MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
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EARNINGS OVERVIEW
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NU faced an extremely difficult year in 1996 as a result of the prolonged
outages at the three Millstone units (Millstone). These outages resulted in
significantly increased expenditures for replacement power and work undertaken
at Millstone, which had a significant negative impact on NU's 1996 earnings. In
1997, while all three units are out of service, NU expects to operate on a
roughly break-even basis. The combination of higher expenditures and the
uncertainty surrounding when the units will return to service made it necessary
to ensure that access to adequate cash levels would be available for the
duration of the outages. Management took various actions during 1996 to address
NU's nuclear program and liquidity issues, however, 1997 will continue to be a
serious challenge in these areas.
NU faces future uncertainty with the rapidly moving trend toward industry
restructuring in the three New England states in which NU subsidiaries provide
retail electric service. While restructuring had little direct impact on 1996
financial results, it creates an environment of significant uncertainty and
financial risk for the coming years. As discussed in further detail in
"Restructuring," the financial treatment that strandable investments will be
accorded will impact NU's ability to compete in a restructured environment.
On February 28, 1997, the New Hampshire Public Utilities Commission (NHPUC)
issued its orders for restructuring the state's electric utility industry,
including setting interim stranded cost charges for Public Service Company of
New Hampshire (PSNH). If the orders are implemented without modification, PSNH
would be required to recognize write-offs of over $400 million, after taxes.
PSNH and other NU subsidiaries filed for and received a temporary restraining
order from the United States District Court, which stayed certain portions of
the NHPUC's orders. If PSNH is unable to keep this stay in effect, receive
another appropriate court action, or otherwise modify the NHPUC's orders, the
write-off triggered by the orders would result in defaults which, if not waived
or renegotiated, would give creditors the right to accelerate the repayment of
over $1.2 billion of PSNH and North Atlantic Energy Corporation (NAEC)
indebtedness. See "Restructuring--New Hampshire" for further information on the
impact of the NHPUC's orders.
Earnings per common share were $0.01 in 1996, compared to $2.24 in 1995.
The 1996 earnings were significantly lower primarily due to costs associated
with the ongoing outages at Millstone. These costs totaled approximately $480
million and reduced earnings by $2.18 per share. They are related to the costs
of replacement power, higher 1996 Millstone operation and maintenance costs, a
reserve recognized in 1996 for 1997 expenditures to return the Millstone units
to service and costs associated with ensuring adequate generating capacity in
Connecticut. In addition, 1996 earnings decreased due to the impact of The
Connecticut Light and Power Company's (CL&P) approved rate settlement agreement,
higher 1996 CL&P cogeneration costs and higher nonnuclear operation and
maintenance costs. These decreases were partially offset by higher retail sales,
lower recognition of Millstone 3 phase-in costs and lower 1996 interest charges.
Retail kilowatt-hour sales increased by 1.6 percent in 1996 as a result of
modest economic growth in southern New England. Retail kilowatt-hour sales
increased 1.8 percent for CL&P, 2.7 percent for Western Massachusetts Electric
Company (WMECO) and 0.4 percent for PSNH. PSNH's retail sales were negatively
affected by a pilot retail access program initiated in New Hampshire in June,
1996, however the pilot had little impact on 1996 financial results. In 1997,
management expects that the regional economy will continue to experience
modest economic growth.
MILLSTONE
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OUTAGES
NU has a 100 percent ownership interest in Millstone 1 and 2 and a 68 percent
ownership interest in Millstone 3. Millstone 1, 2 and 3 have been out of service
since November 4, 1995, February 21, 1996, and March 30, 1996, respectively.
Subsequent to its January 31, 1996, announcement that Millstone had been
placed on its watch list, the Nuclear Regulatory Commission (NRC) has stated
that the units cannot return to service until independent, third-party
verification teams have reviewed the actions taken to improve the design,
configuration and employee concerns issues that prompted the NRC to place the
units on its watch list. Upon successful completion of these reviews, the NRC
must approve the restart of each unit through a formal commission vote.
Management took several key steps toward improving NU's nuclear program
during 1996 and will continue to place a high priority on its recovery in 1997.
The NU Board of Trustees (the Board) formed a committee in April, 1996, to
provide high-level oversight of the safety and effectiveness of NU's nuclear
operations, progress toward resolving open NRC issues and progress in resolving
employee, community and customer concerns. In September, 1996, Bruce D. Kenyon
was appointed President and Chief Executive Officer of Northeast Nuclear Energy
Company (NNECO), a wholly-owned subsidiary of NU that operates Millstone, and
retired Admiral David M. Goebel was selected to serve as Vice President for
Nuclear Oversight. In early 1997, Neil S. Carns was selected to serve as Senior
Vice President and Chief Nuclear Officer to oversee Millstone operations.
Northeast Utilities 1996 Annual Report 11
Shortly after his arrival, Mr. Kenyon unveiled a reorganization of NU's nuclear
organization that includes executives loaned from unaffiliated utility
companies. The new organization is intended to establish direct accountability
for performance at each of the nuclear units that the NU system operates and
includes a recovery team for each Millstone unit.
Under the new nuclear organization, each unit's recovery team will be
working toward restart of its respective unit simultaneously with the other two
units. Management estimates that one of the units will be ready for NNECO to
request the NRC's approval for restart in the third quarter of 1997, with the
second and third units ready in the fourth quarter of 1997 and the first quarter
of 1998, respectively. Subsequent to NNECO's request to restart any of the
units, the NRC will require a period of time to assess the results of the
reviews performed by the NRC and the independent third-party teams. Management
cannot estimate when the NRC will allow any of the units to restart, however, it
hopes to have at least one unit operating in the second half of 1997. A period
of time will be required subsequent to restart for each unit to return to
operating at full power.
Higher costs related to the Millstone outages will continue throughout
1997. Monthly replacement power costs for the NU system companies are projected
to average approximately $35 million in 1997, while all three Millstone units
remain out of service. Replacement power costs for the Millstone units expensed
in 1996 were $260 million, which was a substantial portion of the total 1996
replacement power costs. NU will continue to expense its replacement power costs
in 1997. Nonfuel operation and maintenance costs for NU's share of Millstone to
be expensed in 1997 are estimated to be $386 million. A total of $403 million
was expensed in 1996 for nonfuel operation and maintenance costs for Millstone,
including $116 million for incremental costs related to the outages and $63
million reserved for future costs. Nonfuel operation and maintenance costs have
been, and will continue to be, absorbed through the NU system companies' current
rates.
Although the NU system is not precluded from seeking rate recoveries in the
future, management has committed not to seek rate recovery for the portion of
these costs attributable to failure to meet industry standards in operating
Millstone. In light of that commitment, CL&P and WMECO will not seek rate
recovery for a substantial portion of these costs. Management does not currently
intend to request any such recoveries until after the Millstone units begin
returning to service; therefore, it is unlikely that any additional revenues
from any permitted recovery of these costs will be available to contribute to
funding the recovery efforts while the units are out of service.
Under its present planning assumptions, management believes CL&P and WMECO
have sufficient funds to restore the Millstone units to service and purchase
replacement power. See "Rate Matters--Connecticut and Massachusetts" for further
information on the recovery of outage-related costs. See "Liquidity and Capital
Resources" for further information regarding the system's liquidity.
As a result of the nuclear situation, a number of civil lawsuits and
criminal investigations have been initiated, including shareholder litigation.
In addition, there is the potential for claims by the non-NU owners of Millstone
3 for the costs associated with the current outage. To date, no reserves have
been established for existing or potential litigation. See the "Notes to
Consolidated Financial Statements" Note 7B, for further information on
litigation.
CAPACITY
During 1996 and continuing into 1997, the NU system companies have taken
measures to improve their capacity position, including obtaining additional
generating capacity, improving the availability of NU's generating units and
improving the NU system's transmission capability. During 1996, NU spent
approximately $60 million to ensure adequate generating capacity in Connecticut,
of which $42 million was expensed. NU anticipates spending approximately $47
million for additional capacity-related costs in 1997, of which $27 million is
expected to be expensed.
Assuming normal weather conditions and generating unit availability,
management expects that the NU system will have sufficient capacity to meet peak
load demands even if Millstone is not operational at any time through the summer
of 1997. If there are high levels of unplanned outages at other units in New
England, or if any of the system's transmission lines used to import power from
other states are unavailable at times of peak load demand, NU and the other New
England utilities may have to resort to operating procedures designed to reduce
customer demand. Uncertainties associated with having sufficient capacity
through the summer of 1997 include: a Seabrook refueling outage scheduled for 49
days beginning on May 10, 1997; the availability of Maine Yankee, which was put
on the NRC's watch list in January, 1997, and is currently not expected to
return to service earlier than late summer 1997; and the timing of the repairs
to the Long Island Cable, which is capable of providing as much as 300 megawatts
of transmission capability.
See the "Notes to Consolidated Financial Statements" Note 7B, for further
information on Maine Yankee.
LIQUIDITY AND CAPITAL RESOURCES
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During 1996, the NU system companies took various actions to ensure that they
will have access to adequate cash resources, at reasonable cost. The NU system
as a whole had approximately $200 million of cash as of December 31, 1996,
mostly as a result of two CL&P bond issues, one of which was issued in
anticipation of the maturity of approximately $193 million of CL&P bonds in
April, 1997. CL&P and WMECO established facilities under which they may sell up
to $200 million and $40 million, respectively, of their billed and unbilled
accounts receiv-
12 Northeast Utilities 1996 Annual Report
able. As of February 21, 1997, CL&P and WMECO had sold $10 million and $15
million, respectively, using these facilities. Additionally, NU, CL&P and WMECO
entered into a new $313 million three-year revolving credit agreement (the New
Credit Agreement). Under the New Credit Agreement, NU has a contractual
short-term borrowing limit of $150 million, CL&P has a limit of $313 million and
WMECO has a limit of $150 million. The overall limit for all borrowers is $313
million.
Management believes that the borrowing facilities that are currently in
place provide the system companies with adequate access to the funds needed to
bring Millstone back to service if the units begin operating close to
the currently envisioned schedules, and if the other assumptions on which
management has based its planning do not change substantially.
At its July 22, 1996, meeting, the Board reduced NU's common dividend from
$0.44 to $0.25 per share quarterly. A $0.25 quarterly dividend conserves cash at
the rate of approximately $100 million annually compared with the earlier $0.44
quarterly dividend level. In light of the seriousness of the NHPUC's
restructuring orders for PSNH and the extent of the Millstone outages,
management will recommend that the Board consider suspending the NU dividend.
If a dividend suspension were to occur, it would conserve about $140 million
annually of additional funds, compared with the current $0.25 quarterly
dividend. See "Restructuring--New Hampshire" for further information on the
NHPUC's restructuring orders.
Some of the borrowing facilities contain financial covenants that must be
satisfied before borrowings can be made and for outstanding borrowings to remain
outstanding. Through February 21, 1997, CL&P and WMECO have satisfied all
financial covenants required under their respective borrowing facilities, but NU
needed and obtained a limited waiver of an interest coverage covenant that had
to be satisfied for NU to borrow under the New Credit Agreement.
NU, CL&P and WMECO are currently maintaining their access to the New Credit
Agreement under a written arrangement, which expires March 28, 1997, unless
extended by mutual consent, under which NU agreed not to borrow more than $27
million against the facility for a period of time. In addition, NU agreed to
enter into an interim written arrangement whereby NU, CL&P and WMECO will seek
regulatory approval for certain amendments in order to maintain access to the
New Credit Agreement through its maturity date. It is anticipated that these
amendments will include (i) CL&P and WMECO providing lenders first mortgage
bonds as collateral for specified periods and subject to specified terms for
releasing the collateral, (ii) revised financial covenants that are consistent
with NU's, CL&P's and WMECO's current financial forecasts and (iii) an upfront
payment to the lenders in order to maintain commitments under the New Credit
Agreement.
The holders of $38 million of notes issued by NU's real estate company
(Rocky River Realty Company or RRR) are entitled to require that RRR purchase
the notes because, as of December 31, 1996, PSNH and NAEC were rated below
investment grade; these notes are guaranteed by NU. NU is currently engaged in
discussions with the noteholders regarding this issue. See the "Notes to
Consolidated Financial Statements" Note 7G, for further information on these
notes.
During 1996, Standard & Poor's Ratings Group (S&P) and Moody's Investors
Service (Moody's) downgraded all non-New Hampshire NU system securities at least
once, and in some cases twice, as a direct result of the Millstone outages. As
of December 31, 1996, the CL&P and WMECO first mortgage bonds were the only
securities on the NU system rated at investment grade. In March, 1997, S&P and
Moody's downgraded NU, PSNH and NAEC securities as a result of recent
restructuring activities in New Hampshire. S&P and Moody's are reviewing all NU
system securities for further downgrades. These actions will adversely affect
the availability and cost of funds for the NU system companies.
Although cash flows from operations continue to be much higher than
earnings, cash provided from operations decreased by approximately $73 million
in 1996. The decrease was primarily due to higher cash operating expenses
associated with the Millstone outages, partially offset by lower interest
charges and higher retail sales. Cash flows from operations were also impacted
by a sharp increase in the level of accounts payable caused principally by costs
related to a severe December storm and costs associated with the Millstone
outages that had not been paid by year end.
If the return to service of one or more of the Millstone units is delayed
substantially, or if the needed waivers or modifications discussed above are not
forthcoming on reasonable terms, or if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions, or if the
system encounters additional significant costs or other significant deviations
from management's current assumptions, the currently available borrowing
facilities could be insufficient to meet all of the system's cash requirements.
In those circumstances, management would take actions to reduce costs and cash
outflows and would attempt to take other actions to obtain additional sources of
funds. The availability of these funds would be dependent upon the general
market conditions and the NU system's credit and financial condition at the
time.
See the "Consolidated Statements of Capitalization" for information on
long-term debt funding requirements. See the "Notes to Consolidated Financial
Statements" Notes 7E and 7F, for information on construction and long-term
contractual requirements.
Northeast Utilities 1996 Annual Report 13
RESTRUCTURING
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The movement toward electric industry restructuring continues to gain momentum
nationally as well as within the NU system's jurisdictions. Factors that are
driving the move toward restructuring, in the Northeast in particular, include
legislative and regulatory actions and relatively high electricity prices. These
actions will impact the way that NU has historically conducted its business.
Although the NU system companies continue to operate under cost-of-service based
regulation, various restructuring initiatives in each of NU's jurisdictions,
particularly recent actions taken by the NHPUC, have created uncertainty with
respect to future rates and the recovery of strandable investments. Strandable
investments are regulatory assets or other assets that would not be economical
in a competitive environment. NU has exposure to strandable investments for its
investment in high-priced nuclear generating plants, state mandated purchased
power arrangements that are priced above the market, significant regulatory
assets that represent costs deferred by state regulators for future recovery and
costs incurred and assets created in connection with the bankruptcy
reorganization of PSNH in 1990 and NU's 1992 acquisition of PSNH. NU's exposure
to strandable investments and purchased power obligations exceeds its
shareholder's equity. NU's ability to compete in a restructured environment
would be negatively affected unless NU was able to recover substantially all of
these past investments and commitments.
NU is seeking to mitigate the impacts of restructuring by proposing stable,
lower rates, while pursuing customer choice options and full recovery of its
strandable investments. NU's strategy to recover strandable investments will
include efforts to promote state legislation that will authorize the issuance of
rate reduction bonds that would refinance these investments and which would be
recovered through nonbypassable charges to customers. Management is unable to
predict the ultimate outcome of these initiatives, which will be subject to
regulatory and legislative approvals. Management believes that it is entitled to
full recovery of its prudently incurred costs, including regulatory assets and
other strandable investments, based on the general nature of public utility
industry cost-of-service based regulation, and in New Hampshire, based on PSNH's
rate agreement that was entered into by NU, PSNH and the state of New Hampshire
in 1989 (Rate Agreement).
NEW HAMPSHIRE
On February 28, 1997, the NHPUC issued its orders for restructuring the
state's electric utility industry and setting interim stranded cost charges for
PSNH pursuant to legislation enacted in New Hampshire in 1996 (the Final Plan).
The Final Plan would implement retail choice for all customers by January 1,
1998.
The Final Plan would replace the traditional cost-of-service based
regulation with a regional average rate approach to rate setting and recovery of
strandable investments. Accordingly, unless the litigation described below
results in a stay that leads management to conclude that the ratemaking approach
in the NHPUC's restructuring orders will not go into effect, PSNH will be
required to discontinue accounting under Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." This would result in PSNH writing off from its balance sheet, as
early as the quarter ending March 31, 1997, substantially all of its
regulatory assets. The amount of the potential write-off triggered by the
Final Plan is currently estimated at over $400 million, after taxes. Management
believes that under the Final Plan, PSNH would not be required to recognize any
additional loss resulting from impairment of the value of its other long-lived
assets under the provisions of SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of."
