EXHIBIT 13.1
TABLE OF CONTENTS
FINANCIAL AND STATISTICAL SECTION
Pages 15-21
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MANAGEMENT'S DISCUSSION AND ANALYSIS
Page 22
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COMPANY REPORT
Page 23
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Page 24
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CONSOLIDATED STATEMENTS OF INCOME
Page 25
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Pages 26-27
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CONSOLIDATED BALANCE SHEETS
Pages 28-29
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CONSOLIDATED STATEMENTS OF CAPITALIZATION
Page 30
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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
Page 31
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CONSOLIDATED STATEMENTS OF INCOME TAXES
Pages 32-43
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Page 44
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CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
Page 44
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CONSOLIDATED GENERATION STATISTICS
Page 45
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SELECTED CONSOLIDATED FINANCIAL DATA
Page 46
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CONSOLIDATED SALES STATISTICS
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
OVERVIEW
Earnings per common share were $2.24 in 1995, a decrease of $0.06, from
$2.30 in 1994. The 1995 earnings were lower as a result of higher operation
expenses, lower wholesale revenues, and higher fuel and purchased-power costs.
These decreases were partially offset by higher fuel revenues, higher revenues
from the final step of The Connecticut Light and Power Company's (CL&P)
three-year rate plan and the sixth step of the Public Service Company of New
Hampshire (PSNH) rate agreement, higher deferral of cogeneration expenses in
Connecticut, lower income tax expenses, and a reduction in maintenance costs.
Retail kilowatt-hour sales fell by 0.1 percent in 1995, as a result of a
flat economy in southern New England and mild weather in the first quarter of
1995. Retail kilowatt-hour sales were down 0.3 percent for CL&P, and 0.1 percent
for Western Massachusetts Electric Company (WMECO), but sales rose 0.4 percent
for PSNH. With the southern New England economy not forecasted to grow
substantially during 1996, sales levels are expected to remain flat.
NU's operating companies act as both buyers and sellers of electricity in
the highly competitive wholesale electricity market in the Northeast. Increased
competition has made the renegotiation of expiring wholesale contracts, as well
as the signing of new contracts, financially challenging. As a result, wholesale
power revenues fell to approximately $303 million in 1995, from approximately
$331 million in 1994. NU's efforts to enhance its wholesale revenues resulted in
several new contracts in 1995.
During 1995, the Federal Energy Regulatory Commission issued a proposal for
restructuring the electric-power industry, which calls for open access to
transmission facilities, a standard formula for calculating rates, and full
recovery of stranded investments. The impact on NU of this proposal, which is
expected to be finalized in 1996, is not known at this time.
During 1995, a Massachusetts Senate Committee and the Coalition of
Northeastern Governors released reports addressing the restructuring of the
electric-power industry and its resulting impact on customers and states. Both
of these reports presented the future as one in which there would be some form
of continued regulation for transmission and distribution with fully competitive
generation.
In 1995, the New Hampshire Legislature created a committee to review the
industry's structure and called for the New Hampshire Public Utilities
Commission (NHPUC) to initiate a retail wheeling pilot program. Under the
current NHPUC proposal, the program, which is expected to begin in 1996, will
initially impact 3 percent of PSNH's peak retail electric load, but only
allows for a 50-percent recovery of PSNH's potentially strandable costs. PSNH
and the NHPUC staff have entered into a joint recommendation that, if approved
by the NHPUC, would govern PSNH's participation in the retail wheeling pilot
program. Under this settlement, PSNH would provide competing electric suppliers
access to 3 percent of its retail customers. PSNH would recover 100 percent of
its potentially strandable costs via a delivery charge, but would provide a
10-percent incentive credit off its traditional rates to encourage customer
participation in the two-year experiment.
Also in 1995, Connecticut and Massachusetts regulatory commissions concluded
that while increased competition is in the public interest, electric utilities
should have the opportunity to recover "net, nonmitigatable stranded costs"
during a transition period to full competition. While such a conclusion is
encouraging, there is uncertainty with regard to the final regulatory and
legislative definitions of terms such as "net, nonmitigatable" and "stranded
costs."
NU is taking a proactive role in the electric-power industry's movement
toward competition. In its "Path To A Competitive Future" (the plan), NU
outlined a comprehensive approach to enhancing customer satisfaction and market
efficiency while moving toward full competition in the electricity marketplace.
The plan calls for several significant changes in electricity pricing, the
ability to introduce new products and services, the method of rate-setting, and
the operation of the New England Power Pool. The plan also calls for the
phase-in of supplier choices through the use of pilot programs. Management
believes that a fully competitive market for electricity should begin once all
issues relating to the transition from traditional utility regulation have been
thoroughly addressed.
[REGULATORY ASSETS CHART as follows]
REGULATORY ASSETS
(in millions)
ACTUAL
1993 - $2,032
1994 - $2,045
1995 - $2,034
-------------
PROJECTED
1996 - $2,000
1998 - $1,500
2000 - $1,000
-------------
As our industry becomes more
competitive, significant
reductions of the deferred
costs known as "regulatory
assets" over the next five
years is one of NU's key
financial strategies.
[END CHART]
In addition to the formulation of this plan and ongoing meetings with
legislators, regulators, and others in the industry, NU is moving ahead in other
areas, including revenue enhancement initiatives and cost reductions, to better
position itself for an increasingly competitive environment.
A comprehensive companywide effort, which started in 1994, to reengineer
NU's business and operating processes continued throughout 1995. NU expects that
this effort will have significant positive effects on operating costs and
customer service. Many of the organizational changes in the operating and
service functions announced in 1995 and early 1996 are consistent with the
initial recommendations of the reengineering teams. While NU's reengineering
efforts will be reduced in 1996, implementation costs relating to the previous
reengineering efforts are expected to increase.
With retail electric revenues accounting for approximately 90 percent of its
1995 revenues, NU has continued to develop a number of initiatives to retain and
serve its existing customers and to expand its retail customer base. The most
visible result of these efforts is the expansion of the Retail Marketing
organization. Retail Marketing's mission is to better understand the needs and
concerns of NU's retail customer and to develop innovative approaches to address
these issues. These initiatives include providing discounts to certain customers
for signing economic development and competitive generation-based contracts,
offering demand-side-management services, and providing additional products and
services.
WORKFORCE REDUCTIONS
In January 1996, NU completed its nuclear workforce reduction plan.
Approximately 220 positions were eliminated through a combination of early
retirements, attrition, and layoffs. The total pretax cost of the workforce
reduction, which was recognized in 1995, was approximately $9 million.
RATE MATTERS
NU follows accounting principles in accordance with Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation" that 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 in revenues at a later date.
The creation of these regulatory assets has kept down electric rates in past
years, at the expense of having higher rates in the future. At December 31,
1995, NU's regulatory assets totaled approximately $2.0 billion. The largest
regulatory asset, nearly $1.2 billion, is related to the future recovery of
income taxes. The substantial costs of amortizing these regulatory assets would
hinder NU from competing effectively in an openly competitive electric market if
customers are not required to pay such costs. Given the increasingly competitive
nature of the industry and increased activity in the regulatory environment, NU
has made the recovery of regulatory assets one of its central financial
strategies, while balancing the customer's pricing needs with shareholder's
earnings requirements. Under its existing rate agreements, NU is allowed to
recover a significant portion of its regulatory assets during the next five
years. However, maintaining or increasing the present recovery level is
dependent upon the outcome of negotiations between NU and its regulatory
agencies when its current rate agreements expire in each of its jurisdictions.
The chart on this page illustrates the levels of regulatory assets from 1993
to 1995, and the projected levels for 1996, 1998, and 2000 under existing rate
agreements.
Given that NU's current rate agreements expire during 1996 and 1997, NU will
actively pursue early negotiations with its regulatory agencies to determine
whether, or to what extent, rates should be adjusted going forward. NU's
strategy during these negotiations will be to maintain stable rates, applying
any available earnings that may result to reduce the balance of its regulatory
assets. Management is unable to predict the ultimate outcome of these
negotiations, which will be subject to regulatory approvals.
This strategy will require NU to maintain its strong cash flow from
operations, as measured by approximately a 4:1 cash coverage of the common
dividend in 1995. At its January meeting, the NU Board of Trustees (the Board)
decided to continue the current $0.44 per quarter common dividend. Although NU
has a strong cash coverage of the current dividend, the Board decided against
increasing the dividend at this time, given regulatory uncertainties, continued
weakness in the economy, and the need for improvement of the Millstone nuclear
operations.
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of." SFAS 121, which was effective January 1, 1996,
requires assets, including regulatory assets, that are no longer probable of
recovery through future revenues be charged to earnings.
If future competition or regulatory actions cause any portion of its
operations to no longer be subject to SFAS 71, NU would be required to determine
the fair value of the related regulatory assets and liabilities and record any
necessary write-downs. Additionally, if events create uncertainty about the
recoverability of any of NU's remaining long-lived assets, a similar analysis
would be required for those assets in accordance with SFAS 121. Under its
current regulatory environment, NU believes that its use of SFAS 71 remains
appropriate and that the adoption of SFAS 121 will not have a material impact on
its financial position or results of operations.
See the "Notes to Consolidated Financial Statements," Note 1G, for further
details on regulatory accounting.
CONNECTICUT
CL&P's retail rates increased by approximately $48 million, or 2.06 percent,
in July 1995, representing the final step of a three-year rate plan approved by
the Department of Public Utility Control (DPUC). CL&P's 1993 rate decision has
been appealed; however, management believes it is unlikely that the appeal will
prevail.
CL&P recovers from, or refunds to, customers certain fuel costs if its
nuclear units do not operate at a predetermined capacity factor (currently 72
percent) through a Generation Utilization Adjustment Clause (GUAC). CL&P is
currently recovering approximately $80 million of fuel costs for the 1994-1995
GUAC period (net of $19 million of asserted fuel overrecoveries for the period)
over 18 months. CL&P has appealed the $19 million that was set aside from its
allowed recovery and will seek to join this appeal to appeals currently pending
from previous GUAC periods.
NEW HAMPSHIRE
In June 1995, PSNH's base rates increased by 5.5 percent under the sixth
step of a seven-year 1989 rate agreement approved by the NHPUC. In November
1995, the NHPUC authorized a PSNH request to reduce its Fuel and Purchased Power
Adjustment Clause (FPPAC) rate, which took effect on December 1, 1995, and will
continue through May 31, 1996. The decision reduced PSNH's overall rates by
approximately 2.6 percent.
