Exhibit 13.1
1994
PORTIONS OF ANNUAL REPORT TO SHAREHOLDERS
NORTHEAST UTILITIES
FINANCIAL AND STATISTICAL SECTION
TABLE OF CONTENTS
Page 16-23
Management's Discussion and Analysis
Page 24
Company Report
Page 24
Report of Independent Public Accountants
Page 25
Consolidated Statements of Income
Page 26
Consolidated Statements of Cash Flows
Page 27
Consolidated Statements of Income Taxes
Page 28-29
Consolidated Balance Sheets
Page 30-31
Consolidated Statements of Capitalization
Page 32
Consolidated Statements of Common Shareholders' Equity
Page 33-46
Notes to Consolidated Financial Statements
Page 47
Consolidated Statements of Quarterly Financial Data
Page 47
Consolidated General Operating Statistics
Page 48-49
Selected Consolidated Financial Data
Page 50
Consolidated Electric Operating Statistics
MANAGEMENT DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
Overview
Earnings per common share were $2.30 in 1994, as compared to $2.02
in 1993. The 1994 earnings were higher as a result of higher retail
kilowatt-hour sales, retail rate increases for CL&P and PSNH, the deferral of
cogeneration expenses in Connecticut, and reduced operation and interest
costs. These increases were partially offset by lower revenues from wholesale
sales. The 1993 earnings were impacted by a number of one-time items,
including the cumulative effect of a one-time change in the accounting for
Connecticut municipal property taxes, which resulted in an increase in 1993
earnings of $0.42 per common share. In addition, 1993 earnings reflected a
decrease of $0.14 per share for the costs of the company's employee-reduction
program and a decrease of $0.12 per share for disallowances in 1993 ordered
by Connecticut regulators in the CL&P rate case. Earnings per common share
before the effects of the change in accounting for property taxes and other
one-time items were $1.86 in 1993.
Increased earnings will help the company to achieve its objective
of increasing total return to shareholders (stock price plus dividend
return). In 1994, total return to shareholders was more than 13 percentage
points better than the Dow Jones Utilities Index.
In 1994, NU experienced its most significant retail kilowatt-hour
sales growth in six years, due in large part to the beginning of an economic
recovery in New England. Employment levels-particularly in New Hampshire -
have risen, unemployment rates have fallen, and personal income has
increased in all three states served by the NU operating companies (the
system). NU's 1994 retail sales rose by 2.9 percent over 1993. Overall,
weather had little effect on sales volume, with mild weather after mid-August
offsetting unusually cold weather in January and hot weather in late June and
July.
In 1995, the company expects little retail sales growth over
1994, primarily because of the effects of higher interest rates on the
regional economy and further cutbacks in defense-related industries in
Connecticut. Over the longer term, retail kilowatt-hour sales growth is
expected to be strongest in New Hampshire, which by some measures has the
fastest growing economy in New England. In 1994, many businesses announced
plans to expand in New Hampshire. NU estimates PSNH to have compounded annual
sales growth of 1.9 percent from 1994 through 1999, compared with 1.4 percent
for CL&P and 0.9 percent for WMECO.
Competitive forces within the electric utility industry are
continuing to increase due to a variety of influences, including legislative
and regulatory actions, technological advances, and changes in consumer
demand. The company has developed, and is continuing to develop, a number of
initiatives to retain and to continue to serve its existing customers and to
expand its retail and wholesale customer base.
NU believes the steps it is taking, including a companywide
process reengineering effort, will have significant, positive effects,
including reduced operating costs and improved customer service, in the next
few years. The system also benefits from a diverse retail base with no
significant dependence on any one retail customer or industry.
NU's electric utility subsidiaries continue to operate
predominantly in state-approved franchise territories under traditional
cost-of-service regulation. Retail wheeling, under which a retail customer
would be permitted to select an electricity supplier and require the local
electric utility to transmit the power to the customer's site, is not
required in any of the system's jurisdictions. In 1994, Connecticut
regulators reviewed the desirability of retail wheeling and determined that
it was not in the best interest of the state until new generating capacity is
needed, which the company projects to be in the year 2009. In New Hampshire
and Massachusetts, bills related to retail wheeling have been introduced in
the legislature. Connecticut, New Hampshire, and Massachusetts regulators are
presently studying the potential restructuring of the electric utility
industry. To date, none of these bills have been enacted and none of the
regulatory proceedings have progressed to the point where management can assess
the impact of any potential outcomes on the company.
While retail competition is not required in the system's retail
service territory, competitive forces are nonetheless influencing retail
pricing. These forces include competition from alternate fuels such as
natural gas, competition from customer-owned generation, and regional
competition for business retention and expansion. The company's retail
business group continues to work with customers to address their concerns.
The system has reached long-term rate agreements with many new and existing
customers to gain or retain their business. In general, these rate agreements
have terms of about five years. Negotiated retail rate reductions for system
customers under rate agreements in effect for 1994 amounted to approximately
$20 million. Management believes that the aggregate amount of negotiated
retail rate reductions will increase in 1995 but that the related agreements
will continue to provide significant benefits to the company, including the
preservation of approximately 4 percent of retail revenues.
The company is also working with regulators to address the needs
of customers more widely. The company has multiyear rate plans in effect in
each of its retail jurisdictions. Management will continue to evaluate the
use of agreements of this type to keep retail rates competitive.
The system acts as both a buyer and a seller of electricity in
the highly competitive wholesale electricity market in the Northeastern
United States (Northeast). Many of the contracts signed in the late 1980s
have or will expire in the mid-1990s and much of the revenue produced by such
contracts has not been replaced through new wholesale power arrangements. As
a result, wholesale power revenues fell to approximately $331 million in 1994
from approximately $383 million in 1993. Unless prices on the wholesale market
improve, revenues are expected to fall still further in 1995 before stabilizing
in late 1996 and 1997. Wholesale sales are made primarily to investor-owned
utilities and municipal or cooperative electric systems in the Northeast. The
system will be increasing its efforts to increase wholesale sales through
intensified marketing efforts. The system's wholesale power marketing efforts
benefit from the interconnection of its transmission system with all of the
major utilities in New England, as well as with three of the larger electric
utilities in New York state.
Rate Matters
The operating companies of the system follow accounting principles
that allow the rate treatment for certain events or transactions to be
reflected. These principles may differ from the accounting principles followed
by nonregulated enterprises. Regulators may permit incurred costs, which would
normally be treated as expenses by nonregulated enterprises, to be deferred as
regulatory assets and recovered in revenues at a later date. Regulatory assets
at December 31, 1994 were approximately $2.7 billion. Based on current
regulation, the company believes that its use of regulatory accounting is still
appropriate.
See the "Notes To Consolidated Financial Statements," Note 1H,
for further details on regulatory accounting.
Connecticut
CL&P's retail rates increased by approximately $47 million, or 2.04
percent, in July 1994, representing the second step of a three-year rate plan
approved by the Department of Public Utility Control (DPUC) in 1993. The third
step of an approximately $48-million, or 2.06 percent, increase will become
effective in July 1995. CL&P's 1993 rate decision has been appealed by the
Connecticut Office of Consumer Counsel and the city of Hartford. If this appeal
prevails, there may be revenues subject to refund; however, management believes
that the possibility of the appeal prevailing is unlikely.
CL&P recovers from or refunds to customers certain fuel costs if
the nuclear units do not operate at a predetermined capacity factor (currently
72 percent) through a Generation Utilization Adjustment Clause (GUAC). For the
GUAC year ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel
costs and reduced by approximately $8 million CL&P's overall request to recover
approximately $24 million of deferred GUAC costs. The company plans to appeal
the decision in court as it did for a similar DPUC decision on the 1992-1993
GUAC period, which also disallowed approximately $8 million of GUAC costs.
For the GUAC year ended July 31, 1995, CL&P expects to defer in
excess of $50 million of GUAC fuel costs for projected nuclear performance below
72 percent. As of December 31, 1994, CL&P has reserved approximately $13 million
against this amount, based on the methodology applied by the DPUC in the
previous GUAC decisions.
New Hampshire
In June 1994, PSNH's base rates increased by 5.5 percent under a
seven-year 1989 rate agreement approved by the New Hampshire Public Utilities
Commission (NHPUC).
The costs associated with purchases by PSNH from certain
nonutility generators (NUGs) over the level assumed in rates are deferred and
recovered over ten-year periods through the Fuel and Purchased Power
Adjustment Clause (FPPAC). At December 31, 1994, the unrecovered deferrals
were approximately $174 million. PSNH is attempting to renegotiate these
arrangements with the NUGs.
On September 23, 1994, the NHPUC approved settlement agreements
with two wood-fired NUGs covering approximately 20 megawatts (MW) of
capacity. These two NUGs gave up their rights to sell their output to PSNH in
exchange for lump-sum cash payments by PSNH totaling approximately $40
million. The buyout payments were added to the deferred balance of NUG costs.
The savings resulting from the agreements will be used to reduce the NUG
deferred balance over the remaining period of the canceled arrangements. PSNH
is involved in mediations with the owners of the six remaining wood-fired
facilities, which account for approximately 87 MW of capacity. PSNH has reached
an agreement with one of these six NUGs, which calls for a payment by PSNH of
$52 million in return for a substantial reduction in the rates charged to
PSNH. This agreement was filed with the NHPUC in February 1995.
Massachusetts
On May 26, 1994, the Massachusetts Department of Public Utilities
(DPU) approved a settlement agreement under which WMECO's customers received a
base-rate reduction of approximately $13 million over a 20-month period
effective June 1, 1994 and a guarantee of no general base-rate increases before
February 1996. This agreement also terminated, without findings, all performance
review proceedings regarding the treatment of replacement-power costs incurred
by WMECO during power outages from mid-1987 through mid-1993. The DPU also
approved the amortization of previously deferred expenses for postretirement
benefits beginning in July 1994. In addition, under the agreement, WMECO's
larger customers will be offered discounts on their electric bills in return for
providing WMECO with five years' notice of any plans to self-generate or
purchase electricity from a different provider. The combined base-rate reduction
and service-extension discounts will total 5 percent for those larger customers.
