Eastern Utilities
A diversified energy services
company leading the way
into the era of electric utility
competition
1996 Annual Report
EUA System Profile
Eastern Utilities Associates is a diversified energy services company whose
shares are traded on the New York and Pacific Stock Exchanges under the ticker
symbol EUA. Its subsidiaries are engaged in the generation, transmission,
distribution and sale of electricity, and energy-related services such as
energy management and conservation and efficient use of energy.
To better reflect the competitive business environment in which it operates,
EUA is organized in four distinct business units.
Core Electric Business
EUA's core electric business comprises two business units. The retail business
unit provides electric distribution service to approximately 299,000 customers
in southeastern Massachusetts, and northern and coastal Rhode Island. Electric
distribution subsidiaries are Blackstone Valley Electric Company, Eastern
Edison Company and Newport Electric Corporation. The wholesale business unit
is Montaup Electric Company, EUA's generation and transmission subsidiary,
which provides electricity at whole sale to the electric distribution
subsidiaries and two other non-affiliated municipal electric utilities, and
high voltage transmission services.
Energy Related Business
EUA's energy related business unit includes EUA Cogenex Corporation, EUA Ocean
State Corporation, EUA Energy Investment Corporation and EUA Energy Services
Corporation which owns our interest in Duke/Louis Dreyfus Energy Services (New
England) LLC, a power marketing partnership. EUA Cogenex is the most active
of our energy related companies with energy services contracts throughout the
United States and Canada. EUA Ocean State owns a 29.9% partnership interest
in the Ocean State Power electric generating station in northern Rhode Island.
EUA Energy Investment makes investments in energy related businesses.
Duke/Louis Dreyfus Energy Services plans to market energy and energy related
services in New England.
Corporate
The corporate business unit is made up of Eastern Utilities Associates - the
System's parent company - and EUA Service Corporation which provides
professional and technical services to all EUA System companies.
Cover:
The reorganization of our industry required the untiring efforts of many
members of the EUA team. Our employees are working together with all our
constituents to smooth the transition from monopoly to competition. The photos
in the continuum of this annual report reflect the diversity and diligence of
their contributions.
To Our Shareholders
Dear Shareholder:
1996 was a defining year for the electric utility industry in New England,
including Eastern Utilities Associates. It was a year in which we were
continually challenged to be flexible and innovative. Regulatory and
legislative initiatives addressing electric utility restructuring created an
atmosphere of uncertainty about the future. Massachusetts and Rhode Island,
the two states in which EUA's utility subsidiaries do business, are at the
forefront of electric utility industry restructuring. We took a proactive role
in working with all stakeholders in the restructuring process to bring about a
consensus that is fair to all. By year's end, there was no question that the
age of utility competition had arrived.
The uncertainty created by utility restructuring negatively impacted the
electric utility industry nationwide and particularly in New England. Coupled
with the poor performance of EUA Cogenex and EUA Energy Investment it led to
EUA's common shares underperforming during 1996.
The performance of our Energy Related Businesses was, for the most part, a
disappointment in 1996. While our EUA Ocean State subsidiary continued to
provide a significant contribution to earnings - our investments in EUA Cogenex
and EUA Energy Investment did not meet expectations and operated at a loss.
EUA's 1996 consolidated net earnings of $30.6 million represented a 6.2%
decrease from those in 1995, a year that was also disappointing. EUA Cogenex's
operating losses, which included a one-time charge of 18 cents per share, the
unusual number of severe storms which struck our service territory in 1996,
and increased outage costs related to the Millstone III nuclear generating
plant negatively impacted 1996 results.
While earnings were less than expected, EUA continues to maintain a strong cash
position. Cash flow per share for 1996 was $5.44. The EUA System continues
to generate more than 100% of its cash construction needs internally. This
strong cash flow, coupled with the underlying earnings of our Core Electric
Business, enabled us to increase the dividend by 3.8% in May, 1996 to its
current annual rate of $1.66 per share. Our goal has been to provide our
shareholders with annual dividend increase s, greater than the utility
industry average, while maintaining a conservative payout ratio. While our
goal has not changed we recognize that the developing competitive market for
both our Core Electric Business and diversified operations requires u s to
proceed cautiously.
The section following this letter entitled "The Competitive Revolution"
provides more detail on the regulatory and legislative initiatives impacting
our Core Electric Business and the competitive forces that have slowed the
progress of our Energy Related Businesses.
Not everything that happened during 1996 was negative. Teamwork enabled us to
meet the many challenges we faced in creative ways. (Teams of EUA employees
working together and with our customers appear in the photos running along
these pages.) Positive developments in 1996 included:
- The regulatory and legislative initiatives in Massachusetts and Rhode
Island are now taking shape, removing much of the uncertainty surrounding
utility restructuring and its impact on our Core Electric Business. Our
proactive involvement in the restructuring process, which led to settlement
agreements in Massachusetts and Rhode Island, and our role in building
consensus for Rhode Island's Utility Restructuring Act show that we are ready
to move into the competitive arena. Movement into the competitive arena may
result in EUA divesting its entire generation portfolio.
- We made strategic moves during 1996 to put Cogenex back on the path to
profitability. Enhancing and refocusing of the Cogenex sales and marketing
efforts in the third quarter and a workforce reduction at year's end, together
with additional cost saving measures, should help Cogenex return to
profitability in the second half of 1997.
- The development of a prototype biomass-fueled combustion turbine in
Tennessee by the BIOTEN general partnership, in which we hold a 40% interest.
Testing of the unit has been encouraging to date.
- The June purchase by our EUA Energy Investment subsidiary of a 20%
ownership interest in Separation Technologies, a Massachusetts company which
develops and installs high volume materials separation equipment using
proprietary technology. The company's patented system to separate unburned
carbon from coal ash provides coal-burning power plants with a marketable by-
product at the same time it reduces potential environmental consequences
associated with the disposal of high-carbon fly-ash. The system has been
proven in commercial use. Customer interest from throughout the United States
and Europe makes this an investment that has the potential of making a positive
contribution to earnings in 1997.
- Although TransCapacity, our subsidiary which develops gas industry
software, continued to operate at a loss during 1996, we are encouraged by
the fact that in late 1996 the Federal Energy Regulatory Commission (FERC)
issued new directives which require gas pipelines to phase in compliance with
electronic data interchange (EDI) regulations during April, May and June of
1997. TransCapacity's T/Nominatr TM product is in full compliance with these
mandated FERC standards for transporting natural gas. Pipeline compliance
with FERC mandates during the second quarter of 1997 will be critical to
TransCapacity's success.
The teamwork of our dedicated workforce in all aspects of our business enabled
EUA to successfully meet many of its challenges in this past tumultuous year.
That won't change. If anything, the need to find innovative ways to build our
business in t he competitive arena means we must continue our commitment to
finding creative ways to perform at ever higher levels.
We thank the employees who, as a team, restored power after 18 storms, worked
harder with fewer resources to continue to provide excellent customer service,
and who served on the restructuring teams that continued the reorganization of
our company in 1996. We are confident that this team effort will help us meet
the many challenges we will face as we go forward in the competitive era.
Your management team recognizes that 1996 was a disappointing year. Our team
is fully committed to reversing the downward trend in earnings and restoring
greater value to your EUA Common Shares.
Donald G. Pardus John R. Stevens
Chairman and Chief Executive Officer President and Chief Operating Officer
March 11, 1997
Highlights
1996 1995 1994
FINANCIAL DATA ($ in thousands)
Operating Revenues $ 527,068 $ 563,363 $ 564,278
Consolidated Net Earnings<F1> 30,614 32,626 47,370
Return on Average Common Equity 8.2% 8.8% 13.6%
Common Shareholder Equity-
% of Capitalization (Year-End) 45.8% 44.5% 42.8%
Total Assets 1,257,029 1,206,130 1,234,049
Cash Construction Expenditures 62,730 77,923 50,519
COMMON SHARE DATA
Consolidated Earnings per Share<F1> $ 1.50 $ 1.61 $ 2.41
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515
Annual Dividend Rate $ 1.66 $ 1.60 $ 1.54
Total Common Shares Outstanding 20,435,997 20,436,764 19,936,980
Average Common Shares Traded Daily 91,843 58,573 35,359
Book Value per Share (Year-End) $ 18.19 $ 18.36 $ 18.33
Market Price - High 24 1/4 25 27 3/8
- Low 14 3/4 21 1/2 21 3/8
- Year-End 17 3/8 23 5/8 22
OPERATING DATA
Total Primary Sales (mWh) 4,491,000 4,441,000 4,410,000
System Requirements (mwh) 4,699,000 4,668,000 4,643,000
System Peak Demand (mw) 854 931 921
System Reserve Margin (At Peak) 34.4% 24.2% 22.4%
System Load Factor 62.6% 57.2% 57.5%
Customers (Year-End) 299,471 297,331 293,707
Employees (Year-End) - Core Electric<F2> 468 541 720
- Energy Related 213 253 240
- Corporate<F2> 564 536 437
<FN>
<F1> See Management's Discussion and Analysis of Financial Condition and
Results of Operations for details of one-time impacts to earnings.
<F2> Reflects employee shift resulting from corporate reorganization.
</FN>
The Competitive Revolution
The Age of Utility Competition Is Here
New England, home of the Industrial Revolution two centuries ago, is leading
the nation in the Competitive Revolution sweeping through the electric utility
industry today. Massachusetts and Rhode Island - home of Eastern Utilities
Associates' (EUA) electric distribution subsidiaries - are at the forefront of
states restructuring the way electric utilities conduct business. The age of
competition for electric utility customers is here.
EUA restructuring teams worked throughout the year with regulators, legislators
and various stakeholders in both states to produce a blueprint for a
restructured electric utility industry. Our teams provided comments to the
Federal Energy Regulatory Commission (FERC) during that agency's consideration
of rules to open the nation's bulk transmission system to wholesale
competition. The ground rules have been set in Massachusetts and Rhode Island
and a broad outline drawn at the federal level. Regulators and legislators
recognize the importance of an economically sound electric utility industry to
maintain reliability of service and safety.
The rules to implement competition in both Massachusetts and Rhode Island treat
all stakeholders fairly. They afford a framework for us to provide immediate
customer cost savings and provide for the recovery of the historic investments
incurred to build power plants that provide safe, reliable electric service,
that may not be able to compete on an economic basis - often referred to as
"stranded costs." By doing so, these rules maximize the benefits of
competition for both our shareholders and our customers. How? They remove
much of the uncertainty about stranded cost recovery ensuring the continued
financial health of our utility operations while providing for the opportunity
of additional cost reductions and service benefits for our customers as the
competitive electricity market matures.
At the same time, the advent of competition provides the vehicle to continue to
pursue power marketing opportunities in the six New England States with
Duke/Louis Dreyfus Energy Services (New England), our partnership with Duke
Energy Marketing and Louis Dreyfus Electric Power. The provisions of our
settlement agreements in Massachusetts and Rhode Island are consistent with
those aims.
Federal Energy Regulatory Commission Spurs Competition
On the national level, FERC's order opening bulk power transmission lines to
all users on a non-discriminatory basis provides the framework for an equitable
competitive wholesale power market.
Montaup Electric Company (Montaup), EUA's electric generation subsidiary, filed
its open-access rates with FERC to ensure that all potential power suppliers
will have the appropriate access to EUA System transmission lines. Application
of these rate s for competitive generation sources will begin when
Massachusetts and Rhode Island formally open to competition.
Also, the New England Power Pool (NEPOOL) has filed an amendment with FERC
which provides for an independent system operator of New England's bulk power
system, market-based pricing and easier entry into NEPOOL membership by power
marketers, brokers and load aggregators.
Rhode Island Legislation Leads the Way
While the general principles are effectively the same in Massachusetts and
Rhode Island, the states approached restructuring from different directions.
In Rhode Island, competition was brought into being with history-making
legislation. The state's Utility Restructuring Act of 1996 (URA) made Rhode
Island the first state to legislate competition among electric utilities.
We worked with the governor and the leadership of Rhode Island's legislative
bodies to reach consensus among the many interested parties while the
legislation was under debate. Critical issues were addressed in a responsible
manner, enabling Rhode Island to enact legislation that may well serve as a
model for other states in their approach to restructuring the electric utility
industry.
The Rhode Island legislation provides for unbundling of electric service into
generation, transmission, and distribution functions, recovery of stranded
costs, performance incentives for distribution services, and phases competition
into effect. The state's largest users may choose their supplier starting July
1, 1997; competition will be open to all customers no later than July 1, 1998.
While the legislation opens the state to competition, it also allows customers
to elect to continue to take full service from their local distribution
company. The distribution company will arrange for generation, or supply, at a
non-discriminatory " standard offer" price for those customers.
The law also provides for adjustments to the distribution companies' base rates
using the prior year's Consumer Price Index and other performance factors.
In February 1997, Blackstone Valley Electric Company (Blackstone), Newport
Electric Corporation (Newport) and Montaup reached a settlement with the Rhode
Island Division of Public Utilities and Carriers and the state's Attorney
General. In addition to complying with the URA, the settlement, to be formally
submitted to the Rhode Island Public Utilities Commission (RIPUC) in March 1997,
provides for an immediate 10% rate deduction and the filing of a plan to divest
all of Montaup's generating assets.
Massachusetts: Negotiation and Regulation
Rather than the legislative approach taken in Rhode Island, Massachusetts moved
into the competitive era through the regulatory arena and through the vehicle
of negotiated settlements between utilities, the state's Division of Energy
Resources (DOER) and Attorney General, whose "Consumers First" initiative
envisions that all customers will have their choice of electricity supplier
effective January 1, 1998.
Regulators, the DOER and the Attorney General took the view that a restructured
utility industry must lead to lower costs, over time, for all consumers of
electricity. In December 1996, Eastern Edison Company (Eastern Edison), our
Massachusetts electric distribution subsidiary, and Montaup reached a
settlement in principle with the Attorney General and the DOER. Our settlement
agreement provides for, among other things, a 10% reduction in the total cost
of electric service to our Eastern Edison customers when competition starts,
while at the same time providing for full recovery of our stranded costs
through a non-bypassable transition charge. The settlement also recognizes our
need to fully recover our stranded costs in order to remain financially viable
and provides for the filing of a plan to divest all of Montaup's generating
assets.