In 1995, PSNH completed installation of equipment to comply with the Clean
Air Act Amendments of 1990. The capitalized cost of the installation was
approximately $25 million, and will cause PSNH to spend approximately $4 million
annually for additional operation and maintenance costs. In April 1995, the
NHPUC began proceedings to determine whether these costs are recoverable from
customers. The NHPUC is allowing PSNH to recover these costs through the FPPAC,
subject to refund, pending a final decision.
The costs associated with purchases by PSNH from certain nonutility
generators (NUGs) over the level assumed in rates are deferred for recovery
over ten-year periods through the FPPAC. PSNH is attempting to renegotiate
these arrangements with the NUGs. At December 31, 1995, the unrecovered
deferral was approximately $192 million, including buyout payments of
approximately $34 million for two of PSNH's eight wood-fired NUGs. By December
31, 1995, PSNH had reached agreements with the owners of the remaining six
wood-fired NUGs. If consummated, these agreements could result in net savings of
approximately $430 million to PSNH's customers over a period of 20 years
following guaranteed payments of approximately $250 million. Management will
reevaluate whether to proceed with these agreements if the NHPUC fails to
provide for full recovery of stranded costs.
MASSACHUSETTS
In February 1996, WMECO and the Massachusetts Attorney General proposed a
settlement with the Department of Public Utilities (DPU), which, if approved,
would continue the 2.4-percent rate reduction instituted in June 1994. The
reduction would remain in effect through February 1998. Additionally, the
settlement would terminate WMECO's pending reviews of its generating plant
performance, any potential reviews associated with Millstone 2's 1994-1995
extended outage, and accelerate its recovery of generation assets by
approximately $6 million and $10 million in 1996 and 1997, respectively.
NUCLEAR PERFORMANCE
On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed
Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in
response to a number of performance concerns which have arisen since 1990 and a
failure to resolve employee safety concerns. The NRC's action will result in
close monitoring of programs and performance at Millstone to assure the
development and implementation of effective corrective actions.
Management plans to continue its extensive efforts already under way to
address these concerns. Concurrent with the NRC's action, NU provided the NRC
with the results of a comprehensive self-assessment review of the employee
concern program at Millstone. Additionally, in January 1996, NU announced a
reorganization of its nuclear operations, which included the creation of a new
office of Nuclear Safety and Oversight.
Although the start-up of Millstone 1, which is currently in outage, will be
affected by its placement on the NRC's "watch list," operations at Millstone 2
and 3 have not been restricted. Management expects that the increased NRC
attention will inevitably have effects and costs that are not known at this
time.
In November 1995, Millstone 1 began a planned refueling and maintenance
outage. The outage has been extended to allow NU to complete reviews required by
the NRC. In response to a request by the NRC, NU is conducting a detailed review
of Millstone 1's Final Safety Analysis Report and an assessment of the plant's
readiness to ensure that the future operation of the plant will be conducted in
accordance with the terms and conditions of its operating license and the NRC's
regulations. The outage schedule is currently under review, but the unit is not
expected to return to service before the mid-to-late part of the second quarter
of 1996. Total replacement-power costs attributable to the Millstone 1 outage
extension for CL&P and WMECO are expected to be approximately $6.5 million per
month. In addition, operation and maintenance (O&M) costs to be incurred as a
result of the extension are estimated to be approximately $20 million.
Replacement-power costs are deferred and amortized through rates for CL&P and
are recovered currently through rates for WMECO. Nuclear outage O&M costs are
deferred and amortized through rates for both companies. The recovery, or
refund, of outage costs is subject to prudence reviews in both Connecticut and
Massachusetts.
The composite capacity factor of the five nuclear generating units that NU
operates--including the Connecticut Yankee nuclear unit--was 69.9 percent in
1995, compared with 67.5 percent for 1994, and a 1995 national average of 77.6
percent. The 1995 capacity factor was impacted by an extended refueling and
maintenance outage for Millstone 2.
See the "Notes to Consolidated Financial Statements," Note 6B, for further
information on outage deferrals and recoveries.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and comply with the multitude
of environmental requirements it faces. NU has active auditing programs
addressing a variety of regulatory requirements, including an environmental
auditing program to detect and remedy noncompliance with environmental laws or
regulations.
NU is potentially liable for environmental cleanup costs at a number of
sites both inside and outside its service territories. 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, 1995, NU
had recorded an environmental reserve amounting to approximately $15 million,
the minimum amount required under SFAS 5, "Accounting for Contingencies." These
costs could be significantly higher if alternate remedies become necessary.
In October 1995, the Connecticut Department of Environmental Protection
(CDEP) issued a consent order to CL&P and the Long Island Lighting Company
(LILCO) requiring those companies to address leaks from the Long Island cable,
which is jointly owned by CL&P and LILCO. NU will incur additional costs to meet
the requirements of the order and to meet any subsequent CDEP requirements
resulting from the studies under the consent order, which cannot be estimated at
this time. Management also cannot determine at this time whether long-term
future operation of the cable will remain cost effective subsequent to any
additional CDEP requirements.
NUCLEAR DECOMMISSIONING
NU's estimated cost to decommission its shares of Millstone 1, 2, and 3 and
Seabrook 1 is approximately $1.2 billion in year-end 1995 dollars. These costs
are being recognized over the lives of the respective units and a portion is
being recovered through rates.
The FASB is currently reviewing the accounting for closure and removal
costs, including decommissioning and similar costs for long-lived assets. If
current electric-power industry accounting practices for such decommissioning
costs were changed, annual provisions for decommissioning would increase and the
estimated costs for decommissioning would be recorded as a liability rather than
as a component of accumulated depreciation.
See the "Notes to Consolidated Financial Statements," Note 3, for further
information on nuclear decommissioning, including NU's share of costs to
decommission the regional nuclear generating units.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $49 million in 1995,
from 1994, primarily due to higher cash operating expenses and lower working
capital, partially offset by higher revenues from rate recoveries. Cash used for
financing activities decreased approximately $51 million in 1995, from 1994,
primarily due to lower net reacquisitions and retirements of long-term debt and
the issuance of additional common shares in 1995 for use in NU's Dividend
Reinvestment Plan and the allocation of shares through the Employee Stock
Ownership Plan, partially offset by a net decrease in short-term debt. Cash
used for investments increased approximately $8 million in 1995, from 1994,
primarily due to higher investments in the nuclear decommissioning trust in
1995, partially offset by lower construction expenditures.
In October 1995, Moody's Investors Service lowered its ratings of PSNH and
North Atlantic Energy Corporation (NAEC) securities, bringing the rating for
PSNH's First Mortgage Bonds below investment grade. Standard & Poor's had
previously downgraded PSNH to below investment grade. NAEC securities had not
been previously rated at investment grade. These downgrades could adversely
affect the future availability and cost of funds for these companies.
Over the past three years, NU paid off approximately $1 billion of debt and
reduced outstanding levels of preferred securities by approximately $75 million.
Cash generated by improved earnings and higher levels of noncash expenses more
than offset the cash needs of a modest construction program. NU projects further
reductions of its long-term debt levels by $250 to $350 million during 1996
despite construction expenditures, which are budgeted to be approximately $35
million higher in 1996 than the $230 million program in 1995, since strong cash
generation should continue. Short-term debt is expected to remain at
approximately the same level as 1995.
PSNH may be required to issue a significant amount of new debt in 1996,
since it must fund the maturity of its $172.5 million first mortgage bond issue
at the same time that it may need to finance more than $100 million for payments
to its wood-fired NUGs. NU debt levels could drop by even more than the $250 to
$350 million projected above if PSNH does not make any upfront payments to the
NUGs.
CL&P, PSNH, NAEC, and WMECO have entered into interest-rate-cap,
interest-rate-swap, or fossil-fuel-swap contracts to reduce a portion of NU's
interest-rate and fuel-price risks.
CHANGE IN OPERATING REVENUES
Increase/(Decrease)
- -----------------------------------------------------------------
1995 vs. 1994 1994 vs. 1993
- -----------------------------------------------------------------
(Millions of Dollars)
Regulatory decisions $79 $53
Fuel, purchased power, and
FPPAC cost recoveries 63 (3)
Sales volume (6) 48
Wholesale revenues (19) (67)
Other revenues (11) (17)
---- ---
Total revenue change $106 $14
==== ===
- -----------------------------------------------------------------
See the "Notes to Consolidated Financial Statements," Note 7, for further
information on derivative financial instruments and the "Consolidated Statements
of Capitalization," for information on construction and long-term debt funding
requirements.
RESULTS OF OPERATIONS
The relative magnitude of how revenues received in 1995 were used by NU's
continuing operations in 1995 is illustrated in the chart on the next page.
OPERATING REVENUES
The components of the change in operating revenues for the past two years
are provided in the table above.
Operating revenues increased approximately $106 million in 1995, from 1994.
Regulatory revenues increased primarily because of retail-rate increases for
PSNH and CL&P and higher recoveries for demand-side-management costs. Fuel,
purchased power, and FPPAC cost recoveries increased, primarily due to higher
energy costs and the recovery of GUAC costs for CL&P. Wholesale revenues
decreased, primarily due to capacity sales contracts that expired in 1994.
Operating revenues increased approximately $14 million in 1994, from 1993.
Revenues related to regulatory decisions increased, primarily because of the
effects of changes in retail rates for CL&P and PSNH, and the July 1993
retail-rate increase for WMECO, partially offset by the June 1994 retail-rate
reduction for WMECO and lower recoveries for demand-side-management costs. Sales
volume increased as a result of higher retail sales from an improved economy.
Retail sales increased 2.9 percent in 1994, from 1993 sales levels. Wholesale
revenues decreased, primarily due to the expiration, in late 1993 and 1994, of
some significant capacity sales contracts.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased approximately
$77 million in 1995, from 1994, primarily due to higher fossil generation,
higher priced outside energy purchases from other utilities in 1995, and higher
amortization, in 1995, of previously deferred FPPAC expenses.