The settlement agreement did not have a significant adverse impact on WMECO's
earnings.
Nuclear Performance
The composite capacity factor of the five nuclear generating units
that the system operates-including the Connecticut Yankee (CY) nuclear unit-was
67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the result
of extended refueling and maintenance outages for Millstone 1, Millstone 2, and
Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying
lengths of time in 1994 because of unexpected technical and operating
difficulties. These difficulties included a manual shutdown of CY when both
service water headers were declared inoperable, an automatic trip from 100
percent power for Seabrook when a main steam isolation valve closed during
quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded
lower seal on a reactor coolant pump.
On October 1, 1994, Millstone 2 was shut down for a planned
63-day refueling and maintenance outage. The outage has encountered several
unexpected difficulties, which will lengthen the duration of the outage. The
outage extensions were caused by a significant scope increase in service
water system repairs, as identified through a comprehensive inspection plan
and by a need for management to exercise a deliberate approach to the conduct
of work during the early portions of the outage. The outage schedule is
currently under review, but the unit is not expected to return to service
before April 1995. Total replacement-power costs attributable to the
extension of the outage for CL&P and WMECO are expected to be in the range of
$8 million per month. CL&P's share of these costs is deferred for future
recovery through the GUAC. (See page 18 for further discussion of the GUAC.) In
addition, operation and maintenance costs to be incurred during the outage are
estimated to be $52 million, an increase of $19 million as a result of the
extension. The recovery of these costs is subject to prudence reviews in both
Connecticut and Massachusetts.
The Nuclear Regulatory Commission's (NRC's) latest report for the
Millstone Station noted significant weaknesses in Millstone 2's operations
and maintenance. In a public statement in late 1994, a senior NRC official
expressed disappointment with the continued weaknesses in Millstone 2's
performance. The primary cause of the NRC's disappointment with Millstone 2's
performance appears to be that, despite significant management attention and
action over a period of years, the NRC does not believe it has seen enough
objective evidence of improvement in reducing procedural noncompliance and
other human errors. Management has acknowledged the basis for the NRC's
concern with Millstone 2 and has been devoting increased attention to
resolving these issues. Management and the NRC expect to continue to monitor
closely the developments at Millstone 2.
Environmental Matters
The system devotes substantial resources to identify and then to
meet the multitude of environmental requirements it faces. The company has
active auditing programs addressing a variety of different regulatory
requirements, including an environmental auditing program to detect and
remedy noncompliance with environmental laws or regulations.
The system 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 the company.
At December 31, 1994, the liability recorded by the company amounted to
approximately $11 million. These costs could rise to as much as $16 million
if alternate remedies become necessary.
The company expects that the implementation of the 1990 Clean Air
Act Amendments (CAAA) as they relate to sulfur-dioxide emissions will require
only modest emission reductions for the NU system. NU's exposure is minimal
because of the company's investment in nuclear energy in the 1970s and 1980s and
the burning of low-sulfur fuels. PSNH is subject to more stringent emission
limits for nitrogen oxides within the next five years under the CAAA
requirements. PSNH will install at Merrimack Station a selective catalytic
reduction (SCR) pollution control system by May 1995 to comply with CAAA
requirements. The cost of the SCR installation is approximately $22 million,
with approximately $10 million of costs incurred as of December 31, 1994.
Nuclear Decommissioning
The system's estimated cost to decommission its shares of Millstone
units 1, 2, and 3 and Seabrook is approximately $1.2 billion in year-end 1994
dollars. In addition, the system's estimated cost to decommission its shares of
the regional nuclear generating units is estimated to be approximately $300
million. These costs are being recognized over the lives of the respective units
and a portion of the costs is being recovered through rates. Yankee Atomic
Electric Company (YAEC) has begun component removal activities related to the
decommissioning of its nuclear facility. The system's estimated obligation to
YAEC has been recorded on the Consolidated Balance Sheets. Management expects
that the system will continue to be allowed to recover these costs.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the electric
utility industry, including this company, regarding the recognition,
measurement, and classification of decommissioning costs for nuclear
generating stations in the financial statements of electric utilities. The
Financial Accounting Standards Board is currently reviewing the accounting
for removal costs, including decommissioning and similar costs. If current
electric utility industry accounting practices for such decommissioning costs
were changed: (1) annual provisions for decommissioning could increase, (2)
the estimated costs for decommissioning could be recorded as a liability
rather than as accumulated depreciation, and (3) trust fund income from the
external decommissioning trust could be reported as investment income rather
than as a reduction to decommissioning expense.
See the "Notes To Consolidated Financial Statements," Note 3, for
further information on nuclear decommissioning.
Two separate stacked bar graphs illustrate the sources and uses of cash
requirements for 1993 and 1994 and projections for 1995 through 1999.
NORTHEAST UTILITIES
SOURCES AND USES OF CASH REQUIREMENTS
1993 - 1999
Sources of Cash
Requirements 1993 1994 1995 1996 1997 1998 1999
--------------- ---- ---- ---- ---- ---- ---- ----
(Percentages)
Internally
Generated Funds 36.7 46.7 80.5 80.4 86.2 88.3 69.0
Nuclear Fuel Trust 5.2 6.7 7.2 16.3 13.8 9.3 11.5
LTD and Preferred
Stock 56.9 44.3 12.3 0.0 0.0 0.0 17.5
Short-Term Debt 0.0 1.2 0.0 1.1 0.0 0.0 0.0
Common Stock 1.2 1.1 0.0 2.2 0.0 2.4 2.0
----- ----- ----- ----- ----- ----- -----
Total Sources 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Uses of Cash
Requirements 1993 1994 1995 1996 1997 1998 1999
--------------- ---- ---- ---- ---- ---- ---- ----
(Percentages)
Construction 15.6 18.4 31.1 34.8 32.4 35.8 27.7
Nuclear Fuel 5.9 7.2 9.1 18.9 14.3 11.7 13.7
Maturities and
Sinking Fund 66.1 70.2 36.5 43.1 43.4 41.0 49.1
Repayment of
Short-Term Debt 10.1 0.0 19.6 0.0 8.2 10.6 8.6
Other 2.3 4.2 3.7 3.2 1.7 0.9 0.9
----- ----- ----- ----- ----- ----- -----
Total Uses 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Property Taxes
CY and PSNH have had significant court appeals for municipal property
tax assessments in the towns of Haddam, Connecticut, and Bow, New Hampshire. In
each case, the central issue is the fair market value of utility property. The
company believes that the assessments should be based on a fair market value
that approximates net book cost. This is the assessment level that taxing
authorities are predominantly using throughout Connecticut, Massachusetts, and
in some of New Hampshire. However, towns such as Haddam and Bow advocate a
method that approximates reproduction costs.
PSNH's appeal of the property tax as assessed against them by Bow
has been dismissed by the Supreme Court of New Hampshire. CY's appeal is
still pending. The company estimates that, for assessments in towns such as
Haddam and Bow, the change to the reproduction cost methodology could result
in property valuations approximately three times greater than values
approximating net book cost. If other towns adopt this methodology, there
could be a significant adverse impact on the company's future results of opera
tions and financial condition. However, the extent to which other towns
successfully adopt this methodology and any subsequent increase in the
company's property tax liability cannot be determined at this time.
Liquidity And Capital Resources
Cash provided from operations increased approximately $7 million
in 1994, as compared to 1993, primarily due to higher revenues from rate
increases and sales, combined with lower cash operating expenses. Cash used
for financing activities was approximately $10 million higher in 1994, as
compared to 1993, primarily due to higher net reacquisition and retirements
of long-term debt, partially offset by an increase in short-term debt. Cash
used for investments was approximately $20 million lower in 1994, as compared
to 1993, primarily due to lower construction expenditures in 1994.
The charts opposite illustrate the sources and uses of cash
requirements for 1993 and 1994 and the projections for 1995 through 1999.
In 1994, the NU system companies refinanced $625 million of debt,
which is expected to reduce interest costs by approximately $3 million
annually. With interest rates rising in mid-1994, a lot of refinancing
completed, and construction needs remaining modest, the focus in NU's
financing activities will shift toward using the significant amount of cash
generated by each subsidiary to retire debt and to prepare the company for an
increasingly competitive business environment.
The system companies are obligated to meet approximately $1.4
billion of long-term debt and preferred stock maturities and cash
sinking-fund requirements during the 1995 through 1999 period, including
approximately $176 million for 1995.
The system's construction program expenditures, including
allowance for funds used during construction, for the period 1995 through
1999 are estimated to be approximately $1.2 billion, including approximately
$254 million for 1995. The construction program's main focus is maintaining
and upgrading the existing transmission and distribution system, as well as
nuclear and fossil-generating facilities. The company does not foresee the
need for new, major generating facilities until at least the year 2009.
Construction expenditures and debt maturities and sinking-fund
requirements will continue to be met through internal cash generation. PSNH
may need to supplement its internal cash generation with outside financing,
including additional borrowings, if additional agreements are reached with
the wood-fired NUGs.
CL&P, PSNH, and WMECO entered into interest-rate cap contracts to
reduce a portion of the interest-rate risk on certain variable-rate
tax-exempt pollution control revenue bonds and a PSNH variable-rate term
loan. CL&P also uses fossil-fuel-swap agreements to hedge against fuel-price
risk on certain long-term, negotiated energy contracts. Any premiums paid on
these contracts are deferred and amortized over the life of the contracts.
The differential paid or received as interest rates or fuel prices change is
recognized in income when realized.
See the "Notes To Consolidated Financial Statements," Note 8, for
further information on derivative financial instruments.
Results of Operations
The relative magnitude of the various expenditures incurred by
the system's continuing operations in 1994 is illustrated in the chart on
page 23.
A majority of the changes in items affecting results of
operations between 1992 and 1993 is due to the inclusion of PSNH and NAEC
results for a full year in 1993 and only seven months in 1992.