At the end of the year, the Massachusetts Department of Public Utilities (MDPU)
announced its model rules and legislative proposal for a restructured utility
industry. The MDPU describes the package as a "framework to ensure full and
fair competition in the generation of electric power and model rules to
implement that framework." Legislation, introduced in 1997, is needed to
provide regulators with the authority to fully implement their model rules.
Our settlement with the Attorney General and the DOER is expected to be filed
with the MDPU in March 1997.
Stranded Cost Recovery
The Rhode Island legislation and our Massachusetts and Rhode Island settlements
provide for full recovery of above market net investments in generating
facilities, with a return, over 12 years via a non-bypassable transition charge
passed through to all retail customers in both states. Proceeds realized from
the sale of any or all generating assets (market value) will be used to
mitigate the transition charge.
Commitments to nuclear power are treated somewhat differently. New England's
commitment to nuclear power was made at a time when nuclear power was
considered the best available option to reduce dependence on oil and protect
the environment. Many of those nuclear power plants may not be able to compete
cost effectively with newer generation sources. Regulators and legislators
recognize the need to ensure that funds are available to safely decommission
nuclear plants at the end of their useful lives. Costs of decommissioning
nuclear power plants will be recovered as incurred via the non-bypassable
transition charge over the remaining life of each unit. EUA does not operate
any of New England's nuclear generators, though we are joint owners of some
and are obligated under power purchase contracts to others.
Also, a utility's commitments under power purchase contracts will be compared
to prevailing market costs of electricity. Any contract costs above or below
market rates will be charged or credited to customers through the transition
charge for the duration of the individual contracts. EUA believes its
transition charge is the second lowest among Massachusetts utilities.
How Competition Will Work
In a competitive marketplace, traditional utility services - generation,
transmission, and distribution - will be unbundled into separate and distinct
services. Customers will be permitted to choose their own electric supplier at
an open market price. Distribution and transmission services will remain
regulated. Just as the local telephone company continues to deliver the long
distance service chosen by the customer, the local electric distribution
company - Eastern Edison, Blackstone, and Newport, in our case - retains the
responsibility of providing electric distribution services to all customers no
matter who supplies the electricity.
The distribution companies also arrange for the power supply for customers who
"choose not to choose," at a "standard offer" price.
We plan to put the standard offer energy requirement out to bid, with Montaup
or a successor serving as the backstop generation source. As a result, Montaup
plans to file an application with FERC to replace its all-requirements power
contracts with our three electric distribution companies with a contract
termination charge to recover stranded costs. The distribution companies will
collect these costs from ultimate electricity consumers through the non-
bypassable transition charge discussed above.
As previously mentioned, the rates customers pay for electric distribution and
transmission services will continue to be regulated. But they won't be
regulated in the same way as in the past. Historically, regulators allowed
utilities to recover their costs of doing business, plus a specified "fair
return" on the investment of the utility's shareholders. Under this type of
regulation - known as cost of service regulation - utilities periodically
applied to regulators for changes in rates to c over known or anticipated
changes in costs.
In the restructured environment of the competitive marketplace, rates charged
by distribution companies will incorporate performance standards, commonly
referred to as performance-based regulation. Under this technique, rates are
set for a specified period - five years, for example - during which the
utility is encouraged to manage its costs prudently to earn a premium return
while being penalized for not achieving specific agreed-upon regulated
performance objectives. Utility returns, or earnings, will be subject to a
guaranteed floor and a ceiling. Utilities which manage well can keep some of
their savings; those that manage poorly are penalized by lower earnings and/or
pre-determined penalty charges.
This is another area where our efforts have already proven effective. Since
1990 we have reduced the workforce of our Corporate and Core Electric
businesses by 23% through a combination of normal attrition and voluntary
retirement. In that same time period, our employees held the line on
operation and maintenance costs. We consolidated management of our utilities
into a single structure in 1995, further reducing costs. We will continue to
find creative solutions to the new challenges raised by competition, responding
with ever more creative approaches, including continued cross-functional staff
assignments, and more efficient use of existing equipment.
Energy-Related Business Continues To Be Important
While a great proportion of our attention was devoted to ensuring that we
remain a financially strong utility in the age of competition, our Energy
Related Businesses are also important. This business unit includes our non-
utility investments design ed to enhance shareholder value over the long-term,
and it remains a key factor in our strategy for growth.
EUA Ocean State, with its 29.9% ownership interest in Ocean State Power's twin
250-megawatt, gas-fired generating units, will continue to provide significant
earnings contributions for the foreseeable future.
EUA Cogenex Corporation (EUA Cogenex), the largest of our energy-related
subsidiaries, provides energy efficiency products and energy-management
services throughout North America. Despite a financially difficult year, EUA
Cogenex remains a national leader in the energy services field. In the third
quarter of 1996, EUA Cogenex refocused its sales efforts. Also, EUA Cogenex
reduced its year-end 1995 employee level by 22% through a combination of
attrition and a year-end workforce reduction in 1 996. A return to
profitability for EUA Cogenex is expected in the second half of 1997.
TransCapacity, our limited partnership which provides advanced information
systems to the natural gas industry, performed below our expectations in 1996.
We continue to expand the capability of its product T/Nominatr TM, which
provides clients with a single interface for making electronic data interchange
(EDI) notifications to move gas throughout multiple pipelines. T/Nominatr TM
is in full compliance with standards recently mandated by FERC for transporting
natural gas. Unfortunately, FERC delayed required compliance with these
standards until the second quarter of 1997.
Because of delays by pipelines in effecting EDI services, TransCapacity did not
make a positive contribution to 1996 earnings. We expect that TransCapacity
will start making positive contributions by year-end 1997.
Our BIOTEN partnership is in the final stages of testing its prototype biomass
generation unit. These units can solve disposal problems for producers of
large amounts of environmentally hazardous sawdust while producing electricity.
Its biomass-fired combustion turbine technology has received significant
interest from both potential buyers and fabricators.
And, our newest investment, a 20% ownership interest in Separation
Technologies, Inc., is expected to make a positive earnings contribution
during 1997. Potential customers throughout the United States and in Europe
have shown strong interest in the company's proprietary system to separate
unburned carbon from coal ash, providing coal-burning power plants with a
marketable product - high quality fly-ash - at the same time it reduces a
potential environmental disposal problem. The system has be en proven in
commercial use at New England power plants. This company fits well with our
goal of finding niche-type energy-related investments for our EUA Energy
Investment subsidiary.
We're Ready for Competition
Competition in the electric utility industry is well underway - at a much
quicker pace than anyone might have thought possible a year ago. Certainly, not
every issue of the competitive generation market and the new regulatory
environment has been addressed. But, our success in building consensus in
Massachusetts and Rhode Island shows that the private and public sectors can,
indeed, work as a team to treat all stakeholders fairly in such a complex
situation.
Our team has built strong skills in meeting the challenge of being among the
first to enter the competitive arena. We are ready to enter that arena, and to
act quickly to seize the opportunities presented by competition.
To counter revenue reductions anticipated during 1998 from the 10% rate
reduction required in the Rhode Island and Massachusetts settlement agreements,
we will continue to find ways to reduce costs and improve our operating
efficiency.
Selected Consolidated Financial Data
Years Ended December 31,
(In Thousands Except Common Share Data) 1996 1995 1994 1993 1992
INCOME STATEMENT DATA:
Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964
Operating Income<F1> 55,841 71,728 73,795 75,649 64,347
Consolidated Net Earnings<F1> 30,614 32,626 47,370 44,931 34,111
BALANCE SHEET DATA:
Plant in Service 1,067,056 1,037,662 1,020,859 1,016,453 1,002,717
Construction Work in Progress 3,839 7,570 8,389 8,728 4,943
Gross Utility Plant 1,070,895 1,045,232 1,029,248 1,025,181 1,007,660
Accumulated Depreciation and
Amortization 350,816 324,146 304,034 296,995 274,725
Net Utility Plant 720,079 721,086 725,214 728,186 732,935
Total Assets 1,257,029 1,206,130 1,234,049 1,203,137 1,203,320
CAPITALIZATION:
Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958
Redeemable Preferred Stock - Net 27,035 26,255 25,390 25,053 28,496
Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 6,900 15,850
Common Equity 371,813 375,229 365,443 333,165 266,855
Total Capitalization 812,085 843,255 853,145 861,934 774,159
Short-Term Debt 51,848 39,540 31,678 37,168 109,936
COMMON SHARE DATA:
Consolidated Earnings per Average
Common Share<F1> $ 1.50 $ 1.61 $ 2.41 $ 2.44 $ 2.00
Average Number of Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224
Return on Average Common Equity 8.2% 8.8% 13.6% 15.0% 13.2%
Market Price - High 24 1/4 25 27 3/8 29 7/8 25 1/4
- Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8
- Year-End 17 3/8 23 5/8 22 28 24 3/4
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515 $ 1.42 $ 1.36
<FN>
<F1> See Management's Discussion and Analysis of Financial Condition and Results of Operations for details of one-time
impacts to earnings.
</FN>
Management's Discussion and Analysis of Financial Condition
and Review of Operations
Overview
Consolidated net earnings for 1996 were $30.6 million, or $1.50 per share, on
revenues of $527.1 million, compared with 1995 earnings of $32.6 million, or
$1.61 per share, on revenues of $563.4 million. The results for both years
include one-time, after-tax charges to earnings, discussed below, and listed
in the following table.
Net Earnings and Earnings Per Share by business unit for 1996 and 1995 were
as follows:
1996 1995
Net Earnings (Loss) Earnings (Loss) Net Earnings (Loss) Earnings (Loss)
(000's) Per Share (000's) Per Share
Core Electric Business $ 37,595 $ 1.84 $ 42,062 $ 2.08
Energy Related Business (2,738) (0.13) 3,658 0.18
Corporate (571) (0.03) 151 0.01
From Operations $ 34,286 $ 1.68 $ 45,871 $ 2.27
One-Time Impacts:
Cogenex Charge (3,672) (0.18)
Voluntary Retirement Incentive (2,747) (0.14)
Cogeneration Discontinuance (10,498) (0.52)
Consolidated $ 30,614 $ 1.50 $ 32,626 $ 1.61
Major impacts on earnings by business unit are described in the following
paragraphs.
Cogenex Charge to Earnings
Difficulties in turning project proposals into signed contracts, the virtual
elimination of utility-sponsored demand side management programs and the
termination of the AYP Capital and Westar joint ventures hampered EUA Cogenex
earnings. As a result, a write-off of certain start-up costs of abandoned
joint ventures, and expenses related to certain project proposals along with a
reduction in carrying value of certain ongoing projects necessitated by current
market conditions resulted in a $5.9 million pre-tax ($3.7 million after-tax
or 18 cents per share) charge to earnings in the second quarter of 1996.
In an effort to refocus its sales activity, EUA Cogenex replaced virtually all
of its sales staff with individuals possessing more experience and proven sales
capability in the energy efficiency market. Cogenex has also restructured its
NOVA Division because of changing market conditions. While EUA believes that
the energy efficiency market still provides a viable business opportunity for
EUA Cogenex, it will be important for EUA Cogenex to improve its sales activity
and reduce its overhead burdens.
Voluntary Retirement Incentive (VRI) Offer
In March 1995, EUA announced a corporate reorganization which, among other
things, consolidated management of Eastern Edison, Blackstone and Newport. As
part of the reorganization, a VRI was offered to 66 professionals within the
EUA System. Forty-nine of those eligible for the program accepted the
incentive and retired effective June 1, 1995. This incentive program resulted
in a one-time $4.5 million pre-tax ($2.7 million after-tax, or 14 cents per
share) charge to second quarter 1995 earnings of the Core Electric Business.
Discontinuation of Cogeneration Operations
In September 1995, EUA announced that EUA Cogenex was discontinuing its
cogeneration operations because overall, the cogeneration portfolio had not
performed up to expectations. EUA Cogenex's total net investment in its
cogeneration portfolio was $2 9.2 million. The decision to discontinue
cogeneration operations resulted in a one-time, after-tax charge to third
quarter 1995 earnings of approximately $10.5 million, or 52 cents per share.
Operating Revenues
The following table sets forth estimates of the factors which contributed to
the change in Operating Revenues from 1994 through 1996:
Increase (Decrease)
From Prior Years
($ in millions) 1996 1995
Operating Revenue change attributable to:
Core Electric Business:
Purchased Power Recovery $ (7.0) $ (2.5)
Recovery of Fuel Costs 0.2 11.8
Recovery of C&LM Expenses (5.4) (3.9)
Effect of Rate Changes (4.9)
Unit Contracts and Sales to NEPOOL 0.6 (8.2)
Kilowatthour (kWh) Sales and Other (1.5) 1.8
Energy Related Business:
EUA Cogenex (23.2) 5.0
Total Operating Revenues $(36.3) $(0.9)
Core Electric Business: The revenues attributable to Purchased Power Recovery
reflect our retail companies' recovery of purchased power capacity costs.
Revenues attributable to Recovery of Fuel Costs and conservation and load
management (C&LM) expenses result from the operation of adjustment clauses.
The change in such revenues reflects corresponding underlying changes in costs.
The Effect of Rate Changes reflects a base rate decrease for Montaup
implemented on May 21, 1994.
Revenues attributable to Unit Contracts and sales to NEPOOL reflect energy
revenues from such short-term contracts and interchange sales with NEPOOL.
The change in revenues associated with kWh Sales and Other reflects the effect
of kWh sales and demand billings on base revenues and changes in other
operating revenues including off-system contract demand sales.
Energy Related Business: EUA Cogenex revenues, which account for virtually all
of the Energy Related Business Unit revenues, decreased by $23.2 million in
1996. This decrease was due primarily to lower project sales of approximately
$18.8 million, the absence of cogeneration revenues which aggregated $5.5
million in 1995 and decreased EUA Nova revenues of $7.9 million. These
decreases were offset somewhat by increased revenues of EUA Highland, EUA
Citizens and EUA Day aggregating $8.8 million . The 1995 change was due
primarily to the impact of EUA Cogenex's acquisitions of Highland Energy Group
(Highland) and Citizens Conservation Corporation (Citizens) in 1995.
Core Electric Business kWh Sales
Primary kWh sales of electricity by EUA's Core Electric Business Unit increased
by a modest 1.1% in 1996 compared to the prior year. This change was led by an
increase of 2.6% in the residential customer class, which is typically more
weather sensitive. The first and second quarter increases, largely due to
colder weather, were mitigated by the third and fourth quarter results, when we
saw a milder than normal weather pattern. Total energy sales increased by
2.0%, mainly due to increased sales to NEPOOL, slightly offset by decreased
short-term unit contract energy sales.
