase is due to the $29 million annual vable through fuel and purchased power revenues. is , l
Other operations and maintenance expense increased Inten se 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 postretirement benefit expenses recorded million debentures issuance in May 1995, partially offset by ' i 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- I redemptions in 1994. Other interest charges increased slighdy 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 4
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 l under enhanced retirement programs and 149 employees 1994 versus 1993 l 4 whose positions were climinated 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 approximately one year. effective November 1993, a 2.0% increase in retail kWh l Depreciation and amortization expense increased due sales and an award relating to an eminent domain case. 3 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 Pilgrim 2 nuclear unit.
income tax expenses. In the third quarter of 1995 we changed the amorti- ! zation period of deferred nuclear outage costs to two years operating revenues , from five years as discussed in Note B to the Consolidated i Operating revenues increased 4.2% over 1993 as follows: Financial Statements. The remaining $9 million of deferred l
""M costs allocable to retail customers for refueling outages per-Retail electric revenues $62,945 '
formed in 1991 and 1993 was written off. Approx.imately $15 1 Demand + management revenues 5,056 j
) million of deferred costs from the 1995 refueling outage is Whr.csale and orb revenues (6,644) being amortized over two years.
Sbrt-term sales svenues 1,219
,The increase in demand side management programs 5ncrease in Peraiing 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 pn-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 amornza'
, 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 mcreased primarily due t due to the recovery of certain new purchased power expenses. i higher Boston property taxes resulting from capital additions. 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.
4
$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 in revenue reserve provisions - Other m, come in 1994 related to certain wholesale customer contract issues. The net decrease in other income is primarily due to a $5.7 operating expenses 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 tb costs of new contracts. The timing effect of fuel and pur-m
chased power cost collection also contributed to the decrease . Electric Salcs and Revenues in fuel and purchased power expenses. , Other operations and maintenance expense increased Electnc sales 7,4% primarily due to higher employee beneGt 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 resenues. 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. therefore, result in lower growth in electricity sales. We receive in 1994 we fully expensed the remaining deferred approval from our state regulators for DSM spending levels costs of the cancelled Pilgrim 2 nuclear unit. In accordance and recovery amounts through an annual conservation charge. with the 1992 settlement agreement we did not expense any Through 1994 we collected from customers certain DSM pro-of these costs in 1993. gram costs primarily in the year incurred and other DSM pro-Amortization of deferred nuclear outage costs in gram costs over a six-year period. In 1995 a new annual con- i 1994 and 1993 consists of amounts related to the 1993 and servation charge was implemented under which all 1995 pro-I 1991 refueling outages at 'ilgrim Station. In 1993 we gram costs were recovered in 1995. We are also provided with deferred approximately $14 million of refueling outage co:.ts. incentives and recovery oflost revenues based on the actual We began to amortize these costs in June 1993 over five years reduction in customer electricity usage from these programs as approved in the 1992 seulement agreement. and a return on the costs that we are recovering over six years. The $2 million decrease in demand side manage- , 1 ment programs expense was due to the timing of recovery of Electric revenues program costs. DSM 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 ered over six years. The 1994 expense consists of $22 million increases of $29 million etTective 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 fding upon the expiration of the settle-Municipal 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 etTect at their 1995 levels. Due to our continued commit-increase and capital additions. ment to controlling costs and increasing operating emciencier, Our effective 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 signi6 candy afTect our fmancial 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 signiGcant potential impact of this performance incen-Other income 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 eminent 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 revenues will Intercsr chmges increase by approximately $750.000. For each percentage Total interest 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 signincant $840,000. Pilgrim's capacity factor for the performance year Brst mortgage bond reGnancing 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 oft. There are no maior 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 resuh of a higher AFUDC rate related to the and for a 73-day refueling and maimenance 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. 20
Pilgrim Station was shut down for three months in increased competition from other electric utilities and nonu- l 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 tomers that set rates through 2002 and beyond. In 1995, our i by the station were met by other generating plants or pur- largest retail customer, the hiassachusetts Port Authority 1 chased from other suppliers as necessary. We do not believe (hiassport), issued a request for proposals for a wholesale sup- I that the generator damage resulted from actions within our plier of electricity. We successfully retained hiassport as a cus- ! control. Our recovery of the incremental purchased power tomer through a ten-year wholesale power supply agreement i 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. erating unit performance program. In hiarch 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 ftmds provided fo, tems to file open access tariffs at the FERC, to provide service 95%,98% and 77% of our plant and nuclear fuel expenditures under those tariffs to trammission 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 ftdl 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, alternative 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 hiassachusetts-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 fmancing industry: plan to issue up to $500 million of securities through 1996 provide the broadest possible customer choice using the proceeds to refinance short and long-term securities provide all customers with an opportunity to share in ! and ihr capital expenditures. Refer to Notes J and K to the the benefits ofincreased competition Consolidated Financial Statements for specific informauon ensure full and fair competition in generation markets relating to our recem financing activities. functionally separate generation, transmission and dis-tribution services Outlook for the Future
- provide universal service 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 I
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.