Fuel, purchased and net interchange power decreased approximately $86
million in 1994, from 1993, primarily due to the lower recognition of CL&P
replacement-power fuel costs in 1994, partially offset by a higher level of
outside energy purchases from other utilities in 1994.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses, net increased approximately $29
million in 1995, from 1994. Operation expenses increased approximately $46
million, primarily due to higher demand-side-management costs, higher rate
recovery 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. Maintenance expenses decreased
approximately $17 million, primarily due to lower maintenance costs at the
fossil units and fossil reserves for excess/obsolete inventory in 1994.
Other operation and maintenance expenses decreased approximately $20 million
in 1994, from 1993, primarily due to higher costs in 1993 associated with early-
retirement programs, lower 1994 payroll and benefit costs, lower fossil-unit
costs, and lower capacity charges from the regional nuclear generating units,
partially offset by higher 1994 costs associated with the operation and
maintenance activities of the nuclear units (approximately $23 million), higher
reserves for excess/obsolete inventory at the nuclear and fossil units in 1994,
and higher outside services primarily related to the companywide process
reengineering efforts.
DEPRECIATION EXPENSES
Depreciation expenses increased approximately $19 million in 1995, from
1994, and approximately $14 million in 1994, from 1993, primarily as a result of
higher plant balances and higher decommissioning levels.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased approximately $32 million
in 1995, from 1994, primarily because of the higher CL&P cogeneration deferrals
in 1995 (approximately $18 million), 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 June 1995.
Amortization of regulatory assets, net decreased approximately $48 million
in 1994, from 1993, primarily because of the deferral of CL&P cogeneration
expenses beginning in July 1994 as allowed under CL&P's 1993 retail-rate
decision, the higher amortization in 1994 of PSNH's regulatory liability as
allowed under a 1993 global settlement, and lower expenses associated with the
recovery of Hydro-Quebec support payments, partially offset by higher
amortization of Millstone 3 and Seabrook 1 phase-in costs.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes decreased approximately $18 million in 1995,
from 1994, primarily because of tax benefits from a favorable tax ruling and the
expiration of the federal statute of limitations for 1991.
Federal and state income taxes increased approximately $66 million in 1994,
from 1993, primarily because of higher taxable income.
TAXES OTHER THAN INCOME TAXES
Although the change in 1995, from 1994, was not significant, taxes other
than income taxes increased approximately $7 million in 1994, from 1993,
primarily due to higher Connecticut sales tax expense.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased approximately $31 million in 1995,
from 1994, and approximately $25 million in 1994, from 1993, primarily because
additional Millstone 3 and Seabrook 1 investments were phased into rates.
INTEREST CHARGES
Although the change in 1995, from 1994, was not significant, interest on
long-term debt decreased approximately $19 million in 1994, from 1993, primarily
because of lower average interest rates as a result of refinancing activities
and lower 1994 debt levels.
[PIE CHART as follows]
1995 USE OF REVENUE
- -------------------
24.3% - Energy Costs
20.8% - Other Operation
and Maintenance
Expenses
13.6% - Taxes
13.0% - Nonfuel Operating
Expenses and
Other Income, Net
12.7% - Wages and Benefits
8.6% - Interest Charges
7.0% - Common and Preferred
Dividends
[END CHART]
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
The cumulative effect of the accounting change of approximately $52 million
in 1993 represents the one-time change in the method of accounting for
Connecticut municipal property tax expense recognized in the first quarter of
1993.
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 conflicts 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, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
As explained in Note 1A to the financial statements, effective January
1, 1993, Northeast Utilities and subsidiaries changed their method of accounting
for property taxes.
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 16, 1996
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
OPERATING REVENUES .................................................. $ 3,748,991 $ 3,642,742 $ 3,629,093
------------ ------------ ------------
OPERATING EXPENSES:
Operation--
Fuel, purchased and net interchange power........................ 909,244 832,420 917,957
Other............................................................ 965,443 919,044 979,403
Maintenance........................................................ 288,927 306,429 265,926
Depreciation....................................................... 354,293 335,019 321,359
Amortization of regulatory assets, net............................. 128,413 160,909 208,506
Federal and state income taxes (See Consolidated
Statements of Income Taxes)...................................... 261,228 287,951 222,832
Taxes other than income taxes...................................... 249,463 247,045 240,413
------------ ------------ ------------
Total operating expenses....................................... 3,157,011 3,088,817 3,156,396
------------ ------------ ------------
OPERATING INCOME..................................................... 591,980 553,925 472,697
------------ ------------ ------------
OTHER INCOME:
Deferred nuclear plants return--other funds........................ 14,196 27,085 38,373
Equity in earnings of regional nuclear generating
and transmission companies....................................... 13,208 14,426 12,980
Other, net......................................................... 2,389 7,745 4,747
Income taxes....................................................... (742) 7,825 8,926
------------ ------------ ------------
Other income, net................................................ 29,051 57,081 65,026
------------ ------------ ------------
Income before interest charges................................... 621,031 611,006 537,723
------------ ------------ ------------
INTEREST CHARGES:
Interest on long-term debt......................................... 315,862 314,191 333,163
Other interest..................................................... 6,666 8,037 13,059
Deferred nuclear plants return--borrowed funds..................... (23,310) (41,138) (54,462)
------------ ------------ ------------
Interest charges, net............................................ 299,218 281,090 291,760
------------ ------------ ------------
Income before cumulative effect of accounting change............. 321,813 329,916 245,963
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 1A)..................... -- -- 51,681
------------ ------------ ------------
Income before preferred dividends of subsidiaries................ 321,813 329,916 297,644
PREFERRED DIVIDENDS OF SUBSIDIARIES.................................. 39,379 43,042 47,691
------------ ------------ ------------
NET INCOME........................................................... $ 282,434 $ 286,874 $ 249,953
============ ============ ============
EARNINGS PER COMMON SHARE:
Before cumulative effect of accounting change...................... $2.24 $2.30 $1.60
Cumulative effect of accounting change (Note 1A)................... -- -- .42
------------ ------------ ------------
TOTAL EARNINGS PER COMMON SHARE...................................... $2.24 $2.30 $2.02
============ ============ ============
COMMON SHARES OUTSTANDING (AVERAGE).................................. 126,083,645 124,678,192 123,947,631
============ ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
OPERATING ACTIVITIES:
Income before preferred dividends of subsidiaries....................... $ 321,813 $ 329,916 $ 297,644
Adjustments to reconcile to net cash from operating activities:
Depreciation.......................................................... 354,293 335,019 321,359
Deferred income taxes and investment tax credits, net ................ 164,208 146,560 63,506
Deferred nuclear plants return........................................ (37,506) (68,223) (92,835)
Amortization of deferred nuclear plants return........................ 109,294 118,217 111,024
Recoverable energy costs, net of amortization......................... (51,474) (85,573) 93,302
Amortization of PSNH acquisition costs................................ 55,547 55,319 67,379
Deferred cogeneration costs--CL&P..................................... (55,341) (36,821) --
Other sources of cash................................................. 101,334 69,888 132,662
Other uses of cash.................................................... (43,972) (36,596) (24,186)
Changes in working capital:
Receivables and accrued utility revenues.............................. (72,081) 8,133 2,797
Fuel, materials, and supplies......................................... (10,518) 4,906 10,126
Accounts payable...................................................... 38,096 51,824 (678)
Accrued taxes......................................................... 17,686 17,031 (97,789)
Other working capital (excludes cash)................................. (8,045) 22,329 30,010
---------- ---------- ----------
Net cash flows from operating activities.................................. 883,334 931,929 914,321
---------- ---------- ----------
FINANCING ACTIVITIES:
Issuance of common shares............................................... 47,218 14,551 22,252
Issuance of long-term debt.............................................. 225,100 625,000 924,650
Issuance of preferred stock............................................. -- -- 80,000
Issuance of Monthly Income
Preferred Securities (Note 9)......................................... 100,000 -- --
Net (decrease) increase in short-term debt.............................. (91,000) 16,500 (179,240)
Reacquisitions and retirements of long-term debt........................ (425,500) (982,920) (1,051,501)
Reacquisitions and retirements of preferred stock....................... (140,675) (7,325) (116,496)
Cash dividends on preferred stock....................................... (39,379) (43,042) (47,691)
Cash dividends on common shares......................................... (221,701) (219,317) (218,179)
---------- ---------- ----------
Net cash flows used for financing activities.............................. (545,937) (596,553) (586,205)
---------- ---------- ----------
INVESTMENT ACTIVITIES:
Investment in plant:
Electric and other utility plant...................................... (231,408) (259,904) (275,741)
Nuclear fuel.......................................................... (18,261) (28,308) (33,202)
---------- ---------- ----------
Net cash flows used for investments in plant............................ (249,669) (288,212) (308,943)
Other investment activities, net........................................ (91,399) (44,593) (32,811)
---------- ---------- ----------
Net cash flows used for investments....................................... (341,068) (332,805) (341,754)
---------- ---------- ----------
NET (DECREASE) INCREASE IN CASH FOR THE PERIOD............................ (3,671) 2,571 (13,638)
Cash--beginning of period................................................. 34,579 32,008 45,646
---------- ---------- ----------
Cash--end of period....................................................... $ 30,908 $ 34,579 $ 32,008
========== ========== ==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest, net of amounts capitalized.................................... $ 321,148 $ 306,224 $ 325,552
========== ========== ==========
Income taxes............................................................ $ 108,928 $ 134,727 $ 142,669
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases......................... $ 41,388 $ 65,932 $ 54,205
========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS
At December 31, 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
UTILITY PLANT, AT COST:
Electric................................................................ $ 9,490,142 $ 9,334,912
Other................................................................... 187,389 157,632
----------- -----------
9,677,531 9,492,544
Less: Accumulated provision for depreciation......................... 3,629,559 3,293,660
----------- -----------
6,047,972 6,198,884
Unamortized PSNH acquisition costs (Note 1I)............................ 588,910 678,974
Construction work in progress........................................... 165,111 179,724
Nuclear fuel, net....................................................... 198,844 224,839
----------- -----------
Total net utility plant............................................... 7,000,837 7,282,421
----------- -----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear decommissioning trusts, at market............................... 325,674 240,229
Investments in regional nuclear generating companies, at equity......... 81,996 82,464
Investments in transmission companies, at equity........................ 23,558 26,106
Investments in Charter Oak Energy, Inc. projects........................ 41,221 11,137
Other, at cost.......................................................... 33,448 29,759
----------- -----------
505,897 389,695
----------- -----------
CURRENT ASSETS:
Cash.................................................................... 30,908 34,579
Receivables, less accumulated provision for uncollectible
accounts of $14,378,000 in 1995 and $16,826,000 in 1994............... 435,931 357,322
Accrued utility revenues................................................ 136,260 142,788