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 $14 million in 1994
from 1993. Revenues related to regulatory decisions increased, primarily
because of the effects of the July 1993 and 1994 retail rate increases for
CL&P, the June 1993 and 1994 retail rate increases for 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
improving 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.
Operating revenues increased approximately $412 million in 1993
from 1992, primarily due to the additional revenues of PSNH for a full year
in 1993. Operating revenues, excluding PSNH, increased approximately $45
million in 1993 from 1992. Revenues related to regulatory decisions
increased, primarily because of the effects of the June 1993 retail rate
increase for CL&P and the July 1992 and 1993 retail rate increases for WMECO.
Fuel, purchased power, and FPPAC cost recoveries decreased, primarily due to
lower energy costs. Retail sales for CL&P and WMECO increased only 0.2 percent
in 1993 from 1992 sales levels.
Fuel, Purchased And Net Interchange Power
Fuel, purchased and net interchange power decreased approximately
$86 million in 1994, as compared to 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.
Fuel, purchased and net interchange power increased approximately
$145 million in 1993, as compared to 1992, primarily due to the additional
PSNH and NAEC expenses (approximately $99 million), the timing in the
recognition of fuel expenses under the provisions of CL&P's fuel adjustment cl
auses, and disallowances of replacement- power costs as a result of
regulatory reviews in Connecticut, partially offset by lower outside
purchases due to better nuclear performance in 1993.
Other Operation And Maintenance Expenses
Other operation and maintenance expenses decreased approximately $20
million in 1994, as compared to 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.
Other operation and maintenance expenses increased approximately
$143 million in 1993, as compared to 1992, primarily due to the additional
PSNH and NAEC expenses (approximately $105 million), the 1993 costs
associated with an employee-reduction program (approximately $33 million),
the 1992 reimbursement of previously expended costs associated with the PSNH
acquisition, and 1993 postretirement benefit costs, partially offset by lower
costs associated with the operation and maintenance activities of the nuclear
units.
Depreciation Expenses
Depreciation expenses increased approximately $14 million in
1994, as compared to 1993, primarily as a result of higher depreciable plant
balances, higher average depreciation rates, and higher decommissioning
collections.
Depreciation expenses increased $39 million in 1993, as compared
to 1992, primarily as a result of the additional PSNH and NAEC depreciation
expense ($27 million, including Seabrook), higher depreciation rates, and high
er depreciable plant balances.
Amortization Of Regulatory Assets, Net
Amortization of regulatory assets, net decreased approximately
$48 million in 1994, as compared to 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.
Amortization of regulatory assets, net increased approximately
$58 million in 1993, as compared to 1992, primarily because of the additional
amortization of the PSNH regulatory asset as provided for in the rate
agreement (approximately $38 million) and higher amortization of Millstone 3
and Seabrook phase-in costs. The increase in 1993 is also attributable to the
gross-up of taxes due to a required change in the accounting for income taxes
and the amortization in 1993 of costs paid by CL&P to the developers of two
wood-to-energy plants as allowed in the 1993 rate decision, partially offset
by the amortization of the PSNH regulatory liability recognized as a result
of a 1993 global settlement.
Federal And State Income Taxes
Federal and state income taxes increased approximately $66
million in 1994, as compared to 1993, primarily because of higher taxable
income.
Taxes Other Than Income Taxes
Taxes other than income taxes increased approximately $7 million in
1994, as compared to 1993, primarily due to higher Connecticut sales tax
expense.
Taxes other than income taxes increased approximately $19 million
in 1993, as compared to 1992, primarily due to the additional PSNH and NAEC
taxes ($20 million, including property taxes on Seabrook).
Deferred Nuclear Plants Return
Deferred nuclear plants return decreased approximately $25
million in 1994, as compared to 1993, primarily because additional Millstone
3 and Seabrook investments were phased into rates in 1994.
Deferred nuclear plants return increased approximately $19
million in 1993, as compared to 1992, primarily because of deferred return
associated with NAEC's ownership share of Seabrook (approximately $30
million), partially offset by a decrease in Millstone 3 deferred return
because additional Millstone 3 investment was phased into rates.
Other Income, Net
Other income, net decreased approximately $11 million in 1993, as
compared to 1992, primarily because of the allocation to customers of a
portion of the property tax accounting change as ordered by the DPUC in the
CL&P 1993 rate decision.
Interest Charges
Interest on long-term debt decreased approximately $19 million in
1994, as compared to 1993, primarily because of lower average interest rates
as a result of refinancing activities and lower 1994 debt levels.
Interest on long-term debt increased approximately $57 million in
1993, as compared to 1992, primarily because of higher debt levels from the
addition of PSNH and NAEC (approximately $57 million), partially offset by
lower average interest rates as a result of substantial refinancing activities.
The increase in 1993 is also due to the absence of an interest expense offset in
1993 for Employee Stock Option Plan (ESOP) dividends due to a change in
accounting for ESOPs.
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.
Tax Benefit Of Employee Stock Ownership Plan Dividends
The tax benefit of ESOP dividends of approximately $7 million in 1992
is the result of the company adopting an ESOP. In 1993, these benefits are
reflected as a reduction to income tax expense. See the "Notes To Consolidated
Financial Statements," Note 6, for further information regarding ESOP.
A pie chart illustrates the magnitude of the various expenses incurred by
the System's continuing operations in 1994.
NORTHEAST UTILITIES
1994 DISTRIBUTION OF REVENUE
Percent
-------
Energy Costs 22.9%
Other Operation and
Maintenance Expenses 21.3
Taxes 14.5
Other Operating Expenses
and Other Income, Net 13.0
Wages and Benefits 12.3
Interest Charges 8.8
Common and Preferred Dividends 7.2
-----
100.0%
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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
As explained in Notes 1B, 5B, and 6 to the financial statements, effective
January 1, 1993, Northeast Utilities and subsidiaries changed their methods
of accounting for property taxes, postretirement benefits other than
pensions, and employee stock ownership plans.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------
(Thousands of Dollars,
except share information)
Operating Revenues................................ $ 3,642,742 $ 3,629,093 $ 3,216,874
------------- ------------- -------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power....... 832,420 917,957 772,804
Other........................................... 919,044 979,403 828,345
Maintenance...................................... 306,429 265,926 274,495
Depreciation..................................... 335,019 321,359 282,738
Amortization of regulatory assets, net........... 160,909 208,506 150,413
Federal and state income taxes(See Consolidated
Statements Of Income Taxes)(Note 1I)<F1I>...... 293,644 224,678 246,227
Taxes other than income taxes.................... 247,045 240,413 221,422
------------- ------------- -------------
Total operating expenses.................. 3,094,510 3,158,242 2,776,444
------------- ------------- -------------
Operating Income.................................. 548,232 470,851 440,430
------------- ------------- -------------
Other Income:
Deferred nuclear plants return--other
funds (Note 1L)<F1L>.......................... 27,085 38,373 45,299
Equity in earnings of regional nuclear
generating and transmission companies......... 14,426 12,980 15,357
Other, net...................................... 7,745 4,747 15,672
Income taxes--credit............................ 13,518 10,772 36,787
------------- ------------- -------------
Other income, net......................... 62,774 66,872 113,115
------------- ------------- -------------
Income before interest charges............ 611,006 537,723 553,545
------------- ------------- -------------
Interest Charges:
Interest on long-term debt...................... 314,191 333,163 275,819
Other interest.................................. 8,037 13,059 3,503
Deferred nuclear plants return--borrowed
funds (Note 1L)<F1L>.......................... (41,138) (54,462) (28,838)
------------- ------------- -------------
Interest charges, net..................... 281,090 291,760 250,484
------------- ------------- -------------
Income before cumulative effect of
accounting change....................... 329,916 245,963 303,061
Cumulative effect of accounting
change (Note 1B)<F1B>........................... - 51,681 -
------------- ------------- -------------
Income before Preferred Dividends
of Subsidiaries....................... 329,916 297,644 303,061
Preferred Dividends of Subsidiaries............... 43,042 47,691 47,007
------------- ------------- -------------
Net Income 286,874 249,953 256,054
Tax benefit of Employee Stock Ownership
Plan dividends (Note 6)<F6>................ - - 7,348
------------- ------------- -------------
Earnings For Common Shares........................ $ 286,874 $ 249,953 $ 263,402
============= ============= =============
Earnings Per Common Share:
Before cumulative effect of accounting
change......................................... $ 2.30 $ 1.60 $ 2.02
Cumulative effect of accounting
change (Note 1B)<F1B>.......................... - 0.42 -
------------- ------------- -------------
Total Earnings Per Common Share................... $ 2.30 $ 2.02 $ 2.02
============= ============= =============
Common Shares Outstanding (average) (Note 6)<F6>.. 124,678,192 123,947,631 130,403,488
============= ============= =============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Cash Flows
-------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Cash Flows From Operating Activities:
Income before preferred dividends of subsidiaries........ $ 329,916 $ 297,644 $ 303,061
Adjustments to reconcile to net cash
from operating activities:
Depreciation........................................... 335,019 321,359 282,738
Deferred income taxes and investment tax credits, net.. 146,560 63,506 103,089
Deferred nuclear plants return, net of amortization.... 49,994 18,189 (3,619)
Recoverable energy costs, net of amortization.......... (85,573) 93,302 (109,013)
Amortization of regulatory asset-PSNH, net............. 55,319 67,379 51,143
Deferred demand-side management, net of amortization... (4,691) (23,955) (31,989)
Other sources of cash.................................. 42,375 136,346 127,519
Other uses of cash..................................... (52,260) (3,915) (53,711)
Changes in working capital:
Receivables and accrued utility revenues............... 8,133 2,797 3,162
Fuel, materials, and supplies.......................... 4,906 10,126 (9,686)
Accounts payable....................................... 51,824 (678) (38,889)
Accrued taxes.......................................... 17,031 (97,789) (8,627)
Other working capital (excludes cash).................. 22,329 30,010 30,109
----------- ------------ ------------
Net cash flows from operating activities................... 920,882 914,321 645,287
----------- ------------ ------------
Cash Flows Used For Financing Activities:
Issuance of common shares................................ 14,551 22,252 271,128
Issuance of long-term debt............................... 625,000 924,650 1,141,995
Issuance of preferred stock.............................. - 80,000 75,000
Net increase (decrease) in short-term debt............... 16,500 (179,240) 182,240
Reacquisitions and retirements of long-term debt......... (982,920) (1,051,501) (744,771)
Reacquisitions and retirements of preferred stock........ (7,325) (116,496) (106,893)
Cash dividends on preferred stock........................ (43,042) (47,691) (49,399)
Cash dividends on common shares.......................... (219,317) (218,179) (229,074)
----------- ------------ ------------
Net cash flows (used for) from financing activities........ (596,553) (586,205) 540,226
----------- ------------ ------------
Investment Activities:
Investments in plant:
Electric and other utility plant....................... (259,904) (275,741) (311,892)
Nuclear fuel........................................... (28,308) (33,202) 3,498
----------- ------------ ------------
Net cash flows used for investments in plant............. (288,212) (308,943) (308,394)