To date the effects of competition have been most distribution prominent in the wholesale electric market. In response to a reduce rates in the near term l 21 i 1
- maintain demand side management programs the economic development rates, the lower manufacturing cus-
- ensure an orderly and quick transition that minimizes comer 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 transition to a competitive market and does not establish a would be due to differing plant depreciable lives for regulato-particular model for the new industry structure. Each of the ry and non-regulatory accounting standards. We have not yer 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 order, including unbundled rates fc r generation, transmission our affected plant balances if necessary by recording an addi-and distribution. 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, which remains are also provided for in our related plan. We expect to recov-a monopoly function. 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-formance incentives to be implemented in the new industry ue to meet the criteria of these accounting standards. Ifit does structure. not continue to be 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 reorg;mized 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 Customer, Generating-Fossil, Generating-Nuclear and be Disposed Of. See Netc 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 err bedded pany-wide strategic goals. As a result of enhanced retirement regulatory assets or plant costs could have a material impact on j 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 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 comers. These actions all signify our commitment to be a com- power producer,JMC Altresco,Inc. We have consistently petitively priced, reliable provider of energy. We do not expect opposed this order since we do not believe we need any new 22
1 1 1 power for several years and the proposed contract would also continue to face possible liability as a potentially respon-impose excessive costs on our customers. In 1995 we filed a sible party in the cleanup of approximately ten multi-party motion to dismiss the matter, which is pending. We also fded 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 Ahresco's pro- rently expect to have only a small percentage of the potential posed generating station based pardy 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 orr assessments of the specific site circumstances, we they will meet those needs Ly 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 financial condition. However, additional pro-1994 IRM 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 filing 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 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 545 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 and the production of water treatment systems. In 1996 Statements for further discussion regarding spent nuclear fuel 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 Boston, is not material. natural gas, except in certain emergency circumstances. The We do not currently have a substar.tial investment in station has the ability to burn natural gas, oil or both. We BETG and do not anticipate it significantly impacting cor 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 Other Matters principally utilizes interruptible gas supplies or short-term capacity purchases. Erwironmental The 1990 Clean Air Act Amendments require a sig-We are subject to numerous federal, state and local standards nificant reduction in nationwide emissions of sulfur dioxide with respect to waste disposal, air and water quality and other from fossil fuel-fired 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 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 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 modifications made to New Boston and 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 and the particular characteristics of the different sites. We outcome of certain DEP air quality modeling studies current. 23
f l ly in progress, additional emission reductions may also be Safe harbor cautionary statement j required by 1999 or years thereafter. The extent of any addi- We occasionally make forward-looking statements such as fore-l tional emission restrictions and the cost of any further modi- casts and projections ofexpected future performance or state-fications is uncertain at this time. ments of our plans and objectives. These forward-looking I Public concern continues regarding electromagnetic statements may be contained in filings with the Securities and !
- fields (EhiF) associated with electric transmission and distrib- Exchange Commission, press relea es and oral statements.
ution facilities and appliances and wiring in buildings and Actual results could potentially differ materially from these homes. Such concerns have included the possibility of adverse statements. Therefore, no assurances can be given that the heahh effects caused by EhiF as well as perceived effects on outcomes stated in such forward-looking statements and esti- ) property values. Some scientific reviews conducted to date mates will be achieved. l have suggested associations between EhiF ar d potential health The above sections include certain forward-looking efTects, while other studies have not substantiated such associa-l statements about the effects of the industry restructuring l tions. We support further research into the subject and are process and our related plan, operating resuhs, Pilgrim l participating in the funding ofindustry-sponsored studies. Station's performance and environmental and legal issues. , We are aware that public concern regarding EhiF in some The effects of the industry restructuring process cur- ! cases has resulted in litigation, in opposition to existing or ! proposed facilities in proceedings before regulators or in rently underway at the DPU and our related plan could difTer ) from our expectations. This could occur as regulatory deci- i requests for legislation or regulatory standards concerning sions and negotiated settlements between utilities and inter-EhiF levels. We have addressed issues relative to EhiF 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 dcmand have not been significantly affected by these developments. in New England may affect the uhimate resuhs of the industry [ We continue to closely monitor all aspects of the EhiF issue. restructuring end our plan. The impacts of our continued cost control proce-litiS *'I " dures on our operating results could difTer 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 races, technology and the prices and availability Employment Act of 1967 concerning 46 employees affected by of operating supplies could materially affect our projected ; our 1988 reduction in force. Legal counsel continues to vigor- operating results. l ously defend this case. We have also been named as a party in Pilgrim Station's performance could differ from our l 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 sufTered 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 fully 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 previously 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 affect our estimated litigation costs. from a change in estimates could have a material impact on the results of a reporting period in the near term. New accounting pronouncement Statement of Financial Accounting Standards No.121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, is effective in 1996. l This statement establishes accounting standards for recogniz-ing and measuring asset impairment losses. Refer to Note hi j to the Consolidated Financial Statements for more informa-tion regarding this statement and its potential effects. 24