Fuel, materials, and supplies, at average cost.......................... 200,580 190,062
Recoverable energy costs, net--current portion.......................... 79,300 19,522
Prepayments and other................................................... 34,430 35,364
----------- -----------
917,409 779,637
----------- -----------
DEFERRED CHARGES:
Regulatory assets (Note 1G)............................................. 2,034,351 2,045,390
Unamortized debt expense................................................ 37,645 33,517
Other................................................................... 48,827 54,220
----------- -----------
2,120,823 2,133,127
----------- -----------
TOTAL ASSETS.......................................................... $10,544,966 $10,584,880
=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
At December 31, 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
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; 135,611,166
shares issued and 127,050,647 shares outstanding in 1995 and 134,210,226
shares issued and 124,994,322 shares outstanding in 1994............ $ 678,056 $ 671,051
Capital surplus, paid in.............................................. 936,308 904,371
Deferred benefit plan--employee stock ownership plan (Note 5D)........ (198,152) (213,324)
Retained earnings..................................................... 1,007,340 946,988
----------- -----------
Total common shareholders' equity................................... 2,423,552 2,309,086
Preferred stock not subject to mandatory redemption................... 169,700 234,700
Preferred stock subject to mandatory redemption....................... 302,500 375,250
Long-term debt........................................................ 3,705,215 3,942,005
----------- -----------
Total capitalization................................................ 6,600,967 6,861,041
----------- -----------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES (NOTE 9)................... 99,935 --
----------- -----------
OBLIGATIONS UNDER CAPITAL LEASES.......................................... 147,372 166,018
----------- -----------
CURRENT LIABILITIES:
Notes payable to banks.................................................. 99,000 180,000
Commercial paper........................................................ -- 10,000
Long-term debt and preferred stock--current portion..................... 219,657 174,948
Obligations under capital leases--current portion....................... 83,110 73,103
Accounts payable........................................................ 319,038 280,942
Accrued taxes........................................................... 75,218 57,532
Accrued interest........................................................ 53,699 70,639
Accrued pension benefits................................................ 90,630 90,194
Other................................................................... 105,821 98,296
----------- -----------
1,046,173 1,035,654
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes (Note 1H)............................. 2,135,852 1,968,230
Accumulated deferred investment tax credits............................. 178,060 188,005
Deferred contractual obligation......................................... 103,475 157,147
Other................................................................... 233,132 208,785
----------- -----------
2,650,519 2,522,167
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 6)
TOTAL CAPITALIZATION AND LIABILITIES.................................. $10,544,966 $10,584,880
=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets) ............ $ 2,423,552 $ 2,309,086
----------- -----------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value--authorized 36,600,000 shares at December 31, 1995 and 1994;
7,300,000 shares outstanding in 1995 and 12,927,000 shares in 1994;
$50 par value--authorized 9,000,000 shares at December 31, 1995 and 1994;
5,424,000 shares outstanding in 1995 and 1994;
$100 par value--authorized 1,000,000 shares at December 31, 1995 and 1994;
200,000 shares outstanding in 1995 and 1994
Current Redemption Current Shares
Dividend Rates Prices (a) Outstanding
-------------- ---------- -----------
NOT SUBJECT TO MANDATORY REDEMPTION:
$25 par value--Adjustable Rate $25.00 1,340,000... 33,500 98,500
$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................ 169,700 234,700
----------- -----------
SUBJECT TO MANDATORY REDEMPTION: (b)
$25 par value--$1.90 to $2.65 $25.00 to $25.89 5,960,000... 149,000 224,675
$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.................... 304,000 379,675
Less: Preferred Stock to be redeemed within one year.................... 1,500 4,425
----------- -----------
Preferred Stock Subject to Mandatory Redemption, net..................... 302,500 375,250
----------- -----------
LONG-TERM DEBT: (c)
First Mortgage Bonds--
Maturity Interest Rates
-------- --------------
1995 9.25%............................................ -- 34,300
1996 8.875%........................................... 172,500 172,500
1997 5.75% to 7.625%.................................. 211,945 214,850
1998 6.50% to 9.17%................................... 199,800 199,900
1999 5.50% to 7.25%................................... 280,000 280,000
2000 5.75% to 6.875%.................................. 260,000 260,000
2002 7.75% to 9.05%................................... 420,000 440,000
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.......................................... 2,234,245 2,291,550
----------- -----------
Other Long-Term Debt-- (d)
Pollution Control Notes and Other Notes--
1996 Adjustable Rate.................................. -- 141,000
2000 Adjustable Rate (e) and 15.23%................... 225,000 205,000
2005-2006 8.38% to 8.58%................................... 224,000 236,000
2013-2016 Adjustable Rate.................................. 23,400 23,400
2018-2020 7.17% and Adjustable Rate........................ 49,874 50,191
2021-2022 7.50% to 7.65% and Adjustable Rate............... 552,485 552,485
2028 Adjustable Rate.................................. 369,300 369,300
----------- -----------
Total Pollution Control Notes and Other Notes....................... 1,444,059 1,577,376
Fees and interest due for spent nuclear fuel disposal costs (Note 1N). 185,158 174,934
Other................................................................. 68,312 78,090
----------- -----------
Total Other Long-Term Debt.......................................... 1,697,529 1,830,400
----------- -----------
Unamortized premium and discount, net................................... (8,402) (9,422)
----------- -----------
Total Long-Term Debt.................................................. 3,923,372 4,112,528
Less amounts due within one year...................................... 218,157 170,523
----------- -----------
Long-Term Debt, net................................................... 3,705,215 3,942,005
----------- -----------
TOTAL CAPITALIZATION................................................ $ 6,600,967 $ 6,861,041
=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
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, 1993................ $353,500
Issues.................................. 80,000
Reacquisitions and Retirements.......... (51,500)
--------
Balance at December 31, 1993.............. 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
========
The minimum sinking-fund requirements of the series subject to
mandatory redemption aggregate approximately $1.5 million in 1996, $26.5
million in 1997, $30.3 million in 1998, and $46.3 million in 1999 and 2000.
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, 1995 for the years 1996 through 2000 are
approximately $218.2 million, $261.3 million, $239.5 million, $371.9
million, and $578.2 million, respectively. In addition, there are annual 1
percent sinking- and improvement-fund requirements of approximately $15.6
million for 1996 and 1997, $13.5 million for 1998, $13.2 million for 1999,
and $10.4 million for 2000. 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 May 1996. At December 31, 1995, there were
no borrowings under the Revolving Credit Facility.
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, 1995, $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 was
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 3.6 percent to 6.1 percent for 1995 and 2.5 percent to
4.3 percent for 1994. The average effective interest rates for the PSNH
Term Loan for 1995 and 1994 were approximately 7.1 percent and 5.2 percent,
respectively.
(e) Interest-rate-swap agreements with financial institutions effectively fix
the interest rate of NAEC's $225 million variable-rate bank note at 7.05
percent. For further information on NAEC's interest-rate swaps, see Note 7,
"Derivative Financial Instruments."
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
DEFERRED
BENEFIT
CAPITAL PLAN--
COMMON SURPLUS, ESOP RETAINED
SHARES (a) PAID IN (NOTE 5D) EARNINGS (b) TOTAL
- ------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
BALANCE AT JANUARY 1, 1993.............. $669,315 $897,317 $(240,399) $847,744 $2,173,977
Net income for 1993................... 249,953 249,953
Cash dividends on common shares--
$1.76 per share..................... (218,179) (218,179)
Issuance of 344,106 common shares,
$5 par value........................ 1,720 6,538 8,258
Allocation of benefits--ESOP.......... 1,800 12,194 13,994
Capital stock expenses, net........... (3,915) (3,915)
-------- -------- --------- ---------- ----------
BALANCE AT DECEMBER 31, 1993............ 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
======== ======== ========= ========== ==========
- ------------------------------------------------------------------------------------------------------------------------------
(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, 1995, 462,224 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,
1995, these restrictions totaled approximately $559.6 million.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF INCOME TAXES
For the Years Ended December 31, 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
The components of the federal and state income tax provisions
charged to operations are:
Current income taxes:
Federal............................................................ $ 53,862 $ 88,483 $ 99,591
State.............................................................. 43,900 45,083 50,809
-------- -------- --------
Total current.................................................... 97,762 133,566 150,400
-------- -------- --------
Deferred income taxes, net:
Federal............................................................ 167,091 149,391 87,105
State.............................................................. 7,224 6,988 (10,058)
-------- -------- --------
Total deferred................................................... 174,315 156,379 77,047
-------- -------- --------
Investment tax credits, net........................................... (10,107) (9,819) (13,541)
-------- -------- --------
Total income tax expense................................................. $261,970 $280,126 $213,906
======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses............................. $261,228 $287,951 $222,832
Other income taxes..................................................... 742 (7,825) (8,926)
-------- -------- --------
Total income tax expense................................................. $261,970 $280,126 $213,906
======== ======== ========
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
Depreciation, leased nuclear fuel, settlement credits,
and disposal costs................................................. $ 82,318 $ 72,078 $ 79,288
Energy adjustment clauses............................................ 26,851 49,017 (39,660)
Nuclear plant deferrals.............................................. 2,666 (10,542) (1,773)
Contractual settlements.............................................. (9,496) 109 (308)
Bond redemptions..................................................... 9,224 8,325 8,508
Amortization of New Hampshire regulatory settlement.................. 11,501 11,501 7,667
Deferred tax asset associated with net operating losses.............. 57,543 23,611 25,438
Other................................................................ (6,292) 2,280 (2,113)
-------- -------- --------
Deferred income taxes, net............................................... $174,315 $156,379 $ 77,047
======== ======== ========
A reconciliation between income tax expense and the expected tax
expense at 35 percent of pretax income:
Expected federal income tax............................................ $204,324 $213,515 $179,043
Tax effect of differences:
Depreciation......................................................... 25,639 20,003 21,319
Deferred nuclear plants return....................................... (4,969) (9,480) (13,486)
Amortization of deferred nuclear plants return....................... 21,883 23,103 21,988
Amortization of PSNH acquisition costs............................... 31,522 31,508 31,432
Seabrook intercompany loss........................................... (13,048) (19,637) (19,176)
Investment tax credit amortization................................... (10,107) (9,819) (13,541)
State income taxes, net of federal benefit........................... 33,231 33,847 26,488
Property tax......................................................... (159) 5,824 (13,514)
Adjustment for prior years' taxes.................................... (20,312) (4,588) (4,134)
Other, net........................................................... (6,034) (4,150) (2,513)
-------- -------- --------
Total income tax expense................................................. $261,970 $280,126 $213,906
======== ======== ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRESENTATION
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.