Acquisition of the net assets of PSNH (Note 1A)<F1A>..... - - (828,237)
Other investment activities, net......................... (33,546) (32,811) (40,507)
----------- ------------ ------------
Net cash flows used for investments........................ (321,758) (341,754) (1,177,138)
----------- ------------ ------------
Net Increase (Decrease) In Cash for the Period............. 2,571 (13,638) 8,375
Cash - beginning of period................................. 32,008 45,646 37,271
----------- ------------ ------------
Cash - end of period....................................... $ 34,579 $ 32,008 $ 45,646
=========== ============ ============
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amount capitalized during construction.. $ 306,224 $ 325,552 $ 218,515
=========== ============ ============
Income taxes............................................. $ 134,727 $ 142,669 $ 96,821
=========== ============ ============
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 64,590 $ 49,509 $ 38,172
=========== ============ ============
Capital leases........................................... $ 1,342 $ 4,696 $ 2,985
=========== ============ ============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income Taxes
1994 1993 1992
For the Years Ended December 31, (Note 1I)<F1I>
----------------------------------------------------------------------------------------
(Thousands of Dollars)
The components of the federal and state income
tax provisions charged to operations are:
Current income taxes:
Federal.......................................... $ 88,483 $ 99,591 $ 74,768
State............................................ 45,083 50,809 31,583
---------- -------------- ----------
Total current.................................. 133,566 150,400 106,351
---------- -------------- ----------
Deferred income taxes, net:
Federal.......................................... 149,391 87,105 101,025
State............................................ 6,988 (10,058) 12,550
---------- -------------- ----------
Total deferred................................. 156,379 77,047 113,575
---------- -------------- ----------
Investment tax credits, net....................... (9,819) (13,541) (8,182)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
The components of total income tax expense are
classified as follows:
Income taxes charged to operating expenses........ $ 293,644 $ 224,678 $ 246,227
Income taxes associated with the amortization of
deferred nuclear plants return--borrowed funds... - - (17,566)
Income taxes associated with the allowance for
funds used during construction and deferred
nuclear plants return--borrowed funds............ - - 19,870
Other income taxes--credit........................ (13,518) (10,772) (36,787)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
Deferred income taxes are comprised of the tax
effects of temporary differences as follows:
Depreciation, leased nuclear fuel, settlement
credits, and disposal costs..................... 72,078 79,288 66,683
Energy adjustment clauses........................ 49,017 (39,660) 22,484
Demand-side management........................... 217 8,117 13,635
Alternative minimum tax.......................... (601) 2,306 (13,462)
Early retirement program......................... 1,169 (7,715) 220
Organization costs............................... - - 10,042
Deferred tax asset associated with net
operating losses................................ 23,611 25,438 9,335
Other............................................ 10,888 9,273 4,638
---------- -------------- ----------
Deferred income taxes, net......................... $ 156,379 $ 77,047 $ 113,575
========== ============== ==========
A reconciliation between income tax expense and
the expected tax expense at the applicable
statutory rates is as follows:
Expected federal income tax at 35 percent of
pretax income for 1994 and 1993 and at
34 percent for 1992.............................. $ 213,515 $ 179,043 $ 175,033
Tax effect of differences:
Depreciation differences......................... 20,003 21,319 14,090
Deferred nuclear plants return--other funds...... (9,480) (13,486) (15,402)
Amortization of deferred Millstone 3 return--
other funds..................................... 23,103 21,988 17,367
Amortization of regulatory asset--PSNH........... 20,007 23,764 17,624
Seabrook intercompany loss....................... (19,637) (19,176) (11,903)
Investment tax credits amortization.............. (9,819) (13,541) (8,182)
State income taxes, net of federal benefit....... 33,847 26,488 29,130
Property tax differences......................... 5,824 (13,514) (901)
Other, net....................................... 2,763 1,021 (5,112)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
At December 31, 1994 1993
---------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Utility Plant, at original cost:
Electric............................................. $ 9,334,912 $ 9,119,285
Other................................................ 157,632 146,228
------------ ------------
9,492,544 9,265,513
Less: Accumulated provision for depreciation...... 3,293,660 3,021,987
------------ ------------
6,198,884 6,243,526
Construction work in progress........................ 179,724 208,084
Nuclear fuel, net.................................... 224,839 218,051
------------ ------------
Total net utility plant.......................... 6,603,447 6,669,661
------------ ------------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994
and at cost in 1993 (Note 9)<F9>.................... 240,229 206,179
Investments in regional nuclear generating
companies, at equity................................ 82,464 81,029
Investments in transmission companies, at equity..... 26,106 26,536
Other, at cost....................................... 40,896 36,882
------------ ------------
389,695 350,626
------------ ------------
Current Assets:
Cash................................................. 34,579 32,008
Receivables, less accumulated provision for
uncollectible accounts of $16,826,000 in 1994
and $14,629,000 in 1993............................. 357,322 357,449
Accrued utility revenues............................. 142,788 150,794
Fuel, materials, and supplies, at average cost....... 190,062 194,968
Prepayments and other................................ 54,886 35,278
------------ ------------
779,637 770,497
------------ ------------
Deferred Charges:
Regulatory Assets (Note 1H)<F1H>..................... 2,724,364 2,801,283
Unamortized debt expense............................. 33,517 37,444
Other................................................ 54,220 38,653
------------ ------------
2,812,101 2,877,380
------------ ------------
Total Assets........................................... $10,584,880 $10,668,164
============ ============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets
At December 31, 1994 1993
---------------------------------------------------------------------------------
(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; 134,210,226 shares issued and
124,962,981 shares outstanding in 1994 and
134,207,025 shares issued and 124,326,836 shares
outstanding in 1993................................ $ 671,051 $ 671,035
Capital surplus, paid in............................ 904,371 901,740
Deferred benefit plan--employee stock
ownership plan (Note 6)<F6>........................ (213,324) (228,205)
Retained earnings................................... 946,988 879,518
------------ ------------
Total common shareholders' equity................. 2,309,086 2,224,088
Preferred stock not subject to mandatory redemption.. 234,700 239,700
Preferred stock subject to mandatory redemption...... 375,250 380,500
Long-term debt....................................... 3,942,005 4,045,468
------------ ------------
Total capitalization.............................. 6,861,041 6,889,756
------------ ------------
Obligations Under Capital Leases....................... 166,018 171,004
------------ ------------
Current Liabilities:
Notes payable to banks............................... 180,000 173,500
Commercial paper..................................... 10,000 -
Long-term debt and preferred stock--current portion.. 174,948 420,142
Obligations under capital leases--current portion.... 73,103 72,756
Accounts payable..................................... 280,942 229,118
Accrued taxes........................................ 57,532 40,501
Accrued interest..................................... 70,639 69,682
Accrued pension benefits............................. 90,194 82,513
Other................................................ 98,296 83,853
------------ ------------
1,035,654 1,172,065
------------ ------------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>..... 1,968,230 1,911,981
Accumulated deferred investment tax credits.......... 188,005 201,635
Deferred contract obligation--YAEC (Note 3)<F3>...... 157,147 132,826
Other................................................ 208,785 188,897
------------ ------------
2,522,167 2,435,339
------------ ------------
Commitments and Contingencies (Note 7)<F7>
Total Capitalization and Liabilities $10,584,880 $10,668,164
============ ============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1994 1993
---- ----
(Thousands of Dollars)
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets)............. $2,309,086 $2,224,088
---------- ----------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value--authorized 36,600,000 shares at December 31, 1994 and 1993;
12,927,000 shares outstanding in 1994 and 13,220,000 shares in 1993
$50 par value--authorized 9,000,000 shares at December 31, 1994 and 1993;
5,424,000 shares outstanding in 1994 and 1993;
$100 par value--authorized 1,000,000 shares at December 31, 1994 and 1993;
200,000 shares outstanding in 1994 and 1993
Current Redemption Current Shares
Dividend Rates Prices <F1>(a) Outstanding
-------------- ------------------ --------------
NOT SUBJECT TO MANDATORY REDEMPTION:
$25 par value--Adjustable Rate $ 25.00 3,940,000..... 98,500 103,500
$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............... 234,700 239,700
---------- ----------
SUBJECT TO MANDATORY REDEMPTION: <F2>(b)
$25 par value--$1.90 to $2.65 $ 25.00 to $ 26.50 8,987,000..... 224,675 227,000
$50 par value--$2.65 to $3.615 $ 51.00 to $ 52.41 3,100,000..... 155,000 155,000
---------- ----------
Total Preferred Stock Subject to Mandatory Redemption................... 379,675 382,000
Less: Preferred Stock to be redeemed within one year.................... 4,425 1,500
---------- ----------
Preferred Stock Subject to Mandatory Redemption, Net.................... 375,250 380,500
---------- ----------
LONG-TERM DEBT: <F3>(c)
First Mortgage Bonds--
Maturity Interest Rate
-------- -------------
1994 4.25% to 4.50%......................................... - 182,000
1995 9.25%.................................................... 34,300 34,650
1996 8.875%................................................... 172,500 172,500
1997 5.625% to 7.625%........................................ 214,850 265,000
1998 6.50% to 9.17%......................................... 199,900 290,000
1999 5.50% to 7.25%......................................... 280,000 100,000
2000-2002 5.75% to 9.05%......................................... 700,000 875,000
2003-2004 6.125% to 7.75%......................................... 190,000 90,000
2016-2020 7.375% to 10.13%......................................... 20,000 303,569
2023-2025 7.375% to 8.50%.......................................... 480,000 225,000
---------- ----------
Total First Mortgage Bonds .......................................... 2,291,550 2,537,719
---------- ----------
Other Long-Term Debt--<F4>(d)
Pollution Control Notes and Other Notes--
1996 Adjustable Rate - Term Loan.............................. 141,000 235,000
2000 15.23% .................................................. 205,000 205,000
2005-2006 8.38% to 8.58%........................................... 236,000 245,000
2013-2016 Adjustable Rate.......................................... 23,400 23,400
2018-2020 7.17% and Adjustable Rate................................ 50,191 50,300
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........................ 1,577,376 1,680,485
Fees and interest due for spent fuel disposal costs <F1N>(Note 1N)..... 174,934 168,055
Other.................................................................. 78,090 86,731
---------- ----------
Total Other Long-Term Debt........................................... 1,830,400 1,935,271
---------- ----------
Unamortized premium and discount, net ................................. (9,422) (8,880)
---------- ----------
Total Long-Term Debt.................................................. 4,112,528 4,464,110
Less amounts due within one year...................................... 170,523 418,642
---------- ----------
Long-Term Debt, Net .................................................. 3,942,005 4,045,468
---------- ----------
TOTAL CAPITALIZATION..................................................... $6,861,041 $6,889,756
========== ==========
The accompanying notes are an integral part of these financial statements.