The Final Plan also contains rulings on numerous other issues that would,
if put into effect, have a substantial effect on PSNH's operations. Included
among these rulings are: the requirement that PSNH divest within two years of
the initiation of competition all of its owned generation and all of its
wholesale power purchase contracts (including its contract with NAEC for
Seabrook output); a prohibition on the remaining distribution company and its
affiliates from engaging in retail marketing or load aggregation services; a
mandate for the filing of tariffs with the Federal Energy Regulatory Commission
(FERC) for the provision of unbundled retail transmission service; and
assertions that the Rate Agreement, which was an integral part of NU's
acquisition of PSNH, is not binding on the state. The company will challenge
these assertions.
PSNH must file revised interim stranded cost charges, in accordance with
the terms of the Final Plan, by April 30, 1997. The Final Plan also requires
each utility, including PSNH, to file comprehensive plans by June 30, 1997,
which comply with the Final Plan and supplemental orders. In addition, any
jurisdictional utility that chooses to be a distribution company must submit a
plan by December 31, 1997, to divest its generation and aggregation/marketing
service functions by the end of the two-year period following the initiation of
competition.
On March 3, 1997, PSNH, NU, NAEC and Northeast Utilities Service Company
filed for a temporary restraining order, preliminary and permanent injunctive
relief and for declaratory judgment in the United States District Court for New
Hampshire. The case was subsequently transferred to Rhode Island. On March 10,
1997, the court issued a temporary restraining order, which stayed the NHPUC's
February 28, 1997, orders to the extent they established a rate setting
methodology that is not designed to recover PSNH's costs of providing service
and would require PSNH to write off any regulatory assets under SFAS 71. An
evidentiary hearing regarding the system plaintiffs'
14 Northeast Utilities 1996 Annual Report
request for a preliminary injunction will be held on March 20, 1997. PSNH also
intends to pursue claims for damages against the state of New Hampshire in the
New Hampshire state court for abrogation of the 1989 Rate Agreement. The damage
claims will be in the hundreds of millions of dollars. Management cannot predict
the ultimate outcome of these actions.
If PSNH is unable to keep this stay in effect, receive another appropriate
court action, or otherwise modify the Final Plan, the write-off triggered by the
Final Plan would result in defaults which, if not waived or renegotiated, would
give creditors the right to accelerate the repayment of approximately $686
million of PSNH indebtedness and $515 million of NAEC indebtedness. These
circumstances could force PSNH and NAEC to seek bankruptcy protection under
Chapter 11 of the bankruptcy laws.
See the "Notes to Consolidated Financial Statements" Note 11, for further
information on New Hampshire's orders.
MASSACHUSETTS
In December, 1996, the Massachusetts Department of Public Utilities (DPU)
issued its Model Rules on Restructuring (Model Rules) that set forth the
framework for full customer choice of energy suppliers beginning January 1,
1998, and proposed legislation to support the DPU's framework. After January 1,
1998, the DPU has stated that it will no longer set rates for competitive
suppliers of generation. The DPU also reiterated its concern for the maintenance
of the current level of overall system reliability by stating that it will
continue to regulate distribution companies. In March, 1997, WMECO filed
"unbundled" bills (separate charges on bills for generation, transmission,
distribution and access) with the DPU, as required by the Model Rules.
The Model Rules require a number of statutory changes be enacted in order
to implement the rules. Additionally, the Massachusetts General Court has
established a legislative task force to review restructuring during the 1997
legislative session. The Massachusetts legislature has given no formal
indication as to whether it will enact the statutory changes requested by the
DPU. It is unclear at this time how the DPU will proceed if the requested
statutory changes are not enacted.
While the DPU's Model Rules indicate that utilities will have a reasonable
opportunity to recover strandable investments, the criteria to be used in this
process will likely be subject to review in a rate proceeding.
CONNECTICUT
In December, 1996, the legislative task force on electric utility industry
restructuring issued its final report. Although the report included several
legislative recommendations, the task force members did not reach a consensus
on a restructuring proposal. The legislative members of the task force submitted
a restructuring proposal which includes two alternatives: one for retail
competition pilots available to 10 percent of the load in each rate class by
January 1, 1998, and a second for full retail competition beginning January 1,
1998, unless CL&P has effected 10 percent rate reductions for all classes by
that date. This proposal, among others, will be considered in developing
restructuring legislation in 1997.
In response to the ongoing efforts in Connecticut to restructure the
electric utility industry, CL&P has developed a restructuring proposal that
calls for reduced rates for all Connecticut customers as soon as January, 1998;
the initiation of a retail choice pilot program as soon as July, 1998;
phasing-in all customers to retail choice over four years beginning in 2000;
full recovery of strandable investments through rate reduction bonds; and
retaining ownership of generating facilities.
POTENTIAL ACCOUNTING IMPACTS
NU follows accounting principles in accordance with SFAS 71, which allows the
economic effects of rate regulation to be reflected. Under these principles,
regulators may permit incurred costs for certain events or transactions, which
would be treated as expenses by nonregulated enterprises, to be deferred as
regulatory assets and recovered through revenues at a later date.
If future competition or regulatory actions cause any portion of its
operations to no longer be subject to SFAS 71, NU would no longer be able to
recognize regulatory assets and liabilities for that portion of its business
unless those costs would be recoverable by a portion of the business remaining
on cost-of-service based regulation. Under its current regulatory environment
and subject to the successful resolution of the legal actions PSNH has taken
with respect to the NHPUC's recent restructuring activities, management believes
that NU's use of SFAS 71 remains appropriate.
If events create uncertainty about the recoverability of any of NU's
remaining long-lived assets, NU would be required to determine the fair value of
its long-lived assets, including regulatory assets, in accordance with SFAS 121.
The implementation of SFAS 121 did not have a material impact on the company's
financial position or results of operations as of December 31, 1996. Management
believes it is probable that NU will recover its investments in long-lived
assets through future revenues. This conclusion may change in the future as
competitive factors influence wholesale and retail pricing in the electric
utility industry or if the cost-of-service based regulatory structure were to
change.
See the "Notes to Consolidated Financial Statements" Note 1H, for further
information on regulatory accounting.
COMPETITION
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In addition to legislative and regulatory actions, competition in the electric
utility industry continues to grow at a rapid pace as a result of technological
advances; relatively
Northeast Utilities 1996 Annual Report 15
high electricity prices in certain regions of the country, including New
England; surplus generating capacity; and the increased availability of natural
gas. Competitive forces in the electric utility industry have already caused
some customers to choose alternative energy suppliers or relocate outside of the
NU system's service territory. In response, NU is preparing for a competitive
environment by expanding previously established programs and developing new ways
to fortify its relationships with existing customers and attract new customers,
both within and outside its service territory.
During 1996, NU continued to negotiate long-term power supply arrangements
with certain large commercial and industrial retail customers who require an
incentive to locate or expand their operations within NU's service territory,
are considering leaving or reducing operations in the service territory, are
facing short-term financial problems, or are considering generating their own
electricity. Approximately 12 percent of NU's commercial and industrial retail
revenues were under negotiated rate agreements at the end of 1996 and 1995. In
1996, these negotiated rate reductions amounted to approximately $39 million, up
from $35 million in 1995. These activities are expected to continue in 1997.
During 1996, NU devoted significantly more resources to its Retail
Marketing Organization, whose primary mission is to provide value added energy
solutions to customers. Training was emphasized for its 170 new employees, the
majority of whom are account executives charged with developing tailored
solutions for NU's customers and positioning NU as a valuable partner for the
future. The ability of these account executives to obtain an intimate
understanding of customers' needs and concerns and provide value added energy
solutions will play a key role in NU's ability to effectively compete in the
future.
NU subsidiaries competed actively in two pilot retail access programs that
were initiated in New England in 1996. In New Hampshire, approximately 14,500
customers are participating in a two-year statewide pilot program. NU
subsidiaries introduced three energy and service product offerings under
different brand names and competed against 35 other energy suppliers. Given the
political and regulatory environment in New Hampshire, it is notable that NU
retained approximately 60 percent of PSNH's participating customers (50 percent
of the total energy demand market share) and gained approximately 15 percent of
the customers participating from outside NU's service territory.
In a pilot covering four Massachusetts communities outside of NU's
jurisdiction, NU attained approximately 60 percent of the total energy market
share and 70 percent of the commercial energy market share. In addition to
exposing NU to a competitive environment, these pilots have enabled NU to
develop relationships with customers outside of its service territory and to
secure energy contracts with major commercial customers.
Revenue erosion from traditional retail electric sales may be significant
after restructuring. While margins on retail electric sales are likely to be
thin, utilities can compete successfully if they are allowed to recover
their strandable investments. Given this, simply expanding current programs will
not be enough for NU to maintain its leadership role in a fully competitive
electric utility industry. Therefore, NU must plan, invest in and implement
aggressive programs to grow current revenues and attract customers in markets
outside its territory, primarily through new, unregulated businesses. In an
effort to position itself for these challenges, NU formed NUSCO Energy Partners,
Inc. (Energy Partners), whose strategic intent is to become a provider of
creative energy solutions. In particular, Energy Partners was established for
the purpose of competing in state sanctioned retail access programs and
brokering or marketing all types of energy, along with "ancillary services," in
retail and wholesale markets anywhere in the United States. Energy Partners is
currently participating in pilot programs in New Hampshire, Massachusetts and
New York, offering customers a broad portfolio of energy-related services and
establishing the framework for key strategic alliances. Retail competition is
scheduled to be phased-in beginning in 1997 in Rhode Island, and additional
pilot programs are likely to occur in Pennsylvania and New Jersey.
During 1997 and beyond, NU will continue to participate in
state sanctioned retail access programs; invest in new unregulated businesses;
develop new energy-related products and services; and pursue strategic alliances
with companies in various energy-related fields, including fuel supply and
management, power quality, energy efficiency and load management services.
Strategic alliances will allow NU to enter markets that provide access to new
product lines and technologies that complement NU's current products and
services.
RATE MATTERS
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CONNECTICUT
In July, 1996, the Department of Public Utility Control (DPUC) approved a rate
settlement agreement with CL&P (the CL&P Settlement). Under the CL&P Settlement,
CL&P froze base rates until at least December 31, 1997, and accelerated the
amortization of regulatory assets by $73 million in 1996 and between $54 million
and $68 million in 1997. Additionally, the CL&P Settlement terminated all
pending litigation, as of March 31, 1996, among the parties that could
potentially affect CL&P's rates. The CL&P Settlement does not impact costs
incurred subsequent to March 31, 1996, that are associated with the Millstone
outages. The CL&P Settlement reduced 1996 earnings by approximately $35 million,
or $0.17 per share. The impact on 1997 earnings is not expected to be
significant.
In October, 1996, the DPUC issued a final order establishing an Energy
Adjustment Clause (EAC), which
16 Northeast Utilities 1996 Annual Report
replaced both CL&P's fossil-fuel adjustment clause and its generation
utilization adjustment clause (GUAC). The EAC, which is designed to calculate
the difference between actual fuel costs and fuel costs collected through base
rates, took effect on January 1, 1997. The order includes an incentive mechanism
which disallows recovery of the first $9 million of actual fuel costs in excess
of base rate levels, but permits CL&P to retain the first $9 million in actual
fuel costs below base rate levels.
In January, 1997, the DPUC notified CL&P that it intends to conduct its
prudence review of nuclear cost issues in multiple phases, beginning
immediately. The first phase, covering the period April 1 through June 30, 1996,
has already begun. CL&P will not be permitted to collect any replacement power
costs associated with the current nuclear outages prior to the completion of the
DPUC's prudence reviews. Management does not expect to seek recovery of a
substantial portion of these costs.
NEW HAMPSHIRE
PSNH's Rate Agreement provides for seven base rate increases and a comprehensive
fuel and purchased power adjustment clause (FPPAC). In June, 1996, the final
base rate increase of 5.5 percent went into effect. Although the FPPAC continues
for an additional three years beyond the end of the fixed-rate period, there is
uncertainty regarding how it will function after that time. Given the completion
of the fixed-rate period, and the uncertainty surrounding the FPPAC, management
expects to file a rate case with the NHPUC in May, 1997.
See the "Notes to Consolidated Financial Statements" Note 1K, for further
information on the FPPAC.
MASSACHUSETTS
In April, 1996, the DPU approved a settlement (the Agreement) that included the
continuation through February, 1998, of the 2.4 percent rate reduction
instituted in June, 1994. Additionally, the Agreement terminated certain pending
and potential reviews of WMECO's generating plant performance and accelerated
its amortization of strandable generation assets by approximately $6 million in
1996 and $10 million in 1997. The Agreement did not have a material impact on
earnings for 1996.
In February, 1997, the DPU approved a joint settlement proposed by WMECO
and the Massachusetts Attorney General that provides for a continuation of
WMECO's August, 1996, fuel adjustment charge (FAC) through August, 1997, and
stipulates that WMECO will not seek carrying charges on any deferred fuel costs
not currently recovered as a result of maintaining the prior FAC rate. In
accepting this settlement, the DPU deferred any inquiry into WMECO's replacement
power costs related to the Millstone outages. Management does not expect to seek
recovery of a substantial portion of these costs.
NUCLEAR DECOMMISSIONING
- --------------------------------------------------------------------------------
NU has a 49 percent ownership interest in the Connecticut Yankee nuclear
generating facility (CY or the plant). On December 4, 1996, the CY Board of
Directors voted unanimously to cease permanently the production of power at the
plant. The decision to retire CY from commercial operation was based on an
economic analysis of the costs of operating it compared to the costs of closing
it and incurring replacement power costs over the remaining period of the
plant's operating license, which expires in 2007. The economic analysis showed
that closing the plant and incurring replacement power costs produced
substantial savings.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning. In late December, 1996, CY filed an amendment to its power
contracts with the FERC to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1996, NU's
share of these obligations was approximately $374 million, including the cost of
decommissioning and the recovery of existing assets. Management expects that
CL&P, PSNH and WMECO each will continue to be allowed to recover such
FERC-approved costs from their customers. Accordingly, NU has recognized its
share of the estimated costs as a regulatory asset, with a corresponding
obligation, on its Consolidated Balance Sheets.
NU's estimated cost to decommission its shares of Millstone 1, 2 and 3 and
Seabrook is approximately $1.2 billion in year end 1996 dollars. These costs are
being recognized over the lives of the respective units with a portion being
currently recovered through rates. As of December 31, 1996, the market value of
the contributions already made to the decommissioning trusts, including their
investment returns, was approximately $404 million.
See the "Notes to Consolidated Financial Statements" Note 2, for further
information on nuclear decommissioning, including NU's share of costs to
decommission the regional nuclear generating units.
ENVIRONMENTAL MATTERS
- --------------------------------------------------------------------------------
NU is potentially liable for environmental cleanup costs at a number of sites
inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of NU. At December 31, 1996, NU had
recorded an environmental reserve of approximately $13 million, the most
probable amount as required by SFAS 5, "Accounting for Contingencies."
See the "Notes to Consolidated Financial Statements" Note 7C, for further
information on environmental matters.
RISK MANAGEMENT INSTRUMENTS
- --------------------------------------------------------------------------------
CL&P uses fuel-price management instruments to reduce a portion of the
fuel-price risk associated with certain of its long-term negotiated energy
contracts. NAEC uses inter-
Northeast Utilities 1996 Annual Report 17
est-rate management instruments to reduce interest-rate risk associated with its
$200 million variable-rate bank note. These instruments are not used for trading
purposes. The differential paid or received as fuel prices or interest rates
change is recognized in income when realized. As of December 31, 1996, CL&P and
NAEC had outstanding fuel-price and interest-rate management instruments with a
total notional value of approximately $229 million and $200 million,
respectively. The settlement amounts associated with the instruments reduced
fuel expense by approximately $7.5 million for CL&P and increased interest
expense by approximately $1.0 million for NAEC during 1996. CL&P's fuel-price
management instruments seek to minimize exposure associated with rising fuel
prices and effectively fix the cost of fuel and profitability of certain of its
long-term negotiated contract sales. NAEC's interest-rate management instruments
effectively fix its variable-rate bank note at 7.82 percent as of March
10, 1997.
See the "Notes to Consolidated Financial Statements" Note 8, for further
information on interest-rate and fuel-price management instruments.
RESULTS OF OPERATIONS
================================================================================
The components of significant income statement variances for the past two
years are provided in the table below.
The relative magnitude of how revenues earned in 1996 were used by NU's
continuing operations in 1996 is illustrated in the chart on page 19.