Primary kWh sales of electricity by EUA's Core Electric Business unit increased
by 0.7% in 1995 compared to 1994. Total energy sales decreased 11.1% in 1995,
due mainly to decreased energy sales to NEPOOL and decreased short-term unit
contract sales. Purchased power contracts of Montaup totaling 41 megawatts
(mw) which expired in October 1994 resulted in lower kWh available to Montaup
for interchange and short-term energy sales. These interchange and short-term
energy sales essentially recover fuel costs only and have little or no
earnings impact.
Percentage Changes in kWh Sales by Class of Customer for the past two years
were as follows:
Percent Increase (Decrease)
From Prior Year
1996 1995
Residential 2.6 1.1
Commercial (0.5) 0.2
Industrial 0.1 2.0
Other Electric Utilities 15.7 1.4
Other 2.6 (5.7)
Total Primary Sales 1.1 0.7
Losses and Company Use (8.6) (2.6)
Total System Requirements 0.7 0.5
Unit Contracts 16.2 (59.8)
Total Energy Sales 2.0 (11.1)
Expenses
Fuel and Purchased Power: The EUA System's most significant expense items
continue to be fuel and purchased power expenses of our Core Electric Business
which together comprised about 45% of total operating expenses in 1996.
Fuel expense of the Core Electric Business increased by $1.3 million or 1.4% in
1996, due primarily to a 2.0% increase in total energy generated and purchased.
The $3.3 million increase in 1995 was caused by a 14.1% increase in the average
cost of fuel, offset by an 11.1% decrease in total energy generated and
purchased. Also, a classification adjustment increased fuel expense and
decreased purchased power expense by approximately $1.8 million in 1995.
Purchased Power demand expense decreased $6.8 million or 5.4% in 1996. The
decrease is due primarily to the impact of lower billings from the Pilgrim
nuclear unit of approximately $4.2 million, which includes a prior period
refund of approximately $2 .0 million, and decreased billings from the Ocean
State Power Project (OSP) and the Maine Yankee nuclear unit aggregating $2.5
million. Purchased Power demand expense for 1995 decreased $4.5 million due
primarily to decreases of $6.7 million related to 41 mw of purchased power
contracts which expired in October 1994 and the classification adjustments
discussed above. These decreases were partially offset by increased billings
from OSP and the Yankee nuclear units aggregating $5.2 million.
Other Operation and Maintenance (O&M): O&M expenses for 1996 decreased by $7.5
million or 4.0% compared to 1995. Total O&M expenses are comprised of three
components: Direct Controllable, Indirect and Energy Related.
O&M expenses by component for 1996, 1995 and 1994 were as follows:
($ in millions) 1996 1995 1994
Direct Controllable $ 87.5 $ 83.4 $ 87.7
Indirect 36.7 41.3 46.7
Energy Related 55.7 62.7 50.1
Total O&M $179.9 $187.4 $184.5
Direct Controllable expenses of our Core Electric and Corporate Business units
represent 48.6% of total 1996 O&M and include expense items such as: salaries,
fringe benefits, insurance and maintenance. In 1996 these expenses increased
by $4.1 million due primarily to incremental storm expenses related to an
unusual number of severe storms which struck our retail service territories,
costs related to the electric industry restructuring activities and increased
assessments by FERC. The 1995 decrease was due primarily to one-time computer
software development and hardware buy-out costs aggregating $1.9 million
expensed in 1994, decreased insurance expense of approximately $1.2 million and
strict attention to cost control.
Indirect expenses include items over which we have limited short-term control.
Indirects include such expense items as: O&M expenses related to Montaup's
joint ownership interests in generating facilities such as Seabrook I and
Millstone III (see Note H of Notes to Consolidated Financial Statements for
other jointly-owned units), power contracts where transmission rental fees are
fixed, C&LM expenses that are fully recovered in revenues, and expenses related
to accounting standards such as Statement of Financial Accounting Standard
No. 106, "Accounting for Post-Retirement Benefits Other Than Pensions" (FAS
106). Indirect expenses decreased by $4.6 million in 1996. The decrease
included lower C&LM and Montaup power contract expenses aggregating $6.4
million somewhat offset by increased legal expenses and jointly owned unit
expenses, which include incremental outage costs of Millstone III. The 1995
change was due primarily to $4.2 million of decreased C&LM expense and lower
litigation expense.
The Energy Related component relates to O&M expenses of our Energy Related
Business unit where changes are tied to changes in business activity. EUA
Cogenex continues to be the most active of our Energy Related businesses and
incurred 93% of the total O&M expenses of this business unit in 1996. Energy
Related expenses decreased by $7.0 million in 1996. The change included
decreases in EUA Cogenex sales-related expenses of $10.8 million, decreased EUA
Nova costs of goods sold of $5.6 million and the absence of cogeneration
related expenses which amounted to $4.6 million in 1995. EUA Energy Investment
Corporation (EUA Energy Investment) expenses decreased by $400,000. These
decreases were offset somewhat by the June 1996 EUA Cogenex charge of $5.9
million and increased expenses of EUA Highland and EUA Citizens aggregating
$7.9 million. EUA Cogenex's O&M expenses for 1995 increased by $10.4 million
and are directly related to increased revenues, the acquisition of Citizens and
High land and costs related to new product development of the EUA Day division.
Also, operating and development expenses of EUA Energy Investment increased
$2.2 million in 1995.
Taxes Other Than Income: Taxes other than income increased $3.2 million in
1996 and decreased by $3.6 million in 1995. A 1995 reversal of previously over-
accrued property taxes was primarily responsible for the change in both years.
Income Taxes: EUA files a consolidated federal income tax return for the EUA
System. The composite federal and state effective income tax rate for 1996
increased to 35.1% from 30.1% for 1995 due mainly to a decrease in state income
tax benefits. EUA's 1994 effective tax rate was approximately 29%. In 1994
EUA Ocean State recognized $3.9 million of investment tax credits (ITC) which
lowered the effective rate.
Other Income (Deductions) - Net: Other Income and (Deductions)-Net increased
$2.5 million in 1996. Approximately $1.7 million of this increase was due to
the sale of Seabrook II equipment jointly owned by Montaup. In addition, an
increase in EUA Cogenex interest income was partially offset by the impact of
the write-off of Cogenex's AYP Capital and Westar joint venture start-up costs,
included in the June 1996 $5.9 million charge. Other Income (Deductions) - Net
decreased by $4.3 million in 1 995 from 1994. The 1994 amount included: (i)
ITC recognized by EUA Ocean State of approximately $3.9 million as previously
discussed; (ii) a settlement of $900,000 received in 1994 from the Vermont
Electric Generation and Transmission Cooperative, Inc. related to Seabrook
Nuclear Project payments previously withheld; and (iii) the 1994 income
recognition of $900,000 of capitalized costs related to nuclear fuel buyouts
which were previously deferred. EUA Cogenex interest income and management fee
income increased by approximately $1.1 million in 1995.
Interest Charges: Net interest charges for 1996 decreased approximately $2.3
million from 1995 amounts. This decrease was primarily due to the December 1995
maturity of $25 million of 9-9 1/4% Unsecured Medium Term Notes and $10 million
of 8.9% Firs t Mortgage and Collateral Trust Bonds of Eastern Edison, offset
somewhat by a decrease in capitalized interest by EUA Cogenex and higher
interest expense related to increased short-term debt. The 1995 decrease of
$2.3 million was due primarily to decreased long-term debt interest resulting
from normal cash sinking fund payments, increases in capitalized interest of
EUA Cogenex and decreased Other Interest Expense. Other Interest Expense in
1994 included approximately $1.0 million related to Internal Revenue Service
audits of prior years' consolidated income tax returns.
1996 System Financing Activity
Core Electric Business: On September 1, 1996, Eastern Edison used available
cash to fund maturities of $7 million of 4 7/8% First Mortgage Bonds.
Energy Related Business: As a result of the June 1996 $5.9 million charge to
earnings and lower than anticipated sales, EUA Cogenex was not in compliance
with the interest coverage covenant contained in certain of its unsecured note
agreements and therefore EUA Cogenex was in default under said note
agreements. EUA Cogenex has reached agreement with lenders to modify the
interest coverage covenant contained in these note agreements through January
1, 1998, and to waive the default created by the June 1996 charge.
Financial Condition and Liquidity: The EUA System's need for permanent capital
is primarily related to investments in facilities required to meet the needs of
its existing and future customers. To the extent that EUA divests all or a
portion of its generation assets, these needs will diminish.
Core Electric Business: For 1996, 1995 and 1994, Core Electric Business cash
construction expenditures were $33.3 million, $31.5 million, and $33.0 million,
respectively.
Internally generated funds available after the payment of dividends supplied
approximately 118%, 210%, and 150% of these cash construction requirements in
1996, 1995 and 1994, respectively. Various laws, regulations and contract
provisions limit the use of EUA's internally generated funds such that the
funds generated by one subsidiary are not generally available to fund the
operations of another subsidiary.
Cash construction expenditures of the Core Electric Business for 1997, 1998 and
1999 are estimated to be approximately $22.4 million, $16.3 million and $16.5
million, respectively and are expected to be financed with internally generated
funds.
In addition to construction expenditures, projected requirements for scheduled
cash sinking fund payments and mandatory redemption of securities of the Core
Electric Business in 1997, 1998, 1999, 2000 and 2001 are $2.3 million, $62.2
million, $11.6 million, $2.3 million and $4.1 million, respectively.
Energy Related Business: Capital expenditures of our Energy Related Business
amounted to $28.1 million, $44.7 million, and $17.2 million in 1996, 1995 and
1994, respectively. Internally generated funds supplied 71.5%, 68.8%, and
111.9% of cash capital requirements in 1996, 1995 and 1994, respectively.
Estimated capital expenditures of the Energy Related Business are $49.9
million, $46.7 million and $54.1 million in 1997, 1998 and 1999, respectively.
Internally generated funds are expected to supply approximately 70% of 1997
estimated capital requirements.
In addition to capital expenditures and energy related investments, projected
requirements for scheduled cash sinking fund payments and mandatory redemption
of securities of the Energy Related Business are $24.2 million in 1997, $9.2
million in 1998 and 1999, $59.2 million in 2000 and $9.2 million in 2001.
Corporate: Construction activity of the Corporate Business unit is minimal.
Projected requirements for scheduled cash sinking fund payments for the
corporate operations for each of the five years following 1996 are $1.1
million.
Short-Term Lines of Credit: At December 31, 1996, EUA System companies
maintained short-term lines of credit with various banks aggregating
approximately $140 million.
Year-End Short-Term Debt Outstanding by business unit:
($ in thousands) 1996 1995
Core Electric Business $ 3,670 $ 6,761
Energy Electric Business 24,341 14,421
Corporate 23,837 18,358
Total $51,848 $39,540
EUA expects to repay the outstanding balances of short-term indebtedness
through internally generated funds.
Energy Related Businesses
Net Earnings and Earnings Per Share contributions of EUA's Energy Related
Businesses for 1996 and 1995 were as follows:
1996 1995
Net Net
Earnings Earnings Earnings Earnings
(Loss) (Loss) (Loss) (Loss)
(000's) Per Share (000's) Per Share
EUA Cogenex $ (2,850)<F1> $ (0.14)<F1> $ 2,704<F2> $ 0.13<F2>
EUA Ocean State 4,152 0.20 4,617 0.23
EUA Energy Investment (3,990) (0.19) (3,663) (0.18)
EUA Energy Services (50) (0.00)
From Operations (2,738) (0.13) $ 3,658 $ 0.18
Cogenex Charge (3,672) (0.18)
Cogenex Discontinuance (10,498) (0.52)
Energy Related Business $ (6,410) $ (0.31) $ (6,840) $ 0.34
<FN>
<F1> Excludes June 1996 charge to earnings of $3.7 million or 18 cents per
share.
<F2> Excludes one-time charge of $10.5 million, or 52 cents per share,
related to discontinuance of cogeneration operations.
</FN>
EUA Cogenex: EUA Cogenex's earnings from continuing operations decreased by
approximately $5.6 million in 1996 due primarily to lower earnings on project
sales and operating losses of its EUA Nova division. Also, 1996 saw a
significant reduction in demand side management activity as electric utilities
nationwide prepared themselves for the evolution to a competitive marketplace.
In 1996, EUA Cogenex refocused its national sales force toward the private
sector and reduced its employee level by 22% through attrition and a 1996 year-
end workforce reduction. EUA Cogenex will continue to develop its sales and
marketing organization, evaluate and enter into strategic alliances, and
emphasize cost control in 1997.
EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which
developed and operate Units I and II of Ocean State Power, twin 250-megawatt,
gas-fired generating units in northern Rhode Island. Both units have provided
a premium return since their respective in-service dates of December 31, 1990,
and October 1, 1991. The change in EUA Ocean State's earnings contribution was
due to a lower allowed return on equity and a lower investment base billed by
the project in 1996.
EUA Energy Investment: EUA Energy Investment was organized to seek out
investments in energy related businesses. The 1996 results reflect an increase
in operating and development expenses versus 1995, in particular, expenses
related to the operating expenses of EUA Transcapacity, and development costs
of BIOTEN's biomass-fired combustion turbine electric generation system.
EUA Energy Services: The loss generated by EUA Energy Services relates to
startup costs of the Duke/Louis Dreyfus Energy Services (New England)
partnership in 1996.
Electric Utility Industry Restructuring Initiatives
On August 7, 1996 the Governor of Rhode Island signed into law the Utility
Restructuring Act of 1996 (URA). The URA provides for customer choice of
electricity supplier to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. By July 1, 1998, or sooner, all customers will
have retail access. Under the URA the local distribution company will retain
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who choose not to choose, the local distribution company would arrange for
supply at a non-discriminatory, "standard offer" price. Distribution companies
will also be providers of last resort, required to arrange for supply
at prevailing market prices for customers who are unable to obtain their own
supply.