<FN>NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
<FA>(a) Each of these series is subject to certain refunding limitations for
the first five years after they were issued. Redemption prices reduce
in future years.
<FB>(b) Changes in Preferred Stock Subject to Mandatory Redemption:
(Thousands of Dollars)
Balance at January 1, 1992....... $ 170,394
Issues........................ 75,000
PSNH stock transferred........ 125,000
Reacquisitions and Retirements (16,894)
-------
Balance at December 31, 1992..... 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
========
The minimum sinking-fund provisions of the series subject to
mandatory redemption aggregate approximately $5,300,000 in 1995 and
1996, $30,300,000 in 1997, $34,000,000 in 1998, and $50,000,000 in 1999.
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 would be prohibited from redemption or
purchase of less than all of the preferred stock outstanding.
<FC>(c) Long-term debt maturities and cash sinking-fund requirements,
excluding fees and interest due for spent fuel disposal costs, on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
approximately $170,500,000, $265,200,000, $264,200,000, $239,600,000,
and $371,900,000, respectively. In addition, there are annual 1 percent
sinking- and improvement-fund requirements of approximately $16,000,000
for 1995, $15,600,000 for 1996 and 1997, $13,450,000 for 1998, and
$13,150,000 for 1999. 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 their respective first mortgage bond indentures.
In addition, CL&P and WMECO have secured $369,300,000 of pollution
control notes with second mortgage liens on Millstone 1, junior to the
liens of their respective first mortgage bond indentures. PSNH's two
bank facilities, the Term Loan and the Revolving Credit Facility, have a
second lien, junior to the lien of its first mortgage bond indenture, on
all PSNH property located in New Hampshire. At December 31, 1994, the
principal amount outstanding under the Term Loan was $141,000,000. At
December 31, 1994, 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 five series of Pollution Control
Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1994,
$516,485,000 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.
<FD>(d) The average effective interest rates on the variable-rate
pollution control notes ranged from 2.5 percent to 4.3 percent for 1994
and from 2.2 percent to 3.4 percent for 1993. The average effective
interest rates for the PSNH Term Loan for 1994 and 1993 were
approximately 5.2 percent and 4.3 percent, respectively.
<FE>(e) On January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P,
issued $100 million of 9.3 percent cumulative Monthly Income Preferred
Securities to help finance the retirement of $125 million of CL&P preferred
stock.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements Of Common Shareholders' Equity
--------------------------------------------------------------------------------------------
Deferred
Benefit
Capital Plan--
Common Surplus, ESOP Retained
Shares(a) Paid In (Note 6)<F6> Earnings(b) Total
--------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 1992....... $596,271 $640,119 $ (175,000) $ 814,684 $1,876,074
Net income for 1992............ 256,054 256,054
Tax benefit of ESOP dividends.. 7,348 7,348
Cash dividends on common
shares--$1.76 per share...... (229,074) (229,074)
Loss on the retirement of
preferred stock.............. (1,268) (1,268)
Issuance of 11,417,305 common
shares, $5 par value......... 57,087 204,440 261,527
Issuance of 3,191,489 common
shares, $5 par value,
to ESOP Trust................ 15,957 59,043 (75,000) -
Allocation of benefits--ESOP... 9,601 9,601
Capital stock expenses, net.... (6,285) (6,285)
--------- --------- ------------- ------------ -----------
Balance at December 31, 1992..... 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
========= ========= ============= ============ ===========
<FN>
<F1>(a) As part of its acquistion of PSNH, NU issued 8,430,910 warrants to former PSNH Equity
security holders. Each warrant, which will expire on June 5, 1997, entitles the
holder to purchase one share of NU common at an exercise price of $24 per share. As
of Decemer 31, 1994, 458,595 shares had been purchased through the exercise of
warrants.
<F2>(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, 1994, these restrictions
totaled approximately $559.6 million.
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A>A. Principles of Consolidation
Northeast Utilities (NU) is the parent company of the Northeast Utilities
system (the system). The consolidated financial statements of the company
include the accounts of all wholly owned subsidiaries. Significant
intercompany transactions have been eliminated in consolidation.
On June 5, 1992 (Acquisition Date), NU acquired PSNH. As part of this
transaction, PSNH transferred its 35.6 percent ownership interest in the
Seabrook nuclear power plant to NAEC. Effective with the Acquisition Date,
the consolidated financial statements of the company include, on a
prospective basis, the financial position, the results of operations, and the
cash flows for PSNH and NAEC. For the 12 months ended December 31, 1994, 1993,
and 1992, PSNH and NAEC increased NU's consolidated operating revenues by
$869.8 million, $805.5 million, and $438.4 million, respectively. For the same
periods, PSNH and NAEC increased NU's consolidated earnings for common shares
by $94.7 million, $65.0 million, and $34.6 million, respectively.
<F1B>B. Change in Accounting for Property Taxes
Certain subsidiaries of NU, including CL&P and WMECO, adopted a one-time
change in the method of accounting for municipal property tax expense for
their Connecticut properties. Most municipalities in Connecticut assess
property values as of October 1. Before January 1, 1993, the system accrued
Connecticut property tax expense over the period October 1 through September
30 based on the lien-date method. In the first quarter of 1993, these
subsidiaries changed their method of accounting for Connecticut municipal
property taxes to recognize the expense from July 1 through June 30, to match
the payments and the services provided by the municipalities. This one-time
change increased earnings for common shares and earnings per common share by
approximately $51.7 million and $0.42, respectively, in 1993.
<F1C>C. Reclassifications
Certain reclassifications of prior years' data have been made to conform with
the current year's presentation.
<F1D>D. 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 to
the participants substantially on the basis of their ownership interests and
is billed pursuant to contractual agreements. Under ownership agreements with
the Yankee companies, CL&P, PSNH, and WMECO may be asked to provide direct or
indirect financial support for one or more of the companies. For more
information on these agreements, see Note 7F, "Commitments and Contingencies-
Purchased Power Arrangements."
The YAEC 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, 1994 and 1993, plant-in-service included approximately $2.4
billion, and the accumulated provision for depreciation included approximately
$525.9 million and $460.6 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: 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, 1994 and 1993, plant-in-service included approximately
$881.0 million and $877.3 million, respectively, and the accumulated provision
for depreciation included approximately $83.2 million and $66.4 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,
approximating $26.1 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 7G,
"Commitments and Contingencies-Hydro-Quebec," for additional information.
<F1E>E. 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. For
nuclear production plants, the costs of removal, less salvage, that have been
funded through external decommissioning trusts will be paid with funds from
the trusts and charged to the accumulated reserve for decommissioning
included in the accumulated provision for depreciation over the expected
service life of the plants. See Note 3, "Nuclear Decommissioning," for
additional information.
The depreciation rates for the several classes of electric plant-in-service
are equivalent to a composite rate of 3.7 percent in 1994, 3.6 percent in
1993, and 3.5 percent in 1992.
<F1F>F. 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.
<F1G>G. Revenues
Other than 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. 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.
<F1H>H. Regulatory Accounting
The operating companies of the system follow accounting policies that reflect
the impact of the rate treatment of certain events or transactions that
differ from generally accepted accounting principles for those events or
transactions followed by nonregulated enterprises. Under regulatory
accounting, assuming that future revenues are expected to be sufficient to
provide recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an asset, or
create a liability. If the economic entity no longer comes under the
jurisdiction of a regulator or external forces, such as a move to a
competitive environment, effectively limiting the influence of
cost-of-service based rate regulation, the entity may be forced to abandon
regulatory accounting, requiring a reexamination and potential write-off of
net regulatory assets. The system operating companies continue to be subject
to cost-of-service based rate regulation. Based on current regulation and
recent regulatory decisions regarding competition in the system's markets,
the company believes that its use of regulatory accounting is still appropriate.