Consolidated Stat:ments of income years ended December 31, (in thousands, except earnings per share) 1995 1994 1993 Operating revenues $ 1,628,503 $1,544,735 $ 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 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 1,491,103 1,316,257 1,256,462 l Operating income 227,400 228,478 225,697 { Other income (expense), net (575) 3,979 211 i 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) Totalinterest 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 $ 96,739 $ 109,257 $ 102,513 Weighted average common shares outstanding 46,592 45,338 44,959 Earnings per share of common stock $ 2.03- $ 2.41 $ 2.28 Consolidated Statements of Retained Earnings years ended December 31, (in thousands) 1995 1994 1993 Balance at beginning of year 5 247,004 $ 218,292 $ 192,948 Net income 112,310 125,022 118,218 Subrotal 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 $ 247,004 $ 218,292 The accompanying notes are an integral part of the consolidated financial statements. 25
Consolidated Baltnce Sheets December 31, (in thousands) 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 l Less: accumulated amortization 251,951 50,643 236,239 55,597 l 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 l 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 53.616,576 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 o-bc/ 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 l Pe sion benefits 32,602 31,908 l Other 105,442 551,090 85,204 612,641 Deferred credits: Power contracts 21,396 40,277 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 53,616,576 The accompanying notes are an integral part of the consolidated financial statements, 26 i l
Consolidated Stat:m:nts of Cash Flows years ended December 31, (in thouands) 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 fuci 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 l 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 l Investing activities: Plant expenditures (excluding AFUDC) (180,822) (198,771) (246,774) Nuclear fu 1 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 10,855 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 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 $103,720 l Income taxes $ 96,180 $ 46,074 $ 30,305 The accompanying notes are an integral part of the consolidated financial statements. n
I Notes to Consolidated Financial Statements Note A. Nature of Operations We are an investor-owned regulated public utility operating in the energy and energy services business. This includes the 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 nuclear unit, Pilgrim Station. We supply electricity at ! retail to an area of 590 square miles, including the City of Boston and 39 surrounding cities and towns. We also supply electricity I 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 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. i 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 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 GAAP. The application of SFAS 71 results in differences 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 affect the reported amounts of assets and liabilities and disclo-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 differ from these estimates.
- 2. Revenues We record revenues for electricity used by our customers but not yet billed at the end of each accounting perioc.
1
- 3. Forecasted Fuel and Purchased Pcwer Rates J 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.
1
- 4. Depreciation and Nuclear Fuel Amortization l
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, respectively, based on estimated useful lives of the various classes of property. The cost of decommissioning 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 decontami-nation 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 Outage 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 outages 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 dis-2a
' 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 five year peri- ,
- od resulted in a significant lag between the expenditure and recovery of outage costs. We decided not to request recovery of the i buildup of costs resulting from this regulatory lag. Accordingly, the remaining $9 million of deferred costs allocable to retail cus-l . tomers 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. 1
- 6. Amortization of Discounts and Redemption Premiums on Debt 1 I
, We expense discoun'ts, redemption premiums and related costs associated with issuances or redemptions oflong-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 Funds Used During Construction (AFUDC)
' 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 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 Equivalents 4- 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. ;
i '9. Allowance for Doubtful Accounts l: 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, Accordingly, we do not maintain a significant allowance for doubtful accounts balance. !
i' j 10. Regulatory Assets j 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 earned on the regulatory assets. l Regulatory assets consisted of the following: December 31, 1995 1994 4 Redemption premiums $ 44,709 $ 52,859 Income taxes, net 46,121 44,745 l
- Power contracts 21,396 40,277 t- Pension and postretirement costs 13,811 22,761
- Nuclear outage costs 13,471 17,804 l ' Other' 17,266 19,702
$ 156,774 $198,148 i
j Note C. Kate Regulation
- In 1992 the DPU approved a three-year serdement agreement relating to our rate case proceedings. The agreement provided for retail
! rate increases, accounting adjustments and demand side management program expenditures; darified the timing and recognition of cer-j; rain expenses and set limits on our rate of return on common equity through 1995.
i in February 1996 we filed an industry restructuring plan with the DPU in response to its August 1995 order on restruc-I turing the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in new rates i and performance incentives to be implemented in a new inhstry 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 afTect our l_ contract or wholesale power races, which are regulated by the FERC.
a i
.~,
- ~ - - .- - -- - - - . . - , , - . - . . - -_-.-. .- _ . .- .