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.
PROPERTY TAXES: Certain subsidiaries of NU, including CL&P and WMECO, changed
their method of accounting for municipal property tax expense for their
respective Connecticut properties during 1993. This one-time change increased
1993 net income and earnings per common share by approximately $51.7 million and
$0.42, respectively.
B. FUTURE ACCOUNTING STANDARD
The Financial Accounting Standards Board (FASB) 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, in March 1995. SFAS 121
became effective January 1, 1996 and establishes accounting standards for
evaluating and recording asset impairment. SFAS 121 requires the evaluation of
long-lived assets for impairment when certain events occur or conditions exist
that indicate the carrying amounts of assets may not be recoverable. Refer to
Note 1G, "Regulatory Accounting," for further information on the regulatory
impacts of the company's adoption of SFAS 121.
C. 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 holds a 49.0 percent ownership interest in Connecticut Yankee Atomic
Power Company (CY), a 38.5 percent ownership interest in Yankee Atomic Electric
Company (YAEC), a 20.0 percent ownership interest in Maine Yankee Atomic Power
Company (MY), and a 16.0 percent ownership interest in Vermont Yankee Nuclear
Power Corporation (VY). The system's investments in the Yankee companies are
accounted for on the equity basis due to NU's ability to exercise significant
influence over their operating and financial policies. The electricity produced
by the facilities that are operating 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 6E, "Commitments
and Contingencies--Long-term Contractual Arrangements."
YAEC's nuclear power plant was shut down permanently on February 26, 1992. For
more information on the Yankee companies, see Note 3, "Nuclear Decommissioning."
MILLSTONE 3: CL&P, PSNH, and WMECO have a 68.02 percent joint-ownership interest
in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of December
31, 1995 and 1994, plant-in-service included approximately $2.4 billion and the
accumulated provision for depreciation included approximately $572.3 million and
$525.9 million, respectively, for the system's share of Millstone 3. The
system's share of Millstone 3 expenses is included in the corresponding
operating expenses on the accompanying Consolidated Statements of Income.
SEABROOK 1: CL&P and NAEC 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. As of
December 31, 1995 and 1994, plant-in-service included approximately $889.0
million and $887.4 million, respectively, and the accumulated provision for
depreciation included approximately $107.0 million and $83.2 million,
respectively, for the system's share of Seabrook 1. The system's share of
Seabrook 1 expenses is 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 $23.6 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 6E,
"Commitments and Contingencies--Long-term Contractual Arrangements," for
additional information.
CHARTER OAK ENERGY, INC. (COE): COE owns and/or participates through special
purpose subsidiaries in various nonutility generation projects as permitted
under the Public Utility Holding Company Act of 1935. These investments may
be accounted for on either a cost or equity basis based upon COE's level of
participation.
D. 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 factors 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 1995, 3.7 percent in 1994, and 3.6 percent in
1993. See Note 3, "Nuclear Decommissioning," for information on nuclear plant
decommissioning.
E. 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.
F. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, industrial, and commercial customers, 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.
G. REGULATORY ACCOUNTING
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 in 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
would also be required to determine any impairment to other assets and write
down these assets to fair value. Based on current regulation and recent
regulatory decisions and initiatives relating to competition in the system's
markets, the company believes that its use of regulatory accounting remains
appropriate.
SFAS 121 requires that any assets, including regulatory 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. As noted above,
based on the current regulatory environment in the company's service areas, it
is not expected that SFAS 121 will have a material impact on the company's
financial position or results of operations upon adoption. 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. For further information on the company's
regulatory environment, refer to Management's Discussion and Analysis of
Financial Condition and Results of Operations (MD&A).
The components of regulatory assets are as follows:
- --------------------------------------------------------------------
At December 31, 1995 1994
- --------------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1H). $1,176,356 $1,124,119
Recoverable energy costs,
net (Note 1J). . . . . . . . . . . 260,678 268,982
Deferred costs--nuclear
plants (Note 1K) . . . . . . . . . 168,600 233,145
Unrecovered contractual
obligation (Note 3). . . . . . . . 103,475 157,147
Deferred demand-side
management costs (Note 1L) . . . . . 117,070 116,133
Cogeneration costs--
CL&P (Note 1M) . . . . . . . . . . 92,162 36,821
Other. . . . . . . . . . . . . . . . . 116,010 109,043
---------- ----------
$2,034,351 $2,045,390
========== ==========
- --------------------------------------------------------------------
H. 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 income subject to tax) 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 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 accounting standards, which give rise to the
accumulated deferred tax obligation is as follows:
- ----------------------------------------------------------------------
At December 31, 1995 1994
- ----------------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences. . . $1,703,680 $1,470,372
Net operating loss carryforwards . . . (191,873) (247,440)
Regulatory assets--income tax
gross up . . . . . . . . . . . . . . 477,959 473,399
Other. . . . . . . . . . . . . . . . . 146,086 271,899
---------- ----------
$2,135,852 $1,968,230
========== ==========
- ----------------------------------------------------------------------
At December 31, 1995, PSNH had a net operating loss (NOL) carryforward of
approximately $572 million to be used against PSNH's federal taxable income and
to expire between the years 2000 and 2006. PSNH also had Investment Tax Credit
(ITC) carryforwards of $52 million, which expire between the years 1996 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 $95 million of the NOL and $21 million of the ITC carryforwards
are subject to this limitation.
I. 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 amortization 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, 1995,
approximately $411.8 million of acquisition costs have been collected through
rates.
J. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (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, 1995, the
company's total D&D deferrals were approximately $62.4 million.
CL&P: Retail electric rates include a fuel adjustment clause (FAC) under which
fossil-fuel prices above or below base-rate levels are charged or credited to
customers. Monthly FAC rates are also subject to quarterly retroactive
regulatory review and appropriate adjustments. CL&P also utilizes a generation
utilization adjustment clause (GUAC), which defers the effect on fuel costs
caused by variations from a specified composite nuclear generation capacity
factor embedded in base rates.
CL&P is currently recovering $80 million of its GUAC balance over 18 months.
CL&P set aside $19 million of its 1994-1995 GUAC year request pending the
resolution of CL&P's appeals associated with the two prior GUAC periods.
At December 31, 1995, CL&P's net recoverable energy costs, excluding current
recoverable energy costs, were approximately $27.3 million. For additional
information, see Note 6B, "Commitments and Contingencies--Nuclear
Performance."
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, 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 New Hampshire Public Utilities Commission (NHPUC).
The costs associated with purchases from certain 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. In
1994, 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.
At December 31, 1995, PSNH's net recoverable energy costs were approximately
$220 million, including purchased-power deferrals of $185.6 million and the NUGs
deferred buyout payments of $34.2 million.
K. DEFERRED COSTS--NUCLEAR PLANTS
As prescribed by the Rate Agreement, NAEC is phasing into rates the recoverable
portion of its investment in Seabrook 1 and is deferring certain costs for
future collection. This plan is in compliance with SFAS 92, REGULATED
ENTERPRISES--ACCOUNTING FOR PHASE-IN PLANS.
As of December 31, 1995, the portion of the investment on which NAEC is entitled
to earn a cash return was 85 percent. he investment will be fully phased into
NAEC's rate base as of May 1, 1996. From the Acquisition Date through December
31, 1995, NAEC recorded $162.4 million of deferred return on the excluded
portion of its investment in Seabrook 1. The deferred return on the excluded
portion of NAEC's investment in Seabrook 1 will be recovered with carrying
charges beginning six months after the end of PSNH's fixed-rate period (which
continues through May 1997) and will be fully recovered by May 2001.
L. DEMAND-SIDE MANAGEMENT (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation Adjustment
Mechanism (CAM). As of December 31, 1995, these costs will be fully recovered by
2000. During October 1995, CL&P filed its 1996 DSM program and forecasted CAM
for 1996 with the Connecticut Department of Public Utility Control (DPUC). The
filing proposes expenditures of $37.1 million in 1996, with recovery over 2.4
years and a zero CAM rate.
M. CL&P COGENERATION COSTS
In accordance with its three-year rate plan that began in July 1993, CL&P was
required to defer approximately $72 million and $36 million of cogeneration
expense in years two and three, respectively, of the rate plan. CL&P is allowed
to defer these costs with carrying charges and will begin amortization of these
costs over a five-year period beginning July 1, 1996.
On June 30, 1995, CL&P terminated its existing agreement to purchase power from
the O'Brien EPA cogeneration facility and entered into an agreement to purchase
an equivalent amount of power from Citizens Lehman Power LP, at a cost below the
O'Brien EPA rates. CL&P has applied the resulting savings to the amortization of
the cogeneration deferral.
N. 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 may be made anytime prior to the first
delivery of spent fuel to the DOE, which may be as early as 1998. Until such
payment is made, the outstanding balance will continue to accrue interest at
the three-month Treasury Bill Yield Rate. At December 31, 1995, fees due to the
DOE for the disposal of prior-period fuel were approximately $185.2 million,
including interest costs of $103.1 million. As of December 31, 1995, all fees
have been collected through rates.
O. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes interest-rate caps, interest-rate swaps, and fuel swaps to
manage well-defined interest-rate and fuel-price risks. Premiums paid for
purchased interest-rate-cap agreements are amortized to interest expense over
the terms of the caps. Unamortized premiums are included in deferred charges.
Amounts receivable under cap agreements and amounts receivable or payable under
interest-rate-swap agreements are accrued and offset against interest expense.