The components of regulatory assets are as follows:
--------------------------------------------------------------------
At December 31, 1994 1993
--------------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1I). . . $1,124,119 $1,183,716
Regulatory asset-PSNH
(Note 1J). . . . . . . . . . . 678,974 769,498
Recoverable energy costs, net
(Note 1K). . . . . . . . . . . 268,982 202,264
Deferred costs-nuclear plants
(Note 1L). . . . . . . . . . . 233,145 271,337
Unrecovered contract obligation-
YAEC (Note 3). . . . . . . . . 157,147 132,826
Deferred demand-side-
management costs (Note 1M) . . 116,133 111,442
Other. . . . . . . . . . . . . . 145,864 130,200
---------- ----------
$2,724,364 $2,801,283
========== ==========
<F1I>I. Income Taxes
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods
in which they affect the determination of income subject to tax) is accounted
for in accordance with the ratemaking treatment of the applicable regulatory
commissions. See Consolidated Statements Of Income Taxes on page 27 for the
components of income tax expense.
In 1992, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109).
SFAS 109 supersedes previously issued income tax accounting standards. NU
adopted SFAS 109, on a prospective basis, during the first quarter of 1993 and
increased the net deferred tax obligation by $1.2 billion at that time. As it
is probable that the increase in deferred tax liabilities will be recovered from
customers through rates, NU also established a regulatory asset.
The tax effect of temporary differences which give rise to the accumulated
deferred tax obligation is as follows:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences . $1,495,323 $1,472,509
Net operating loss carryforwards. . (247,440) (270,612)
Regulatory assets-income tax
gross up. . . . . . . . . . . . . 393,117 424,997
Other . . . . . . . . . . . . . . . 327,230 285,087
----------- ----------
$1,968,230 $1,911,981
=========== ==========
At December 31, 1994, PSNH had a regular tax net operating loss (NOL)
carryforward of approximately $726 million, and an Alternative Minimum Tax
(AMT) NOL carryforward of $529 million, both to be used against PSNH's
federal taxable income and expiring between the years 2000 and 2006. PSNH
also had Investment Tax Credit (ITC) carryforwards of $54 million, which
expire between the years 1995 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 $249 million of the NOL, $189
million of the AMT NOL, and $23 million of the ITC carryforwards are subject
to this limitation.
<F1J>J. Regulatory Asset-PSNH
The regulatory asset-PSNH represents the aggregate value placed by the 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 and the
$700-million value assigned to Seabrook by the Rate Agreement. The regulatory
asset-PSNH was valued at approximately $920.6 million on the Acquisition
Date. The Rate Agreement provides for the recovery, through rates, of the
amortization of the regulatory asset-PSNH with a return each year on the
unamortized portion of the asset. The Rate Agreement provides that $425
million of the regulatory asset-PSNH 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.
<F1K>K. 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
have begun to recover these costs.
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 retroactive
review and appropriate adjustment. 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.
In the past two GUAC proceedings before the Connecticut Department of Public
Utility Control (DPUC), the DPUC determined that CL&P overrecovered its fuel
costs and offset the amount of the overrecovery against the GUAC balance. This
has resulted in disallowances of GUAC recovery of $7.9 million for the 1992-1993
GUAC period and $7.8 million for the 1993-1994 GUAC period. CL&P has appealed
the first decision and will appeal the second decision.
At December 31, 1994, CL&P's recoverable energy costs were $61.0 million,
including the D&D assessments of $37.4 million.
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
purchase power costs assumed in the Rate Agreement and PSNH's actual costs,
which include the costs under the Seabrook Power Contract. 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 attempting to negotiate the rate orders
mandating the purchase of high-cost NUG power. In September 1994, the NHPUC
approved an amendment to the Rate Agreement allowing settlement agreements to
be implemented with two NUGs. The two NUGs have given up their right to sell
their output to PSNH in exchange for lump-sum cash payments of 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
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. At December 31, 1994, PSNH's recoverable energy costs included
fuel and purchase power deferrals ($154.9 million), the deferred buyout
($39.8 million), and the D&D assessments ($0.3 million).
For additional information, see Note 7B, "Commitments and Contingencies -
Nuclear Performance."
<F1L>L. Deferred Costs-Nuclear Plants
The system's operating companies are phasing into rates the recoverable
portions of their investments in Millstone 3 and Seabrook 1 and are deferring
costs as part of these phase-in plans. All plans are in compliance with SFAS
No. 92, Regulated Enterprises-Accounting for Phase-in Plans.
CL&P: As allowed by the DPUC, effective January 1, 1995, CL&P has placed
into rate base its allowed investments in Millstone 3 and Seabrook 1 and is
recovering deferrals and carrying charges on these units. As of December 31,
1994, $448.5 million of the deferred return, including carrying charges, has
been recovered, and $101.6 million of the deferred return to date, plus
carrying charges, remains to be recovered. Recovery will be completed by
December 31, 1995 and August 31, 1996 for Millstone 3 and Seabrook 1,
respectively.
NAEC: As prescribed by the Rate Agreement, NAEC is phasing in its investment
in Seabrook 1. As of December 31, 1994, the portion of the investment on
which NAEC is entitled to earn a cash return was 70 percent and will increase
by 15 percent in each of the next two years beginning May 1, 1995. From the
Acquisition Date through December 31, 1994, NAEC recorded $131.5 million of
deferred return on the excluded portion of its investment in Seabrook 1,
which has been recorded in "Regulatory assets" on the Consolidated Balance
Sheets. 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.
<F1M>M. Demand-side Management (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). These costs are being recovered over periods
ranging from four to eight years. On October 31, 1994, CL&P filed its 1995
CAM for 1995 DSM costs and programs. The filing proposes expenditures
of $36.7 million with recovery over four years and a zero CAM rate.
<F1N>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, 1994,
fees due to the DOE for the disposal of prior-period fuel were approximately
$174.9 million, including interest costs of $92.8 million. As of December 31,
1994, all fees had been collected through rates.
<F1O>O. Derivative Financial Instruments
The company utilizes interest-rate caps 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 are accrued as a reduction of interest expense.
Amounts receivable or payable under fuel-swap agreements are recognized in
income when realized. Any material unrealized gains or losses on fuel swaps or
interest-rate caps will be deferred until realized. For further information on
derivatives, see Note 8, "Derivative Financial Instruments."
<F2>2. LEASES
CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital
lease agreement to finance up to $530 million of nuclear fuel for Millstone 1
and 2 and their shares of the nuclear fuel for Millstone 3. 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 $81,952,000
in 1994, $100,911,000 in 1993, and $81,376,000 in 1992. Interest included in
capital lease rental payments was $14,881,000 in 1994, $16,525,000 in 1993,
and $20,581,000 in 1992. Operating lease rental payments charged to operating
expense were $20,118,000 in 1994, $22,630,000 in 1993, and $27,451,000 in 1992.
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, 1994, are provided on the
next page.
Capital Operating
Year Leases Leases
-------- ---------
(Thousands of Dollars)
1995. . . . . . . . . . . . . $ 9,600 $ 23,300
1996. . . . . . . . . . . . . 8,700 20,600
1997. . . . . . . . . . . . . 8,000 18,000
1998. . . . . . . . . . . . . 7,900 10,400
1999. . . . . . . . . . . . . 7,500 7,900
After 1999. . . . . . . . . . 49,400 36,500
-------- --------
Future minimum lease
payments . . . . . . . . . 91,100 $116,700
========
Less amount representing
interest . . . . . . . . . 44,800
--------
Present value of future
minimum lease payments
for other than nuclear fuel 46,300
Present value of future nuclear
fuel lease payments. . . . 192,800
--------
Total. . . . . . . $239,100
========
<F3>3. NUCLEAR DECOMMISSIONING
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, which is currently under review by the New Hampshire
Decommissioning Finance Committee, 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, technology,
and inflation.
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1994
dollars, is $410.9 million and $330.0 million, respectively. The system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 (utilizing the currently approved decommissioning study), in
year-end 1994 dollars, is $305.2 million and $152.8 million, respectively.
These estimated costs have been levelized and assume after-tax earnings
on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1
percent, respectively. Future escalation rates in decommissioning costs for
the Millstone units and for Seabrook 1 are assumed. 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 $33.5 million in 1994, $29.4 million in 1993,
and $28.1 million in 1992. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on the Consolidated
Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $278.0 million. See "Nuclear Decommissioning" in the
Management's Discussion And Analysis for a discussion of changes being
considered by the FASB related to accounting for decommissioning costs.
CL&P and WMECO have established independent decommissioning trusts 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, 1994, CL&P, PSNH, and WMECO have collected, through rates,
$173.4 million, $1.5 million, and $42.4 million, respectively, toward the
future decommissioning costs of their share of the Millstone units, of which
$179.7 million has been transferred to external decommissioning trusts. As of
December 31, 1994, CL&P and NAEC (including pre-Acquisition Date payments made
by PSNH) have paid approximately $1.2 million and $10.1 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. Due to NU's adoption,
effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in
Debt and Equity Securities, 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. 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. Because allowances for
decommissioning have increased significantly in recent years, customers in
future years may need to increase their payments to offset the effects of any
insufficient rate recoveries in previous years.
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. The system's ownership share of estimated costs, in
year-end 1994 dollars, of decommissioning CY, MY, and VY are $177.4 million,
$67.6 million, and $52.7 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 by CL&P, PSNH, and WMECO.
YAEC has begun component removal activities related to the decommissioning of
its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC
authorization to collect the closing and decommissioning costs and to recover
the remaining investment in the YAEC nuclear power plant over the remaining
period of the plant's Nuclear Regulatory Commission (NRC) operating license.
The bulk of these costs has been agreed to by the YAEC joint owners and
approved as a settlement by FERC. In October 1994, YAEC submitted a revised
decommissioning cost estimate as part of its decommissioning plan with the
NRC. Following the receipt of NRC approval, this estimate will be filed with
the FERC. The revised estimate increased the system's ownership share of
decommissioning YAEC's nuclear facility by approximately $36 million in
January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs,
including decommissioning, amounted to $408.2 million, of which the system's
share was approximately $157.1 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.