O p ! I Nots D, income Taxes l l - Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No.109, Accounting for income Taxes i (SEAS 109), 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 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, i and December 31,1994, respectively. The regulatory assets represent the additional future revenues to be collected from customers for l deferred income taxes. 3 l Accumulated deferred income taxes consisted of the following: l December 31, j ( (in thousands) ' 1995 1994 l i Deferred tax liabilities: Plant-related $ 521,280 $511,572 Other 95,148 105,786 : 616,428 617,358 ! Deferred tax assets: Plant-related 12,590 13,216 f nvestment tax credits 40,632 43,273 iternative minimum tax 0 1,332
)ther 65,924 44,083 1
~
119,146 101,904 ; Net accumulated deferred income taxes
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$ 497,282 $515,454 i i
No valuation allowances for deferred tax assets are deemed necessary. Components ofincome tax expense were as follows: I years ended December 31, (in thousands) 1995 1994 1993 i Current income tax expense $93,469 5 63.358 5 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 I (1,729) 2,834 1,205 l Total income tax expense $ 66,047 5 57,632 5 36.348 i 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 lavestment tax credits (2.3) (2.3) (2.6 Municipal property tax adjustment - - (9.6) Reversal of deferred taxes - settlement agreement - (5.5) (' 3.0) Other 0.1 (0.1) 0.4 F$ective 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 restored 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 he 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 upcv 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 trent fuel storage technology along with th impact on the decommissioning estimate. In February 1996 the Financial Accounting Standards Bo.ad (FASB) issued proposed new rules for accounting for liabili-ties related to closure and removal oflong-lived assets, which includes decommissioning. If these draft rules are adopted we would be 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-sured based on the 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 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 efTect , 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 curiently 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 Mountain. 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 j 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. i 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 eventually construct a spent fuel repository and what the effect on us will be of any delays in such construction.
- 3. Low-l evel Radioactive Waste We regained access to low-level radioactive waste (LIW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currendy 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 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.
31
- 4. Other Nuclear Units v We are an investor in and customer 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 units at the end of their usefullives.
Note F. Corporate Restructuring in 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen l our competitiveness in the changing electric energy market. In conjunction with this reorganization we ofTered enhanced retire- ) ment programs and implemented a special severance pn gram to reduce employee stafTmg levels. Under the enhanced retirement l programs 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under i the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million net of tax) over the third I and founh 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 all management and administrative support personnel. Severance benefits provided were salary payments, medical insurance and outplacement services. The retirement progran s' 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 defmed 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 nor less than the minimum required contribu-tion under federallaw or greater than the maximum tax deductible amount. Tb- rement plan assets consist of equities, bonds, money market funds, insurance contracts and real estate funds. We also have a supplemental pension plan for cenain management e - t Benefits under this plan are based on final compensation upon retirement. The plan is not funded. The plan's cost and ' at 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: - years ended December 31, On thousands) 1995 1994 1993 Current service cost - benefits earned $ 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 amonir.ation and deferral 49,557 (32,169) 8,528 Net pension cost (a) $ 20,493 $ 17,063 $ 8,973 l l (a)In ac ordance with our 1992 settlement agreement we deferred the difference in the net pension cost of the retirement plan and its annual funding amount. Net oeferred costs amounted to ($1.2) million and 56.5 mil! ion at December 31.1995 and 1994. respectivdy. Total net pension costs recorded as expense in 1995,1994 and 1993 were 528 million. 525 million and 55 million. respectively. U
We used the following assumptions for calculating pension cost: 1 1995 1994 1993 l
\
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 % l 1 l The pension plans' funded status was as follows: December 31, i (in thousands) 1995 1994 l Actuarial present value of benef t obligations: Accumulated benefit obligation, including vested benefits of $386,020 and $305,632 (b) 9 401,329 $321,072 Plan assets at fcir 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 pension liability (d) $ (42,759) $(31,903) (b) The accumulated benefn obligation at December 31,1995, includes $13.5 million related to the enhanced retirement programs offered in 1995 as discussed in Note E (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 acc imulated 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 milhon on our consolidated balance sheets at j December 31,1995 and 1994, respectively. (d) Net pension liability includ:d on the consolidated balance sheets in current liabilities is $33 million and $32 million, and in deferred credits is $10 million and $0 at December 31,1995 and 1994, respectively. We used the fcMowmg assumptions for calculating the plans' year-end funded status: 1995 1994 Discount rate 7.25 % 8.25 % Compensation increase rate 3.90 % 3.90 % i 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 million in 1994 and $7 million in 1993. l
- 2. Other Postretirement Benefits in addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accor.
dance with Statement of Financial Accounting Standards No.106, Employers' Accounting for Postretirement Benefits Other Than I 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. ; i Our funding policy is to contribute 100% of postretirement benefits costs to external trusts. Accordingly, we recorded expenses of
$23 million in 1995, $17 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. i I J l l u l 6 1 I 1
. .- -- _- - . . - . ~~ _ - .. .