OPERATING REVENUES
Total operating revenues increased in 1996, primarily due to higher retail
sales, regulatory decisions and higher other revenues, partially offset by lower
fuel recoveries and lower wholesale revenues. Retail sales increased 1.6 percent
($40 million), primarily due to modest economic growth in 1996. Regulatory
decisions increased revenues by $22 million, primarily due to retail rate
increases for CL&P and PSNH, partially offset by 1996 reserves for CL&P
over-recoveries of demand side management costs. Other revenues increased $31
million and included higher recognition in 1996 of reimbursable conservation
services and higher transmission revenues. Fuel recoveries decreased $40
million, primarily due to lower FPPAC revenues for PSNH as a result of a
customer refund ordered by the NHPUC, partially offset by higher base fuel
revenues for PSNH as a result of the PSNH retail rate increases. Wholesale
revenues decreased $13 million, primarily due to higher recognition in 1995 of
lump-sum payments for the termination of a CL&P long-term contract and capacity
sales contracts that expired in 1995.
Total operating revenues increased in 1995, primarily due to regulatory
decisions and higher fuel recoveries, partially offset by lower wholesale
revenues. Regulatory decisions increased revenues by $79 million, primarily due
RESULTS OF OPERATIONS
- -----------------------------------------------------------------------------------------------
Income Statement Variances
(Millions of Dollars)
- -----------------------------------------------------------------------------------------------
1996 over/(under) 1995 1995 over/(under) 1994
Amount Percent Amount Percent
- -----------------------------------------------------------------------------------------------
Operating revenues $42 1% $108 3%
Fuel, purchased and net interchange power 230 25 77 9
Other operation 191 20 48 5
Maintenance 127 44 (18) (6)
Depreciation 5 1 19 6
Amortization of regulatory assets, net (6) (5) (32) (20)
Federal and state income taxes (192) (73) (18) (6)
Other, net 20 (a) 3 41
Minority interest in income of subsidiary 1 7 9 100
Deferred nuclear plants return (other and
borrowed funds) (13) (36) (31) (45)
Interest on long-term debt (30) (10) 2 1
Preferred dividends of subsidiaries (6) (14) (4) (9)
Net income (281) (99) (4) (2)
- -----------------------------------------------------------------------------------------------
(a) Percentage greater than 100
18 Northeast Utilities 1996 Annual Report
to retail rate increases for PSNH and CL&P and higher recoveries of
demand side management costs. Fuel recoveries increased $63 million, primarily
due to higher energy costs and the recovery of GUAC costs for CL&P. Wholesale
revenues decreased $19 million, primarily due to capacity sales contracts that
expired in 1994.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 1996, primarily
due to higher energy costs in 1996 due to the nuclear outages and the write-off
of GUAC balances under the CL&P Settlement, partially offset by lower nuclear
generation.
Fuel, purchased and net interchange power expense increased in 1995,
primarily due to higher fossil generation, higher priced outside energy
purchases from other utilities in 1995 and higher amortization of previously
deferred FPPAC expenses in 1995.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased in 1996, primarily due to
higher costs associated with the Millstone outages ($179 million, including
$63 million of reserves for future costs) and 1996 costs to ensure adequate
generating capacity in Connecticut ($39 million). In addition, 1996 costs
reflect higher storm and reliability expenditures, higher recognition of
conservation expenses and higher marketing costs.
Other operation and maintenance expenses increased in 1995, primarily due
to higher recognition of conservation expenses, higher recognition of
postretirement benefit costs and higher capacity charges from the regional
nuclear generating units, partially offset by higher nuclear reserves for
excess/obsolete inventory in 1994, and lower maintenance costs at the fossil
units and fossil reserves for excess/obsolete inventory in 1994.
DEPRECIATION
Although the change in 1996 was not significant, depreciation expense increased
in 1995, primarily due to higher plant balances and higher decommissioning
levels.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased in 1996, primarily due to the
completion of Millstone 3 phase-in plans in 1995, partially offset by lower
CL&P cogeneration deferrals and the accelerated amortization of regulatory
assets as a result of the CL&P Settlement.
Amortization of regulatory assets, net decreased in 1995, primarily due to
higher CL&P cogeneration deferrals in 1995, the completion during 1994 of the
amortization of a 1993 cogeneration buyout and the completion of WMECO's
amortization of Millstone 3 phase-in costs in 1995.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased in 1996, primarily due to lower
book taxable income, partially offset by 1995 tax benefits from a favorable tax
ruling and the expiration of the 1991 federal statute of limitations. Income tax
expense totaled approximately $70 million in 1996, despite relatively low pretax
earnings, due to the tax effect of differences for certain items, particularly
depreciation and the amortization of PSNH acquisition costs.
Federal and state income taxes decreased in 1995, primarily due to 1995 tax
benefits from a favorable tax ruling and the expiration of the 1991 federal
statute of limitations.
OTHER, NET
Other, net increased in 1996, primarily due to higher interest income on
temporary cash investments in 1996, the 1995 write-down of CL&P's wholesale
investment in Millstone 3 and a 1995 increase to the environmental reserve. The
change in 1995 was not significant.
MINORITY INTEREST IN INCOME OF SUBSIDIARY
Although the change in 1996 was not significant, minority interest in income of
subsidiary increased in 1995, primarily due to the issuance of Monthly Income
Preferred Securities in 1995. See the "Notes to Consolidated Financial
Statements" Note 10, for further information on these securities.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased in 1996, primarily due to additional
Seabrook investment being phased into rates, partially offset by a one-time
adjustment to NAEC's Seabrook deferred return balance of approximately $5
million in 1995.
Deferred nuclear plants return decreased in 1995, primarily due to
additional Millstone 3 and Seabrook investments being phased into rates.
INTEREST ON LONG-TERM DEBT
Interest on long-term debt decreased in 1996, primarily due to lower average
interest rates as a result of refinancing activities and lower average 1996
debt levels. The change in 1995 was not significant.
PREFERRED DIVIDENDS OF SUBSIDIARIES
Preferred dividends of subsidiaries decreased in 1996, primarily due to a 1995
charge to earnings for premiums on redeemed preferred stock and a reduction in
preferred stock levels. The change in 1995 was not significant.
[PIE CHART here]
1996 USE OF REVENUE
Nonfuel Operating Expenses and Other Income, Net (6%)
Wages and Benefits (14%)
Interest and Charges (8%)
Common and Preferred Dividends (5%)
Other Operation and Maintenance Expenses (28%)
Energy Costs (30%)
Taxes (9%)
[end of Pie chart]
Northeast Utilities 1996 Annual Report 19
COMPANY REPORT
The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that
encourages the maintenance of high standards of conduct in all of its business
activities. The company maintains a system of internal controls over financial
reporting which is designed to provide reasonable assurance to the company's
management and Board of Trustees regarding the preparation of reliable,
published financial statements. The system is supported by an organization of
trained management personnel, policies and procedures, and a comprehensive
program of internal audits. Through established programs, the company regularly
communicates to its management employees their internal control responsibilities
and policies prohibiting conflict of interest.
The Audit Committee of the Board of Trustees is composed entirely of
outside trustees. This committee meets periodically with management, the
internal auditors and the independent auditors to review the activities of each
and to discuss audit matters, financial reporting and the adequacy of internal
controls.
Because of inherent limitations in any system of internal controls, errors
or irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation of
all financial statements, are reliable.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees and Shareholders
of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 1996 and 1995, and the related consolidated
statements of income, common shareholders' equity, cash flows and income
taxes for each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these 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 financial statements referred to above present fairly,
in all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 21, 1997 (except with respect to the matter discussed in Note 11,
as to which the date is March 10, 1997)
20 Northeast Utilities 1996 Annual Report
CONSOLIDATED STATEMENTS OF INCOME
- -----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES...................................................... $ 3,792,148 $ 3,750,560 $ 3,642,742
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Operation--
Fuel, purchased and net interchange power........................... 1,139,616 909,244 832,420
Other............................................................... 1,157,510 966,845 919,044
Maintenance............................................................. 415,532 288,927 306,429
Depreciation............................................................ 359,507 354,293 335,019
Amortization of regulatory assets, net.................................. 122,573 128,413 160,909
Federal and state income taxes (See Consolidated
Statements of Income Taxes) ........................................ 68,261 261,287 287,951
Taxes other than income taxes........................................... 257,577 249,463 247,045
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses............................................ 3,520,576 3,158,472 3,088,817
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME........................................................ 271,572 592,088 553,925
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME:
Deferred nuclear plants return--other funds............................. 8,988 14,196 27,085
Equity in earnings of regional nuclear generating
and transmission companies.......................................... 13,155 13,208 14,426
Other, net.............................................................. 30,932 10,954 7,745
Minority interest in income of subsidiary (Note 9)...................... (9,300) (8,732) --
Income taxes............................................................ (1,747) (683) 7,825
- -----------------------------------------------------------------------------------------------------------------------
Other income, net................................................... 42,028 28,943 57,081
- -----------------------------------------------------------------------------------------------------------------------
Income before interest charges...................................... 313,600 621,031 611,006
- -----------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt.............................................. 285,463 315,862 314,191
Other interest.......................................................... 7,649 6,666 8,037
Deferred nuclear plants return--borrowed funds.......................... (15,119) (23,310) (41,138)
- -----------------------------------------------------------------------------------------------------------------------
Interest charges, net............................................... 277,993 299,218 281,090
- -----------------------------------------------------------------------------------------------------------------------
Income after interest charges....................................... 35,607 321,813 329,916
PREFERRED DIVIDENDS OF SUBSIDIARIES..................................... 33,776 39,379 43,042
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME.............................................................. $ 1,831 $ 282,434 $ 286,874
=======================================================================================================================
EARNINGS PER COMMON SHARE............................................... $0.01 $2.24 $2.30
=======================================================================================================================
COMMON SHARES OUTSTANDING (AVERAGE)..................................... 127,960,382 126,083,645 124,678,192
=======================================================================================================================
The accompanying notes are an intergral part of these financial statements.
Northeast Utilities 1996 Annual Report 21
CONSOLIDATED BALANCE SHEETS
- -----------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
UTILITY PLANT, AT COST:
Electric............................................................ $ 9,688,005 $ 9,490,142
Other............................................................... 189,453 187,389
- -----------------------------------------------------------------------------------------------------------------------
9,877,458 9,677,531
Less: Accumulated provision for depreciation (Note 1F).............. 3,979,864 3,629,559
- -----------------------------------------------------------------------------------------------------------------------
........................................................................ 5,897,594 6,047,972
Unamortized PSNH acquisition costs (Note 1J)............................ 491,709 588,910
Construction work in progress........................................... 146,438 165,111
Nuclear fuel, net....................................................... 196,424 198,844
- -----------------------------------------------------------------------------------------------------------------------
Total net utility plant............................................. 6,732,165 7,000,837
- -----------------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS:
Nuclear decommissioning trusts, at market............................... 403,544 325,674
Investments in regional nuclear generating companies, at equity (Note 1E) 85,340 81,996
Investments in transmission companies, at equity (Note 1E).............. 21,186 23,558
Investments in Charter Oak Energy, Inc. projects (Note 1E).............. 57,188 41,221
Other, at cost.......................................................... 43,372 35,247
- -----------------------------------------------------------------------------------------------------------------------
610,630 507,696
- -----------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents (Note 1Q)..................................... 194,197 29,038
Special deposits (Note 1Q).............................................. 7,039 71
Receivables, less accumulated provision for uncollectible
accounts of $17,062,000 in 1996 and $14,378,000 in 1995............. 477,021 435,931
Accrued utility revenues................................................ 127,162 136,260
Fuel, materials and supplies, at average cost........................... 211,414 200,580
Recoverable energy costs, net--current portion.......................... 1,804 79,300
Prepayments and other................................................... 48,279 34,430
- -----------------------------------------------------------------------------------------------------------------------
1,066,916 915,610
- -----------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Regulatory assets (Note 1H)............................................. 2,221,839 2,048,959
Unamortized debt expense................................................ 38,146 37,645
Other................................................................... 72,052 48,827
- -----------------------------------------------------------------------------------------------------------------------
2,332,037 2,135,431
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS............................................................ $10,741,748 $10,559,574
=======================================================================================================================
The accompanying notes are an integral part of these financial statements.
22 Northeast Utilities 1996 Annual Report
CONSOLIDATED BALANCE SHEETS (continued)
- -----------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION: (See Consolidated Statements of Capitalization)
Common shareholders' equity (See Note (a)--Consolidated
Statements of Common Shareholders' Equity):
Common shares, $5 par value--authorized 225,000,000 shares; 136,051,938 shares issued
and 128,444,373 shares outstanding in 1996 and 135,611,166 shares issued
and 127,050,647 shares outstanding in 1995...................... $ 680,260 $ 678,056
Capital surplus, paid in............................................ 940,446 936,308
Deferred benefit plan--employee stock ownership plan (Note 5D)...... (176,091) (198,152)
Retained earnings................................................... 832,520 1,007,340
- -----------------------------------------------------------------------------------------------------------------------
....Total common shareholders' equity................................... 2,277,135 2,423,552
Preferred stock not subject to mandatory redemption..................... 136,200 169,700
Preferred stock subject to mandatory redemption......................... 276,000 302,500
Long-term debt.......................................................... 3,613,681 3,705,215
- -----------------------------------------------------------------------------------------------------------------------
Total capitalization................................................ 6,303,016 6,600,967
- -----------------------------------------------------------------------------------------------------------------------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES (Note 9) ................ 99,972 99,935
- -----------------------------------------------------------------------------------------------------------------------
OBLIGATIONS UNDER CAPITAL LEASES (Note 4)............................... 186,860 147,372
- -----------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Notes payable to banks.................................................. 38,750 99,000
Long-term debt and preferred stock--current portion..................... 319,503 219,657
Obligations under capital leases--current portion (Note 4).............. 19,305 83,110
Accounts payable........................................................ 507,139 319,038
Accrued taxes........................................................... 7,050 75,218
Accrued interest........................................................ 51,386 53,699
Accrued pension benefits................................................ 99,699 90,630
Nuclear compliance (Note 7B)............................................ 63,200 --
Other................................................................... 98,570 105,821
- -----------------------------------------------------------------------------------------------------------------------
1,204,602 1,046,173
- -----------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS:
Accumulated deferred income taxes (Note 1I)............................. 2,044,123 2,135,852
Accumulated deferred investment tax credits............................. 168,444 178,060
Deferred contractual obligations (Note 2)............................... 440,495 103,475
Other................................................................... 294,236 247,740
- -----------------------------------------------------------------------------------------------------------------------
2,947,298 2,665,127
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES.................................... $10,741,748 $10,559,574
=======================================================================================================================
The accompanying notes are an integral part of these financial statements.
Northeast Utilities 1996 Annual Report 23
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES:
Income before preferred dividends of subsidiaries....................... $ 35,607 $ 321,813 $ 329,916
Adjustments to reconcile to net cash from operating activities:
Depreciation........................................................ 359,507 354,293 335,019
Deferred income taxes and investment tax credits, net............... 45,730 164,208 146,560
Deferred nuclear plants return, net of amortization................. (14,948) 71,788 49,994
Recoverable energy costs, net of amortization....................... (14,289) (27,874) (85,573)
Amortization of PSNH acquisition costs.............................. 56,884 55,547 55,319
Deferred cogeneration costs, net of amortization.................... 25,957 (55,341) (36,821)
Deferred demand side management costs, net of amortization.......... 26,941 (937) (4,691)
Deferred nuclear refueling outage, net of amortization.............. 51,831 (29,569) --
Nuclear compliance, net (Note 7B)................................... 63,200 -- --
Other sources of cash............................................... 164,915 132,106 74,579
Other uses of cash.................................................. (41,589) (67,838) (36,596)
Changes in working capital:
Receivables and accrued utility revenues............................ (31,992) (72,081) 8,133
Fuel, materials and supplies........................................ (10,834) (10,518) 4,906
Accounts payable.................................................... 188,101 38,096 51,824
Accrued taxes....................................................... (68,168) 17,686 17,031
Other working capital (excludes cash)............................... (21,383) (2,458) 23,995
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows from operating activities................................ 815,470 888,921 933,595
- -----------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES:
Issuance of common shares............................................... 10,622 47,218 14,551
Issuance of long-term debt.............................................. 222,150 225,100 625,000
Issuance of Monthly Income Preferred Securities......................... -- 100,000 --
Net (decrease) increase in short-term debt.............................. (60,250) (91,000) 16,500
Reacquisitions and retirements of long-term debt........................ (248,142) (425,500) (982,920)
Reacquisitions and retirements of preferred stock....................... (36,500) (140,675) (7,325)
Cash dividends on preferred stock....................................... (33,776) (39,379) (43,042)
Cash dividends on common shares......................................... (176,277) (221,701) (219,317)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used for financing activities............................ (322,173) (545,937) (596,553)
- -----------------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES:
Investment in plant:
Electric and other utility plant.................................... (222,829) (231,408) (259,904)
Nuclear fuel........................................................ (14,529) (18,261) (28,308)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments in plant............................ (237,358) (249,669) (288,212)
Investment in nuclear decommissioning trusts............................ (65,716) (60,642) (34,050)
Other investment activities, net........................................ (25,064) (30,761) (10,516)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments..................................... (328,138) (341,072) (332,778)
- -----------------------------------------------------------------------------------------------------------------------
NET INCREASE IN CASH FOR THE PERIOD..................................... 165,159 1,912 4,264
Cash and cash equivalents--beginning of period.......................... 29,038 27,126 22,862
- -----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents--end of period................................ $ 194,197 $ 29,038 $ 27,126
- -----------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest, net of amounts capitalized.................................... $ 268,129 $ 321,148 $ 306,224
=======================================================================================================================
Income taxes............................................................ $ 64,189 $ 108,928 $ 134,727
=======================================================================================================================
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases..................... $ 3,524 $ 41,388 $ 65,932
=======================================================================================================================
The accompanying notes are an integral part of these financial statements.