The URA provides for full recovery of prudently incurred embedded generation
costs that might not be recovered in a competitive electric generation market,
commonly referred to as "stranded costs," through a non-bypassable transition
charge initially set at 2.8 cents per kWh through December 31, 2000. The
transition charge recovers, among other things, costs of depreciated
generation, net of its market value, regulatory assets, nuclear decommissioning
costs and above market payments to power suppliers. The costs of net, above-
market generation assets and regulatory assets will be recovered, with a
return, through a fixed component of the transition charge from July 1, 1997,
through December 31, 2009. A variable component of the transition charge will
recover, on a reconciling basis, among other things, nuclear decommissioning
and above market purchased power commitments from July 1, 1997, through the
life of the respective unit or contract. The URA also provides for commitments
to demand side management initiatives and renewables, low income customer
protections, divestiture of at least 15% of owned non-nuclear generating units
as a valuation basis for mitigation of stranded cost recovery, and performance
based rate-making standards for electric distribution companies. These
performance based standards provide for a 6% minimum and an approximate 12%
maximum allowed return on equity for EUA's Rhode Island distribution companies,
Blackstone and Newport. In addition, the URA provides for adjustments to
electric distribution companies' base rates using the prior year's Consumer
Price Index and other performance factors. Under this provision of the law,
base rates were increased 1.88% for customers of Blackstone, and 2.18% for our
Newport customers effective January 1, 1997.
The implementation of the URA requires approvals from applicable regulatory
agencies, including the Federal Energy Regulatory Commission (FERC), the RIPUC,
and the Securities and Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached a settlement with the
Rhode Island Division of Public Utilities and Carriers and the state's Attorney
General. In addition to complying with the URA, the settlement, to be formally
submitted to the RIPUC in March 1997, provides for an immediate 10% rate
reduction and the filing of a plan to divest all of Montaup's generating
assets, and is similar in many respects to the settlement negotiated in
Massachusetts, described below.
On December 23, 1996, Eastern Edison and Montaup reached an agreement in
principle with the Attorney General of Massachusetts and the Massachusetts DOER
on a plan, similar in many aspects to the URA, which would allow retail
customers to choose their supplier of electricity in 1998 and provide Eastern
Edison and Montaup full recovery of "stranded costs." A formal plan is
expected to be filed with the MDPU in March 1997.
The agreement envisions that all of Eastern Edison's customers will have the
ability to choose an alternative supplier of electricity beginning January 1,
1998. Until a customer chooses an alternative supplier, that customer would
receive "standard offer" service which would be priced to guarantee at least a
10% savings from today's electricity rates. Eastern Edison would be required
to arrange for "standard offer" service and would purchase power for "standard
offer" service from suppliers through a competitive bidding process. The
agreement is also designed to achieve full divestiture of Montaup's generating
assets via implementation of a plan, to be submitted to the MDPU by July 1,
1997, that would require (1) separation by Montaup of its generating and
transmission businesses and (2) full market valuation and sale of all
generating assets through an auction or equivalent process, to be conducted by
an independent third party.
Upon the commencement of retail choice in Massachusetts, Montaup's wholesale
contract with Eastern Edison would be terminated. In return, the cost of
Montaup's above market, embedded generation commitments to serve Eastern
Edison's customers would be recovered, with a return, through a non-bypassable
transition access charge to all Eastern Edison customers. The transition
access charge would be reduced by the fair market value of Montaup's generating
assets as determined by selling, spinning off, or otherwise disposing of such
generating facilities.
Embedded costs associated with generating plants and regulatory assets would be
recovered, with a return, over a period of 12 years. Purchased power contracts
and nuclear decommissioning costs would be recovered as incurred over the life
of those obligations, a period expected to extend beyond 12 years. The
initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.
The agreement also establishes performance-based regulation for Eastern Edison,
incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates would be frozen until December
31, 2000. Subsequent to the commencement of retail choice, Eastern Edison's
annual return on equity would be subject to a floor of 6% and a ceiling of
11.75%.
In addition to MDPU approval of the agreement, implementation is also subject
to the approval of FERC. Any disposition of generation assets resulting from
the agreements or the URA would also require the approval of the SEC under the
Public Utility Holding Company Act of 1935.
While removing much of the uncertainty which currently exists as to how EUA
will be impacted by electric utility restructuring, the agreements, if
approved, are expected to have an estimated negative impact on EUA System
earnings in 1998 of between 1 0% and 12%.
Historically, electric rates have been designed to recover a utility's full
costs of providing electric service including recovery of investment in plant
assets. Also, in a regulated environment, electric utilities are subject to
certain accounting rules that are not applicable to other industries. These
accounting rules allow regulated companies, in appropriate circumstances, to
establish regulatory assets and liabilities, which defer the current financial
impact of certain costs that are expected to be recovered in future rates.
The SEC has raised issues concerning the continued applicability of these
standards with certain other electric utilities in other states facing
restructuring. EUA believes that its Core Electric operations will continue
to meet the criteria established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in EUA no longer meeting the criteria of
these accounting standards which could trigger the discontinuance of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (FAS71). Should it be required to discontinue the
application of FAS71, EUA would be required to take an immediate write-down of
the affected assets in accordance with FAS101, "Accounting for the
Discontinuation of Application of FAS71."
In addition, if legislative or regulatory changes and/or competition result in
electric rates which do not fully recover the company's costs, a write-down of
plant assets could be required pursuant to Financial Accounting Standard No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" (FAS121).
Environmental Matters
EUA's Core Electric Business subsidiaries and other companies owning generating
units from which power is obtained are subject, like other electric utilities,
to environmental and land use regulations at the federal, state and local
levels. The federal Environmental Protection Agency (EPA), and certain state
and local authorities, have jurisdiction over releases of pollutants,
contaminants and hazardous substances into the environment and have broad
authority to set rules and regulations in connection therewith, such as the
Clean Air Act Amendments of 1990, which could require installation of pollution
control devices and remedial actions. In 1994, EUA instituted an environmental
audit program to ensure compliance with environmental laws and regulations and
to identify and reduce liability.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by such authorities. The EUA System
typically provides for t he disposal of such substances through licensed
contractors, but statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for clean-up costs.
Subsidiaries of EUA have been notified with respect to a number of sites where
they may be responsible for such costs, including sites where they may have
joint and several liability with other responsible parties. It is the policy
of the EUA System companies to notify liability insurers and to initiate
claims. However, EUA is unable to predict whether liability, if any, will be
assumed by, or can be enforced against, insurance carriers in these matters.
As of December 31, 1996, the EUA System had incurred costs of approximately
$5.7 million in connection with these sites. These amounts have been financed
primarily by internally generated cash. The EUA System is currently amortizing
substantially all of its incurred costs over a five-year period consistent
with prior regulatory recovery periods and is recovering certain of those costs
in rates.
EUA estimates that additional costs of up to $2.8 million may be incurred at
these sites through 1998 by its subsidiaries. Estimates beyond 1998 cannot be
made since site studies, which are the basis of these estimates, have not been
completed.
In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million incurred by the Commonwealth of Massachusetts at a site in which
Blackstone has been named as a responsible party. See Note J of "Notes to
Consolidated Financial Statements" for further discussion.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found everywhere there is electricity. Research to date has not conclusively
established a dire ct causal relationship between EMF exposure and human
health. Additional studies, which are intended to provide a better
understanding of the subject, are continuing. Management cannot predict the
ultimate outcome of the EMF issue.
Nuclear Power Issues
Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw nuclear
unit that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast), the operator of the plant. On
March 30, 1996, Northeast shut down the unit following an engineering
evaluation which determined that four safety-related valves would not be able
to perform their design function during certain postulated events. The Nuclear
Regulatory Commission (NRC) has raised numerous issues with respect to the
unit and certain of the other nuclear units operated by Northeast. The NRC has
established a Special Projects Office to oversee inspection and licensing
activities at Millstone and directed Northeast to submit a plan for
disposition of safety issues raised by employees and retain an independent
third party to oversee implementation of this plan. Northeast management has
indicated it cannot currently estimate the effect these efforts will have on
the timing of restarts or what additional costs, if any, these developments may
cause.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $400,000 to $800,000 per month. Montaup
bills its replacement power costs through its fuel adjustment clause, a
wholesale tariff jurisdictional to FERC. However, there is no comparable
clause in Montaup's FERC-approved rates which at this time would permit Montaup
to recover its share of the incremental O&M costs incurred at Millstone III.
EUA cannot predict the ultimate outcome of the NRC inquiries or the impact
which they may have on Montaup and the EUA system. Montaup is also evaluating
its rights and obligations under the various agreements relating to the
ownership and operation of Millstone III.
Montaup holds a 4.0% ownership interest in the Maine Yankee Nuclear Unit. In
December 1996 the unit was shut down for inspections and repairs and in January
1997 the NRC announced that it had placed the unit on its watch list. The
operator of the u nit had been addressing issues of non-conformance to the
unit's licensing basis identified by the NRC in October 1996, prior to the
NRC's January 1997 announcement. The operator of the plant cannot estimate
when the unit will restart.
Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996
because of issues related to certain containment air recirculation and service
water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with
a book value of $ 4.8 million at December 31, 1996.
In October 1996, Montaup, as one of the joint owners, participated in an
economic evaluation of Connecticut Yankee which recommended permanently closing
the unit and replacing its output with less expensive energy sources. As a
result of the analysis, work at the plant had slowed pending a final board
decision. In December 1996, the Board of Directors voted to retire the
generating station. Connecticut Yankee certified to the NRC that it had
permanently closed power generation operations and removed fuel from the
reactor. Connecticut Yankee has two years to submit its decommissioning plan
with the NRC. The preliminary estimate of the sum of future payments for the
permanent shutdown, decommissioning, and recovery of the remaining investment
in Connecticut Yankee, is approximately $758 million. Montaup's share of the
total estimated costs is $34.1 million and is included with Other Liabilities
on the Consolidated Balance Sheet at December 31, 1996. Due to anticipated
recoverability, a regulatory asset has been recorded for the same amount and
is included with Other Assets.
Recent actions by the NRC, some of which are cited above, indicate that the NRC
has become more critical and active in its oversight of nuclear power plants.
EUA is unable to predict at this time, what, if any, ramifications these NRC
actions will h ave on any of the other nuclear power plants in which Montaup
has an ownership interest or power contract.
Montaup is recovering through rates its share of estimated decommissioning
costs for the Millstone III and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
III is approximately $18.6 million in 1996 dollars and Seabrook I is
approximately $13.1 million in 1996 dollars. These figures are based on
studies performed for the lead owners of the units. Montaup also pays into
decommissioning reserves, pursuant to contractual arrangements, at other
nuclear generating facilities in which it has an equity ownership interest or
life-of-unit entitlement. Such expenses are currently recovered through rates.
Other
EUA occasionally makes forward-looking projections of expected future
performance or statements of our plans and objectives. These forward-looking
statements may be contained in filings with the SEC, press releases and oral
statements. Actual results could differ materially from these statements.
Therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.
"Management's Discussion and Analysis of Financial Condition and Review of
Operations" provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Consolidated Financial Statements" and "Notes to Consolidated Financial
Statements" to arrive at a more complete understanding of such matters.