Net postretirement benefus cost consisted of the following components: J years ended December 31, Gn thousands) 1995 1994 1993 Current service cost - benefits earned $ 3,408 $ 4,978 5 4,351 Inrerest 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 $ 24,993 $ 27,788 l
)
We used the following assumptions for calculating postretirement benefits cost: l 1995 1994 1993 Discount rate 8.25 % 7.00 % 8.00 % l 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 % 1 1 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%. l l The postretirement benefits program's ftmded status was as follows: December 31, l Gn thousanda 1995 1994 Trust assets at fair value $ 51,064 5 33,300 Accumulated obligation for service rendered to date from: Retirees $ (110,877) $ (93,960) - Active employees eligible to retire (31,980) (31 159) l Active employees not eligible to retire (53,514) (196,371) (51,545) (176,664) l 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) $ 0 , l 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. l The weighted average discount rates used to measure the accumulated benefit obligation were 7.25% in 1995 and 8.25% l !' in 1994. The trust assets consist of equities, bonds and money market funds. i Note H. 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 certtin of our property in 1989. Note 1. Cancelbl Nuclear Unit In 1982 we began expensing the cost of our cancelled Pilgrim 2 nuclear unit over approximately cleven 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. l I I t 34 l 1
r 1 Note J. Crpitil Stock December 31, ;
- (dollars in thousands, except 'per share amounts) 1995 1994 1993- !
Common stock equity: Common stock, par value $1 per share, ! 100,000,000 shares authorized: 48.a03,178, 45,535,477 and 45,129,227 shat:s issued and outstanding: - $ 48,003 $ 45,535 $ 45,129 i
- 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 i
'Ibral common stock equity $ 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 I 4.25 % 180,000 $103.625 $ 18,000 $ 18,000 - $ 18,000 ) I 4.78 % 250,000 $102.800 25,000 25,000 25,000 7.75 % 400,000 -- 40,000 40,000 40,000
]
8.25 % 400,000 - 40,000 40,000 40,000 ( lbtal nonmandatory redeemable senes $ 123,000 $123,000 $123,000 , l 1 Mandatory redeemable senes: 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 l Total mandatory redeemable series 94,000 96,000 98,000 Less: due within one year 2,000 2,000 2,000 l lbral mandatory redeemable series, net $ 92,000 $ 94,000 $ 96,000 I ! Dividends Declared per Share l Common stock $ 1.835 $ 1.775 $ 1.715 Preferred stock: 4.25% series $ 4.250 $ 4.250 $ 4.253 l 4.78% series 4.780 4.780 4.785 l 7.27% series 7.270 7.270 7.270 7,75% series 7.750 7.750 5.707 l 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 i l l i 4 35
, . . . .. .- - - - - - . . . . _ - - . _ _ . ~ -~
.1. Common Stock
. Common stock issuances in 1993 through 1995 were as follows:
Number Total Premium on ;
- (in thousands) of Shares Par Value Common Stock l I
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 reinvestment plan (a). '468 468 11,404 New issuances (b) 2,000 2,000 49,479 l Balance December 31,1995 48,003 $48,003 $683,686. l (a) At December 31,1995, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock
- Purchase Plan were 1,941,219 shares.
(b)Te used the net proceeds of the 1995 common stock issuances to reduce short-term debt.
- 2. Cumulative Nonmandatory Redeemable Preferred Stock I 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 j 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. i The redenption 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 l 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 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 1CJ,000 100,000 6.800%, due March 2003 E0,000 150,000 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 36
~I I Nota K. Indebtedness cont. )
December 31, On thousands) 1995 1994 l Sewage facility revenue bonds $ 35,700 $ 36,300 I Less: due within one year 1,600 600 ) r 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:
l 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 Total notes payable $ 126,441 5 214,786
- 1. Long-Term Debt in 1994 the hiassachusetts 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 ofTrust and First hiortgage 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 in At gust 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at ; 103.780% and the 7.80% series duc 2023 are first redeemable in hiarch 2003 at 103.730%. No other series are redeemable prior l 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 2.015. In hiay 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 'o 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 l are $101.6 million per year in 1996 through 1998, $1.6 million in 1999 and $166.6 million in 2000. j
- 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 equiry ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. Information regarding our short-term borrowings, comprised of bank loans and commercial paper, is as follows: (dollars in thousands) 1995 1994 1993 j hiaximum short-term borrowings $ 327,769 $ 268,100 $ 320,000 l Weighted average amount outstanding $ 165,720 $ 214,640 $ 220,149 Weighted average interest rate, excluding commitment fees 6.2 % 4.5% 3.4% 37
l
' Note L Frir Vtlue cI 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:
1 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. f 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 l 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 ! P In 1995 the FASB 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(SFAS 121), effective in 1996. This statement clarifies when and how to rec- ; ognize asset impairments. In addition, SFAS 121 requires that all regulatory assets, which must have a high probability'of recovery i to be initially established, continue to meet that high probability standard or be written off. However, if written off, a regulatory asser can be restored ifit regains a high probability of recovery. The impa :t 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 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 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 Commitments I 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- l sion agreements and noncancellable leases for the years after 1995 are as follows: ' (in thousands) 1996 $ 24,908
.I997 22,109 1998 19,002 1999 17,408 2000 16,656 Years thereafter 108,417 j 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 I
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 ponions 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. Hydro-Quebec
- We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included 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 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 Board of Directors of Yankee Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generat-i ing station and decommission the facility. We relied on Yankee Atomic for less than one percent of our system capacity under a long-term purchased power contract.