24 Northeast Utilities 1996 Annual Report
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
- -----------------------------------------------------------------------------------------------------------------------
Deferred
Benefit
Common Capital Surplus, Plan--ESOP Retained
Shares (a) Paid In (Note 5D) Earnings (b) Total
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 1994.................. $671,035 $901,740 $(228,205) $879,518 $2,224,088
- -----------------------------------------------------------------------------------------------------------------------
Net income for 1994..................... 286,874 286,874
Cash dividends on common shares--
$1.76 per share...................... (219,317) (219,317)
Loss on retirement of preferred stock... (87) (87)
Issuance of 3,201 common shares,
$5 par value......................... 16 61 77
Allocation of benefits--ESOP............ (406) 14,881 14,475
Capital stock expenses, net............. 2,976 2,976
- -----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1994................ 671,051 904,371 (213,324) 946,988 2,309,086
- -----------------------------------------------------------------------------------------------------------------------
Net income for 1995..................... 282,434 282,434
Cash dividends on common shares--
$1.76 per share...................... (221,701) (221,701)
Loss on retirement of preferred stock... (381) (381)
Issuance of 1,400,940 common shares,
$5 par value......................... 7,005 24,971 31,976
Allocation of benefits--ESOP............ 70 15,172 15,242
Capital stock expenses, net............. 6,896 6,896
- -----------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1995................ 678,056 936,308 (198,152) 1,007,340 2,423,552
- -----------------------------------------------------------------------------------------------------------------------
Net income for 1996..................... 1,831 1,831
Cash dividends on common shares--
$1.38 per share...................... (176,277) (176,277)
Loss on retirement of preferred stock... (374) (374)
Issuance of 440,772 common shares,
$5 par value......................... 2,204 8,418 10,622
Allocation of benefits--ESOP............ (8,103) 22,061 13,958
Capital stock expenses, net............. 3,077 3,077
Currency translation adjustments........ 746 746
- -----------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1996................ $680,260 $940,446 $(176,091) $832,520 $2,277,135
=======================================================================================================================
(a) As part of its acquisition of PSNH, NU issued 8,430,910 warrants to former
PSNH equity security holders. Each warrant, which expires on June 5, 1997,
entitles the holder to purchase one share of NU common stock at an exercise
price of $24 per share. As of December 31, 1996, 464,187 shares had been
purchased through the exercise of warrants.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount
of retained earnings available for NU common dividends. At December 31,
1996, these restrictions totaled approximately $559.6 million.
The accompanying notes are an integral part of these financial statements.
Northeast Utilities 1996 Annual Report 25
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- -----------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets)........... $2,277,135 $2,423,552
- -----------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value--authorized 36,600,000 shares at December 31, 1996 and 1995;
5,840,000 shares outstanding in 1996 and 7,300,000 shares outstanding in 1995
$50 par value--authorized 9,000,000 shares at December 31, 1996 and 1995;
5,424,000 shares outstanding in 1996 and 1995
$100 par value--authorized 1,000,000 shares at December 31, 1996 and 1995;
200,000 shares outstanding in 1996 and 1995
- -----------------------------------------------------------------------------------------------------------------------
Dividend Rates Current Redemption Prices (a) Current Shares Outstanding
- -----------------------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
$25 par value--Adjustable Rate $ -- --....... -- 33,500
$50 par value--$1.90 to $3.28 $50.50 to $54.00 2,324,000....... 116,200 116,200
$100 par value--$7.72 $103.51 200,000....... 20,000 20,000
- -----------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory Redemption ....................... 136,200 169,700
- -----------------------------------------------------------------------------------------------------------------------
SUBJECT TO MANDATORY REDEMPTION: (b)
$25 par value--$1.90 to $2.65 $25.00 to $25.76 5,840,000....... 146,000 149,000
$50 par value--$2.65 to $3.615 $51.00 to $52.41 3,100,000....... 155,000 155,000
- -----------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption............................ 301,000 304,000
Less: Preferred Stock to be redeemed within one year............................. 25,000 1,500
- -----------------------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption, net............................. 276,000 302,500
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT: (c)
First Mortgage Bonds --
Maturity Interest Rates
- -----------------------------------------------------------------------------------------------------------------------
1996 8.875%........................................................... -- 172,500
1997 5.75% to 7.625%.................................................. 207,988 211,945
1998 6.50% to 9.17%................................................... 199,800 199,800
1999 5.50% to 7.25%................................................... 279,000 280,000
2000 5.75% to 6.875%.................................................. 260,000 260,000
2001 7.875%........................................................... 160,000 --
2002 7.75% to 9.05%................................................... 400,000 420,000
2004 6.125%........................................................... 140,000 140,000
2019-2023 7.375% to 7.50%.................................................. 120,000 120,000
2024-2025 7.375% to 8.50%.................................................. 430,000 430,000
- -----------------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds................................................... 2,196,788 2,234,245
- -----------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt--(d)
Pollution Control Notes and Other Notes--
2000 Adjustable Rate (e).............................................. 200,000 225,000
2005-2006 8.38% to 8.58%................................................... 210,000 224,000
2013-2016 Adjustable Rate.................................................. 23,400 23,400
2018-2020 7.17% and Adjustable Rate........................................ 49,482 49,874
2021-2022 7.50% to 7.65% and Adjustable Rate............................... 552,485 552,485
2028 Adjustable Rate.................................................. 369,300 369,300
2031 Adjustable Rate (f).............................................. 62,000 --
- -----------------------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other Notes................................ 1,466,667 1,444,059
Fees and interest due for spent nuclear fuel disposal costs (Note 1o)............ 195,023 185,158
Other............................................................................ 57,169 68,312
- -----------------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt....................................................... 1,718,859 1,697,529
- -----------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net............................................ (7,463) (8,402)
- -----------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt............................................................. 3,908,184 3,923,372
Less: Amounts due within one year................................................ 294,503 218,157
- -----------------------------------------------------------------------------------------------------------------------
Long-Term Debt, net.............................................................. 3,613,681 3,705,215
- -----------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION............................................................. $6,303,016 $6,600,967
=======================================================================================================================
The accompanying notes are an integral part of these financial statements.
26 Northeast Utilities 1996 Annual Report
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
- ---------------------------------------------------------------------
(Thousands of Dollars)
- ---------------------------------------------------------------------
Balance at January 1, 1994.............................. $382,000
Reacquisitions and Retirements...................... (2,325)
- ---------------------------------------------------------------------
Balance at December 31, 1994............................ 379,675
Reacquisitions and Retirements...................... (75,675)
- ---------------------------------------------------------------------
Balance at December 31, 1995............................ 304,000
Reacquisitions and Retirements...................... (3,000)
- ---------------------------------------------------------------------
Balance at December 31, 1996............................ $301,000
=====================================================================
The minimum sinking-fund requirements of the series subject to mandatory
redemption aggregate approximately $25.0 million in 1997, $30.3 million in 1998
and $46.3 million in 1999, 2000 and 2001. In case of default on sinking-fund
payments, no payments may be made on any junior stock by way of dividends or
otherwise (other than in shares of junior stock) so long as the default
continues. If a subsidiary is in arrears in the payment of dividends on any
outstanding shares of preferred stock, the subsidiary is prohibited from
redeeming or purchasing less than all of the outstanding preferred stock.
(c) Long-term debt maturities and cash sinking-fund requirements, excluding fees
and interest due for spent nuclear fuel disposal costs, on debt outstanding at
December 31, 1996 for the years 1997 through 2001 are approximately $294.5
million, $238.1 million, $369.4 million, $551.6 million and $252.7 million,
respectively. In addition, there are annual one percent sinking- and
improvement-fund requirements of approximately $17.1 million for 1997, $15.0
million for 1998, $14.7 million for 1999, $12.0 million for 2000 and $9.4
million for 2001. Such sinking- and improvement-fund requirements may be
satisfied by the deposit of cash or bonds or by certification of property
additions. Essentially all utility plant of The Connecticut Light and Power
Company (CL&P), Public Service Company of New Hampshire (PSNH), Western
Massachusetts Electric Company (WMECO), and North Atlantic Energy Corporation
(NAEC), wholly-owned subsidiaries of NU, is subject to the liens of each
company's respective first mortgage bond indenture.
NAEC's first mortgage bonds are also secured by payments made to NAEC by
PSNH under the terms of the Seabrook Power Contracts.
In addition, CL&P and WMECO have secured $369.3 million of
pollution-control notes with second mortgage liens on Millstone 1, junior to the
liens of their respective first mortgage bond indentures. PSNH's Revolving
Credit Facility has a second lien, junior to the lien of its first mortgage bond
indenture, on all PSNH property located in New Hampshire, which will expire in
April, 1999. At December 31, 1996, there were no borrowings under the Revolving
Credit Facility. For further information on PSNH's Revolving Credit Facility,
see Note 3 "Short-Term Debt."
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA
issued seven series of Pollution Control Revenue Bonds (PCRBs) and loaned the
proceeds to PSNH. At December 31, 1996, $516.5 million of the PCRBs were
outstanding. PSNH's obligation to repay each series of PCRBs is secured by a
series of first mortgage bonds that were issued under its indenture. Each such
series of first mortgage bonds contains terms and provisions with respect to
maturity, principal payment, interest rate and redemption that correspond to
those of the applicable series of PCRBs. For financial reporting purposes, these
bonds would not be considered outstanding unless PSNH fails to meet its
obligations under the PCRBs.
(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.2 percent to 5.5 percent for 1996 and 3.6 percent to 6.1
percent for 1995.
(e) Interest-rate management instruments with financial institutions
effectively fix the interest rate of NAEC's $200 million variable-rate
bank note at 7.07 percent as of February 21, 1997. For further information,
see Note 8, "Interest Rate and Fuel Price Management."
(f) On January 23, 1997, the letter of credit associated with CL&P's $62 million
tax-exempt PCRBs, issued on May 21, 1996, was replaced with a bond insurance and
liquidity facility secured by first mortgage bonds. The bonds were originally
backed by a five-year letter of credit and secured by a second mortgage on
CL&P's interest in Millstone 1.
Northeast Utilities 1996 Annual Report 27
CONSOLIDATED STATEMENTS OF INCOME TAXES
- -----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
The components of the federal and state income tax provisions charged to
operations are:
Current income taxes:
Federal.............................................................. $13,500 $ 53,862 $ 88,483
State................................................................ 10,778 43,900 45,083
- -----------------------------------------------------------------------------------------------------------------------
Total current............................................................ 24,278 97,762 133,566
- -----------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal.............................................................. 70,117 167,091 149,391
State................................................................ (14,793) 7,224 6,988
- -----------------------------------------------------------------------------------------------------------------------
Total deferred........................................................... 55,324 174,315 156,379
- -----------------------------------------------------------------------------------------------------------------------
Investment tax credits, net.............................................. (9,594) (10,107) (9,819)
- -----------------------------------------------------------------------------------------------------------------------
Total income tax expense................................................. $70,008 $261,970 $280,126
=======================================================================================================================
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses........................... $68,261 $261,287 $287,951
Other income taxes................................................... 1,747 683 (7,825)
- -----------------------------------------------------------------------------------------------------------------------
Total income tax expense................................................. $70,008 $261,970 $280,126
=======================================================================================================================
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
Depreciation, leased nuclear fuel, settlement credits
and disposal costs................................................ $18,401 $82,318 $ 72,078
Energy adjustment clauses............................................ (8,268) 26,851 49,017
Nuclear plant deferrals.............................................. (15,549) 2,666 (10,542)
Contractual settlements.............................................. 2,513 (9,496) 109
Bond redemptions..................................................... (4,685) 9,224 8,325
Amortization of New Hampshire regulatory settlement.................. 11,501 11,501 11,501
Deferred tax asset associated with net operating losses.............. 96,756 57,543 23,611
Nuclear compliance reserves.......................................... (26,102) -- --
Demand side management............................................... (14,954) 765 217
Other................................................................ (4,289) (7,057) 2,063
- -----------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net............................................... $55,324 $174,315 $156,379
=======================================================================================================================
A reconciliation between income tax expense and the expected tax
expense at 35 percent of pretax income:
Expected federal income tax.............................................. $35,852 $204,324 $213,515
Tax effect of differences:
Depreciation......................................................... 24,337 25,639 20,003
Deferred nuclear plants return....................................... (3,146) (4,969) (9,480)
Amortization of regulatory assets.................................... 9,630 21,883 23,103
Amortization of PSNH acquisition costs............................... 31,410 31,522 31,508
Seabrook intercompany loss........................................... (7,503) (13,048) (19,637)
Investment tax credit amortization................................... (9,594) (10,107) (9,819)
State income taxes, net of federal benefit........................... (2,610) 33,231 33,847
Sale of Seabrook 2 steam generator................................... (2,516) -- --
Adjustment for prior years' taxes.................................... (962) (20,312) (4,588)
Employee stock ownership plan........................................ (4,007) (2,192) (2,198)
Dividends received deduction......................................... (3,027) (3,936) (3,692)
Other, net........................................................... 2,144 (65) 7,564
- -----------------------------------------------------------------------------------------------------------------------
Total income tax expense................................................. $70,008 $261,970 $280,126
=======================================================================================================================
The accompanying notes are an integral part of these financial statements.
28 Northeast Utilities 1996 Annual Report
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT NORTHEAST UTILITIES
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (the system). The system furnishes retail electric service in
Connecticut, New Hampshire and western Massachusetts through four wholly-owned
subsidiaries: CL&P, PSNH, WMECO, and Holyoke Water Power Company (HWP). A fifth
wholly-owned subsidiary, NAEC, sells all of its capacity to PSNH. In addition to
its retail service, the system furnishes firm and other wholesale electric
services to various municipalities and other utilities. The system serves about
30 percent of New England's electric needs and is one of the 20 largest electric
utility systems in the country as measured by revenues.
Several wholly-owned subsidiaries of NU provide support services for the
system companies and, in some cases, for other New England utilities. Northeast
Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing and other services to the system companies.
North Atlantic Energy Service Corporation (NAESCO) has operational
responsibility for the Seabrook nuclear generating facility. Northeast Nuclear
Energy Company (NNECO) acts as agent for the system companies and other New
England utilities in operating the Millstone nuclear generating facilities.
Three other subsidiaries construct, acquire or lease some of the property and
facilities used by the system companies.
NU has four other subsidiaries, Charter Oak Energy, Inc. (COE), HEC, Inc.
(HEC), Mode 1 Communications, Inc. (Mode 1) and NUSCO Energy Partners, Inc.
(Energy Partners), which engage in a variety of activities. Directly and through
subsidiaries, COE develops and invests in cogeneration, small-power production
and other forms of nonutility generation as permitted under the Public Utility
Regulatory Policy Act, and in exempt wholesale generators and foreign utility
companies as permitted under the Energy Policy Act of 1992 (Energy Act). HEC
provides energy management services for the system's commercial, industrial and
institutional electric customers and others. Both Mode 1 and Energy Partners
were formed in 1996 to develop and invest in telecommunications and
energy-related activities, respectively.
B. PRESENTATION
The consolidated financial statements of the company include the accounts of
all wholly-owned subsidiaries. Significant intercompany transactions have been
eliminated in consolidation.