Financial Table of Contents
Consolidated Statement of Income 26
Consolidated Statement of Cash Flows 27
Consolidated Balance Sheet 28
Consolidated Statement of Retained Earnings 29
Consolidated Statement of Equity Capital and Preferred Stock 29
Consolidated Statement of Indebtedness 30
Notes to Consolidated Financial Statements 31
Report of Independent Accountants 40
Report of Management 40
Quarterly Financial and Common Share Information 41
Consolidated Operating and Financial Statistics 42
Shareholder Information 44
Trustees and Officers Inside Back Cover
Consolidated Statement of Income
Years Ended December 31,
(In Thousands Except Common Shares and per Share Amounts) 1996 1995 1994
OPERATING REVENUES $ 527,068 $ 563,363 $ 564,278
OPERATING EXPENSES:
Fuel 92,166 90,888 87,573
Purchased Power-Demand 118,830 125,616 130,080
Other Operation 154,831 163,907 160,985
Voluntary Retirement Incentive 4,505
Maintenance 25,047 23,468 23,510
Depreciation and Amortization 45,478 45,492 46,455
Taxes - Other Than Income 23,933 20,744 24,337
Income Taxes 10,942 17,015 17,543
Total Operating Expenses 471,227 491,635 490,483
Operating Income 55,841 71,728 73,795
Equity in Earnings of Jointly Owned Companies 10,698 12,063 12,485
Allowance for Other Funds Used
During Construction 452 538 351
Loss on Disposal of Cogeneration Operations (18,086)
Income Tax Impact of Loss on Disposal of Cogeneration
Operations 7,588
Other Income (Deductions) - Net 5,054 2,574 6,847
Income Before Interest Charges 72,045 76,405 93,478
INTEREST CHARGES:
Interest on Long-Term Debt 34,035 38,216 38,987
Amortization of Debt Expense and Premium - Net 2,620 2,752 2,729
Other Interest Expense 4,199 3,167 3,849
Allowance for Borrowed Funds Used During
Construction (Credit) (1,735) (2,677) (1,788)
Net Interest Charges 39,119 41,458 43,777
Net Income 32,926 34,947 49,701
Preferred Dividends of Subsidiaries 2,312 2,321 2,331
Consolidated Net Earnings $ 30,614 $ 32,626 $ 47,370
Average Common Shares Outstanding 20,436,217 20,238,961 19,671,970
Consolidated Earnings per Share $ 1.50 $ 1.61 $ 2.41
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515
Consolidated Statement of Cash Flows
Years Ended December 31, (In Thousands) 1996 1995 1994
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 32,926 $ 34,947 $ 49,701
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 50,690 52,413 54,091
Amortization of Nuclear Fuel 1,676 3,647 3,310
Deferred Taxes 11,610 (985) 8,017
Non-cash Expenses/(Gains) on Sales of Investments in
Energy Savings Projects 8,262 (1,264) 382
Loss on Disposal of Cogeneration Operations 18,086
Investment Tax Credit, Net (1,207) (1,212) (181)
Allowance for Other Funds Used During Construction (452) (538) (351)
Collections and Sales of
Project Notes and Leases Receivable 7,776 17,748 11,115
Other - Net 6,373 5,129 (10,360)
Changes in Operating Assets and Liabilities:
Accounts Receivable (5,777) 5,729 (4,509)
Materials and Supplies 2,385 (1,280) (2,035)
Accounts Payable (1,958) 1,543 (2,668)
Taxes Accrued (1,539) (1,921) (5,834)
Other - Net 4,930 (19,079) 9,641
Net Cash Provided from Operating Activities 115,695 112,963 110,319
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (62,730) (77,923) (50,519)
Collections on Notes and Lease Receivables of EUA Cogenex 3,665 3,125 1,635
Proceeds from Disposal of Cogeneration Assets 11,501
Increase in Other Investments (3,889) (2,300) (11,329)
Net Cash (Used in) Investing Activities (62,954) (65,597) (60,213)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuances:
Common Shares 5,985 9,538
Long-Term Debt 7,925
Redemptions:
Long-Term Debt (20,617) (42,725) (13,233)
Preferred Stock (90) (100) (100)
Premium on Reacquisition and
Financing Expenses (15) (63) (689)
EUA Common Share Dividends Paid (33,618) (32,050) (29,795)
Subsidiary Preferred Dividends Paid (2,314) (2,324) (2,333)
Net Increase (Decrease) in Short-Term Debt 12,308 7,862 (5,490)
Net Cash (Used in) Financing Activities (44,346) (63,415) (34,177)
NET INCREASE (DECREASE) IN CASH AND
TEMPORARY CASH INVESTMENTS: 8,395 (16,049) 15,929
Cash and Temporary Cash Investments at Beginning of Year 4,060 20,109 4,180
Cash and Temporary Cash Investments at End of Year $ 12,455 $ 4,060 $ 20,109
Cash Paid during the year for:
Interest (Net of Amounts Capitalized) $ 40,658 $ 39,306 $ 39,650
Income Taxes $ 11,530 $ 9,412 $ 15,233
Conversion of Investments in Energy Savings Projects
to Notes and Leases Receivable $ 7,779 $ 19,324 $ 10,914
Consolidated Balance Sheet
December 31, (In Thousands) 1996 1995
ASSETS
Utility Plant and Other Investments:
Utility Plant in Service $ 1,067,056 $ 1,037,662
Less Accumulated Provisions for Depreciation and Amortization 350,816 324,146
Net Utility Plant in Service 716,240 713,516
Construction Work in Progress 3,839 7,570
Net Utility Plant 720,079 721,086
Non-utility Property - Net 72,653 82,347
Investments in Jointly Owned Companies 71,626 70,210
Other 68,031 67,157
Total Utility Plant and Other Investments 932,389 940,800
Current Assets:
Cash and Temporary Cash Investments 12,455 4,060
Accounts Receivable:
Customers, Net 66,089 61,096
Accrued Unbilled Revenues 10,282 11,311
Other 13,782 11,969
Notes Receivable 24,691 18,663
Materials and Supplies (at average cost):
Fuel 6,924 7,450
Plant Materials and Operating Supplies 7,207 9,066
Other Current Assets 7,668 11,804
Total Current Assets 149,098 135,419
Other Assets 175,542 129,911
Total Assets $ 1,257,029 $ 1,206,130
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 371,813 $ 375,229
Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900
Redeemable Preferred Stock of Subsidiaries - Net 27,035 26,255
Long-Term Debt - Net 406,337 434,871
Total Capitalization 812,085 843,255
Current Liabilities:
Short-Term Debt 51,848 39,540
Long-Term Debt Due Within One Year 27,512 19,506
Accounts Payable 33,811 35,769
Redeemable Preferred Stock Sinking Fund Requirement 50
Taxes Accrued 3,004 4,544
Interest Accrued 9,612 10,861
Other Current Liabilities 26,772 19,931
Total Current Liabilities 152,559 130,201
Other Liabilities 123,209 91,934
Accumulated Deferred Taxes 169,176 140,740
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $1,257,029 $ 1,206,130
Consolidated Statement of Retained Earnings
Years Ended December 31, (In Thousands) 1996 1995 1994
Retained Earnings - Beginning of Year $ 56,228 $ 56,617 $ 39,642
Consolidated Net Earnings 30,614 32,626 47,370
Total 86,842 89,243 87,012
Dividends Paid - EUA Common Shares 33,618 32,050 29,795
Other 820 965 600
Retained Earnings - Accumulated since June 1991 Accounting
Reorganization $ 52,404 $ 56,228 $ 56,617
Consolidated Statement Of Equity Capital & Preferred Stock
December 31, (Dollar Amounts In Thousands) 1996 1995
EASTERN UTILITIES ASSOCIATES:
Common Shares:
$5 par value 36,000,000 shares authorized,
20,435,997 shares outstanding in 1996
and 20,436,764 shares in 1995 $ 102,180 $ 102,184
Other Paid-In Capital 221,160 220,730
Common Share Expense (3,931) (3,913)
Retained Earnings - Accumulated since June 1991
Accounting Reorganization 52,404 56,228
Total Common Equity 371,813 375,229
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
Non-Redeemable Preferred:
Blackstone Valley Electric Company:
4.25% $100 par value 35,000 shares <F1> 3,500 3,500
5.60% $100 par value 25,000 shares <F1> 2,500 2,500
Premium 129 129
Newport Electric Corporation:
3.75% $100 par value 7,689 shares <F1> 769 769
Premium 2 2
Total Non-Redeemable Preferred Stock 6,900 6,900
Redeemable Preferred:
Eastern Edison Company:
65/8 $100 par value 300,000 shares <F2> 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Costs (2,630) (3,447)
Newport Electric Corporation:
9.75% $100 par value 900 shares 90
Expense (3)
Sinking Fund Requirement Due Within One Year (50)
Total Redeemable Preferred Stock 27,035 26,255
Total Preferred Stock of Subsidiaries $ 33,935 $ 33,155
<FN>
<F1> Authorized and Outstanding.
<F2> Authorized 400,000 shares. Outstanding 300,000 at December 31, 1996.
</FN>
Consolidated Statement of Indebtedness
December 31, (In Thousands) 1996 1995
EUA Service Corporation:
10.2% Secured Notes due 2008 $ 10,100 $ 12,300
EUA Cogenex Corporation:
7.22% Unsecured Notes due 1997 15,000 15,000
7.0% Unsecured Notes due 2000 50,000 50,000
9.6% Unsecured Notes due 2001 16,000 19,200
10.56% Unsecured Notes due 2005 31,500 35,000
EUA Ocean State Corporation:
9.59% Unsecured Notes due 2011 31,067 33,544
Blackstone Valley Electric Company:
First Mortgage Bonds:
9 1/2% due 2004 (Series B) 12,000 13,500
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds due 2014<F1> 6,500 6,500
Eastern Edison Company
First Mortgage and Collateral Trust Bonds:
4 7/8% due 1996 7,000
5 7/8% due 1998 20,000 20,000
5 3/4% due 1998 40,000 40,000
7.78 % Secured Medium Term Notes due 2002 35,000 35,000
6 7/8% due 2003 40,000 40,000
6.35% due 2003 8,000 8,000
8.0% due 2023 40,000 40,000
Pollution Control Revenue Bonds:
5 7/8% due 2008 40,000 40,000
Newport Electric Corporation:
First Mortgage Bonds:
9.0% due 1999 1,386 1,386
9.8% due 1999 8,000 8,000
8.95% due 2001 3,250 3,900
Small Business Administration Loan:
6.5% due 2005 719 809
Variable Rate Revenue Refunding Bonds due 2011<F1> 7,925 7,925
Unamortized (Discount) - Net (598) (687)
433,849 454,377
Less Portion Due Within One Year 27,512 19,506
Total Long-Term Debt - Net $ 406,337 $ 434,871
<FN>
<F1> Weighted average interest rate was 3.5% for 1996 and 3.9% for 1995.
</FN>
Notes to Consolidated Financial Statements
December 31, 1996, 1995 and 1994
(A) Nature of Operations and
Summary of Significant Accounting Policies:
General: Eastern Utilities Associates (EUA) is a diversified energy services
holding company. Its subsidiaries are principally engaged in the generation,
transmission, distribution and sale of electricity; energy related services
such as energy management; and promoting the conservation and efficient use of
energy.
Estimates: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure 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 those estimates.
Reclassifications: Certain prior period amounts on the financial statements
have been reclassified to conform with current presentation.
Basis of Consolidation: The consolidated financial statements include the
accounts of EUA and all subsidiaries. All material intercompany transactions
between the consolidated subsidiaries have been eliminated.
System of Accounts: The accounts of EUA and its consolidated subsidiaries are
maintained in accordance with the uniform system of accounts prescribed by the
regulatory bodies having jurisdiction.
Jointly Owned Companies: Montaup Electric Company (Montaup) follows the
equity method of accounting for its stock ownership investments in jointly
owned companies including four regional nuclear generating companies.
Montaup's investments in these nuclear generating companies range from 2.50% to
4.50%. Montaup is entitled to electricity produced from these facilities based
on its ownership interests and is billed for its entitlement pursuant to
contractual agreements which are approved by the Federal Energy Regulatory
Commission (FERC).
One of the four facilities, Yankee Atomic, is being decommissioned, but Montaup
is required to pay, and has received FERC authorization to recover, its
proportionate share of any unrecovered costs and costs incurred after the
plant's retirement. Montaup's share of all unrecovered assets and the total
estimated costs to decommission the unit aggregated approximately $7.8 million
at December 31, 1996 and is included with Other Liabilities on the Consolidated
Balance Sheet. Also, due to recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets.
In December 1996, the Board of Directors of Connecticut Yankee voted to retire
the generating station. Connecticut Yankee certified to the NRC that it had
permanently closed power generation operations and removed fuel from the
reactor. Montaup has a 4.5% equity ownership in Connecticut Yankee. Montaup's
share of all unrecovered assets and the total estimated costs to decommission
the unit aggregated approximately $34.1 million at December 31, 1996 and is
included with Other Liabilities on the Consolidated Balance Sheet. Also, due
to anticipated recoverability, a regulatory asset has been recorded for the
same amount and is included with Other Assets.
Montaup also has a stock ownership investment of 3.27% in each of two companies
which own and operate certain transmission facilities between the Hydro Quebec
electric system and New England.
EUA Ocean State Corporation (EUA Ocean State) follows the equity method of
accounting for its 29.9% partnership interest in the Ocean State Power Project
(OSP). Also, EUA Energy Investment follows the equity method of accounting for
its 40% partners hip interest in BIOTEN, G.P. and for its 20% stock ownership
in Separation Technologies, Inc. These ownership interests and Montaup's stock
ownership investments are included in "Investments in Jointly Owned Companies"
on the Consolidated Balance Sheet.
Plant and Depreciation: Utility plant is stated at original cost. The cost of
additions to utility plant includes contracted work, direct labor and material,
allocable overhead, allowance for funds used during construction and indirect
charges for engineering and supervision. For financial statement purposes,
depreciation is computed on the straight-line method based on estimated useful
lives of the various classes of property. On a consolidated basis, provisions
for depreciation on utility plant were equivalent to a composite rate of
approximately 3.7% in 1996, 3.6% in 1995, and 3.3% in 1994 based on the average
depreciable property balances at the beginning and end of each year. Non-
utility property and equipment of EUA Cogenex Corporation (EUA Cogenex) is
stated at original cost. For financial statement purposes, depreciation on
office furniture and equipment, computer equipment and real property is
computed on the straight-line method based on estimated useful lives ranging
from five to forty years. Project equipment is depreciated over the term of the
applicable contracts or based on the estimated useful lives, whichever is
shorter, ranging from five to fifteen years.
Other Assets: The components of Other Assets at December 31, 1996 and 1995 are
detailed as follows:
(In Thousands) 1996 1995
Regulatory Assets:
Unamortized losses on reacquired debt $ 14,088 $ 15,894
Unrecovered plant and
decommissioning costs 41,914 10,100
Deferred FAS 109 costs (Note B) 58,712 48,196
Deferred FAS 106 costs 4,054 4,583
Mendon Road judgment (Note J) 6,154 5,857
Other regulatory assets 6,363 6,031
Total regulatory assets 131,285 90,661
Other deferred charges and assets:
Unamortized debt expenses 4,625 5,349
Goodwill 6,848 7,054
Other 32,784 26,847
Total Other Assets $ 175,542 $ 129,911
Regulatory Accounting: EUA's Core Electric companies are subject to certain
accounting rules that are not applicable to other industries. These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact of
certain costs that are expected to be recovered in future rates. EUA believes
that its Core Electric operations continue to meet the criteria established in
these accounting standards. Effects of legislation and/or regulatory
initiatives or EUA's own initiatives could ultimately cause the Core Electric
companies to no longer follow these accounting rules. In such an event, a non-
cash write-off of regulatory assets and liabilities could be required at that
time.
Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest:
AFUDC represents the estimated cost of borrowed and equity funds used to
finance the EUA System's construction program. In accordance with regulatory
accounting, AFUDC is capitalized as a cost of utility plant in the same manner
as certain general and administrative costs. AFUDC is not an item of current
cash income but is recovered over the service life of utility plant in the form
of increased revenues collected a s a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 9.0% in 1996, 9.2% in 1995, and
9.7% in 1994. The caption "Allowance for Borrowed Funds Used During
Construction" also includes interest capitalized for non-regulated entities in
accordance with Financial Accounting Standards Board (FASB) Statement No. 34.
Operating Revenues: Utility revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison Company
(Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue
the estimated amount of unbilled base rate revenues at the end of each month to
match costs and revenues more closely. In addition they also record the
difference between fuel costs incur red and fuel costs billed. Montaup
recognizes revenues when billed. Montaup, Blackstone, and Newport also record
revenues related to rate adjustment mechanisms.
EUA Cogenex's revenues are recognized based on financial arrangements
established by each individual contract. Under paid-from-savings contracts,
revenues are recognized as energy savings are realized by customers. Revenue
from the sale of energy savings projects and sales-type leases are recognized
when the sales are complete. Interest on the financing portion of the
contracts is recognized as earned at rates established at the outset of the
financing arrangement. All construction and installation costs are recognized
as contract expenses when the contract revenues are recorded. In circumstances
in which material uncertainties exist as to contract profitability, cost
recovery accounting is followed and revenues received under such con tracts are
first accounted for as recovery of costs to the extent incurred.
Federal Income Taxes: EUA and its subsidiaries generally reflect in income the
estimated amount of taxes currently payable, and provide for deferred taxes on
certain items subject to temporary timing differences to the extent permitted
by the various regulatory agencies. EUA's rate-regulated subsidiaries defer
recognition of annual investment tax credits (ITC) and amortize these credits
over the productive lives of the related assets.
Cash and Temporary Cash Investments: EUA considers all highly liquid
investments and temporary cash investments with a maturity of three months or
less when acquired to be cash equivalents.