Amounts receivable or payable under fuel-swap agreements are recognized in
income when realized. Any material unrealized gains or losses on interest-rate
swaps, fuel swaps or interest-rate caps will be deferred until realized. For
further information on derivatives, see Note 7, "Derivative Financial
Instruments."
2. LEASES
CL&P and WMECO finance up to $475 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, nuclear control room simulators, and
office space. The provisions of these lease agreements generally provide for
renewal options.
Capital lease rental payments charged to operating expense were $75,894,000 in
1995, $81,952,000 in 1994, and $100,911,000 in 1993. Interest included in
capital lease rental payments was $15,025,000 in 1995, $14,881,000 in 1994, and
$16,525,000 in 1993. Operating lease rental payments charged to operating
expense were $20,859,000 in 1995, $20,118,000 in 1994, and $22,630,000 in 1993.
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, 1995, are:
- -----------------------------------------------------------------
Capital Operating
Year Leases Leases
- -----------------------------------------------------------------
(Thousands of Dollars)
1996. . . . . . . . . . . . . . . . . . $ 9,000 $21,500
1997. . . . . . . . . . . . . . . . . . 8,400 18,900
1998. . . . . . . . . . . . . . . . . . 8,000 11,200
1999. . . . . . . . . . . . . . . . . . 7,500 8,500
2000. . . . . . . . . . . . . . . . . . 6,900 7,100
After 2000. . . . . . . . . . . . . . . 42,500 13,600
-------- -------
Future minimum lease payments . . . . . 82,300 $80,800
=======
Less amount representing
interest . . . . . . . . . . . . . . 40,500
--------
Present value of future
minimum lease payments
for other than nuclear fuel. . . . . 41,800
Present value of future nuclear
fuel lease payments. . . . . . . . . 188,700
--------
Total . . . . . . . . . . . . $230,500
========
- -----------------------------------------------------------------
3. NUCLEAR DECOMMISSIONING
The NU 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. The company's 1992 decommissioning study concluded that complete
and immediate dismantlement at retirement continues to be the most viable and
economic method of decommissioning the three Millstone units. A 1994 Seabrook
decommissioning study also confirmed that complete and immediate dismantlement
at retirement is the most viable and economic method of decommissioning Seabrook
1. Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, costs, technology, and inflation.
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1995
dollars, is $370.7 million and $328.1 million, respectively. The system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 in year-end 1995 dollars, is $298.2 million and $169.7 million,
respectively. These estimated costs assumed levelized collections for the
Millstone units and escalated collections for Seabrook 1, and after-tax earnings
on the Millstone and Seabrook decommissioning funds of 6.5 percent
and 6.1 percent, 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 $38.9 million in
1995, $33.5 million in 1994, and $29.4 million in 1993. Nuclear decommissioning,
as a cost of removal, is included in the accumulated provision for depreciation
on the Consolidated Balance Sheets. At December 31, 1995, the balance in the
accumulated reserve for decommissioning amounted to $357.7 million. See "Nuclear
Decommissioning" in the MD&A for a discussion of changes being considered by the
FASB relating to accounting for closure and removal of long-lived assets
(including nuclear decommissioning)
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.
As of December 31, 1995, CL&P, PSNH, and WMECO collected, through rates, $203.5
million, $1.8 million, and $47.4 million, respectively, toward the future
decommissioning costs of their share of the Millstone units, of which $220.6
million has been transferred to external decommissioning trusts. As of December
31, 1995, CL&P and NAEC (including payments made prior to the Acquisition Date
by PSNH) paid approximately $1.9 million and $13.1 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 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.
CL&P, PSNH, and WMECO, along with other New England utilities, have equity
investments in the four Yankee companies. Each Yankee company owns a single
nuclear generating unit with service lives that are expected to end during the
years 2007 through 2012. The system's ownership share of estimated costs, in
year-end 1995 dollars, of decommissioning the units owned and operated by CY,
MY, and VY are $188.9 million, $70.7 million, and $55.6 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.
YAEC is in the process of dismantling its nuclear facility. Accelerated
decommissioning of that unit has been delayed because of litigation over the
Nuclear Regulatory Commission's (NRC) approval of YAEC's decommissioning plan.
Effective November 1995, YAEC began billing its sponsors, including the NU
system companies, amounts based on a revised estimate approved by the FERC that
assumes decommissioning of the plant by the year 2000. This revised
decommissioning estimate was based on access to the Barnwell, South Carolina,
low-level radioactive waste facility, changes in assumptions about earnings in
decommissioning trust investments, and changes in other decommissioning cost
assumptions. At December 31, 1995, the estimated remaining costs, including
decommissioning, amounted to $268.8 million of which the NU system's share was
approximately $103.5 million. Management expects that CL&P, PSNH, and WMECO will
continue to be allowed to recover such FERC-approved costs from their customers.
Accordingly, NU has recognized these costs as regulatory assets, with
corresponding obligations, on its Consolidated Balance Sheets.
4. SHORT-TERM DEBT
The system companies have various revolving credit lines, totaling $468 million.
NU, CL&P, WMECO, HWP, Northeast Nuclear Energy Company (NNECO), and The Rocky
River Realty Company (RRR) have established a revolving-credit facility with a
group of 15 banks. Under this facility, the participating companies may borrow
up to an aggregate of $343 million. Individual borrowing limits as of January 1,
1996 were $150 million for NU, $325 million for CL&P, $60 million for WMECO, $5
million for HWP, $50 million for NNECO, and $22 million for RRR. The system
companies may borrow funds on a short-term revolving basis, using either
fixed-rate loans or standby loans. Fixed rates are set using competitive
bidding. Standby-loan rates are based upon several alternative variable rates.
The system companies are obligated to pay a facility fee of 0.15 percent per
annum of each bank's total commitment under the three-year portion of the
facility, representing 75 percent of the total facility, plus 0.10 percent per
annum of each bank's total commitment under the 364-day portion of the
facility, representing 25 percent of the total facility. At December 31, 1995
and 1994, there were $42.5 million and $30 million in borrowings, respectively,
under the facility.
PSNH has credit lines totaling $125 million available through a revolving-credit
agreement with a group of 19 banks. PSNH may borrow funds on a short-term
revolving basis using either fixed-rate or standby loans. Fixed rates are set
using competitive bidding. Standby loan rates are based upon several alternative
variable rates. PSNH is obligated to pay a facility fee of 0.25 percent per
annum on the total commitment. At December 31, 1995 and 1994, there were no
borrowings under the agreement. These credit lines expire in May 1996. PSNH is
in the process of negotiating an increase and extension to the revolving
credit agreement.
The weighted average interest rate on notes payable to banks outstanding on
December 31, 1995 was 6.0 percent. The weighted average interest rates on notes
payable to banks and commercial paper outstanding on December 31, 1994 were 6.2
and 6.4 percent, respectively. Maturities of the short-term debt obligations
were for periods of three months or less.
The amount of short-term borrowings that may be incurred by the system's utility
companies is subject to periodic approval by the SEC under the 1935 Act. 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, PSNH, WMECO, and NAEC were authorized, as of January 1, 1995, to incur
short-term borrowings up to a maximum of $325 million, $175 million, $60
million, and $50 million, respectively. PSNH is see king approval from the NHPUC
to increase its short-term debt limit to $225 million.
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 employees' highest eligible compensation during
five consecutive years of employment. Total pension cost, part of which was
charged to utility plant, approximated $0.4 million in 1995, $7.7 million in
1994, and $29.2 million in 1993. Pension costs for 1995, 1994, and 1993 included
approximately $6.8 million, $9.2 million, and $27.7 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, 1995 1994 1993
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . $ 35,771 $ 39,317 $ 59,068
Interest cost. . . . . . . . . . . . 89,351 84,284 81,456
Return on plan assets. . . . . . . . (310,997) 2,268 (176,798)
Net amortization . . . . . . . . . . 186,310 (118,188) 65,447
--------- --------- ---------
Net pension cost . . . . . . . . . . $ 435 $ 7,681 $ 29,173
========= ========= =========
- ------------------------------------------------------------------------------
For calculating pension cost, the following assumptions were used:
- ------------------------------------------------------------------------------
For the Years Ended
December 31, 1995 1994 1993
- ------------------------------------------------------------------------------
Discount rate. . . . . . . . . . . . 8.25% 7.75% 8.00%
Expected long-term rate
of return. . . . . . . . . . . . 8.50 8.50 8.50
Compensation/progression
rate . . . . . . . . . . . . . . 5.00 4.75 5.00
- ------------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- ------------------------------------------------------------------------------
At December 31, 1995 1994
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31, 1995 and 1994
of $913,269,000 and
$815,646,000, respectively . . . $ 998,614 $ 893,653
========== ==========
Projected benefit obligation . . . . $1,278,434 $1,112,993
Market value of plan assets. . . . . 1,503,597 1,266,239
---------- ----------
Market value in excess of
projected benefit obligation . . . 225,163 153,246
Unrecognized transition amount . . . (13,648) (15,191)
Unrecognized prior service costs . . 9,710 10,373
Unrecognized net gain. . . . . . . . (311,855) (238,622)
--------- -----------
Accrued pension liability. . . . . . $ (90,630) $ (90,194)
========= ==========
- ------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- ------------------------------------------------------------------------------
At December 31, 1995 1994
- ------------------------------------------------------------------------------
Discount rate. . . . . . . . . . . . 7.50% 8.25%
Compensation/progression rate. . . . 4.75 5.00
- ------------------------------------------------------------------------------
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 costs. 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
$44.1 million in 1995, $47.6 million in 1994, and $50.1 million in 1993. All of
the subsidiaries of NU 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, 1995 1994 1993
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . $ 7,137 $ 7,418 $ 9,175
Interest cost. . . . . . . . . . . . . 24,693 25,319 25,330
Return on plan assets. . . . . . . . . (7,812) 236 (220)
Amortization of unrecognized
transition obligation. . . . . . . . 15,134 15,134 15,961
Other amortization, net. . . . . . . . 4,924 (553) (106)
------- ------- -------
Net health care and life
insurance costs. . . . . . . . . . . $44,076 $47,554 $50,140
======= ======= =======
- ------------------------------------------------------------------------------
For calculating SFAS 106 benefits cost, the following assumptions were used:
- ------------------------------------------------------------------------------
For the Years Ended
December 31, 1995 1994 1993
- ------------------------------------------------------------------------------
Discount rate. . . . . . . . . . . . . 8.00% 7.75% 7.75%
Long-term rate of return--
Health assets, net of tax. . . . . . 5.00 5.00 5.00
Life assets. . . . . . . . . . . . . 8.50 8.50 8.50
- ------------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- ------------------------------------------------------------------------------
At December 31, 1995 1994
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees . . . . . . . . . . . . . $ 253,993 $ 251,448
Fully eligible active employees. . 354 416
Active employees not eligible
to retire. . . . . . . . . . . . 84,056 69,556
--------- ---------
Total accumulated postretirement
benefit obligation . . . . . . . . . 338,403 321,420
Market value of plan assets. . . . . . 56,791 26,406
--------- ---------
Accumulated postretirement benefit
obligation in excess of plan assets. (281,612) (295,014)
Unrecognized transition
amount . . . . . . . . . . . . . . . 257,283 272,417
Unrecognized net loss (gain) . . . . . 96 (4,772)
--------- ---------
Accrued postretirement
benefit liability. . . . . . . . . . $ (24,233) $ (27,369)
========= =========
- ------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plan's year-end
funded status:
- ------------------------------------------------------------------------------
At December 31, 1995 1994
- ------------------------------------------------------------------------------
Discount rate. . . . . . . . . . . . . 7.50% 8.00%
Health care cost trend rate (a) . . . 8.40 10.20
- ------------------------------------------------------------------------------
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 5.4 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, 1995 by $18.3 million and the aggregate of
the service and interest-cost components of net periodic postretirement benefit
cost for the year then ended by $1.6 million. The trust holding the plan assets
is subject to federal income taxes at a 35 percent tax rate.