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 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.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
C. PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as a holding
company under the Public Utility Holding Company Act of 1935 (1935 Act), and it
and its subsidiaries are subject to the provisions of the 1935 Act. Arrangements
among the system companies, outside agencies and other utilities covering
interconnections, interchange of electric power and sales of utility property
are subject to regulation by the Federal Energy Regulatory Commission (FERC)
and/or the SEC. The operating subsidiaries are subject to further regulation for
rates, accounting and other matters by the FERC and/or applicable state
regulatory commissions.
D. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) has issued Statement of
Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which
established accounting standards for evaluating and recording asset impairment.
The company adopted SFAS 121 as of January 1, 1996. See Note 1H, "Summary of
Significant Accounting Policies -- Regulatory Accounting and Assets" for further
information on the regulatory impacts of the company's adoption of SFAS 121.
See Note 6, "Sale of Customer Receivables," and Note 7C, "Commitments and
Contingencies -- Environmental Matters," for information on newly issued
accounting and reporting standards related to those specific areas.
E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock of
four regional nuclear generating companies (Yankee companies). The system's
investments in the Yankee companies are accounted for on the equity basis due
to NU's ability to exercise significant
Northeast Utilities 1996 Annual Report 29
influence over their operating and financial policies. The Yankee companies,
with the system's equity investments and ownership interests are:
- --------------------------------------------------------
(Thousands of Dollars Except for Percentages)
- --------------------------------------------------------
Connecticut Yankee Atomic Power
Company (a) (CY)............... $52,677 49.0%
Yankee Atomic Electric
Company (a) (YAEC)............. 9,161 38.5
Maine Yankee Atomic Power
Company (MY)................... 14,878 20.0
Vermont Yankee Nuclear Power
Corporation (VY)............... 8,624 16.0
- --------------------------------------------------------
Total Equity Investment $85,340
========================================================
(a) YAEC's and CY's nuclear power plants were shut down permanently
on February 26, 1992, and December 4, 1996, respectively.
The electricity produced by MY and VY is committed substantially on the basis of
ownership interests and is billed pursuant to contractual agreements. Under
ownership agreements with the Yankee companies, CL&P, PSNH and WMECO may be
asked to provide direct or indirect financial support for one or more of the
companies. For more information on these agreements, see Note 7F, "Commitments
and Contingencies -- Long-Term Contractual Arrangements." For more information
on the Yankee companies, see Note 2, "Nuclear Decommissioning" and Note 7B
"Commitments and Contingencies -- Nuclear Performance."
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660-megawatt (MW) nuclear generating unit and Millstone 2, a 870-MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. For more
information regarding the Millstone units, see Note 7B, "Commitments and
Contingencies--Nuclear Performance."
Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook 1 to PSNH under two long-term
contracts (the Seabrook Power Contracts).
Plant-in-service and the accumulated provision for depreciation for the
system's share of the three Millstone units and Seabrook 1 are as follows:
- ---------------------------------------------------------
At December 31,
- ---------------------------------------------------------
(Millions of Dollars) 1996 1995
- ---------------------------------------------------------
Plant-in-service
Millstone 1........................ $ 474.7 $ 460.0
Millstone 2........................ 851.8 844.5
Millstone 3........................ 2,402.4 2,399.7
Seabrook 1......................... 892.4 889.0
Accumulated provision for depreciation
Millstone 1........................ $ 196.6 $ 182.9
Millstone 2........................ 275.8 244.3
Millstone 3........................ 633.3 572.3
Seabrook 1......................... 131.7 107.0
- ---------------------------------------------------------
The system's share of Millstone and Seabrook 1 expenses are included in the
corresponding operating expenses on the accompanying Consolidated Statements of
Income.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
approximately $21.2 million, in two companies that transmit electricity imported
from the Hydro-Quebec system in Canada. The two companies own and operate
transmission and terminal facilities, which have the capability of importing up
to 2,000 MW from the Hydro-Quebec system. See Note 7F, "Commitments and
Contingencies--Long-Term Contractual Arrangements," for additional information.
Charter Oak Energy, Inc.: COE owns and/or participates through special
purpose subsidiaries in various nonutility generation projects. These
investments are accounted for on either a cost or equity basis based upon COE's
level of participation. At December 31, 1996, COE's investments totaled
approximately $57.2 million.
F. DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency.
Except for major facilities, depreciation rates are applied to the average
plant-in-service during the period. Major facilities are depreciated from the
time they are placed in service. When plant is retired from service, the
original cost of plant, including costs of removal, less salvage, is charged
to the accumulated provision for depreciation. The depreciation rates for the
several classes of electric plant-in-service are equivalent to a composite rate
of 3.8 percent in 1996 and 1995, and 3.7 percent in 1994. See Note 2, "Nuclear
Decommissioning," for information on nuclear plant decommissioning.
30 Northeast Utilities 1996 Annual Report
NU's nonnuclear generating facilities have limited service lives. Plant
may be retired in place or dismantled based upon expected future needs, the
economics of the closure and environmental concerns. The costs of closure and
removal are incremental costs and, for financial reporting purposes, are
accrued over the life of the asset as part of depreciation. At December 31,
1996, the accumulated provision for depreciation included approximately $77.3
million accrued for the cost of removal, net of salvage for nonnuclear
generation property.
G. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, industrial and commercial customers and limited pilot retail access
programs, utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through a
formal proceeding before the appropriate regulatory commission. At the end of
each accounting period, CL&P, PSNH and WMECO accrue an estimate for the amount
of energy delivered but unbilled.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of the operating companies and the accompanying
consolidated financial statements conform to generally accepted accounting
principles applicable to rate regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." Assuming a cost-of-service based regulatory
structure, regulators may permit incurred costs, normally treated as expenses,
to be deferred and recovered through future revenues. Through their actions,
regulators may also reduce or eliminate the value of an asset, or create a
liability. If any portion of the company's operations were no longer subject to
the provisions of SFAS 71, as a result of a change in the cost-of-service based
regulatory structure or the effects of competition, the company would be
required to write off related regulatory assets and liabilities. The company
continues to believe that its use of regulatory accounting remains appropriate.
SFAS 121 requires the evaluation of long-lived assets, including regulatory
assets, for impairment when certain events occur or when conditions exist that
indicate the carrying amounts of assets may not be recoverable. SFAS 121
requires that any long-lived assets which are no longer probable of recovery
through future revenues be revalued based on estimated future cash flows. If the
revaluation is less than the book value of the asset, an impairment loss would
be charged to earnings. The implementation of SFAS 121 did not have a material
impact on the company's financial position or results of operations as of
December 31, 1996. Management continues to believe that it is probable that the
operating companies will recover their investments in long-lived assets through
future revenues. This conclusion may change in the future as competitive factors
influence wholesale and retail pricing in the electric utility industry or if
the cost-of-service based regulatory structure were to change. The components of
the system companies' regulatory assets are as follows:
- ---------------------------------------------------------
At December 31,
- ---------------------------------------------------------
(Thousands of Dollars) 1996 1995
- ---------------------------------------------------------
Income taxes, net (Note 1I)..... $1,012,343 $1,176,356
Recoverable energy costs,
net (Note 1K)............... 328,863 237,078
Deferred costs--nuclear
plants (Note 1L)............ 185,078 168,600
Unrecovered contractual
obligations (Note 2)........ 435,495 103,475
Deferred demand side
management costs
(Note 1M)................... 90,129 117,070
Cogeneration costs (Note 1N).... 66,205 92,162
Other........................... 103,726 154,218
- ---------------------------------------------------------
$2,221,839 $2,048,959
=========================================================
For more information on the company's regulatory environment and the
potential impacts of restructuring,see Note 7A, "Commitments and Contingencies
- --Restructuring," Note 11 "Subsequent Event" and Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A).
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the
periods in which they affect the determination of taxable income) is accounted
for in accordance with the ratemaking treatment of the applicable regulatory
commissions. The adoption of SFAS 109, "Accounting for Income Taxes," in 1993
increased the company's net deferred tax obligation. As it is probable that the
increase in deferred tax liabilities will be recovered from customers through
rates, NU established a regulatory asset. See Note 11, "Subsequent Event" for
the possible impacts on PSNH and NAEC of the New Hampshire Public Utilities
Commission's (NHPUC) decision related to industry restructuring. See
Consolidated Statements of Income Taxes for the components of income tax
expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved
Northeast Utilities 1996 Annual Report 31
accounting standards, which give rise to the accumulated deferred tax
obligation is as follows:
- ----------------------------------------------------------
At December 31,
- ----------------------------------------------------------
(Thousands of Dollars) 1996 1995
- ----------------------------------------------------------
Accelerated depreciation
and other plant-
related differences......... $1,640,068 $1,703,680
Net operating loss
carryforwards............... (94,149) (191,873)
Regulatory assets--
income tax gross up......... 423,363 477,959
Other........................... 74,841 146,086
- ----------------------------------------------------------
$2,044,123 $2,135,852
==========================================================
At December 31, 1996, PSNH had a net operating loss (NOL) carryforward of
approximately $292 million which can be used against PSNH's federal taxable
income and which, if unused, expires between the years 2000 and 2006. PSNH also
had Investment Tax Credit (ITC) carryforwards of $42 million, which, if unused,
expire between the years 1997 and 2004. For a portion of the carryforward
amounts indicated above, the reorganization of PSNH under Chapter 11 of the
United States Bankruptcy Code limits the annual amount of NOL and ITC
carryforwards that may be used. Approximately $31 million of the NOL and $11
million of the ITC carryforwards are subject to this limitation.
J. UNAMORTIZED PSNH ACQUISITION COSTS
The unamortized PSNH acquisition costs represent the aggregate value placed
by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on
PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets,
plus the $700 million value assigned to Seabrook by the Rate Agreement, as part
of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate
Agreement provides for the recovery, through rates, with a return, of the
unamortized PSNH acquisition costs. The Rate Agreement provides that $425
million of the unamortized PSNH acquisition costs be amortized over the first
seven years after PSNH's May 16, 1991, reorganization from bankruptcy
(Reorganization Date), with the remaining amount to be amortized over the
20-year period after the Reorganization Date. As of December 31, 1996, PSNH has
collected approximately $501.6 million of acquisition costs.
K. RECOVERABLE ENERGY COSTS
Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed
for their proportionate shares of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States Department
of Energy (D&D assessment). The Energy Act requires that regulators treat D&D
assessments as a reasonable and necessary current cost of fuel, to be fully
recovered in rates, like any other fuel cost. CL&P, PSNH, WMECO and NAEC are
currently recovering these costs through rates. As of December 31, 1996, the
company's total D&D deferrals were approximately $62.8 million.
CL&P: During 1996, retail electric rates included a fuel adjustment clause
(FAC) under which fossil fuel prices above or below base-rate levels are charged
or credited to customers. In addition, CL&P also utilized a generation
utilization adjustment clause (GUAC), which deferred the effect on fuel costs
caused by variations from a specified composite nuclear generation capacity
factor embedded in base rates.
At December 31, 1996, CL&P's net recoverable energy costs, excluding
current net recoverable energy costs, were approximately $97.9 million which
includes its share of the D&D assessment. For additional information, see Note
7B, "Commitments and Contingencies -- Nuclear Performance."
On October 8, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order establishing an Energy Adjustment Clause (EAC) effective
January 1, 1997. The EAC will replace CL&P's existing FAC and GUAC. For further
information regarding the EAC, see the MD&A.
PSNH: The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period that began in May, 1991, the retail portion of differences
between the fuel and purchased power costs assumed in the Rate Agreement and
PSNH's actual costs, which include the costs related to the Seabrook Power
Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are
subject to a prudence review by the NHPUC.
The costs associated with purchases from nonutility generators (NUGs) over
the level assumed in the Rate Agreement are deferred and recovered through the
FPPAC. PSNH has been renegotiating the rate orders mandating the purchase of
high-cost NUG power. The NHPUC has approved an amendment to the Rate Agreement
allowing settlement agreements to be implemented with two wood-fired NUGs.
Pursuant to the 1994 settlement agreements, the two NUGs that were settled gave
up their rights to sell their output to PSNH in exchange for lump-sum cash
payments totaling approximately $40 million. The deferred buyout payments are
included as part of PSNH's recoverable energy costs. During the Rate Agreement's
fixed-rate period, all of the savings from the buyout will be used to reduce
PSNH's recoverable energy costs. At the end of the fixed-rate period, 50 percent
of the savings will be used to reduce the recoverable energy costs, with the
remainder reducing current rates.
PSNH has also reached tentative agreements with the six remaining
wood-fired NUGs. These agreements are subject to NHPUC approval. In January,
1997, the NHPUC
32 Northeast Utilities 1996 Annual Report
issued an order approving one of the six NUG settlements. However, the
conditions imposed within the order, along with the uncertainty caused by
industry restructuring proceedings, may impede PSNH's ability to move
forward with the settlements.
At December 31, 1996, PSNH's net recoverable energy costs were
approximately $211.2 million, including purchased power deferrals of $183.4
million and the NUGs deferred buyout payments of $27.6 million.
For further information on recoverable energy costs see the MD&A. See Note
11, "Subsequent Event" for the possible impacts on PSNH and NAEC of the NHPUC's
decision related to industry restructuring.
L. DEFERRED COSTS--NUCLEAR PLANTS
As prescribed by the Rate Agreement, as of May 1, 1996, NAEC phased into
rates 100 percent of the recoverable portion of its investment in Seabrook 1.
This plan is in compliance with SFAS 92, "Regulated Enterprises--Accounting for
Phase-in Plans." From the Acquisition Date through December 31, 1996, NAEC
recorded $185.1 million of deferred return on its investment in Seabrook 1.
In addition, NAEC's utility plant includes $84.1 million of deferred return
that was transferred as part of the Seabrook plant assets to NAEC on the
Acquisition Date. The deferred return, including the portion transferred to
NAEC, will be recovered with carrying charges beginning December 1, 1997, and
will be fully recovered by May, 2001.
See Note 11 "Subsequent Event" for the possible impacts on NAEC of the
NHPUC's decision related to industry restructuring.
M. DEMAND SIDE MANAGEMENT (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). The $90.1 million of costs on CL&P's books as of
December 31, 1996, will be fully recovered by 2000. During November, 1996, CL&P
filed its 1997 DSM program and forecasted CAM for 1997 with the DPUC. The
filing proposes expenditures of $36 million in 1997, with recovery over
1.9 years and a zero CAM rate.
N. CL&P COGENERATION COSTS
Beginning on July 1, 1996, the deferred cogeneration balance of approximately
$86 million is being amortized over a five year period. An additional $9
million of amortization will be applied to the deferred balance in 1997, as
required under a settlement agreement which CL&P reached with the DPUC. CL&P
will continue to apply any savings associated with the renegotiation of a
certain contract with a cogeneration facility to the deferred balance. Under
current expectations, CL&P expects complete amortization of the deferred balance
by December 31, 1998.
O. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO and NAEC must
pay the United States Department of Energy (DOE) for the disposal of spent
nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on
or after April 7, 1983, are billed currently to customers and paid to the DOE on
a quarterly basis. For nuclear fuel used to generate electricity prior to April
7, 1983 (prior-period fuel), payment must be made prior to the first delivery of
spent fuel to the DOE. The DOE was originally scheduled to begin accepting
delivery of spent fuel in 1998. However, delays in identifying a permanent
storage site have continually postponed plans for the DOE's long-term storage
and disposal site. The DOE's current estimate for an available site is 2010.
Until such payment is made, the outstanding balance will continue to accrue
interest at the three-month Treasury Bill Yield Rate. At December 31, 1996,
fees due to the DOE for the disposal of prior-period fuel were approximately
$195 million, including interest costs of $112.9 million. As of December 31,
1996, all fees had been collected through rates.
P. INTEREST RATE AND FUEL PRICE MANAGEMENT
The company utilizes interest-rate and fuel-price management instruments to
manage well defined interest rate and fuel price risks. Amounts receivable or
payable under interest-rate management instruments are accrued and offset
against interest expense. Amounts receivable or payable under fuel-price
management instruments are recognized in income when realized. Any material
unrealized gains or losses on interest rate or fuel-price management
instruments will be deferred until realized. For further information,
see Note 8, "Interest Rate and Fuel Price Management."
Q. CASH AND CASH EQUIVALENTS; SPECIAL DEPOSITS
Cash and cash equivalents includes cash on hand and short-term cash
investments which are highly liquid in nature and have original maturities of
three months or less. Special deposits at December 31, 1996 and 1995 included
approximately $7 million and $71 thousand respectively, in special deposits
that will be used to fund NAEC's share of future Seabrook operational costs.