(B) Income Taxes:
EUA adopted FASB statement No. 109, "Accounting for Income Taxes" (FAS 109),
which requires recognition of deferred income taxes for temporary differences
that are reported in different years for financial reporting and tax purposes
using the liability method. Under the liability method, deferred tax
liabilities or assets are computed using the tax rates that will be in effect
when temporary differences reverse. Generally, for regulated companies, the
change in tax rates may not be immediately recognized in operating results
because of ratemaking treatment and provisions in the Tax Reform Act of 1986.
Total deferred tax assets and liabilities for 1996 and 1995 are comprised as
follows:
Deferred Tax Deferred Tax
($ in thousands) Assets ($ in thousands) Liabilities
1996 1995 1996 1995
Plant Related Plant Related
Differences $18,442 $21,028 Differences $188,425 $170,562
Alternative Refinancing
Minimum Tax 852 9,302 Costs 1,623 1,919
NOL Carryforward 1,655 1,646 Pensions 1,313 1,496
Pensions 4,012 3,392
Acquisitions 3,965 4,281
Other 5,657 5,663 Other 12,042 11,684
Total $34,583 $45,312 Total $203,403 $185,661
As of December 31, 1996 and 1995, EUA has recorded on its Consolidated Balance
Sheet a regulatory liability to ratepayers of approximately $21.2 million and
$27.2 million, respectively. These amounts primarily represent excess deferred
income taxes resulting from the reduction in the federal income tax rate and
also include deferred taxes provided on investment tax credits. Also at
December 31, 1996 and 1995, a regulatory asset of approximately $58.7 million
and $48.2 million, respectively, h as been recorded, representing the
cumulative amount of federal income taxes on temporary depreciation differences
which were previously flowed through to ratepayers.
EUA has $0.9 million of alternative minimum tax credits which have no
expiration and can be utilized to reduce the consolidated regular tax
liability.
In 1994, EUA Ocean State utilized $3.9 million of ITC related to its investment
in OSP, which were charged against 1994 federal income tax expense and reduced
the consolidated regular tax liability. EUA has no remaining ITC carryforwards
available.
Components of income tax expense for the year 1996, 1995, and 1994 are as
follows:
($ in thousands) 1996 1995 1994
Federal:
Current $ (231) $ 10,335 $ 5,986
Deferred 9,838 6,456 9,199
Investment Tax Credit, Net (1,125) (1,130) (99)
8,482 15,661 15,086
State:
Current 2,823 2,579 1,154
Deferred (363) (1,225) 1,303
2,460 1,354 2,457
Charged to Operations 10,942 17,015 17,543
Charged to Other Income:
Current 4,798 4,353 9,243
Deferred 2,135 (6,217) (2,486)
Investment Tax Credit, Net (82) (82) (3,972)
6,851 (1,946) 2,785
Total $17,793 $ 15,069 $ 20,328
Total income tax expense was different from the amounts computed by applying
federal income tax statutory rates to book income subject to tax for the
following reasons:
($ in thousands) 1996 1995 1994
Federal Income Tax Computed at Statutory Rates $ 17,751 $ 17,506 $ 24,510
(Decrease) Increase in Tax From:
Equity Component of AFUDC (189) (187) (123)
Depreciation Differences 2 118 50
Amortization and Utilization of ITC (1,207) (1,212) (5,115)
State Taxes, Net of Federal Income Tax Benefit 1,952 (44) 2,285
Other (516) (1,112) (1,279)
Total Income Tax Expense $ 17,793 $ 15,069 $ 20,328
(C) Capital Stock:
The changes in the number of common shares outstanding and related increases in
Other Paid-In Capital during the years ended December 31, 1996, 1995, and 1994
were as follows:
Number of Common Shares Issued
Dividend Northeast Highland Common Other
Reinvestment Energy Energy Shares Paid-In
and Employee J.L. Day Co. Management Group At Par Capital
Savings Plans Acquisition Acquisition Acquisition (000) (000)
1996 (767) $ (4) $ 4
1995 323,526 176,258 2,499 7,683
1994 427,304 12,499 464,579 4,522 10,209
The preferred stock provisions of the Retail Subsidiaries place certain
restrictions upon the payment of dividends on common stock by each company. At
December 31, 1996 and 1995, each company was in excess of the minimum
requirements which would make these restrictions effective.
In the event of involuntary liquidation, the holders of non-redeemable
preferred stock of the Retail Subsidiaries are entitled to $100 per share plus
accrued dividends. In the event of voluntary liquidation, or if redeemed at
the option of these companies, each share of the non-redeemable preferred
stock is entitled to accrued dividends plus the following:
Company Issue Amount
Blackstone: 4.25% issue $104.40
5.60% issue 103.82
Newport: 3.75% issue 103.50
(D) Redeemable Preferred Stock:
Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003. The redemption price is $100 per share plus accrued dividends. All
outstanding shares of the 6 5/8% issue are subject to mandatory redemption on
September 1, 2008, at a price of $100 per share plus accrued dividends.
In the event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred
Stock are entitled to $100 per share plus accrued dividends.
In October 1996, Newport redeemed the remaining 900 shares of its 9.75%
Preferred Stock, representing 500 shares under the mandatory sinking fund
provision and 400 shares under the optional provision of the sinking fund.
(E) Long-Term Debt:
The various mortgage bond issues of Blackstone, Eastern Edison, and Newport are
collateralized by substantially all of their utility plant. In addition,
Eastern Edison's bonds are collateralized by securities of Montaup, which are
wholly-owned by Eastern Edison, in the principal amount of approximately $236
million.
Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable
letter of credit which expires on January 21, 1998. The letter of credit
permits an extension of one year upon mutual agreement of the bank and
Blackstone.
Newport's Variable Rate Electric Energy Facilities Revenue Refunding Bonds are
collateralized by an irrevocable Letter of Credit which expires on January 6,
1998, and permits an extension of one year upon mutual agreement of the Bank
and Newport. EUA Service Corporation's (EUA Service) 10.2% Secured Notes due
2008 are collateralized by certain real estate and property of the company.
In September, Eastern Edison used available cash to redeem $7 million of 4 7/8%
First Mortgage Bonds at maturity.
The EUA System's aggregate amount of current cash sinking fund requirements and
maturities of long-term debt, (excluding amounts that may be satisfied by
available property additions) for each of the five years following 1996 are:
$27.5 million in 19 97, $72.5 million in 1998, $21.9 million in 1999, $62.5
million in 2000, and $14.3 million in 2001.
As a result of the June 1996 $5.9 million charge to earnings and lower than
anticipated sales, EUA Cogenex was not in compliance with the interest coverage
covenant contained in certain of its unsecured note agreements and therefore
EUA Cogenex was i n default under said note agreements. EUA Cogenex has
reached agreement with lenders to modify the interest coverage covenant
contained in these note agreements through January 1, 1998, and to waive the
default created by the June 1996 charge.
(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short-term maturity of these instruments.
Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair
value of these assets are based on market rates of similar securities.
Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the
System's redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1996.
The estimated fair values of the System's financial instruments at December 31,
1996, are as follows:
Carrying Fair
($ in thousands) Amount Value
Cash and Temporary Cash Investments $ 12,455 $ 12,455
Long-Term Notes Receivable and
Net Investment in Sales-Type Leases 52,599 54,869
Redeemable Preferred Stock 30,000 30,300
Long-Term Debt 434,447 450,419
(G) Lines Of Credit:
EUA System companies maintain short-term lines of credit with various banks
aggregating approximately $140 million. At December 31, 1996, unused short-
term lines of credit were approximately $89 million. In accordance with
informal agreements with the various banks, commitment fees are required to
maintain certain lines of credit. During 1996, the weighted average interest
rate for short-term borrowings was 5.5%.
(H) Jointly Owned Facilities:
At December 31, 1996, in addition to the stock ownership interests discussed in
Note A, Nature of Operations and Summary of Significant Accounting Policies -
Jointly Owned Companies, Montaup and Newport had direct ownership interests in
the following electric generating facilities:
Accumulated
Provision For Net Construc-
Utility Depreciation Utility tion
Percent Plant in and Plant in Work in
($ in thousands) Owned Service Amortization Service Progress
Montaup:
Canal Unit 2 50.00% $ 83,194 $41,843 $ 41,351 $446
Wyman Unit 4 1.96% 4,051 2,130 1,921
Seabrook Unit 1 2.90% 194,928 29,983 164,945 251
Millstone Unit 3 4.01% 178,854 49,560 129,294 170
Newport:
Wyman Unit 4 0.67% 1,285 726 559
The foregoing amounts represent Montaup's and Newport's interest in each
facility, including nuclear fuel where appropriate, and are included on the
like-captioned lines on the Consolidated Balance Sheet. At December 31, 1996,
Montaup's total net investment in nuclear fuel of the Seabrook and Millstone
Units amounted to $2.8 million and $1.8 million, respectively.
Montaup's and Newport's shares of related operating and maintenance expenses
with respect to units reflected in the table above are included in the
corresponding operating expenses.
(I) Financial Information By Business Segments:
The Core Electric Business includes results of the electric utility operations
of Blackstone, Eastern Edison, Newport and Montaup.
Energy Related Business includes results of our diversified energy related
subsidiaries, EUA Cogenex, EUA Ocean State and EUA Energy Investment
Corporation (EUA Energy) and EUA Energy Services.
Corporate results include the operations of EUA Service and EUA Parent.
Pre-Tax Depreciation Cash Equity in
Operating Operating Income and Construction Subsidiary
($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings
Year Ended
December 31, 1996
Core Electric $ 470,719 $ 80,042 $ 19,902 $ 35,178 $ 33,337 $ 1,587
Energy Related 56,349 (11,536) (9,231) 10,290 28,121 9,111
Corporate (1,723) 271 10 1,272
Total $ 527,068 $ 66,783 $ 10,942 $ 45,478 $ 62,730 $10,698
Year Ended
December 31, 1995
Core Electric $ 483,864 $ 86,505 $ 20,312 $ 34,218 $ 31,466 $ 1,646
Energy Related 79,499 3,377 (3,318) 11,265 44,684 10,417
Corporate (1,139) 21 9 1,773
Total $ 563,363 $ 88,743 $ 17,015 $ 45,492 $ 77,923 $12,063
Year Ended
December 31, 1994
Core Electric $ 489,798 $ 83,966 $ 18,879 $ 33,409 $ 32,978 $ 1,700
Energy Related 74,480 9,905 (1,149) 12,491 17,231 10,785
Corporate (2,533) (187) 555 310
Total $ 564,278 $ 91,338 $ 17,543 $ 46,455 $ 50,519 $12,485
December 31,
($ in thousands) 1996 1995
Total Plant and Other Investments
Core Electric $ 715,796 $ 716,828
Energy Related 196,236 203,670
Corporate 20,357 20,302
Total Plant and Other Investments 932,389 940,800
Other Assets
Core Electric 232,443 191,152
Energy Related 66,212 57,083
Corporate 25,985 17,095
Total Other Assets 324,640 265,330
Total Assets $1,257,029 $1,206,130
(J) Commitments And Contingencies:
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs: The owners (or
lead participants) of the nuclear units in which Montaup has an interest have
made, or expect to make, various arrangements for the acquisition of uranium
concentrate, the conversion, enrichment, fabrication and utilization of nuclear
fuel and the disposition of that fuel after use. The owners (or lead
participants) of United States nuclear units have entered into contracts with
the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance
with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject
to various contingencies) that the federal government design, license,
construct and operate a permanent repository for high level radioactive wastes
and spent nuclear fuel and establish a prescribed fee for the disposal of such
wastes and nuclear fuel. The NWPA specifies that the DOE provide for the
disposal of such waste and spent nuclear fuel starting in 1998. Objections on
environmental and other grounds have been asserted against proposals for
storage as well as disposal of spent nuclear fuel. The DOE now estimates that
a permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. Montaup owns a 4.01%
interest in Millstone III and a 2.9% interest in Seabrook I. Northeast
Utilities, the operator of the units, indicates that Millstone III has
sufficient on-site storage facilities which, with rack additions, can
accommodate its spent fuel for the projected life of the unit. At the Seabrook
Project, there is on-site storage capacity which, with rack additions, will be
sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners o r power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through rates.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone III and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone III is $18.6 million
in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars. These
figures are based on studies performed for the lead owners of the units.
Montaup also pays into decommissioning reserves pursuant to contractual
arrangements with other nuclear generating facilities in which it has an equity
ownership interest or life of the unit entitlement. Such expenses are
currently recoverable through rates.
Pensions: EUA maintains a non-contributory defined benefit pension plan
covering substantially all employees of the EUA System (Retirement Plan).
Retirement Plan benefits are based on years of service and average compensation
over the four years prior to retirement. It is the EUA System's policy to fund
the Retirement Plan on a current basis in amounts determined to meet the
funding standards established by the Employee Retirement Income Security Act of
1974.
Total pension expense for the Retirement Plan, including amounts related to the
1995 voluntary retirement incentive offer, for 1996, 1995 and 1994 included the
following components:
($ in thousands) 1996 1995 1994
Service cost-benefits earned
during the period $ 3,126 $ 2,776 $ 3,281
Interest cost on projected
benefit obligations 9,765 9,391 8,848
Actual loss (return) on assets (16,451) (36,220) 1,523
Net amortization and deferrals 4,060 24,392 (12,494)
Net periodic pension expense 500 339 1,158
Voluntary Retirement Incentive 1,653
Total periodic pension expense $ 500 $ 1,992 $ 1,158
Assumptions used to determine pension costs:
Discount Rate 7.25% 8.25% 7.25%
Compensation Increase Rate 4.25% 4.75% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
The following table sets forth the actuarial present value of benefit
obligations and funded status at December 31, 1996, 1995 and 1994:
($ in thousands) 1996 1995 1994
Accumulated benefit obligations
Vested $ (118,739) $ (117,060) $ (96,045)
Non-vested (254) (271) (315)
Total $ (118,993) $ (117,331) $ (96,360)
Projected benefit obligations $ (136,286) $ (135,415) $ (112,483)
Plan assets at fair value,
primarily stocks and bonds 161,300 152,308 122,816
Unrecognized net (gain) (29,963) (21,769) (13,643)
Unamortized net
assets at January 1 4,513 4,939 5,365
Net pension (liability) assets $ (436) $ 63 $ 2,055
The discount rate and compensation increase rate used to determine pension
obligations, effective January 1, 1997 are 7.5% and 4.25% respectively, and
were used to calculate the plan's funded status at December 31, 1996.