Yankee Atomic received -nproval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period u ine 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 i sh:et as a power contract liability and an ofTsetting regulatory asset as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement.
- 4. Nuclear lasurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insur-ance. Additional nuclear liability insurance up to approximately $8.3 billion is provided by a retrospective assessment of up to
$75.5 million per incident lesied 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 prolonged 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 w 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 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 ftdly 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.
39 l
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 l sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party l hazardous waste sites in Massachusetts 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 potentialliability. 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, aEhough 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 i change in estimates could have a material impact on the resuhs of a reporting period in the near term. l Note O. Long-Term Power Contracts
- 1. Long-Term Contracts for the Furchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of the generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidated income statements. Information relating to these contracts as of December 31,1995, is as follows:
proportionate share (in thousands) Units of 1995 1995 Interest 1)ebt Contract Capacity Minimum Portion of Outstanding Expiration Purchased (a) Debt Minimum Through Cont. Generating Unit Date % MW Service Debt Service Exp. Date Canal Unit 1 2001 25.0 139 $ 1,122 5 349 5 3,400 Mass. Bay Transportation 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 Transportation Authority - 2 2019 100.0 34 (f) (f) (f) Total 795 5 24,894 $ 16,164 $ 137,217 (a) The Northeast Energy Associates contract represents 5.9% of our total system generation capability. The remaining units listed above represent 15.6% in total. (b)Te are required to pay the greater of 522.00 per kilowan-year or 90% of the New England Power Pool capability responsibility adjustment charge up to 563.00 per kilowatt-year times the qualified capacity (currendy 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 5127 million. (d)We pay for this energy based on a price per kWh actually received. The total charges under this contract for 1995 were approximately $25 million. (c) 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 availabil. icy 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 549 million. (f) The second Massachusetts Bay Transportation Authonty contract started in June 1995. Capacity payments under this contract do not begin until 2003.
.At that time will be required to pay 584.57 per kilowatt-year times the qualified capacity plus incremental operating maintenance and fi.iel costs.
l l 40
__ m _ .. . _ . . . . _ . . _ . __ _ _ ... _ _ _ . . . ._ . . _ _ . _ _ Our total fixed and variable costs for these contracts in 1995,1994 and 1993 were approximately $283 million, $286 mil-l lion and $225 million, respectively. Our minimum fixed payments under these contracts for the years after 1995 are as follows: a (in thousands) t 1996 $ 106,649 I 1- 1997 103,682 1998 105.778 l . 1999 105,258 2000
^
, 103,676 Years thereafter 1,187,672 j Total 5 1,712,715 Total present value $ 883,409 ; I
- 2. long-Term Power Sales In addition to wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts. l j Information relating to these contracts is as follows: i 4
Contract Expiration Units of Capacity Sold , Contract Customer Date % MW i Commonweahh 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 certam adjustments. ! Under these contracts, 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, decommis- ! sioning and a return on capital. i 1 41
1 R: port of Independ:nt Accountants To the Stocidwiders 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 consolidated statements ofincc,me, 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 rnanagement, 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 l 42
Selected 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 5 47,610 $ 20,202 $ 16,300 $ 0.36 Second quarter 380,828 55,6b3 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 $ 19,812 515,850 $ 0.35 l Second quarter 368,245 50,812 23,982 20,031 0.44 i Third quarter 448,179 96,880 70,182 66,256 1.46 i Fourth quarter 351,376 34,895 11,046 7,120 0.16 i l (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 million pre. tax charge related to our corporate restructuring over j the third and fourth quarters of 1995. Amounts excluding the restructuring charge are as follows: 1 Balance Available Earnings Operating Net for Common Per Average Income Income Stock Common Share 1995 Third quarter $ 107,779 $ 77,452 $73,562 5 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 M//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 I.ow 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 j 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) l l 1995 1994 1993 1992 1991 Capacity - MW: New Boston Station 760 760 760 760 760 Pilgrim Station 669 669 670 670 670 Mystic Station 1,005 1,006 1,006 1,005 1,015 W.E Wyman Unit 4 36 36 36 36 36 j Jet turbines 284 287 283 281 281 Total (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 - MW 3,466 3,484 3,663 3,587 3,695 l Capability responsibility to NEPOOL at peak - MW 3,306 3,306 3,190 3,396 3,311 Edison territory:
)
Hourly peak - MW 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 I (BTU / 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 , 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 % 1 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 $ 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) \hter capability awfit results (b) At. muary 1,1996 Certain reclassifications were made to the data reported in prior years to conform with the method of presentation used in 1995. 44
Sel:cted Censolidated 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 3 Total 17,497,123 16,884,331 16,688,626 18,061,170 16,527,733 Disposition. Commercial 7,604,841 7,478,631 7,263,358 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 Total 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 Jibral system 16,378,267 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 Total 17,497,123 16,884,331 16,688,626 18,061,170 16,527,733 l Kilowarthours - annual growth: Commercial 1.7 % 3.0 % 1.2 % 0.5 % (0.5)% Residential 0.8 1.6 1.9 0.8 (1.2) I , Industrial (0.1) (2.6) (5.4) (0.8) (3.4) Other 0.7 (10.0) (50.3) 4.6 1.6
'Ibtal retail sales (a) 1.2 1.7 (0.7) 0.5 (1.0) i 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)
'Ibral system 3.8 % 1.0 % (8.0)% 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 % 11 % 12 % 13 % 13 % Other 2% 2% 1% 2% 2% Retail revenue per kWh 11.08 e 10.68 e 10.33 e 9.55 e 9.27 e 4 Average number of customers 653,757 655,707 651,141 646,215 642,967 (a) ffTective February 1993 a former retail customer became a wholesale customer as allowed under Massachusetts state law. Excluding the etTect of this 4 customer's change in status, total retail sales increased 2.0% in 1994 and 1.2% in 1993. l 45
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Selected Consolidated Financial Statistics (Unaudited) l 1 1995 1994 1993 1992 1991 Operating revenues (000) $1,628,503 51,544,735 $ 1,482,159 5 1,411,753 $ 1,354,501 Balance for comr..on (000) $ 96,739 $ 109,257 $ 102,513 $ 90,748 $ 77,059 1 Per common share: Earnings $ 2.52 (a) $ 2.41 $ 2.28 $ 2.10 $ 1.96 Dividends declared $ 1.835 $ 1.775 5 1.715 $ 1.655 $ 1.595 I 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 flow $ 6.81 $ 8.12 $ 6.58 $ 6.80 (b) $ 5.50 (b) Payout ratio 72% (a) 73 % 75% . 78 % 81 % l Return on average common equity 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% j Fixed charge coverage (SEC) 2.38 2.46 2.22 1.89 1.83 ; Capitalization: Total debt 54 % 56 % 57 % 56 % 58 %
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Preferred equity 8% 9% 9% 9% 10 % Common equity 38 % 35 % 34 % 35% 32 % long-term debt (000) $1,160,223 $ 1,136,617 $ 1,272,497 $ 1,091,073 $1,136,765 Mandatory redeemable preferred stock (000) $ 94,000 $ 96,000 $ 98,000 $ 98,000 $ 100,000
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Total assets (000) $3,643,849 $3,616,576 53,476,601 $ 3,294,212 $3,098,742 l Internal generation after dividends (000) $ 184,492 $ 217,030 $ 194,209 $ 204,248 $ 193,019 ; Plant and nuclear fuel expenditures (000) $ 194,443 $ 220,705 5 253,265 $ 231,025 5 214,213 I Internal generation 95 % 98 % 77 % 88 % 90 % Common shares outstanding: Weighted average 46,591,662 45,337,661 44,959,050 43,143,953 39,347,824 Year-end 48,003,178 45,535,477 45,129,227 44,763,055 42,047,356 j Stock price: j
- High 29 1/2 29 7/8 32 5/8 28 1/4 24 7/8 1ow 23 1/8 21 1/2 26 3/8 22 1/8 181/4 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 Marker / book ratio (year-end) 1.43 1.19 1.53 1.47 1.38 Price / earnings ratio (year-end) 11.7 (a) 10.0 13.0 13.1 12.6 (a) Amounts including 534 million pre-tax restructuring charge:
Earnings $ 2.08 Payour ratio 88 % Return on average common equity 10.0 % Price / earnings ratio 14.2 l l (b) Excludes effect of rate and contract settlements. i l Certain reclassifications and recalculations were made to the data reported in prior years to conform with the method of l presentation used in 1995. 46
1 l l Officers Direct:rs l l l Thomas J. May, Chairman of the Board, President and Chief Executive Officer ad William E Connell, Chairman and Chief Executive Officer, Connell Limited Partnership (metals E. Thomas Boulette, Senior Vice President - Nuclear recycling and processing and industrial production) l l L Carl Gustin, Senior Vice President - Corporate Relations d,f Gary L Countryman, Chairman of the Board and l Chief Executive Officer, Liberty Mutual l John J. Higgins,Jr., Senior Vice President - Human Resources Insurance Company a,e,f Thomas G. Dignan, Jr., Partner, Ropes & Gray Douglas S. Horan, Senior Vice President and General (law firm) Counsel b,c,d Charles K. Gifford, Chairman, President and Chief I
. Executive O$cer, Bank of Boston Corporation James J. Judge, Sem.or Vice President and Treasurer (bank holding company) and The First National l Bank of Boston Ronald A. Ledgett, Senior Vice President - Fossil ]