2. NUCLEAR DECOMMISSIONING
Millstone and Seabrook: The system's nuclear power plants have service lives
that are expected to end during the years 2010 through 2026. Upon retirement,
these units must be decommissioned. Decommissioning studies prepared in 1996
concluded that complete and immediate dismantlement at retirement continues to
be the most viable and economic method of decommissioning the three Millstone
units and Seabrook 1. Decommissioning studies are reviewed and updated
periodically to reflect changes in decommissioning requirements, costs,
technology and inflation.
Northeast Utilities 1996 Annual Report 33
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1996
dollars, is $390.1 million and $344.5 million, respectively. The system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 in year-end 1996 dollars, is $314.7 million and $180.4 million,
respectively. The Millstone units and Seabrook 1 decommissioning costs will be
increased annually by their respective escalation rates. Nuclear decommissioning
costs are accrued over the expected service life of the units and are included
in depreciation expense on the Consolidated Statements of Income. Nuclear
decommissioning costs amounted to $47.8 million in 1996, $38.9 million in 1995,
and $33.5 million in 1994. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on the Consolidated
Balance Sheets. At December 31, 1996, the balance in the accumulated reserve
for decommissioning amounted to $435.7 million.
CL&P and WMECO have established external decommissioning trusts through a
trustee for their portions of the costs of decommissioning Millstone 1, 2, and
3. PSNH makes payments to an independent decommissioning trust for its portion
of the costs of decommissioning Millstone 3. CL&P's and NAEC's portions of the
cost of decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the estimated
decommissioning costs assumes levelized collections for the Millstone units and
escalated collections for Seabrook 1 and after-tax earnings on the Millstone and
Seabrook decommissioning funds of 5.8 percent and 6.5 percent, respectively.
As of December 31, 1996, CL&P, PSNH and WMECO collected, through rates,
$240.8 million, $2.2 million and $53.5 million, respectively, toward the future
decommissioning costs of their share of the Millstone units, of which $264.8
million has been transferred to external decommissioning trusts. As of December
31, 1996, CL&P and NAEC (including payments made prior to the Acquisition Date
by PSNH) paid approximately $2.4 million and $16.6 million, respectively, into
Seabrook 1's decommissioning financing fund. Earnings on the decommissioning
trusts and financing fund increase the decommissioning trust balance and the
accumulated reserve for decommissioning. Unrealized gains and losses associated
with the decommissioning trusts and financing fund also impact the balance of
the trusts and the accumulated reserve for decommissioning.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. CL&P, PSNH and WMECO attempt to recover sufficient
amounts through their allowed rates to cover their expected decommissioning
costs. Only the portion of currently estimated total decommissioning costs that
has been accepted by regulatory agencies is reflected in rates of the system
companies. Based on present estimates and assuming its nuclear units operate to
the end of their respective license periods, the system expects that the
decommissioning trusts and financing fund will be substantially funded when the
units are retired from service.
MY and VY: Each Yankee company owns a single nuclear generating unit. MY
and VY have service lives that are expected to end in 2008 and 2012,
respectively. The system's ownership share of estimated costs, in year-end 1996
dollars, of decommissioning the units owned and operated by MY and VY is $73.9
million and $58.5 million, respectively. Under the terms of the contracts with
the Yankee companies, the shareholders-sponsors are responsible for their
proportionate share of the operating costs of each unit, including
decommissioning. The nuclear decommissioning costs of the Yankee companies are
included as part of the cost of power purchased by CL&P, PSNH and WMECO.
CY and YAEC: On December 4, 1996, the board of directors of CY voted
unanimously to cease permanently the production of power at its nuclear plant.
The system companies relied on CY for approximately three percent of their
capacity.
CY has undertaken a number of regulatory filings intended to implement the
decommissioning and the recovery of remaining assets of CY. During late
December, 1996, CY filed an amendment to its power contracts to clarify the
obligations of its purchasing utilities following the decision to cease power
production. At December 31, 1996, the estimated obligation, including
decommissioning, amounted to $762.8 million of which NU's share was
approximately $373.8 million.
YAEC is in the process of decommissioning its nuclear facility. At
December 31, 1996, the estimated remaining costs, including decommissioning,
amounted to $173.3 million of which the NU system's share was approximately
$66.7 million.
Management expects that CL&P, PSNH and WMECO will each continue to be
allowed to recover these costs from their customers. Accordingly, NU has
recognized these costs as regulatory assets, with corresponding obligations, on
its Consolidated Balance Sheets.
Proposed Accounting: The staff of the SEC has questioned certain of the
current accounting practices of the electric utility industry, including the
company, regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating units in the financial statements.
In response to these questions, FASB agreed to review the accounting for removal
costs, including decommissioning, and issued a proposed statement entitled
"Accounting for Liabilities Related to Closure or Removal of Long-Lived
Assets," in February, 1996. If current electric utility industry accounting
practices for
34 Northeast Utilities 1996 Annual Report
decommissioning are changed in accordance with the proposed statement: (1)
annual provisions for decommissioning could increase, (2) the estimated cost
for decommissioning could be recorded as a liability with an offset to plant
rather than as part of accumulated depreciation, and (3) trust fund income
from the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense.
3. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by the system's
utility companies is subject to periodic approval by either the SEC under the
1935 Act or by their respective state regulators. In addition, the charters of
CL&P and WMECO contain provisions restricting the amount of short-term
borrowings. Under the SEC and/or charter restrictions, CL&P, WMECO and NAEC were
authorized, as of January 1, 1997, to incur short-term borrowings up to a
maximum of $375 million, $150 million and $50 million, respectively. PSNH was
authorized, under a waiver from the NHPUC, to incur short-term borrowings of up
to a maximum of $225 million. This limit will be reduced to $125 million
effective May, 1997.
Credit Agreements: In November, 1996, NU entered into a three-year
revolving credit agreement (New Credit Agreement) with a group of 12 banks.
Under the terms of the New Credit Agreement, NU, CL&P and WMECO will be able to
borrow up to $150 million, $313.75 million, and $150 million, respectively. The
overall limit for all of the borrowing system companies under the entire New
Credit Agreement is $313.75 million. The system companies are obligated to pay a
facility fee of .30 percent per annum of each bank's total commitment under the
new credit facility which will expire November 21, 1999. At December 31, 1996,
there were $27.5 million in borrowings under this agreement.
Access to the New Credit Agreement is contingent upon certain financial
tests being met. NU is currently renegotiating these restrictions so that the
financial impacts of the current nuclear outages do not impact the ability to
access these facilities. Through February 21, 1997, CL&P and WMECO have
satisfied all financial covenants required under their respective borrowing
facilities, but NU needed and obtained a limited waiver of an interest coverage
covenant that had to be satisfied for NU to borrow under the New Credit
Agreement. NU, CL&P and WMECO are currently maintaining their access to the New
Credit Agreement under an interim written arrangement, under which NU agreed not
to borrow more than $27.5 million against the facility.
In addition to the New Credit Agreement, NU, CL&P, WMECO, HWP, NNECO and
The Rocky River Realty Company (RRR) have various revolving credit lines through
separate bilateral credit agreements. Under the remaining three-year portion of
the facility, four banks maintain commitments to the respective system companies
totaling $56.25 million. NU, CL&P and WMECO may borrow up to the aggregate
$56.25 million, whereas HWP, NNECO and RRR may borrow up to their short-term
debt limit of $5 million, $50 million and $22 million, respectively. Under the
terms of the agreement, the system companies are obligated to pay a facility fee
of .15 percent per annum of each bank's total commitment under the
three-year portion of the facility. These commitments will expire December 3,
1998. At December 31, 1996 and 1995, there were $11.3 million and $42.5 million
in borrowings, respectively, under the facility.
On April 30, 1996, PSNH increased its $125 million revolving-credit
agreement to $225 million with approval from the NHPUC. The agreement, which was
scheduled to expire in May, 1996, has been extended so that $100 million of the
agreement will expire in April, 1997, and the remaining $125 million will expire
in April, 1999. The revolving credit agreement is with a group of 16 banks. PSNH
is obligated to pay a facility fee of .25 percent per annum on the three-year
commitment of $125 million and .20 percent per annum on the one-year commitment
of $100 million. At December 31, 1996 and 1995, there were no borrowings under
the facility.
Under the credit facilities discussed above, the system companies may
borrow funds on a short-term revolving basis under the remaining portion of
their agreement, using either fixed-rate loans or standby loans. Fixed
rates are set using competitive bidding. Standby loans are based upon several
alternative variable rates. The weighted average annual interest rate on the
system companies' notes payable to banks outstanding on December 31, 1996 and
1995 was 8.3 percent and 6.0 percent, respectively. Maturities of short-term
debt obligations were for periods of three months or less. For further
information on short-term debt see the MD&A.
4. LEASES
CL&P and WMECO finance up to $450 million of nuclear fuel for Millstone 1
and 2 and their respective shares of the nuclear fuel for Millstone 3 under the
Niantic Bay Fuel Trust (NBFT) capital lease agreement. CL&P and WMECO make
quarterly lease payments for the cost of nuclear fuel consumed in the reactors,
based on a units-of-production method at rates which reflect estimated
kilowatt-hours of energy provided, plus financing costs associated with
the fuel in the reactors. Upon permanent discharge from the reactors, ownership
of the nuclear fuel transfers to CL&P and WMECO. The system companies have also
entered into lease agreements, some of which are capital leases, for the use
of data processing and office equipment, vehicles, gas turbines, nuclear
control room sim-
Northeast Utilities 1996 Annual Report 35
ulators and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $28,187,000
in 1996, $75,894,000 in 1995 and $81,952,000 in 1994. Interest included in
capital lease rental payments was $14,112,000 in 1996, $15,025,000 in 1995 and
$14,881,000 in 1994. Operating lease rental payments charged to expense
were $18,316,000 in 1996, $20,859,000 in 1995 and $20,118,000 in 1994.
Substantially all of the capital lease rental payments were made pursuant
to the nuclear fuel lease agreement. Future minimum lease payments under the
nuclear fuel capital lease cannot be reasonably estimated on an annual basis due
to variations in the usage of nuclear fuel. Future minimum rental payments,
excluding annual nuclear fuel lease payments and executory costs, such as
property taxes, state use taxes, insurance and maintenance, under long-term
noncancelable leases, as of December 31, 1996, are:
- -------------------------------------------------------------------------------
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Capital Operating
Year Leases Leases
- --------------------------------------------------------------------------------
1997................................ $ 8,800 $29,200
1998................................ 8,600 21,600
1999................................ 8,300 18,500
2000................................ 7,700 16,700
2001................................ 5,700 13,000
After 2001.......................... 67,100 23,900
- --------------------------------------------------------------------------------
Future minimum
lease payments...................... 106,200 122,900
- ----------------------------------------------------------------------=========
Less amount
representing interest........... 68,800
Present value of future
minimum lease payments
for other than nuclear fuel..... 37,400
Present value of future nuclear
fuel lease payments............. 168,800
- --------------------------------------------------------------------------------
Total............................... $206,200
================================================================================
5. EMPLOYEE BENEFITS
A. PENSION BENEFITS
The system's subsidiaries participate in a uniform noncontributory defined
benefit retirement plan covering all regular system employees. Benefits are
based on years of service and the employees' highest eligible compensation
during 60 consecutive months of employment. Total pension cost, part of which
was charged to utility plant, approximated $9.1 million in 1996, $0.4 million
in 1995 and $7.7 million in 1994. Pension costs for 1996, 1995 and 1994
included approximately $7.8 million, $6.8 million and $9.2 million,
respectively, related to workforce reduction programs.
Currently, the subsidiaries fund annually an amount at least equal to that
which will satisfy the requirements of the Employee Retirement Income Security
Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets. Pension assets are invested primarily
in domestic and international equity securities and bonds.
The components of net pension cost are:
- --------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995 1994
- --------------------------------------------------------------------------------
Service cost................... $ 43,206 $ 35,771 $ 39,317
Interest cost.................. 94,722 89,351 84,284
Return on
plan assets................ (232,604) (310,997) 2,268
Net amortization............... 103,745 186,310 (118,188)
- --------------------------------------------------------------------------------
Net pension cost............... $ 9,069 $ 435 $ 7,681
================================================================================
For calculating pension costs, the following assumptions were used:
- --------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Discount rate.................. 7.50% 8.25% 7.75%
Expected long-term
rate of return............. 8.75 8.50 8.50
Compensation/
progression rate........... 4.75 5.00 4.75
- --------------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995
- --------------------------------------------------------------------------------
Accumulated benefit obligation,
including vested benefits at
December 31, 1996 and 1995
of $943,696,000 and
$913,269,000, respectively..... $1,037,908 $ 998,614
================================================================================
Projected benefit obligation....... $1,321,146 $1,278,434
Market value of plan assets........ 1,660,404 1,503,597
- --------------------------------------------------------------------------------
Market value in excess of
projected benefit obligation... 339,258 225,163
Unrecognized transition amount..... (12,105) (13,648)
Unrecognized prior service costs... 31,802 9,710
Unrecognized net gain.............. (458,654) (311,855)
- --------------------------------------------------------------------------------
Accrued pension liability.......... $ (99,699) $ (90,630)
================================================================================
36 Northeast Utilities 1996 Annual Report
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
Discount rate..................................... 7.75% 7.50%
Compensation/progression rate..................... 4.75 4.75
- --------------------------------------------------------------------------------
B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The system's subsidiaries provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees (referred to as SFAS 106 benefits). These benefits are
available for employees retiring from the system who have met specified service
requirements. For current employees and certain retirees, the total SFAS 106
benefit is limited to two times the 1993 per-retiree health care cost. The SFAS
106 obligation has been calculated based on this assumption. Total SFAS 106
benefits, part of which were deferred or charged to utility plant, approximated
$39.2 million in 1996, $44.1 million in 1995 and $47.6 million in 1994. NU's
subsidiaries are funding SFAS 106 postretirement costs through external trusts.
The subsidiaries are funding, on an annual basis, amounts that have been
rate-recovered and which also are tax deductible under the Internal Revenue
Code. The trust assets are invested primarily in equity securities and bonds.
The components of health care and life insurance costs are:
- --------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995 1994
- --------------------------------------------------------------------------------
Service cost....................... $ 7,457 $ 7,137 $ 7,418
Interest cost...................... 22,698 24,693 25,319
Return on plan assets.............. (9,330) (7,812) 236
Amortization of
unrecognized
transition obligation.......... 15,134 15,134 15,134
Other amortization, net............ 3,194 4,924 (553)
- --------------------------------------------------------------------------------
Net health care and
life insurance costs........... $39,153 $44,076 $47,554
================================================================================
For calculating SFAS 106 benefit costs, the following assumptions were
used:
- --------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Discount rate ..................... 7.50% 8.00% 7.75%
Long-term rate of return--
Health assets, net of tax...... 5.25 5.00 5.00
Life assets.................... 8.75 8.50 8.50
- -------------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995
- --------------------------------------------------------------------------------
Accumulated postretirement
benefit obligation of:
Retirees............................. $ 226,774 $253,993
Fully eligible active employees...... 323 354
Active employees
not eligible to retire........... 78,985 84,056
- --------------------------------------------------------------------------------
Total accumulated postretirement
benefit obligation................... 306,082 338,403
Market value of plan assets.............. 105,086 56,791
- --------------------------------------------------------------------------------
Accumulated postretirement
benefit obligation in
excess of plan assets................ (200,996) (281,612)
Unrecognized transition amount........... 242,149 257,283
Unrecognized net (gain) loss............. (41,457) 96
- --------------------------------------------------------------------------------
Accrued postretirement
benefit liability.................... $ (304) $(24,233)
================================================================================
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
Discount rate ........................... 7.75% 7.50%
Health care cost trend rate (a).......... 7.23 8.40
- --------------------------------------------------------------------------------
(a) The annual growth in per capita cost of covered health care benefits
was assumed to decrease to 4.91 percent by 2001.
The effect of increasing the assumed health care cost trend rate by one
percentage point in each year would increase the accumulated postretirement
benefit obligation as of December 31, 1996, by $16.6 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for the year then ended by $1.5 million. The
trust holding the health plan assets is subject to federal income taxes at a
39.6 percent tax rate.
CL&P and WMECO are currently recovering SFAS 106 costs. PSNH is currently
recovering SFAS 106 costs, including amounts previously deferred.
C. 401(K) SAVINGS PLAN
NU maintains a 401(k) Savings Plan for substantially all system employees.
This savings plan provides for employee contributions up to specified
limits. The company matches employee contributions up to a maximum of three
percent of eligible compensation. The matching contributions for the company
were $11.8 million for 1996 and $12.1 million per year for 1995 and 1994.
Northeast Utilities 1996 Annual Report 37
D. EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
NU maintains an ESOP for purposes of allocating shares to employees
participating in the system's 401(k) plan. Under this arrangement, NU issued
unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of
which were lent to the ESOP trust for purchase of approximately 10.8 million
newly issued NU common shares. NU makes principal and interest payments on the
ESOP notes at the same rate that ESOP shares are allocated to employees.