The one-time voluntary retirement incentive also resulted in $1.6 million of
non-qualified pension benefits which were expensed in 1995. At December 31,
1996, approximately $1.4 million was included in other liabilities for these
unfunded benefits. EUA also maintains non-qualified supplemental retirement
plans for certain officers of the EUA System (Supplemental Plans). Benefits
provided under the Supplemental Plans are based primarily on compensation at
retirement date. EUA maintains life insurance on certain participants of the
Supplemental Plans to fund in whole, or in part, its future liabilities under
the Supplemental Plans. As of December 31, 1996, approximately $4.4 million
was included in accrued expenses and other liabilities f or these plans. For
the years ended December 31, 1996, 1995 and 1994 expenses related to the
Supplemental Plans were $1.5 million, $1.5 million, and $516,000, respectively.
EUA also provides a defined contribution 401(K) savings plan for substantially
all employees. EUA's matching percentage of employees' voluntary contributions
to the plan, amounted to $1.3 million in 1996, $1.4 million in 1995 and $1.3
million in 1994.
Post-Retirement Benefits: Retired employees are entitled to participate in
health care and life insurance benefit plans. Health care benefits are subject
to deductibles and other limitations. Health care and life insurance benefits
are partially funded by EUA System companies for all qualified employees.
The EUA System adopted Statement of Financial Accounting Standard No. 106,
"Accounting for Post-Retirement Benefits Other Than Pensions," (FAS 106) as of
January 1, 1993. This standard establishes accounting and reporting standards
for such post-retirement benefits as health care and life insurance. Under FAS
106 the present value of future benefits is recorded as a periodic expense over
employee service periods through the date they become fully eligible for
benefits. With respect to period s prior to adopting FAS 106, EUA elected to
recognize accrued costs (the Transition Obligation) over a period of 20 years,
as permitted by FAS 106. The resultant annual expense, including amortization
of the Transition Obligation and net of capitalized and deferred amounts, was
approximately $6.1 million in 1996, $6.3 million in 1995 and $5.8 million in
1994.
The total cost of post-retirement benefits other than pensions, including
amounts related to the 1995 voluntary retirement incentive offer, for 1996,
1995 and 1994 includes the following components:
($ in thousands) 1996 1995 1994
Service cost $ 1,123 $ 996 $ 1,537
Interest cost 4,449 4,822 5,381
Actual return on plan assets (253) (671) (126)
Amortization of transition obligation 3,313 3,312 3,429
Other amortizations & deferrals - net (1,211) (970) (85)
Net periodic post-retirement
benefit cost 7,421 7,489 10,136
Voluntary Retirement Incentive 832
Total periodic post-retirement
benefit costs $ 7,421 $ 8,321 $10,136
Assumptions used to determine post-retirement benefit costs
Discount rate 7.25% 8.25% 7.25%
Health care cost trend rate
- near-term 9.00% 11.00% 13.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.75% 4.75%
Long-term return on assets
- union 8.50% 8.50% 8.50%
- non-union 7.50% 5.50% 5.50%
Reconciliation of funded status:
($ in thousands) 1996 1995 1994
Accumulated post-retirement benefit
obligation (APBO):
Retirees $(36,518) $(40,817) $(35,386)
Active employees fully eligible
for benefits (5,952) (9,760) (9,778)
Other active employees (19,652) (20,115) $(23,306)
Total $(62,122) $(70,692) $(68,470)
Plan assets at fair value, primarily
notes and bonds 17,743 12,614 7,722
Unrecognized transition obligation 53,001 56,314 61,718
Unrecognized net loss (gain) (17,551) (7,575) (9,098)
(Accrued)/prepaid post-retirement
benefit cost $ (8,929) $ (9,339) $(8,128)
The discount rate and compensation increase rate used to determine post-
retirement benefit obligations effective January 1, 1997 are 7.5% and 4.25%,
respectively, and were used to calculate the funded status of post-retirement
benefits at December 31 , 1996.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1996 by $800,000 and
increase the total accumulated post-retirement benefit obligation by $7.5
million.
The EUA System has also established separate irrevocable external Voluntary
Employees' Beneficiary Association Trust Funds for union and non-union
retirees. Contributions to the funds commenced in March 1993 and totaled
approximately $7.8 million in 1996, $7.1 million during 1995, and $6.7 million
in 1994.
Long-Term Purchased Power Contracts: The EUA System is committed under long-
term purchased power contracts, expiring on various dates through September
2021, to pay demand charges whether or not energy is received. Under terms in
effect at December 31, 1996, the aggregate annual minimum commitments for such
contracts are approximately $122 million in 1997, $116 million in 1998, $114
million in 1999, $111 million in 2000, $111 million in 2001 and will aggregate
$1.0 billion for the ensuing year s. In addition, the EUA System is required
to pay additional amounts depending on the actual amount of energy received
under such contracts. The demand costs associated with these contracts are
reflected as Purchased Power-Demand on the Consolidate d Statement of Income.
Such costs are currently recoverable through rates.
Environmental Matters: There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities. The EUA System generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. Subsidiaries
of EUA have been notified with respect to a number of sites where they may be
responsible for such costs, including sites where they may have joint and
several liability with other responsible parties. It is the policy of the EUA
System companies to notify liability insurers and to initiate claims. EUA is
unable to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carrier in these matters.
On December 13, 1994, the United States District Court for the District of
Massachusetts (District Court) issued a judgment against Blackstone, finding
Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the
full amount of response costs incurred by the Commonwealth in the cleanup of a
by-product of manufactured gas at a site at Mendon Road in Attleboro,
Massachusetts. The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment. The total liability is
approximately $5.9 million, including approximately $3.6 million in interest
which has accumulated since 1985. Due to the uncertainty of the ultimate
outcome of this proceeding and anticipated recoverability, Blacks tone recorded
the $5.9 million District Court judgment as a deferred debit. This amount is
included with Other Assets at December 31, 1996 and 1995.
Blackstone filed a Notice of Appeal of the District Court's judgment and filed
its brief with the United States Court of Appeals for the First Circuit (First
Circuit) on February 24, 1995. On October 6, 1995 the First Circuit vacated
the District Court's judgment and ordered the District Court to refer the
matter to the EPA to determine whether the chemical substance, ferric
ferrocyanide (FFC), contained within the by-product is a hazardous substance.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
On January 28, 1994, Blackstone filed a complaint in the District Court,
seeking, among other relief, contribution and reimbursement from Stone &
Webster Inc., of New York City and several of its affiliated companies (Stone &
Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any
damages incurred by Blackstone regarding the Mendon Road site. On November 7,
1994, the court denied motions to dismiss the complaint which were filed by
Stone & Webster and Valley. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is hazardous.
In addition, Blackstone has notified certain liability insurers and has filed
claims with respect to the Mendon Road site, as well as other sites. Blackstone
reached settlement with one carrier for reimbursement of legal costs related to
the Mendon Road case. In January 1996, Blackstone received the proceeds of the
settlement.
As of December 31, 1996, the EUA System had incurred costs of approximately
$5.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with these sites, substantially all of which relate to Blackstone. These
amounts have been financed primarily by internally generated cash. Blackstone
is currently amortizing all of its incurred costs over a five-year period
consistent with prior regulatory recovery periods and is recovering certain of
those costs in rates.
EUA estimates that additional costs of up to $2.8 million (excluding the $5.9
million Mendon Road judgment) may be incurred at these sites through 1998,
substantially all of which relates to sites at which Blackstone is a
potentially responsible part y. Estimates beyond 1998 cannot be made since
site studies, which are the basis of these estimates, have not been completed.
As a result of the recoverability of cleanup costs in rates and the uncertainty
regarding both its estimated liability, as well as its potential contributions
from insurance carriers and other responsible parties, EUA does not believe
that the ultimate impact of the environmental costs will be material to the
financial position of the EUA System or to any individual subsidiary and thus
no loss provision is required at this time.
The Clean Air Act Amendments created new regulatory programs and generally
updated and strengthened air pollution control laws. These amendments expanded
the regulatory role of the EPA regarding emissions from electric generating
facilities and a host of other sources. EUA System generating facilities were
first affected in 1995, when EPA regulations took effect for facilities owned
by the EUA System. Montaup's coal-fired Somerset Unit #6 is utilizing lower
sulfur content coal to meet the 1995 air standards. EUA does not anticipate
the impact from the Amendments to be material to the financial position of the
EUA System.
In November of 1996, the EPA proposed to toughen the nation's ozone standards
as well as the particulate matters standards. The effect that such rules will
have on the EUA System cannot be determined by management at this time.
On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney
General and Division of Energy Resources reached a settlement in principle
regarding electric utility industry restructuring in the state of
Massachusetts. The proposed settlement includes a plan for emissions
reductions related to Montaup's Somerset Station Units 5 and 6, and to
Montaup's 50% ownership share of Canal Electric's Unit #2. The basis for SO2
and NOx emission reductions in the proposed settlement is an allowance
cap calculation. Montaup may meet its allowance caps by any combination of
control technologies, fuel switching, operational changes, and/or the use of
purchased or surplus allowances. The settlement is expected to be submitted to
the MDPU in March 1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight northeast states including
Massachusetts and Rhode Island, issued recommendations for NOx controls for
existing utility boiler s required to meet the ozone non-attainment
requirements of the Clean Air Act. The NESCAUM recommendations are more
restrictive than the Clean Air Act requirements. The Massachusetts Department
of Environmental Management has amended its regulation s to require that
Reasonably Available Control Technology (RACT) be implemented at all stationary
sources potentially emitting 50 tons or more per year of NOx Similar
regulations have been issued in Rhode Island. Montaup has initiated
compliance, through, among other things, selective noncatalytic reduction
processes.
A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. The research to date has not conclusively established a direct
causal relationship between EMF exposure and human health. Additional studies,
which are intended to provide a better understanding of EMF, are continuing.
On October 31, 1996, the National Academy of Sciences issued a literature
review of all research to date, "Possible Health Effects of Exposure to
Residential Electric and Magnetic Fields." Its most widely reported conclusion
stated, "No clear, convincing evidence exists to show that residential
exposures to EMF are a threat to human health."
Some states have enacted regulations to limit the strength of magnetic fields
at the edge of transmission line rights-of-way. Rhode Island has enacted a
statute which authorizes and directs the Energy Facility Siting Board to
establish rules and regulations governing construction of high voltage
transmission lines of 69kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
Guarantee of Financial Obligations: EUA has guaranteed or entered into equity
maintenance agreements in connection with certain obligations of its
subsidiaries. EUA has guaranteed the repayment of EUA Cogenex's $31.5 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $31.1 million,
9.59% unsecured long-term notes due 2011. In addition, EUA has entered into
equity maintenance agreements in connection with the issuance of EUA Service's
10.2% Secured Notes and EUA Cogenex's 7.22% and 9.6% Unsecured Notes.
Under the December 1992 settlement agreement with EUA Power, EUA reaffirmed its
guarantee of up to $10 million of EUA Power's share of the decommissioning
costs of Seabrook I and any costs of cancellation of Seabrook I or Seabrook II.
EUA guaranteed this obligation in 1990 in order to secure the release to EUA
Power of a $10 million fund established by EUA Power at the time EUA Power
acquired its Seabrook interest. EUA has not provided a reserve for this
guarantee because management believes it unlikely that EUA will ever be
required to honor the guarantee.
Montaup is a 3.27% equity participant in two companies which own and operate
transmission facilities interconnecting New England and the Hydro Quebec system
in Canada. Montaup has guaranteed approximately $4.8 million of the
outstanding debt of these two companies. In addition, Montaup and Newport have
minimum rental commitments which total approximately $12.7 million and $1.6
million, respectively under a noncancelable transmission facilities support
agreement for years subsequent to 1996. Other: In the fourth quarter of 1996
EUA Cogenex was notified by Ridgewood/Mass. Corporation that it intended to
seek damages related to certain claims and alleged misrepresentations by EUA
Cogenex regarding the sale of its cogeneration portfolio. As part of the
"Agreement for Assignment for Beneficial Interests," Ridgewood exercised these
rights under the mandatory arbitration clause contained within said agreement.
A date has not been determined for the arbitration proceedings at this time.
EUA Cogenex has filed a counter-claim against Ridgewood for its failure to pay
for certain transitional expenses as stipulated in the "Assignment Agreement."
On January 10, 1997, the Internal Revenue Service (IRS) issued a report in
connection with its examination of the consolidated income tax returns of EUA
for 1992 and 1993. The report includes an adjustment to disallow EUA's
inclusion of its investment in EUA Power's Preferred Stock as a deduction in
determining Excess Loss Account (ELA) taxable income relating to the redemption
of EUA Power's Common and Preferred Stock in 1993. The IRS has taken the
position that the redemption of the Preferred Stock resulted in a capital loss
transaction and not a deduction in determining ELA. The Company disagrees with
the IRS's position and filed a protest in March 1997. EUA believes that it
will ultimately prevail in this matter. However, if the ultimate resolution of
this matter is a favorable decision for the IRS and EUA has not generated
sufficient capital gain transactions to offset the capital loss then EUA would
be required to record a charge that could have a material impact on financial
results in the year of the charge but would not materially impact the financial
position of the company.
In early 1997, ten plaintiffs brought suit against numerous defendants,
including EUA, for injuries and illness allegedly caused by exposure to
asbestos over approximately a thirty-year period, at premises, including some
owned by EUA companies. The total damages claimed in all of these complaints
is $25 million in compensatory and punitive damages, plus exemplary damages and
interest and costs. Each complaint names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the
applicable insurance companies, and EUA is consulting with those insurers to
determine the availability and extent of coverage. EUA cannot predict the
ultimate outcome of this matter at this time.
Report of Independent Accountants
To the Trustees and Shareholders of Eastern Utilities Associates
We have audited the accompanying consolidated balance sheet and consolidated
statements of equity capital and preferred stock and indebtedness of Eastern
Utilities Associates and subsidiaries (the Company) as of December 31, 1996 and
1995, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to ex press an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of the
Company as of December 31, 1996 and 1995, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting principles.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
Report of Management
The management of Eastern Utilities Associates is responsible for the
consolidated financial statements and related information included in this
annual report. The financial statements are prepared in accordance with
generally accepted accounting principles and include amounts based on the best
estimates and judgments of management, giving appropriate consideration to
materiality. Financial information included elsewhere in this annual report is
consistent with the financial statements.