b,f Nelson S. Gifford, Principal, Fleetwing Capital l Alison Alden, Vice President - Sales & Service ("*"'"'" I""*8' **"'5) 1 a,e Kenneth I. Guscott, General Partner, Long Bay l William N. Dimoulas, Vice President - Information Systems Management Company (real estate development) l a,b,c Matina S. Horner, Executive Vice President, Teachers l Richard S. IIahn, Vice President - Technology Insurance and Annuity Association and College l Research & Development Retirement Equities Fund Leon J. Olivier, Vice President - Nuclear Operations and
**' * ** 3 ' 'F' Chairman of the Board, President and Chief E.xecutive Officer, Boston Edison Station Director Company Robert A. Ruscitto, Vice President - Field Service and b,d Sherry H. Penney, Chancellor, University of Electric Delivery Massachusetts at Boston e,f Bernard W. Reznicek, Dean, College of Business l Robert J. Weafer, Jr., Vice President - Finance, Controller and Administration, Creighton University and former I Chief Accounting Officer Chairman of the Board and Chief Executive Oflicer, Boston Edison Company l Theodora S. Convisser, Clerk of the Corporation c,f Herbert Roth, Jr., Former Chairman of the Board j and Chief Executive Officer, LFE Corporation Donald Anastasia, Assistant Treasurer (traflic and industrial control systems) I e,f Stephen J. Sweeney, Former Chairman of the Board l Wayne R. Frigard, Assistant Clerk of the Corporation and Chief Executive Officer, Boston Edison Company l l
b,c.d Paul E. Tsongas, Partner, Foley Hoag & Eliot (law firm) a Member of Executive Committee b Member of Audit, Finance and Risk Management Committee c Member of Pricing Committee d Member of Executive Personnel Committee e Member of Nuclear Oversight Committee f Member of Capital Investment Committee 47
- 80 penn nth minimum not to exceed $40,000 -
Important Shartholder information per calendar year .
- Safekeeping of common stock certificates ,
Shareholder Inquiries Beneficial owners of our stock whose shares are registered in names other than their own (e.g., a broker or bank nominee) If you have questions concerning your dividend payments, the Dividend Reinvestment and Common Stock Purchase Plan, Inust arranSe Participation with the record holder. If for any direct deposit service, transfer procedures or other stock reason you are unable 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. The First National Bank 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.O. Box 644 Safekeeping Program (New) Boston, MA 02102-0644 Shareholders who are participants in the Dividend Toll Free Phone: 1-800-736-3001 Reinvestment and Common Stock Purchase Plan can transfer If you are submitting documents requesting a transfer, their common stock certificates into their plan account for J address change or account consolidation, please use this same safekeeping. Dividends on those shares will be reinvested l address with Mail Stop: 45-01-05. If you would like to automatically like any other shares held in the plan. To con- ! contact the bank by telephone call 617-575-3100. tinue receiving cash dividends, you must hold your shares in j certificate form. For additional information, contact our j Dividend Payments Dates stock transfer agent. Common and Preferred SEC Form 10-K ' 1st of February, May, August and November Stockholders may obtain a copy of our annual report to the i Tax Status of 1995 Dividends t Securities and Exchange Commission on Form 10-K, Generally, unless you are subject to certain exemptions, all by contacting our Investor Relations Department. j dividends on our common or preferred stock are to be consid" Quarterly Report to Shareholders i ered 100% taxable. Beneficial owners of our stock whose shares are registered in ] Stock Symbol and Exchange 1.istings names other than their own may obtain copies of our Ticker Symboh BSE Quarterly Reports to Shareholders by contacting our Investor Relations Department. Note that the Annual P.cport will [ New York and Boston stock exchanges ;j continue to be mailed to beneficial owners 6tectly by their i 1996 Annual Shareholders Meeting bank or broker. l All shareholders are invited to attend our Annual Meetmg on d I Wednesday, May 8,1996, at 11:00 A.M. at the Sheraton ; Boston Hotel and Towers. Theodora S. Convisser Clerk of the Corporation Dividend Payments - Direct Deposit Service investor Relations Contacts Sharehoklers receiving dividend checks can arrange for elec-tronic direct deposit. Transfers are made on the dividend pay. Philip J. Lembo ment dates and confirmation statements are mailed to share. Director, Investor Relations holders. To take advantage of this convenient program, con. (617) 424-3562 tact our stock transfer agent as noted above. Of Jean M. Carella Dividend Reinvestment and Common Stock Investor Relations Specialist Purchase Plan (617) 424-2658 In 1995, we modified and improved our Dividend Ema.li Address Reinvestment and Common Stock Purchase Plan (the plan). It is available to our common and preferred shareholders, our ir@bedison.com residential electric customers and employees. Participants do General Offices not pay brokerage fees or commissions related to the purchase of shares. Some important features of the plan are as follows: 800 Boylston Street
- Optional cash payments invested monthly Boston, MA 02199-8003 48
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