In 1996 and 1995, the ESOP trust issued approximately 953,000 and 655,000
of NU common shares, respectively, totaling approximately $22.1 million and
$15.2 million, respectively. These costs were charged to the 401(k) plan. As of
December 31, 1996 and 1995, the total allocated ESOP shares were 3,192,620 and
2,239,666, respectively, and total unallocated ESOP shares were 7,607,565 and
8,560,519, respectively. The fair market value of unallocated ESOP shares as of
December 31, 1996 and 1995 was approximately $99.8 million and $207.6 million,
respectively.
During 1996, the ESOP trust used approximately $17.0 million in dividends
paid on NU common shares and $31.5 million in contributions from NU to meet
principal and interest payments on ESOP notes.
6. SALE OF CUSTOMER RECEIVABLES
CL&P and WMECO have entered into agreements to sell up to $200 million and $40
million, respectively, of eligible customer billed and unbilled accounts
receivable. The eligible receivables are sold with limited recourse. The
agreements were entered into during July, 1996, and September, 1996, for CL&P
and WMECO, respectively, and will expire in five years. The companies have
retained collection responsibilities for receivables which have been sold under
the agreements. For the WMECO agreement, as collections reduce previously sold
undivided interests, new receivables would routinely be sold. Both agreements
provide for a loss reserve determined by a formula which reflects credit
exposure. As of February 21, 1997, CL&P and WMECO have sold approximately $10
million and $15 million, respectively, of their accounts receivable under these
agreements.
The FASB issued SFAS 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," in June, 1996. SFAS 125
became effective on January 1, 1997, and establishes, in part, criteria for
concluding whether a transfer of financial assets in exchange for consideration
should be accounted for as a sale or as a secured borrowing.
CL&P and WMECO are in the process of restructuring their receivables
programs to comply with the requirements of SFAS 125. Management believes that
the adoption of SFAS 125 will not have a material impact on the companies'
financial position or results of operations.
7. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING
New Hampshire: The 1996 restructuring legislation that the NHPUC is charged with
implementing provides that the NHPUC may not adopt a restructuring plan that
imposes a severe financial hardship on a utility. NU management has testified
that the implementation of certain methodologies would result in a significant
loss to PSNH. If these losses were to result in the triggering of acceleration
rights that PSNH's creditors have and, if any single significant creditor
demanded payment because of the triggering of acceleration rights, all other
major creditors would immediately follow and PSNH and NAEC bankruptcy filings
would be unavoidable.
Management believes that PSNH is entitled to full recovery of its prudently
incurred costs, including regulatory assets and stranded costs. It bases this
belief both on the general nature of public utility industry cost-of-service
based regulation and the specific circumstances of the resolution of PSNH's
previous bankruptcy proceedings and its acquisition by NU, including the
recoveries provided by the Rate Agreement and related agreements.
See Note 11 "Subsequent Event" for the possible impacts on PSNH and NAEC
of the NHPUC's decision related to industry restructuring.
Connecticut/Massachusetts: Although CL&P, WMECO and HWP continue to operate
under cost-of-service based regulation, various restructuring initiatives in
each of the companies' jurisdictions have created uncertainty with respect to
future rates and the recovery of strandable investments and certain future costs
such as purchase power obligations. Strandable investments are regulatory assets
or other assets that would not be economical in a competitive environment.
Management is unable to predict the ultimate outcome of restructuring
initiatives; however, it believes that it is entitled to full recovery of its
prudently incurred costs, including regulatory assets and strandable investments
based on the general nature of public utility cost of service regulation. For
further information on restructuring, see the MD&A.
B. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2, and
3 have been out of service since November 4, 1995, February 21, 1996 and March
30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC)
watch list. The company has restructured its nuclear organization and is
currently implementing comprehensive plans to restart the units.
According to the plans, each unit's recovery team will be working towards
restart of its respective unit on a parallel basis with the other two units.
Based upon management's current plans, it is estimated that one of the units
will be ready for restart in the third quarter of 1997 with
38 Northeast Utilities 1996 Annual Report
the other two units being ready for restart during the fourth quarter of 1997
and the first quarter of 1998, respectively.
The NRC has also issued two orders affecting the Millstone units on the
subjects of independent corrective action verification and employee concerns.
Independent third parties have been retained by NNECO and area waiting NRC
approval.
Prior to and following notification to the NRC that the units are ready to
resume operations, the NRC staff will conduct extensive reviews and inspections
and, prior to such notification, independent corrective action verification
teams also will inspect each unit. The units will not be allowed to restart
without an affirmative vote of the NRC commissioners following completion of
these reviews and inspections. Management cannot estimate when the NRC will
allow any of the units to restart, but hopes to have at least one unit operating
in the second half of 1997.
The company is currently incurring substantial costs, including replacement
power costs, while the three Millstone units are not operating. Management does
not expect to recover a substantial portion of these costs. NU expensed
approximately $179 million of incremental nonfuel nuclear operation and
maintenance costs (O&M) in 1996, including a reserve of $63 million against 1997
expenditures. Management estimates NU will expense approximately $386 million of
nonfuel nuclear O&M costs in 1997.
As discussed above, management cannot predict when the NRC will allow any
of the Millstone units to return to service and thus cannot estimate the total
replacement power costs the companies will ultimately incur. At December 31,
1996, NU had expensed incremental replacement power costs associated with the
Millstone outages of approximately $260 million. Replacement power costs for NU
system companies are expected to average approximately $35 million per month
during 1997 while all three Millstone units remain out of service. Management
believes the system has sufficient resources to fund the restoration of the
Millstone units to service under its present timetable.
MY: The system companies rely on MY for approximately two percent of their
capacity. The MY nuclear generating plant has been limited to operating at 90
percent of capacity since early 1996, pending the resolution of issues related
to investigations initiated by the NRC, and on December 6, 1996, was taken off
line to resolve cable-separation and associated issues. The NRC has notified MY
that the NRC staff has placed the MY plant on its watch list. Returning the
plant to service will require NRC approval. Management cannot predict when MY's
plant will be allowed to return to service and expects there will be substantial
costs associated with the NRC's action that cannot be accurately estimated at
this time.
Shareholder Litigation: Several class-action lawsuits have been filed
against the company and certain present and former officers and employees of NU
in connection with the company's nuclear operations. Management cannot estimate
the potential outcome of these suits, but believes these suits are without merit
and intends to defend itself vigorously in all these actions.
Potential Litigation: The non-NU owners of Millstone 3 have been paying
their share of the monthly costs for Millstone 3 since the unit went out of
service in March, 1996, but have reserved their rights to contest whether the NU
system companies have any responsibility for the additional costs the non-NU
owners have borne as a result of the current outage. No formal claims have been
made, but management believes that it is possible that some or all of the non-NU
owners will assert liability on the part of the NU system. CL&P and WMECO,
through NNECO as agent, operate Millstone 3 at cost, and without profit, under a
Sharing Agreement that obligates them to utilize good utility operating practice
and requires the joint owners to share the risk of employee negligence and other
risks pro rata in accordance with their ownership shares. The Sharing Agreement
provides that CL&P and WMECO would only be liable for damages to the non-NU
owners for a deliberate breach of the Sharing Agreement. At December 31, 1996,
the costs related to this potential litigation were estimated to be $13 million
for incremental O&M costs and between $40 million and $50 million for
replacement power costs. These costs are likely to increase as long as Millstone
3 remains out of service. NU will vigorously contest such suits if they are
brought.
C. ENVIRONMENTAL MATTERS
The system is subject to regulation by federal, state and local authorities with
respect to air and water quality, the handling and disposal of toxic substances
and hazardous and solid wastes, and the handling and use of chemical products.
The system has an active environmental auditing and training program and
believes that it is in substantial compliance with current environmental laws
and regulations.
Environmental requirements could hinder the construction of new generating
units, transmission and distribution lines, substations and other facilities.
Changing environmental requirements could also require extensive and costly
modifications to the system's existing generating units and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the system may incur significant additional environmental costs, greater
than amounts included in cost of removal and other reserves, in connection with
the generation and transmission of electricity and the storage, transportation
and disposal of by-products and wastes. The system may also encounter
significantly increased costs to remedy the environmental effects of prior waste
handling activities. The cumulative long-term cost impact of increasingly
stringent environmental requirements cannot accurately be estimated.
Northeast Utilities 1996 Annual Report 39
The system has recorded a liability based upon currently available
information for what it believes are its estimated environmental remediation
costs that the system's subsidiaries expect to incur for waste disposal sites.
In most cases, additional future environmental cleanup costs are not reasonably
estimable due to a number of factors, including the unknown magnitude of
possible contamination, the appropriate remediation methods, the possible
effects of future legislation or regulation and the possible effects of
technological changes. At December 31, 1996, the net liability recorded by the
system for its estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to approximately
$13 million, which management has determined to be the most probable amount
within the range of $13 million to $30 million.
The system cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against it.
However, considering known facts, existing laws and regulatory practices,
management does not believe the matters disclosed above will have a material
effect on the system's financial position or future results of operations.
On October 10, 1996, the American Institute of Certified Public Accountants
issued Statement of Position 96-1, "Environmental Remediation Liabilities"
(SOP). The principal objective of the SOP is to improve the manner in which
existing authoritative accounting literature is applied by entities to specific
situations of recognizing, measuring and disclosing environmental remediation
liabilities. The SOP became effective January 1, 1997. The company believes that
the adoption of this SOP will not have a material impact on the company's
financial position or results of operations.
D. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities covered by the federal government's third-party liability
indemnification program, the system could be assessed in proportion to its
ownership interest in each nuclear unit up to $75.5 million, not to exceed $10.0
million per nuclear unit in any one year. Based on its ownership interests in
Millstone 1, 2, and 3 and in Seabrook 1, the system's maximum liability,
including any additional potential assessments, would be $244.2 million per
incident. In addition, through power purchase contracts with MY, VY and CY, the
system would be responsible for up to an additional $67.4 million per incident.
Payments for the system's ownership interest in nuclear generating facilities
would be limited to a maximum of $39.3 million per incident per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from insured
occurrences. The system is subject to retroactive assessments if losses exceed
the accumulated funds available to the insurer. The maximum potential assessment
against the system with respect to losses arising during the current policy year
is approximately $13.3 million under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and the excess
cost of repair, replacement, or decontamination or premature decommissioning of
utility property resulting from insured occurrences. The system is subject to
retroactive assessments if losses exceed the accumulated funds available to the
insurer. The maximum potential assessments against the system with respect to
losses arising during current policy years are approximately $12.9 million under
the replacement power policies and $32.6 million under the excess property
damage, decontamination and decommissioning policies. The cost of a nuclear
incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry basis
for coverage of worker claims. All participating reactor operators insured under
this coverage are subject to retrospective assessments of $3 million per
reactor. The maximum potential assessment against the system with respect to
losses arising during the current policy period is approximately $12.9 million.
E. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision by
management. The system companies currently forecast construction expenditures of
approximately $1.3 billion for the years 1997-2001, including $280 million for
1997. In addition, the system companies estimate that nuclear fuel requirements,
including nuclear fuel financed through the NBFT, will be approximately $356.1
million for the years 1997-2001, including $30.3 million for 1997. See Note 4,
"Leases," for additional information about the financing of nuclear fuel.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: The NU system relies on MY and VY for approximately three
percent of its capacity under long-term contracts. Under the terms of their
agreements, the system companies pay their ownership (or entitlement) shares
of costs, which include depreciation, O&M expenses, taxes, the estimated cost
of decommissioning and a return on invested capital. These costs are recorded
as purchased power expense and recovered through the companies' rates. The
total cost of purchases under contracts with the Yankee companies, excluding
YAEC, amounted to $149.7 million in 1996, $161.1 million in 1995, and $154.3
million in 1994. See Note 1E, "Summary of Significant
40 Northeast Utilities 1996 Annual Report
Accounting Policies--Investments and Jointly Owned Electric Utility Plant,"
and Note 2, "Nuclear Decommissioning," for more information on the Yankee
companies.
Nonutility Generators: CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from NUGs. These
arrangements have terms from 10 to 30 years, currently expiring in the years
1998 through 2027, and require the companies to purchase energy at specified
prices or formula rates. For the 12 months ended December 31, 1996,
approximately 13 percent of system electricity requirements was met by NUGs. The
total cost of purchases under these arrangements amounted to $448.1 million in
1996, $440.4 million in 1995, and $435.0 million in 1994. These costs are
eventually recovered through the companies' rates.
New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement
to purchase the capacity and energy of the New Hampshire Electric Cooperative,
Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for
a ten-year period, which began on July 1, 1990. The total cost of purchases
under this agreement was $14.6 million in 1996, $15.8 million in 1995, and $14.6
million in 1994. A portion of these costs is collected currently through the
FPPAC and the remaining costs are deferred for future collection in accordance
with the Rate Agreement. In connection with the agreement, NHEC agreed to
continue as a firm-requirements customer of PSNH for 15 years.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and
HWP have entered into agreements to support transmission and terminal facilities
to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO
and HWP, are obligated to pay, over a 30-year period ending in 2020, their
proportionate shares of the annual O&M and capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of the system's
significant long-term contractual arrangements are as follows:
- --------------------------------------------------------------------------------
(Millions of Dollars) 1997 1998 1999 2000 2001
- --------------------------------------------------------------------------------
MY and VY.................... $66.9 $56.9 $66.7 $66.3 $59.8
Nonutility
Generators............... 441.0 453.0 469.0 475.0 485.0
NHEC......................... 22.7 29.8 29.9 14.6 --
Hydro-Quebec................. 34.1 33.1 32.1 31.4 30.4
- --------------------------------------------------------------------------------
For additional information regarding the recovery of purchased power costs, see
Note 1K, "Summary of Significant Accounting Policies--Recoverable Energy
Costs--PSNH."
G. THE ROCKY RIVER REALTY COMPANY -- OBLIGATIONS
RRR provides real estate support services which includes the leasing of property
and facilities used by system companies. RRR is the obligor under financing
arrangements for certain system facilities. Under those financing arrangements,
the holders of notes for $38.4 million would be entitled to request that RRR
repurchase the notes if any major subsidiary of NU (as defined by the notes) has
debt ratings below investment grade as of any year-end during the term of the
financing. The notes are secured by real estate leases between RRR as lessor and
NUSCO as lessee. The leases provide for the acceleration of rent equal to RRR's
note obligations if RRR is unable to repay the obligation. The operating
companies, primarily CL&P, WMECO and PSNH may be billed by NUSCO for their
proportionate share of the accelerated lease obligations if the rateholders
request repurchase of the notes. NU has guaranteed the notes.
Based on the terms of the notes, PSNH and NAEC will be defined as major
subsidiaries of NU, effective as of the end of 1996, and both PSNH's and NAEC's
debt ratings were below investment grade. Accordingly, under the terms of the
RRR financing arrangements, the holders may elect to require RRR to repurchase
the notes at par. If the noteholders make such an election, RRR has the option
to refinance the notes with an institutional investor. However, it is possible
that RRR may be required to repurchase the notes. Therefore, the RRR notes have
been classified as a current obligation. As of February 21, 1997, the holders
had not made such an election. RRR plans to engage in discussions with the
noteholders regarding this issue. Management does not expect the resolution to
have a material impact on its financial condition.
8. INTEREST RATE AND FUEL PRICE MANAGEMENT
The company utilizes various financial instruments to manage well-defined
interest rate and fuel price risks. The company does not use these
instruments for trading purposes.
Fuel Price Management: CL&P uses fuel-price management instruments with
financial institutions to hedge against some of the fuel-price risk created by
long-term negotiated energy contracts. These agreements minimize exposure
associated with rising fuel prices and effectively fix a portion of CL&P's cost
of fuel for these negotiated energy contracts. Under the agreements, CL&P
exchanges monthly payments based on the differential between a fixed and
variable price for the associated fuel. As of December 31, 1996, CL&P had
outstanding agreements with a total notional value of approximately $228.8
million, and a positive mark-to-market position of approximately $1.1 million.
Interest Rate Management: NAEC uses interest-rate management instruments
with financial institutions to hedge against interest-rate risk associated with
its $200
Northeast Utilities 1996 Annual Report 41
million variable rate bank note. Interest-rate management instruments minimize
exposure associated with rising interest rates, and effectively fix the interest
rate for this borrowing arrangement. Under the agreements, NAEC exchanges
quarterly payments based on a differential between a fixed contractual interest
rate and the three-month LIBOR rate at a given time. As of December 31, 1996,
NAEC had outstanding agreements with a total notional value of approximately
$200 million and a positive mark-to-market position of approximately $1.6
million.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "BBB+" or better by Standard & Poor's
rating group. CL&P and NAEC will be exposed to credit risk on fuel-price
management instruments and interest-rate management instruments if the
counterparties fail to perform their obligations. However, management
anticipates that the counterparties will be able to fully satisfy their
obligations under the agreements.
9. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
In January, 1995, CL&P Capital LP (CL&P LP is a subsidiary of CL&P) issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million
capital contribution, back to CL&P in the form of an unsecured debenture. CL&P
consolidates CL&P LP for financial reporting purposes. Upon consolidation,
the unsecured debenture is eliminated, and the MIPS securities are accounted for
as minority interests.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash, special deposits and nuclear decommissioning trusts: The carrying
amounts approximate fair value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity
Securities," requires investments in debt and equity securities to be presented
at fair value. As a result of this requirement, the investments held in the
system companies' nuclear decommissioning trusts were adjusted to market by
approximately $31.4 million as of December 31, 1996, and by approximately $19.3
million as of December 31, 1995, with corresponding offsets to the accumulated
provision for depreciation. The amounts adjusted in 1996 and in 1995 represent
cumulative gross unrealized holding gains. The cumulative gross unrealized
holding losses were immaterial for both 1996 and 1995.
Preferred stock and long-term debt: The fair value of the system's
fixed-rate securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair value
equal to their carrying value. The carrying amounts of the system's financial
instruments and the estimated fair values are as follows:
- --------------------------------------------------------------------------------
At December 31, 1996
- --------------------------------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- --------------------------------------------------------------------------------
Preferred stock not subject to
mandatory redemption.................. $136,200 $127,045
Preferred stock subject to
mandatory redemption.................. 301,000 264,304
Long-term debt--
First Mortgage Bonds.................. 2,196,788 2,163,031
Other long-term debt.................. 1,718,859 1,741,818
MIPS...................................... 100,000 108,520
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
At December 31, 1995
- --------------------------------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- --------------------------------------------------------------------------------
Preferred stock not subject to
mandatory redemption.................. $169,700 $ 136,148
Preferred stock subject to
mandatory redemption.................. 304,000 313,910
Long-term debt--
First Mortgage Bonds.................. 2,234,245 2,283,920
Other long-term debt.................. 1,697,529 1,733,816
MIPS...................................... 100,000 108,520
- --------------------------------------------------------------------------------
The fair values shown above have been reported to meet disclosure requirements
and do not purport to represent the amounts at which those obligations would be
settled.
11. SUBSEQUENT EVENT
New Hampshire Restructuring: On February 28, 1997, the NHPUC issued its decision
related to restructuring the state's electric utility industry and setting
interim stranded cost charges for PSNH pursuant to legislation enacted in New
Hampshire in 1996.
In the decision, the NHPUC announced a departure from cost-based ratemaking
and instead adopted a market-priced approach to ratemaking and stranded cost
recovery as advocated by the NHPUC's consultants. Accordingly, unless the
litigation described below results in a stay, or necessary modifications to the
final plan are made that leads management to conclude that the ratemaking
approach utilized in the NHPUC's restructuring decision will not go into effect,
PSNH will be required to discontinue accounting under SFAS 71. That would result
in PSNH writing off from its balance sheet, as early as the quarter ending March
31, 1997, substantially all of its regulatory
42 Northeast Utilities 1996 Annual Report
assets. The amount of the potential write-off which is triggered by the order is
currently estimated at over $400 million, after taxes. PSNH does not believe
that under the decision, it would be required to recognize any additional loss
resulting from the impairment of the value of its other long-lived assets under
the provisions of SFAS 121.
The decision also contains rulings on numerous other issues that may have a
substantial effect on the operations of PSNH. Included among these rulings are
assertions that the Rate Agreement by and between PSNH's parent company, NU and
the state of New Hampshire, which was an integral part of NU's acquisition of
PSNH in 1992, is not binding on the state; the requirement that PSNH divest
within two years from the inception of competition all of its owned generation
and all of its wholesale power contracts (including its contracts with NAEC for
Seabrook output); a prohibition on the remaining distribution company and its
affiliates from engaging in retail marketing or load aggregation services in New
Hampshire; and a mandate for the filing of tariffs with the FERC for the
provision of unbundled retail transmission service.
On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary
restraining order, preliminary and permanent injunctive relief, and for
declaratory judgment in the Federal District Court for New Hampshire. The case
was subsequently transferred to Rhode Island. On March 10, 1997, the Chief Judge
of the Rhode Island federal court issued a temporary restraining order which
stayed the NHPUC's February 28, 1997, decision to the extent it established a
rate setting methodology that is not designed to recover PSNH's costs of
providing service and would require PSNH to write off any regulatory assets. A
hearing regarding the system plaintiffs' request for a preliminary injunction
will be held in the same court on March 20, 1997.
PSNH also intends to pursue claims against the state of New Hampshire for
damages in state court in New Hampshire for abrogation of the 1989 Rate
Agreement. The damage claims will be in the hundreds of millions of dollars.
PSNH and NAEC are parties to a variety of financing agreements providing
that the credit thereunder can be terminated or accelerated if they do not
maintain specified minimum ratios of common equity to capitalization (as defined
in each agreement). In addition, PSNH and NAEC are parties to a variety of
financing agreements providing in effect that the credit thereunder can be
terminated or accelerated if there are actions taken, either by PSNH or NAEC or
by the state of New Hampshire, that deprive PSNH and/or NAEC of the benefits of
the Rate Agreement and/or the Seabrook Power Contracts. If the NHPUC's February
28, 1997 decision becomes effective, it would, unless PSNH and NAEC receive
waivers from their respective lenders, result in (i) write-offs that would cause
PSNH's common equity to fall below the contractual minimums, (ii) reductions in
income that would cause PSNH's income to fall below the contractual minimums,
(iii) potential violation of the contractual provisions with respect to actions
depriving PSNH and NAEC of the benefits of the Rate Agreement, and (iv) the
potential for cross defaults to other PSNH and NAEC financing documents.
Substantially all of PSNH's and NAEC's debt obligations ($686 million of PSNH
debt and $515 million of NAEC debt) would be affected. For these actions to be
avoided, management believes that it is essential that the March 10, 1997,
temporary restraining order issued by a federal court judge be extended and made
applicable to the foregoing issues.
If these events transpired and the requested court relief is not
forthcoming, and if the creditors holding PSNH and NAEC debt obligations decide
to exercise their rights to demand payment and not to forebear while the
litigation is pending, then either creditors or PSNH and NAEC could initiate
proceedings under Chapter 11 of the bankruptcy laws.
PSNH and NAEC Report Considerations: As a result of the NHPUC decision and
the potential consequences discussed above, the reports of our auditors on the
individual financial statements of PSNH and NAEC contain explanatory paragraphs.
Those explanatory paragraphs indicate that a substantial doubt exists currently
about the ability of PSNH and NAEC to continue as going concerns. The accounts
of PSNH and NAEC are included in the accompanying consolidated financial
statements on the basis of a going concern. While the effect of the
implementation of that decision would have a material adverse impact on NU's
financial position, results of operations and cash flows, it would not in and of
itself result in defaults under borrowing or other financial agreements of NU or
its other subsidiaries.
Northeast Utilities 1996 Annual Report 43
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
- -----------------------------------------------------------------------------------------------------------------------
1996 Quarter Ended (a)
- -----------------------------------------------------------------------------------------------------------------------
March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share data)
Operating Revenues............................... $1,028,202 $871,904 $955,518 $936,524
=======================================================================================================================
Operating Income (Loss).......................... $ 133,261 $ 81,819 $ 68,032 $(11,540)
=======================================================================================================================
Net Income (Loss)................................ $ 65,502 $ 11,666 $ 1,033 $(76,370)
=======================================================================================================================
Earnings (Loss) Per Common Share................. $ 0.51 $ 0.09 $ 0.01 $ (0.60)
=======================================================================================================================
1995
=======================================================================================================================
Operating Revenues............................... $ 944,705 $840,333 $985,092 $980,430
=======================================================================================================================
Operating Income................................. $ 167,327 $118,410 $162,298 $144,053
=======================================================================================================================
Net Income....................................... $ 86,284 $ 42,398 $ 89,526 $ 64,226
=======================================================================================================================
Earnings Per Common Share........................ $ 0.69 $ 0.34 $ 0.71 $ 0.50
=======================================================================================================================
CONSOLIDATED GENERATION STATISTICS
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992(b)
- -----------------------------------------------------------------------------------------------------------------------
Source of Electric Energy: (kWh--millions)
Nuclear--Steam (c)........................... 9,405 18,235 19,443 22,965 15,520
Fossil--Steam................................ 9,188 9,162 8,292 7,676 6,784
Hydro--Conventional.......................... 1,544 1,099 1,239 1,140 1,076
Hydro--Pumped Storage........................ 1,217 1,209 1,195 1,269 1,221
Internal Combustion.......................... 206 37 13 8 9
Energy Used for Pumping...................... (1,668) (1,674) (1,629) (1,749) (1,671)
- -----------------------------------------------------------------------------------------------------------------------
Net Generation........................... 19,892 28,068 28,553 31,309 22,939
- -----------------------------------------------------------------------------------------------------------------------
Purchased and Net Interchange................ 22,111 14,256 14,028 10,499 14,165
Company Use and Unaccounted for.............. (2,473) (2,706) (2,535) (2,591) (2,028)
- -----------------------------------------------------------------------------------------------------------------------
Net Energy Sold.......................... 39,530 39,618 40,046 39,217 35,076
=======================================================================================================================
System Capability--MW (c).................... 8,894.0 8,394.8 8,494.8 7,795.3 7,823.2
System Peak Demand--MW....................... 5,946.9 6,358.2 6,338.5 6,191.0 5,781.0
Nuclear Capacity--MW (c)..................... 3,117.8 3,239.6 3,272.6 3,110.0 2,981.1
Nuclear Contribution to Total
Energy Requirements (%) (c).............. 28.0 52.0 54.0 62.1 48.5
Nuclear Capacity Factor (%) (d).............. 38.0 69.9 67.5 80.8 63.7
- -----------------------------------------------------------------------------------------------------------------------
(a) Reclassifications of prior data have been made to conform with the current
presentation.
(b) Effective with the June 5, 1992 acquisition of PSNH, the consolidated
financial and statistical information of NU includes, on a prospective
basis, the operations of PSNH and NAEC.
(c) Includes the system's entitlements in regional nuclear generating
companies, net of capacity sales and purchases.
(d) Represents the average capacity factor for the nuclear units operated by
the NU system.
44 Northeast Utilities 1996 Annual Report
SELECTED CONSOLIDATED FINANCIAL DATA
- ------------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992(a)
- ------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except percentages and per share data)
- ------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA:
Net Utility Plant (b)..................... $ 6,732,165 $ 7,000,837 $ 7,282,421 $ 7,439,159 $7,588,368
Total Assets.............................. 10,741,748 10,559,574 10,584,880 10,668,164 9,724,340
Total Capitalization (c).................. 6,622,519 6,820,624 7,035,989 7,309,898 7,421,592
Obligations Under Capital Leases (c)...... 206,165 230,482 239,121 243,760 266,100
- ------------------------------------------------------------------------------------------------------------------------
INCOME DATA:
Operating Revenues........................ $ 3,792,148 $ 3,750,560 $ 3,642,742 $ 3,629,093 $3,216,874
Net Income................................ 1,831 282,434 286,874 249,953(d) 256,054
- ------------------------------------------------------------------------------------------------------------------------
COMMON SHARE DATA:
Earnings per Share........................ $0.01 $2.24 $2.30 $2.02(d) $2.02
Dividends per Share....................... $1.38 $1.76 $1.76 $1.76 $1.76
Number of Shares
Outstanding--Average.................. 127,960,382 126,083,645 124,678,192 123,947,631(e) 130,403,488
Market Price--High........................ $25 1/4 $25 3/8 $25 3/4 $28 7/8 $26 3/4
Market Price--Low......................... $9 1/2 $21 $20 3/8 $22 $22 1/2
Market Price--Closing Price
(end of year)......................... $13 1/8 $24 1/4 $21 5/8 $23 3/4 $26 1/2
Book Value per Share (end of year)........ $17.73 $19.08 $18.47 $17.89 $16.24
Rate of Return Earned on Average
Common Equity (%)..................... 0.1 12.0 12.7 11.4 12.7
Dividend Yield (end of year) (%).......... 10.3 7.3 8.1 7.4 6.6
Cash Coverage of Common Dividends......... 4.1 4.2 4.0 3.3 2.6
Market-to-Book Ratio (end of year)........ 0.8 1.3 1.2 1.3 1.6
- ------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Common Shareholders' Equity............... 34% 36% 33% 30% 29%
Preferred Stock (c)(f).................... 7 7 9 9 9
Long-term Debt (c)........................ 59 57 58 61 62
- ------------------------------------------------------------------------------------------------------------------------
Total Capitalization...................... 100% 100% 100% 100% 100%
========================================================================================================================
(a) Effective with the June 5, 1992 acquisition of PSNH, the consolidated
financial and statistical information of NU includes, on a prospective
basis, the operations of PSNH and NAEC.
(b) Includes reclassification of the unamortized PSNH acquisition costs to
net utility plant.
(c) Includes portions due within one year.
(d) Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares and
earnings per common share by $51.7 million and $0.42, respectively.
(e) Decrease in the number of shares results from a change in accounting for
ESOP shares.
(f) Excludes $100 million of Monthly Income Preferred Securities.
Northeast Utilities 1996 Annual Report 45
CONSOLIDATED SALES STATISTICS
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1994(a) 1993 1992(b)
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REVENUES: (thousands)
Residential................................ $1,501,465 $1,469,988 $1,430,239 $1,385,818 $1,213,140
Commercial................................. 1,246,822 1,230,608 1,173,808(c) 1,043,125 943,832
Industrial................................. 565,900 583,204 559,801(c) 649,876 554,587
Other Utilities............................ 299,653 303,004 330,801 383,129 346,791
Streetlighting and Railroads............... 48,053 47,510 45,943 45,480 43,296
Miscellaneous.............................. 47,797 50,353 44,140 60,008 59,465
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Total Electric......................... 3,709,690 3,684,667 3,584,732 3,567,436 3,161,111
Other...................................... 82,458 65,893 58,010 61,657 55,763
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Total.................................. $3,792,148 $3,750,560 $3,642,742 $3,629,093 $3,216,874
=======================================================================================================================
SALES: (kWh--millions)
Residential................................ 12,241 12,005 12,231 11,988 10,839
Commercial................................. 12,012 11,737 11,649(c) 10,304 9,608
Industrial................................. 6,820 6,842 6,729(c) 7,572 6,593
Other Utilities............................ 8,100 8,718 9,123 9,046 7,733
Streetlighting and Railroads............... 319 316 314 307 303
Pilot Program (PSNH)....................... 38 -- -- -- --
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Total.................................. 39,530 39,618 40,046 39,217 35,076
=======================================================================================================================
CUSTOMERS: (average)
Residential................................ 1,532,015 1,526,127 1,513,987 1,503,182 1,351,019
Commercial................................. 157,347 156,652 154,703(c) 155,487 132,680
Industrial................................. 7,792 7,861 7,813(c) 6,272 5,774
Other...................................... 3,916 3,878 3,818 3,793 3,581
- -----------------------------------------------------------------------------------------------------------------------
Total.................................. 1,701,070 1,694,518 1,680,321 1,668,734 1,493,054
=======================================================================================================================
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)......................... 8,005 7,880(d) 8,152 7,987 8,129
=======================================================================================================================
AVERAGE ANNUAL BILL PER RESIDENTIAL
....CUSTOMER............................... $980.19 $964.88(d) $953.23 $923.32 $909.80
=======================================================================================================================
AVERAGE REVENUE PER KWH: (in cents)
Residential................................ 12.27 12.24 11.69 11.56 11.19
Commercial................................. 10.38 10.49 10.08 10.12 9.82
Industrial................................. 8.30 8.52 8.32 8.58 8.41
=======================================================================================================================
(a) Effective January 1, 1994, the accounting for unbilled revenues was
revised to report unbilled revenues by Customer Class.
(b) Effective with the June 5, 1992 acquisition of PSNH, the consolidated
financial and statistical information of NU includes, on a prospective
basis, the operations of PSNH and NAEC.
(c) Effective January 1, 1994, approximately 1,300 customers previously
classified as commercial customers were reclassified to industrial
customers.
(d) Effective January 1, 1996, the amounts shown reflect billed and unbilled
sales. 1995 has been restated to reflect this change.
46 Northeast Utilities 1996 Annual Report