The EUA System maintains an accounting system and related internal controls
which are designed to provide reasonable assurances as to the reliability of
financial records and the protection of assets. The System's staff of internal
auditors conducts reviews to maintain the effectiveness of internal control
procedures.
Coopers & Lybrand L.L.P., an independent accounting firm, is engaged by EUA to
audit and express an opinion on our financial statements. Their audit includes
a review of internal controls to the extent required by generally accepted
auditing standards for such audit.
The Audit Committee of the Board of Trustees, which consists solely of outside
Trustees, meets with management, internal auditors and Coopers & Lybrand L.L.P.
to discuss auditing, internal controls and financial reporting matters. The
internal audit ors and Coopers & Lybrand L.L.P. have free access to the Audit
Committee without management present.
Quarterly Financial and Common Share Information (unaudited)
(Thousands of Dollars, Except Per Share and Share Price Amounts)
Earnings
per Dividends Common Share
Consolidated Average Paid Per Market Price
Operating Operating Net Net Common Common
Revenues Income Income Earnings Share Share High Low
FOR THE QUARTERS
ENDED 1996:
December 31 $ 138,407 $ 14,208 $ 8,312 $ 7,735 $ 0.38 $ 0.415 17 1/2 16
September 30 131,076 13,328 9,389 8,811 0.43 0.415 19 1/2 14 3/4
June 30 122,785 10,024 3,299 2,720 0.13 0.415 21 7/8 18 1/2
March 31 134,800 18,281 11,926 11,348 0.56 0.40 24 1/4 20 5/8
FOR THE QUARTERS
ENDED 1995:
December 31 $ 135,327 $ 17,274 $ 10,989 $ 10,411 $ 0.51 $ 0.40 25 22 1/2
September 30 143,333 20,626 3,666 3,084 0.15 0.40 24 1/8 21 1/2
June 30 146,736 15,017 8,405 7,825 0.38 0.40 24 7/8 21 5/8
March 31 137,967 18,811 11,887 11,306 0.57 0.385 24 1/8 21 3/4
Consolidated Operating and Financial Statistics
Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986
ENERGY GENERATED
AND PURCHASED (millions of kWh):
Generated
- by Somerset Station 719 679 658 319 936 957 887
- by Nuclear Units 977 752 1,008 1,033 1,050 1,109 543
- by Jointly-Owned Units 848 1,410 1,615 1,809 2,105 2,053 2,101
- by Life of the Unit Contracts 526 236 648 602 793 863 667
- by Newport 1 1 1
Interchange with NEPOOL 381 573 295 360 157 191 157
Purchased Power - Unit Power 1,765 1,463 1,526 1,396 1,489 1,006 309
Total Generated and Purchased 5,216 5,113 5,750 5,520 6,531 6,180 4,664
OPERATING REVENUES
($ in thousands):
Residential $ 192,569 $ 193,233 $ 190,662 $ 189,470 $ 176,538 $ 178,812 $ 115,744
Commercial 164,096 169,841 169,241 179,145 170,034 171,732 105,777
Industrial 80,417 83,061 81,500 81,445 76,946 78,273 67,973
Other Electric Utilities 5,411 5,447 4,900 5,098 5,103 4,828 16,189
Other 14,281 17,482 17,282 21,790 21,314 17,984 15,019
Total Primary Sales Revenues 456,774 469,064 463,585 476,948 449,935 451,629 320,702
Unit Contracts 13,945 14,800 26,213 22,617 47,875 41,225 22,622
Non-Electric 56,349 79,499 74,480 66,912 44,154 29,729
Total Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964 $ 522,583 $ 343,324
ENERGY SALES (millions of kWh):
Residential 1,740 1,697 1,678 1,624 1,575 1,579 1,262
Commercial 1,665 1,674 1,671 1,704 1,704 1,689 1,243
Industrial 868 867 850 816 785 777 855
Other Electric Utilities 86 75 74 61 68 66 372
Other 132 128 137 147 147 154 28
Total Primary Sales 4,491 4,441 4,410 4,352 4,279 4,265 3,760
Losses and Company Use 208 227 233 247 241 280 211
Total System Requirements 4,699 4,668 4,643 4,599 4,520 4,545 3,971
Unit Contracts 517 445 1,107 921 2,011 1,635 693
Total Energy Sales 5,216 5,113 5,750 5,520 6,531 6,180 4,664
NUMBER OF CUSTOMERS:
Residential 270,319 268,203 263,054 259,654 257,026 255,620 217,899
Commercial 27,331 27,401 29,004 30,805 32,851 32,745 24,356
Industrial 1,779 1,685 1,603 1,294 1,197 1,172 1,250
Other Electric Utilities 8 8 12 12 15 15 15
Other 34 34 34 34 34 34 30
Total Customers 299,471 297,331 293,707 291,799 291,123 289,586 243,550
Average Annual Revenue
per Residential Customer ($) 712 720 725 730 687 699 531
Average Annual Use per Residential
Customer (kWh) 6,437 6,327 6,379 6,254 6,128 6,177 5,792
AVERAGE REVENUE
PER KWH (cents):
Residential 11.06 11.39 11.36 11.67 11.21 11.32 9.17
Commercial 9.86 10.15 10.13 10.51 9.98 10.17 8.51
Industrial 9.26 9.58 9.59 9.98 9.80 10.07 7.95
Consolidated Operating and Financial Statistics
Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986
CAPITALIZATION ($ in thousands):
Bonds - Net $277,313 $ 279,374 $ 288,449 $ 300,389 $ 306,898 $ 346,146 $ 246,500
Other Long-Term Debt - Net 129,024 155,497 166,963 196,427 156,060 142,306 177,289
Total Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958 488,452 423,789
Preferred Stock - Net 33,935 33,155 32,290 31,953 44,346 45,830 44,931
Common Equity 371,813 375,229 365,443 333,165 266,855 248,598 225,156
Total Capitalization $812,085 $ 843,255 $ 853,145 $ 861,934 $ 774,159 $ 782,880 $ 693,876
CAPITALIZATION RATIOS (%)
Long-Term Debt 50 52 53 57 60 62 61
Preferred Stock 4 4 4 4 6 6 7
Common Equity 46 44 43 39 34 32 32
COMMON SHARE DATA:
Earnings (Loss) per Average
Common Share ($) 1.50 1.61 2.41 2.44 2.00 1.58 2.82
Dividends per Share ($) 1.645 1.585 1.515 1.42 1.36 1.45 2.15
Payout (%) 109.7 98.4 62.9 58.2 68.0 91.8 76.2
Average Common
Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224 16,608,090 11,537,677
Total Common Shares
Outstanding 20,435,997 20,436,764 19,936,980 19,032,598 17,237,788 16,831,062 11,676,229
Book Value per Share ($) 18.19 18.36 18.33 17.50 15.48 14.77 19.28
Percent Earned On Average
Common Equity 8.2 8.8 13.6 15.0 13.2 10.8 15.0
Market Price ($):
High 24 1/4 25 27 3/8 29 7/8 25 1/4 25 39 1/2
Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8 15 3/4 25 3/4
Year End 17 3/8 23 5/8 22 28 24 3/4 20 5/8 38 1/2
Miscellaneous ($ in thousands):
Total Construction Expenditures ($) 63,182 78,461 50,870 76,770 71,914 60,174 64,371
Cash Construction Expenditures ($) 62,730 77,923 50,519 76,391 71,365 57,570 47,137
Internally Generated Funds ($) 77,545 90,883 79,274 79,691 48,933 63,681 44,832
Internally Generated Funds as
a % of Cash Construction (%) 123.6 116.6 156.9 104.3 68.6 110.6 95.1
Installed Capability - mw 1,208 1,191 1,212 1,256<F1> 1,325 1,349 971
Less: Unit Contract Sales - mw 60 35 85 85 85 216 108
System Capability - mw 1,148 1,156 1,127 1,171 1,240 1,133 863
System Peak Demand - mw 854 931 921 854 849 879 691
Reserve Margin (%) 34.4 24.2 22.4 37.1 46.1 28.9 24.9
System Load Factor (%) 62.6 57.2 57.5 61.5 57.5 59.0 65.6
Sources of Energy (%):
Nuclear 29.0 28.2 33.8 34.0 34.1 31.3 19.0
Coal 14.7 14.7 11.7 5.4 18.6 21.0 22.0
Oil 19.8 25.5 20.0 28.3 12.7 26.9 59.0
Gas 30.8 26.5 28.4 26.0 29.3 17.2
Other 5.7 5.1 6.1 6.3 5.3 3.6
Cost of Fuel (Mills per kWh):
Nuclear 5.0 6.3 6.1 7.5 7.7 8.7 8.6
Coal 19.6 20.3 20.9 24.1 21.2 21.4 23.7
Oil 37.7 30.2 27.1 25.5 26.0 18.9 23.6
Gas 14.4 14.3 14.1 15.1 13.0 16.2
All Fuels Combined 16.7 16.7 14.5 15.5 14.8 15.7 20.8
<FN>
<F1> Excludes the 69 mw Somerset Station Unit #5 which was placed in deactivated
reserve on January 25, 1994.
</FN>
Shareholder Information
Shares of Eastern Utilities Associates are listed on the New York and Pacific
Stock Exchanges, under the ticker symbol EUA. As of February 1, 1997, there
were 11,978 common shareholders of record.
Form 10-K
A copy of EUA's 1996 Annual Report on Form 10-K filed with the Securities and
Exchange Commission is available to shareholders without charge by writing to
us.
Annual Meeting
The 1997 Annual Meeting of Shareholders will be held on
Monday, May 19, 1997, at 9:30 a.m., in the
Enterprise Room, 5th Floor
State Street Bank and Trust Company
225 Franklin Street
Boston, Massachusetts
Registrar, Transfer Agent and Dividend Disbursing Agent for Common and
Preferred Shares
Investor Relations
The First National Bank of Boston
c/o Boston EquiServe
P. O. Box 8040
Boston, MA 02266-8040
1-800-736-3001 (Toll-Free)
Lost or Stolen Stock Certificates
If your stock certificate is lost, destroyed or stolen, you should notify the
transfer agent immediately so a "stop transfer" order can be placed on the
missing certificate. The transfer agent then will send you the required
documents to obtain a replacement certificate.
Dividends
Schedule of anticipated record and payment dates for 1997 dividends on EUA
Common Shares:
Record Payment
January 31 February 15
May 1 May 15
August 1 August 15
October 31 November 15
Direct Deposit Plan
EUA Shareholders have the option of having their EUA Dividends deposited
directly into their bank accounts. If you wish to participate, contact EUA
investor relations at 1-800-736-3001 (Toll-Free).
Replacement of Dividend Checks
If you do not receive your dividend check within ten business days after the
dividend payment date, or if your check is lost, destroyed or stolen, you
should notify the disbursing agent in writing for a replacement.
Dividend Reinvestment and Common Share Purchase Plan
A Dividend Reinvestment and Common Share Purchase Plan is available to all
registered shareholders and EUA System company employees. It is a simple and
convenient method of purchasing additional shares of EUA common stock.
Participants also may make cash payments to purchase additional shares. You
may obtain complete details by writing to Clifford J. Hebert Jr.,
Treasurer/Secretary at the address shown below under "Financial Community
Inquiries."
Duplicate Mailings
Duplicate mailings are costly. Shareholders may be receiving duplicate copies
of annual and quarterly reports due to multiple stock accounts in the same
household. To eliminate additional mailings of these reports, please write to
us and enclose label(s) or label information from the duplicate reports.
Dividend checks and proxy material will continue to be sent for each account on
record.
EUA is required by law to create a separate account for each name when stock is
held in similar but different names (e.g., John A. Smith, J. A. Smith, John A.
and Mary K. Smith, etc.). Please contact the Company for instructions if you
wish to consolidate multiple accounts.
Financial Community Inquiries
Institutional investors and securities analysts should direct
inquiries to:
Clifford J. Hebert, Jr., Vice President - Finance & Treasurer
EUA Service Corporation
Post Office Box 2333
Boston, MA 02107
(617) 357-9590
The name Eastern Utilities Associates is the designation of the Trustees for
the time being under a Declaration of Trust dated April 2, 1928, as amended.
All persons dealing with Eastern Utilities Associates must look solely to the
trust property for the enforcement of any claims against Eastern Utilities
Associates, as neither the Trustees, Officers nor Shareholders assume any
personal liability for obligations entered into on behalf of Eastern Utilities
Associates.
Internet Address
Visit EUA's Home Page on the World Wide Web at:
http://www.eua.com
Trustees
Russell A. Boss (A,P)
President and Chief Executive Officer, A. T. Cross Company
Lincoln, Rhode Island
Paul J. Choquette, Jr. (C,P)
President, Gilbane Building Company
Providence, Rhode Island
Peter S. Damon (A,P)
President and Chief Executive Officer, Bank of Newport
Newport, Rhode Island
Peter B. Freeman (A,F)
Corporate Director and Trustee
Providence, Rhode Island
Larry A. Liebenow (A,F)
President and Chief Executive Officer, Quaker Fabric Corporation
Fall River, Massachusetts
Jacek Makowski (F,P)
Chairman, Poseidon Resources Corporation
Stamford, Connecticut
Wesley W. Marple, Jr. (A,C)
Professor of Business Administration, Northeastern University
Boston, Massachusetts
Donald G. Pardus
Chairman of the Board of Trustees and
Chief Executive Officer of the Association
Margaret M. Stapleton (C,F)
Vice President, John Hancock Mutual Life Insurance Company
Boston, Massachusetts
John R. Stevens
President and Chief Operating Officer of the Association
W. Nicholas Thorndike (C,F)
Corporate Director and Trustee
Brookline, Massachusetts
A- Indicates member of Audit Committee
C- Indicates member of Compensation and Nominating Committee
F- Indicates member of Finance Committee
P- Indicates member of Pension Trust Committee
EUA System Officers
Donald G. Pardus
Chairman of the Board of Trustees and Chief Executive Officer
John R. Stevens
President and Chief Operating Officer
John D. Carney
Executive Vice President
Robert G. Powderly
Executive Vice President
Richard M. Burns
Comptroller
Clifford J. Hebert, Jr.
Treasurer and Secretary
Donald T. Sena
Assistant Treasurer
Left to Right: Richard M. Burns, Donald T. Sena, John D. Carney, Robert G.
Powderly, Donald G. Pardus, John R. Stevens, Clifford J. Hebert, Jr.