CL&P, PSNH, and WMECO are currently recovering SFAS 106 costs, including amounts
previously deferred.
C. 401(K) SAVINGS PLAN
NU maintains a 401(k) Savings Plan for substantially all employees. This savings
plan provides for employee contributions up to specified limits. The company
matches employee contributions up to a maximum of 3 percent of eligible
compensation. The matching contributions for the company were $12.1 million for
1995 and 1994, and $12.2 million for 1993.
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 1995 and 1994, the ESOP trust issued approximately 655,000 and 664,000 of NU
common shares, respectively, totaling approximately $15.2 million and $15.5
million, respectively. These costs were charged to the 401(k) plan. As of
December 31, 1995 and 1994, the total allocated ESOP shares were 2,239,666 and
1,585,281, respectively, and total unallocated ESOP shares were 8,560,519 and
9,215,904, respectively. The fair market value of unallocated ESOP shares as of
December 31, 1995 and 1994 was approximately $207.6 million and $199.3 million,
respectively.
During 1995, the ESOP trust used approximately $22.7 million in dividends paid
on NU common shares and $13.2 million in contributions from NU to meet principal
and interest payments on ESOP notes.
6. COMMITMENTS AND CONTINGENCIES
A. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision. The system
companies currently forecast construction expenditures of approximately $1.2
billion for the years 1996-2000, including $265.1 million for 1996. In addition,
the system companies estimate that nuclear fuel requirements, including nuclear
fuel financed through the NBFT, will be $344.9 million for the years 1996-2000,
including $45.7 million for 1996. See Note 2, "Leases," for additional
information about the financing of nuclear fuel.
B. NUCLEAR PERFORMANCE
Outages that occurred over the period October 1990 through February 1992 at the
Millstone nuclear units have been the subject of five ongoing prudence reviews
in Connecticut. CL&P has received final decisions on each of the reviews. Three
of these prudence reviews are either on appeal or still pending at the DPUC. The
exposure under these three dockets is approximately $92 million.
On April 10, 1995, the DPUC initiated a proceeding to investigate the prudence
of a Millstone 2 extended outage, which ended June 1994.
Approximately $13 million of costs are at issue.
In October 1994, Millstone 2 began a planned refueling and maintenance outage
that was originally scheduled for 63 days. The outage encountered several
unexpected difficulties which extended the duration of the outage until August
4, 1995. Total replacement-power costs attributable to the extension of the
outage for CL&P and WMECO were approximately $85 million. Operation and
maintenance (O&M) costs incurred during the outage were approximately $70
million, an increase of $24 million as a result of the outage extension. O&M
costs associated with the refueling outage are deferred and amortized through
rates for CL&P and WMECO. The recovery of replacement-power and O&M costs is
subject to refund pending prudence reviews in both Connecticut and
Massachusetts.
Management does not believe the outcome of the prudence reviews discussed above
will have a material adverse impact on the system's financial position and
results of operations.
In November 1995, Millstone 1 began a planned refueling and maintenance outage
that was originally scheduled for 49 days. The outage has encountered several
unexpected difficulties, which have lengthened the duration of the outage. The
impact of the outage extension is currently under review, but the unit is not
expected to return to service until the mid-to-late part of the second quarter
of 1996. The estimated costs attributable to the outage extension are
replacement-power costs of $6.5 million per month and O&M costs of approximately
$20 million. Recovery of the costs related to this outage is subject to prudence
reviews by the DPUC and the Massachusetts Department of Public Utilities.
On January 31, 1996, the NRC announced that the three Millstone nuclear power
plants had been placed on its "watch list" because of long-standing performance
concerns. The NRC cited a number of operational problems, which have arisen
since 1990 at the Millstone plants.
The NRC recognized that there are significant current variations in the
performance of the three units. The performance concerns cited by the NRC,
combined with NU's failure to maintain previous performance improvements, have
resulted in the NRC requiring close monitoring of Millstone unit operations and
the implementation of a corrective action program. While the NRC has not
specifically restricted operations at the Millstone site, the company expects
that there will be costs associated with the NRC's actions that cannot
accurately be estimated at this time.
C. ENVIRONMENTAL MATTERS
The system is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the 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.
The cumulative long-term, cost impact of increasingly stringent environmental
requirements cannot accurately be estimated. 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 system has recorded a liability for what it believes, based upon information
currently available, are its estimated environmental remediation costs for waste
disposal sites that the system's subsidiaries expect to incur. 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, 1995, 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 $15
million, which management has determined to be the most probable amount within
the range of $15 million to $19 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.
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
million per nuclear unit in any one year. The maximum assessment is to be
adjusted at least every five years for inflationary changes. Based on the
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
the three operating Yankee regional nuclear generating companies, 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 was 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 $15.6 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 $12.3 million under
the replacement-power policies and $50.6 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 $3.0 million per
reactor. The maximum potential assessment against the system with respect to
losses arising during the current policy period is approximately $13.1 million.
E. LONG-TERM CONTRACTUAL ARRANGEMENTS
YANKEE COMPANIES: CL&P, PSNH, and WMECO purchased approximately 6.7 percent of
their electricity requirements pursuant to long-term contracts with the Yankee
companies. Under the terms of their agreements, the companies pay their
ownership (or entitlement) shares of generating 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
these contracts for the units that are operating amounted to $161.1 million in
1995, $154.3 million in 1994, and $169.0 million in 1993.
See Note 1C, "Summary of Significant Accounting Policies--Investments and
Jointly Owned Electric Utility Plant," and Note 3, "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. Some of these
arrangements have terms from 10 to 30 years, currently expiring in the years
1998 through 2026, and require the companies to purchase the energy at specified
prices or formula rates. For the 12 months ended December 31, 1995,
approximately 13 percent of system electricity requirements was met by NUGs. The
total cost of purchases under these arrangements amounted to $440.4 million in
1995, $435.0 million in 1994, and $426.8 million in 1993. These costs are
eventually recovered through the companies' rates. For additional information,
see Note 1J, "Summary of Significant Accounting Policies--Recoverable Energy
Costs--PSNH."
NEW HAMPSHIRE ELECTRIC COOPERATIVE, INC. (NHEC): PSNH entered into a buy-back
agreement to purchase the capacity and energy of NHEC's share of Seabrook 1 and
to pay all of NHEC's Seabrook 1 costs for a ten-year period, which began July 1,
1990. The total cost of purchases under this agreement was $15.8 million in
1995, $14.6 million in 1994, and $14.4 million in 1993. 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
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, in the aggregate, 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.
The estimated annual costs of the system's significant long-term contractual
arrangements are as follows:
- --------------------------------------------------------------------------
1996 1997 1998 1999 2000
- --------------------------------------------------------------------------
(Millions of Dollars)
Yankee
Companies . . . . . $160.1 $156.8 $169.0 $171.3 $182.9
Nonutility
Generators. . . . . 430.2 440.5 452.1 467.3 474.8
NHEC. . . . . . . . 14.6 22.5 29.5 29.7 14.6
Hydro-Quebec. . . . 35.8 34.0 32.9 32.1 31.6
- --------------------------------------------------------------------------
7. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-defined
interest-rate and fuel-price risks. The company does not use them for trading
purposes.
INTEREST-RATE CAP CONTRACTS: CL&P, PSNH, and WMECO have entered into
interest-rate cap contracts with financial institutions in order to reduce a
portion of the interest-rate risk associated with certain variable-rate
tax-exempt pollution control revenue bonds. During 1995, there were three
outstanding contracts held by CL&P, PSNH, and WMECO covering $467 million of
variable-rate debt, all of which expired in January 1996. The contracts entitled
CL&P, PSNH, and WMECO to receive from counterparties the amounts, if any, by
which the interest payments on a portion of its variable-rate tax-exempt
pollution control revenue bonds exceed the J.J. Kenny High Grade Index. Due to
their upcoming expiration, as of December 31, 1995, the total fair market value
of these caps was $0.
FUEL SWAPS: CL&P also uses fuel-swap agreements with financial institutions
to hedge against some of the fuel-price risk created by long-term negotiated
energy contracts. These fuel swaps minimize exposure associated with rising fuel
prices and effectively fix most of CL&P's cost of fuel for these negotiated
energy contracts. Under the swap agreements, CL&P exchanges monthly payments
based on the differential between a fixed and variable price for the associated
fuel. As of December 31, 1995, CL&P had outstanding agreements with a total
notional value of approximately $249 million, and a negative mark-to-market
position of approximately $19 million. When the mark-to-market position for the
swap agreements is negative, the profitability of the long-term negotiated
energy contracts whose fuel exposure has been hedged increases by a
corresponding amount.