<F4>4. SHORT-TERM DEBT
The system companies have various revolving credit lines, totaling $485
million. NU, CL&P, WMECO, Holyoke Water Power Company (HWP), Northeast
Nuclear Energy Company (NNECO), and The Rocky River Realty Company (RRR) have
established a revolving-credit facility with a group of 16 banks. Under this
facility, the participating companies may borrow up to an aggregate of $360
million. Individual borrowing limits as of January 1, 1995 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 0.20 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 0.135 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, 1994 and 1993, there were
$30.0 million and $22.5 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, 1994 and
1993, there were no borrowings under the agreement.
The weighted average interest rates on notes payable to banks and commercial
paper outstanding on December 31, 1994 were 6.2 percent and 6.4 percent,
respectively. The weighted average interest rate on notes payable to banks
outstanding on December 31, 1993 was 3.3 percent. 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
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,
NU, CL&P, PSNH, WMECO, and NAEC were authorized, as of January 1, 1995, to
incur short-term borrowings up to a maximum of $150 million, $325 million,
$175 million, $60 million, and $50 million, respectively.
5. EMPLOYEE BENEFITS
<F5A>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 $7.7 million in 1994, $29.2 million in
1993, and $9.7 million in 1992. Pension costs for 1994 and 1993 included
approximately $9.2 million and $27.7 million, respectively, related to work
force-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, 1994 1993 1992
----------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . $ 39,317 $ 59,068 $ 32,662
Interest cost. . . . . . . . 84,284 81,456 78,092
Return on plan assets. . . . 2,268 (176,798) (83,371)
Net amortization . . . . . . (118,188) 65,447 (17,702)
--------- --------- ---------
Net pension cost.. . . . . . $ 7,681 $ 29,173 $ 9,681
========= ========= =========
For calculating pension cost, the following assumptions were used:
----------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------
Discount rate . . . . . . . . . . 7.75% 8.00% 8.41%
Expected long-term rate
of return. . . . . . . . . . . 8.50 8.50 9.00
Compensation/progression
rate . . . . . . . . . . . . . 4.75 5.00 6.56
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31,1994 and 1993
of $815,646,000 and
$817,421,000, respectively .. $ 893,653 $ 898,788
========== ==========
Projected benefit obligation. . . . $1,112,993 $1,141,271
Market value of plan assets . . . . 1,266,239 1,340,249
---------- ----------
Market value in excess of projected
benefit obligation. . . . . . . 153,246 198,978
Unrecognized transition amount. . . (15,191) (16,735)
Unrecognized prior service costs. . 10,373 10,287
Unrecognized net gain . . . . . . . (238,622) (275,043)
---------- ----------
Accrued pension liability. . . . $ (90,194) $ (82,513)
========== ==========
The following actuarial assumptions were used in calculating
the plan's year-end funded status:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
Discount rate . . . . . . . . . . . 8.25% 7.75%
Compensation/progression rate . . . 5.00 4.75
<F5B>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. These benefits are available for employees leaving the
system who are otherwise eligible to retire and have met specified service
requirements. Effective January 1, 1993, the system adopted SFAS 106,
Employer's Accounting for Postretirement Benefits Other Than Pensions on a
prospective basis. Total health care and life insurance costs, part of which
were deferred or charged to utility plant, approximated $47.6 million in 1994,
$50.1 million in 1993, and $15.6 million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the system's transition obligation upon the adoption of SFAS 106.
As allowed by SFAS 106, the system is amortizing its transition obligation of
approximately $306 million over a 20-year period. 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.
Certain subsidiaries of NU are funding SFAS 106 postretirement costs through
external trusts. The subsidiaries are funding annually 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 following table represents the plan's funded status
reconciled to the Consolidated Balance Sheets:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees. . . . . . . . . . . . . $ 251,448 $ 242,889
Fully eligible active employees 416 540
Active employees not eligible
to retire. . . . . . . . . . . . 69,556 67,955
---------- ----------
Total accumulated postretirement
benefit obligation . . . . . . . . . 321,420 311,384
Market value of plan assets. . . . . . 26,406 12,642
---------- ----------
Accumulated postretirement benefit
obligation in excess of
plan assets. . . . . . . . . . . . . (295,014) (298,742)
Unrecognized transition
amount. . . . . . . . . . . . . . . 272,417 287,551
Unrecognized net gain . . . . . . . . (4,772) (5,150)
---------- ----------
Accrued postretirement
benefit liability . . . . . . . . . $(27,369) $ (16,341)
========== ==========
The components of health care and life insurance costs are:
----------------------------------------------------------------------
For the Years Ended December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . $ 7,418 $ 9,175
Interest cost. . . . . . . . . . . . 25,319 25,330
Return on plan assets. . . . . . . . 236 (220)
Net amortization . . . . . . . . . . 14,581 15,855
------- -------
Net health care and life
insurance costs. . . . . . . . . . $47,554 $50,140
======= =======
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
Discount rate . . . . . . . . . . . . . . 8.00% 7.75%
Long-term rate of return-health assets,
net of tax. . . . . . . . . . . . . . . 5.00 5.00
Long-term rate of return-life assets. . . 8.50 8.50
Health care cost trend rate (a). . . . . 10.20 11.10
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 percent by 2002.
The effect of increasing the assumed health care cost trend rates by one
percentage point in each year would increase the accumulated postretirement
benefit obligation as of December 31, 1994 by $17.2 million and the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for the year then ended by $1.7 million. The trust holding the plan assets
is subject to federal income taxes at a 35-percent tax rate.
PSNH and WMECO are currently recovering SFAS 106 costs, including previously
deferred costs. CL&P has received regulatory approval to defer SFAS 106 costs
in excess of costs incurred on a pay-as-you-go basis. Deferral of such costs
is permitted since it is expected that the period of recovery of deferred
costs will be within the time frame established by the applicable accounting
requirements.
<F5C>C. 401(k) Savings Plan
The company also maintains a 401(k) Savings Plan for substantially all
employees. This savings plan provides for employee contributions up to
specified limits. The company's savings plan provides up to 3 percent of
matching contributions. The matching contributions for the company for 1994,
1993, and 1992 were $12.1 million, $12.2 million, and $8.6 million,respectively.
For further information on the 401(k) Savings Plan, see Note 6, "Employee Stock
Ownership Plan."
<F6>6. 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 in
1991 and 1992 a total of $250 million principal amount of unsecured and
amortizing notes, the proceeds of which were lent to the ESOP trust for purchase
of approximately 10.8 million newly issued NU common shares from the company.
NU makes principal and interest payments on the ESOP notes at the same rate that
ESOP shares are allocated to employees.
In 1994 and 1993, the ESOP trust issued approximately 664,000 and 530,000,
respectively, of NU common shares, with costs of approximately $15.5 million
and $14.0 million, respectively, to the 401(k) plan. As of December 31, 1994
and 1993, the total allocated ESOP shares were 1,547,219 and 899,284,
respectively, and total unallocated ESOP shares were 9,215,904 and 9,880,189,
respectively. The fair market value of unallocated ESOP shares as of December
31, 1994 and 1993 was approximately $199.3 million and $234.7 million,
respectively.
During 1994, the ESOP trust used approximately $23.3 million in dividends
paid on NU common shares and $13.1 million in contributions from NU to meet
principal and interest payments on ESOP notes. During the 12-month periods
ending December 31, 1994 and 1993, the ESOP trust incurred approximately
$20.0 million and $20.9 million, respectively, in interest expense.
NU adopted the American Institute of Certified Public Accountant's Statement
of Position 93-6, Employers' Accounting for Employee Stock Ownership Plans
(SOP 93-6) in 1993. This new standard requires: (1) offsetting of ESOP tax
benefits against income tax expense, (2) charging allocated ESOP dividends
directly to retained earnings, (3) exclusion of unallocated ESOP dividends for
financial reporting purposes, and (4) exclusion of unallocated ESOP shares from
earnings-per-common share (EPS) calculations. The adoption of SOP 93-6 did not
have a material impact on 1993 EPS; however, 1993 earnings for common shares
decreased by approximately $19.9 million. Had the provisions of SOP 93-6 been
applied to 1992 results of operations, the impact on EPS would not have been
material; however, earnings for common shares would have decreased by $16.0
million.
7. COMMITMENTS AND CONTINGENCIES
<F7A>A. Construction Program
The construction program is subject to periodic review and revision. Actual
construction expenditures may vary from estimates due to factors such as
revised load estimates, inflation, revised nuclear safety regulations,
delays, difficulties in the licensing process, the availability and cost of
capital, and the granting of timely and adequate rate relief by regulatory
commissions, as well as actions by other regulatory bodies.
The system companies currently forecast construction expenditures (including
the allowance for funds used during construction) of approximately $1.2 billion
for the years 1995-1999, including $253.7 million for 1995. In addition, the
system companies estimate that nuclear fuel requirements, including nuclear
fuel financed through the NBFT, will be $366.7 million for the years 1995-1999,
including $67.9 million for 1995. See Note 2, "Leases," for additional
information about the financing of nuclear fuel.
<F7B>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. The Office of Consumer Counsel (OCC) appealed decisions favorable to
the company in two dockets. For the one appeal decided, which related to a
procedural issue, the OCC prevailed and the case has been remanded to the
DPUC for further proceedings. The exposure under these two dockets is
approximately $66 million. The DPUC has suspended a third docket, pending the
outcome of one of the appeals. The exposure under this remaining docket is
$26 million. Management believes that its actions with respect to these
outages have been prudent, and it does not expect the outcome of the appeals
to result in material disallowances.
In October 1994, Millstone 2 began a planned refueling and maintenance outage
that was originally scheduled for 63 days. The outage has encountered several
unexpected difficulties which have lengthened the duration of the outage. The
magnitude of the schedule impact is currently under review, but the unit is
not expected to return to service before April 1995. CL&P and WMECO expect
that replacement power costs in the range of $7 million and $1 million per
month, respectively, will be attributable to the extension of the outage.
Recovery of the costs related to this outage is subject to scrutiny by the DPUC
and the Massachusetts Department of Public Utilities (DPU).