INTEREST-RATE SWAPS: NAEC uses interest-rate swap agreements with financial
institutions to hedge against interest-rate risk associated with its $225
million variable-rate bank note. The interest-rate swaps minimize exposure
associated with rising interest rates, and effectively fix the interest rate for
this borrowing arrangement. Under the swap agreement, 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, 1995, NAEC had
outstanding agreements with a total notional value of approximately $225 million
and a negative mark-to-market position of approximately $3.8 million.
These swap agreements have been made with various financial institutions, each
of which are rated "A" or better by Standard & Poor's rating group. The system
companies are exposed to credit risk on fuel swaps, and interest-rate
swaps if the counterparties fail to perform their obligations. However, the
system companies anticipate that the counterparties will be able to fully
satisfy their obligations under the contracts.
8. 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 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, and was adopted by the company on a prospective basis as of January 1,
1994. During 1995, the investments held in the company's nuclear decommissioning
trusts increased by approximately $19.3 million as of December 31, 1995 and
decreased by approximately $5.5 million as of December 31, 1994, with a
corresponding offset to the accumulated provision for depreciation. The $19.3
million increase in 1995 represents cumulative gross unrealized holding gains.
The cumulative gross unrealized holding losses were immaterial for 1995. The
$5.5 million decrease in 1994 represents cumulative gross unrealized holding
gains of $1.9 million, offset by cumulative gross unrealized holding losses of
$7.4 million. There was no change in funding requirements of the trusts nor any
impact on earnings as a result of the adoption of SFAS 115.
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:
- ------------------------------------------------------------------------------
Carrying Fair
At December 31, 1995 Amount Value
- ------------------------------------------------------------------------------
(Thousands of Dollars)
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
Monthly Income
Preferred Securities. . . . . . . . 100,000 108,520
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
Carrying Fair
At December 31, 1995 Amount Value
- ------------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption . . . . . . . . $ 234,700 $ 179,875
Preferred stock subject to
mandatory redemption . . . . . . . . 379,675 370,250
Long-term debt --
First Mortgage Bonds . . . . . . . . 2,291,550 22,151,744
Other long-term debt . . . . . . . . 1,830,400 1,811,627
- ------------------------------------------------------------------------------
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.
9. MONTHLY INCOME PREFERRED SECURITIES OF SUBSIDIARY
In January 1995, CL&P Capital, L.P. (CL&P LP) 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
a minority interest.
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED (a)
1995 March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share data)
Operating Revenues .................................. $944,705 $840,333 $985,092 $978,861
======== ======== ======== ========
Operating Income..................................... $167,327 $118,410 $162,298 $143,945
======== ======== ======== ========
Net Income .......................................... $ 86,284 $ 42,398 $ 89,526 $64,226
======== ======== ======== ========
Earnings Per Common Share............................ $0.69 $0.34 $0.71 $0.50
======== ======== ======== ========
1994
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues .................................. $966,174 $854,627 $923,708 $898,233
======== ======== ======== ========
Operating Income..................................... $161,290 $124,988 $137,254 $130,393
======== ======== ======== ========
Net Income .......................................... $ 95,888 $ 61,145 $ 65,029 $ 64,812
======== ======== ======== ========
Earnings Per Common Share............................ $0.77 $0.49 $0.52 $0.52
======== ======== ======== ========
CONSOLIDATED GENERATION STATISTICS
1995 1994 1993 1992(b) 1991
- -------------------------------------------------------------------------------------------------------------------------------
SOURCE OF ELECTRIC ENERGY: (KWH--MILLIONS)
Nuclear--Steam (c)................................ 18,235 19,443 22,965 15,520 11,062
Fossil--Steam..................................... 9,162 8,292 7,676 6,784 6,179
Hydro--Conventional............................... 1,099 1,239 1,140 1,076 994
Hydro--Pumped Storage............................. 1,209 1,195 1,269 1,221 1,173
Internal Combustion............................... 37 13 8 9 25
Energy Used for Pumping........................... (1,674) (1,629) (1,749) (1,671) (1,605)
------ ------ ------ ------ ------
Net Generation.................................. 28,068 28,553 31,309 22,939 17,828
Purchased and Net Interchange..................... 14,256 14,028 10,499 14,165 13,430
Company Use and Unaccounted for .................. (2,706) (2,535) (2,591) (2,028) (1,958)
------ ------ ------ ------ ------
Net Energy Sold................................. 39,618 40,046 39,217 35,076 29,300
====== ====== ====== ====== ======
- -------------------------------------------------------------------------------------------------------------------------------
System Capability-MW (c).............................. 8,394.8 8,494.8 7,795.3 7,823.2 5,916.2
System Peak Demand-MW................................. 6,358.2 6,338.5 6,191.0 5,781.0 4,999.8
Nuclear Capacity-MW (c)............................... 3,239.6 3,272.6 3,110.0 2,981.1 2,380.0
Nuclear Contribution to Total
Energy Requirements (%) (c)......................... 52.0 54.0 62.1 48.5 43.5
Nuclear Capacity Factor (%) (d)....................... 69.9 67.5 80.8 63.7 50.6
- -------------------------------------------------------------------------------------------------------------------------------
(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.
SELECTED CONSOLIDATED FINANCIAL DATA
1995 1994 1993 1992(a) 1991
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except percentages and share data)
BALANCE SHEET DATA:
Net Utility Plant (b)................. $ 7,000,837 $ 7,282,421 $ 7,439,159 $ 7,588,368 $ 5,257,567
Total Assets.......................... 10,544,966 10,584,880 10,668,164 9,724,340 6,781,746
Total Capitalization (c).............. 6,820,624 7,035,989 7,309,898 7,421,592 5,138,426
Obligations Under Capital Leases (c).. 230,482 239,121 243,760 266,100 279,729
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME DATA:
Operating Revenues.................... $ 3,748,991 $ 3,642,742 $ 3,629,093 $ 3,216,874 $ 2,753,803
Net Income ........................ 282,434 286,874 249,953(d) 256,054 236,709
Earnings per Common Share............. $2.24 $2.30 $2.02(d) $2.02 $2.12
- ----------------------------------------------------------------------------------------------------------------------------------
COMMON SHARE DATA:
Earnings per Share.................... $2.24 $2.30 $2.02(d) $2.02 $2.12
Dividends per Share................... $1.76 $1.76 $1.76 $1.76 $1.76
Payout Ratio (%)...................... 78.6 76.5 87.1 87.1 83.0
Number of Shares
Outstanding--Average................ 126,083,645 124,678,192 123,947,631(e) 130,403,488 111,453,550
Market Price--High.................... $25 3/8 $25 3/4 $28 7/8 $26 3/4 $24 3/8
Market Price--Low..................... $21 $20 3/8 $22 $22 1/2 $19
Market Price--Closing Price...........
(end of year)....................... $24 1/4 $21 5/8 $23 3/4 $26 1/2 $23 5/8
Book Value per Share (end of year)... $19.08 $18.47 $17.89 $16.24 $15.73
Rate of Return Earned on Average
Common Equity (%)................. 12.0 12.7 11.4 12.7 13.0
Dividend Yield (end of year) (%)...... 7.3 8.1 7.4 6.6 7.4
Cash Coverage of Common Dividends..... 4.2 4.0 3.3 2.6 2.4
Market-to-Book Ratio (end of year).... 1.3 1.2 1.3 1.6 1.5
Price-Earnings Ratio (end of year).... 10.8 9.4 11.8 13.1 11.1
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Common Shareholders' Equity........... 36% 33% 30% 29% 37%
Preferred Stock (c)(f)................ 7 9 9 9 11
Long-term Debt (c).................... 57 58 61 62 52
---------- ----------- ----------- ----------- -----------
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.
CONSOLIDATED SALES STATISTICS
1995 1994(a) 1993 1992(b) 1991
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REVENUES: (THOUSANDS)
Residential....................... $1,469,988 $1,430,239 $1,385,818 $1,213,140 $995,098
Commercial........................ 1,230,608 1,173,808(c) 1,043,125 943,832 828,117
Industrial........................ 583,204 559,801(c) 649,876 554,587 419,003
Other Utilities................... 303,004 330,801 383,129 346,791 366,231
Streetlighting and Railroads...... 47,510 45,943 45,480 43,296 38,656
Miscellaneous..................... 48,784 44,140 60,008 59,465 49,539
---------- ---------- ---------- ---------- ----------
Total Electric.................. 3,683,098 3,584,732 3,567,436 3,161,111 2,696,644
Other............................. 65,893 58,010 61,657 55,763 57,159
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Total........................... $3,748,991 $3,642,742 $3,629,093 $3,216,874 $2,753,803
========== ========== ========== ========== ==========
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SALES: (KWH--MILLIONS)
Residential....................... 12,005 12,231 11,988 10,839 9,518
Commercial........................ 11,737 11,649(c) 10,304 9,608 8,900
Industrial........................ 6,842 6,729(c) 7,572 6,593 5,208
Other Utilities................... 8,718 9,123 9,046 7,733 5,388
Streetlighting and Railroads...... 316 314 307 303 286
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Total........................... 39,618 40,046 39,217 35,076 29,300
========== ========== ========== ========== ==========
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CUSTOMERS: (AVERAGE)
Residential....................... 1,526,127 1,513,987 1,503,182 1,351,019 1,150,357
Commercial........................ 156,652 154,703(c) 155,487 132,680 102,867
Industrial........................ 7,861 7,813(c) 6,272 5,774 5,067
Other............................. 3,878 3,818 3,793 3,581 3,305
---------- ---------- ---------- ---------- ----------
Total......................... 1,694,518 1,680,321 1,668,734 1,493,054 1,261,596
========== ========== ========== ========== ==========
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AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (KWH)................. 7,917 8,152 7,987 8,129 8,285
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AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER....................... $969.41 $953.23 $923.32 $909.80 $866.20
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AVERAGE REVENUE PER KWH:(in cents)
Residential....................... 12.24 11.69 11.56 11.19 10.45
Commercial........................ 10.49 10.08 10.12 9.82 9.30
Industrial........................ 8.52 8.32 8.58 8.41 8.05
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(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.