<F7C>C. PSNH Rate Agreement
The Rate Agreement provided the financial basis for PSNH's Plan of
Reorganization (the Plan). The Rate Agreement calls for seven successive 5.5
percent annual increases in PSNH's base rates for its charges to retail
customers (the Fixed-Rate Period). The first increase was put into effect on
January 1, 1990 and the remaining two increases are scheduled to be put into
effect annually beginning on June 1, 1995. As discussed in Note 1K, "Summary
of Significant Accounting Policies-Recoverable Energy Costs-PSNH," the FPPAC
protects PSNH from changes in fuel and purchased power costs. Although the
Rate Agreement provides an unusually high degree of certainty as to PSNH's
retail rates for the next two years, it also entails a risk when sales are
lower than anticipated or if PSNH should experience unexpected increases in
its costs other than those for fuel and purchased power, since PSNH has
agreed that it will not seek additional rate relief during the Fixed-Rate
Period, except in limited circumstances. However, in order to provide protection
from significant variations from the costs assumed in base rates over the
Fixed-Rate Period, the Rate Agreement establishes a return on equity (ROE)
collar to prevent PSNH from earning a ROE in excess of an upper limit or below a
lower limit. To date, PSNH's ROE has been within the limits of the ROE collar.
<F7D>D. 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.
Changing environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations, and other
facilities. The cumulative long-term, economic 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 for which the system's subsidiaries expect to
bear legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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, 1994, the liability recorded by the system for its estimated environmental
remediation costs, excluding any possible insurance recoveries or recoveries
from third parties, amounted to approximately $11 million. However, in the event
that it becomes necessary to effect environmental remedies that are currently
not considered probable, it is reasonably possible that the upper limit of the
system's environmental liability range could increase to approximately $16
million.
The system cannot estimate the potential liability for future claims 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.
<F7E>E. Nuclear Insurance Contingencies
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first $200 million of
liability would be provided by purchasing the maximum amount of commercially
available insurance. Additional coverage of up to a total of $8.3 billion
would be provided by an assessment of $75.5 million per incident, levied on
each of the 110 nuclear units that are currently subject to the Secondary
Financial Protection Program in the United States, subject to a maximum
assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs arising
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5 percent, up to $3.8
million, or $415.3 million in total, for all 110 nuclear units. The maximum
assessment is to be adjusted at least every five years to reflect
inflationary changes. Based on the ownership interests in Millstone 1, 2, and
3 and in Seabrook 1, the system's maximum liability 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.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences with
respect to the system's ownership interest in Millstone 1, 2, and 3 and in
CY. All companies insured with NML are subject to retroactive assessments if
losses exceed the accumulated funds available to NML. The maximum potential
assessment against the system with respect to losses arising during the
current policy year is approximately $16.6 million under the NML primary
property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL)
to cover: (1) certain extra costs incurred in obtaining replacement power
during prolonged accidental outages with respect to the system's ownership
interests in Millstone 1, 2, and 3, Seabrook 1, and CY, and PSNH's Seabrook
Power Contract with NAEC; and (2) the excess cost of repair, replacement, or
decontamination or premature decommissioning of utility property resulting
from insured occurrences with respect to the system's ownership interests in
Millstone 1, 2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with
NEIL are subject to retroactive assessments if losses exceed the accumulated
funds available to NEIL. The maximum potential assessments against the system
with respect to losses arising during current policy years are approximately
$10.8 million under the replacement power policies and $51.7 million
under the excess property damage, decontamination, and decommissioning
policies. Although the system has purchased the limits of coverage currently
available from the conventional nuclear insurance pools, the cost of a
nuclear incident could exceed available insurance proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual Atomic
Energy Liability Underwriters, 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 $3.1 million
per reactor. The maximum potential assessments against the system with
respect to losses arising during the current policy period are approximately
$13.3 million.
<F7F>F. Purchased Power Arrangements
CL&P, PSNH, and WMECO purchase approximately 10 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 shares (or
entitlement shares) of generating costs, which include depreciation, operation
and maintenance 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
$154.3 million in 1994, $169.0 million in 1993, and $145.4 million in 1992.
See Note 1D, "Summary of Significant Accounting Policies-Investments and
Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning,"
for more information on the Yankee companies.
CL&P, PSNH, and WMECO have entered into various arrangements for the purchase
of capacity and energy from nonutility generators. Some of these arrangements
have terms from 10 to 30 years and require the companies to purchase
the energy at specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of system electricity requirements
was met by nonutility generators. The total cost of purchases under these
arrangements amounted to $435.0 million in 1994, $426.8 million in 1993, and
$323.8 million in 1992. These costs are eventually recovered through the
companies' rates. For additional information, see Note 1K, "Summary of
Significant Accounting Policies-Recoverable Energy Costs-PSNH."
PSNH entered into a buy-back agreement to purchase the capacity and energy of
the New Hampshire Electric Cooperative, Inc.'s (NHEC) Seabrook share and to
pay all of NHEC's Seabrook costs for a ten-year period, which began July 1,
1990. The total cost of purchases under this agreement was $15.7 million in
1994, $14.4 million in 1993, and $13.8 million in 1992. Part of these costs
is collected currently though the FPPAC and part is 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.
The estimated annual costs of the system's significant purchase power
arrangements are as follows:
----------------------------------------------------------------------
1995 1996 1997 1998 1999
----------------------------------------------------------------------
(Millions of Dollars)
Yankee
Companies . . . . . . $168.5 $177.1 $158.4 $188.0 $180.5
Nonutility
Generators . . . . . . $447.1 468.4 478.9 489.3 493.1
NHEC . . . . . . . . . $ 16.5 16.5 25.1 33.2 32.8
<F7G>G. 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, their
proportionate shares of the annual operation, maintenance, and capital costs
of these facilities, which are currently forecast to be $171.9 million for
the years 1995-1999, including $38.4 million for 1995.
<F8>8. 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, as well as a portion of the PSNH
Variable-Rate Term Loan. During 1994, there were five outstanding contracts
held by CL&P, PSNH, and WMECO covering $617 million of variable-rate debt,
with terms ranging from one to three years. Two of the five contracts expired
in 1994. The contracts entitle 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, and the PSNH Variable-Rate Term Loan
exceed the three-month LIBOR rate. These contracts are settled on a quarterly
basis. As of December 31, 1994, CL&P, PSNH, and WMECO had a total of $467
million in caps with maturities of one year, with a positive mark-to-market
position of approximately $5.0 million.
Fuel Swaps: CL&P also uses fuel-swap agreements with financial institutions
to hedge against fuel-price risk created by long-term negotiated energy
contracts. These fuel swaps minimize exposure associated with rising fuel
prices and effectively fix 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, 1994, CL&P had five outstanding agreements with a
total notional value of approximately $126 million, and a positive
mark-to-market position of approximately $3.1 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 both the interest-rate
caps and fuel 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.
<F9>9. 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 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. As a result of the adoption of SFAS 115, the investments
held in the company's nuclear decommissioning trusts decreased by approximately
$5.5 million as of December 31, 1994, with a corresponding offset to the
accumulated provision for depreciation. The $5.5 million decrease 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, 1994 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 2,151,744
Other long-term debt. . . . . . 1,830,400 1,811,627
----------------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
----------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption . . . . . $ 239,700 $ 202,826
Preferred stock subject to
mandatory redemption . . . . . 382,000 407,990
Long-term debt -
First Mortgage Bonds . . . . . 2,537,719 2,632,983
Other long-term debt . . . . . 1,935,271 2,055,433
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.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED
1994 March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(Thousands of Dollars, except per share data)
Operating Revenues .............. $966,174 $854,627 $923,708 $898,233
======== ======== ======== ========
Operating Income................. $159,559 $123,688 $135,882 $129,103
======== ======== ======== ========
Net Income ...................... $ 95,888 $ 61,145 $ 65,029 $ 64,812
======== ======== ======== ========
Earnings Per Common Share........ $ 0.77 $ 0.49 $ 0.52 $ 0.52
======== ======== ======== ========
1993
Operating Revenues .............. $958,192 $853,769 $915,239 $901,893
======== ======== ======== ========
Operating Income................. $129,745 $ 94,059 $l07,772 $139,275
======== ======== ======== ========
Net Income....................... $112,447 $ 14,759 $ 46,421 $ 76,326
======== ======== ======== ========
Earnings Per Common Share ....... $ 0.91 $ 0.12 $ 0.37 $ 0.62
======== ======== ======== ========
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED GENERAL OPERATING STATISTICS
1994 1993 1992<F1>(a) 1991 1990
---- ---- ----------- ---- ----
System Capability-MW (b)<F2>... 8,494.8 7,795.3 7,823.2 5,916.2 5,909.6
System Peak Demand-MW.......... 6,338.5 6,191.0 5,781.0 4,999.8 4,753.9
Nuclear Capacity-MW(b)<F2>..... 3,272.6 3,110.0 2,981.1 2,380.0 2,459.5
Nuclear Capacity
Factor(c)<F3>................ 67.5 80.8 63.7 50.6 69.4
Nuclear Contribution to Total
Energy Requirements (%) (b)<F2> 54.0 62.1 48.5 43.5 57.5
<FN>
<F1>(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.
<F2>(b) Includes the system's entitlements in regional nuclear generating companies, net of capacity
sales and purchases.
<F3>(c) Represents the average capacity factor for the nuclear units operated by the NU system.
NORTHEAST UTILITIES AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
1994 1993 1992<F1>(a) 1991
---- ---- ------------ ----
(Thousands of Dollars, except percentages and share data)
BALANCE SHEET DATA:
Net Utility Plant-
Continuing Operations ............... $ 6,603,447 $ 6,669,661 $ 6,719,652 $ 5,257,567
Discontinued Gas Plant............... -- -- -- --
Total Assets ......................... 10,584,880 10,668,164 9,724,340 6,781,746
Total Capitalization <F2>(b).......... 7,035,989 7,309,898 7,421,592 5,138,426
Obligations Under Capital Leases <F2>(b) 239,121 243,760 266,100 279,729
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 3,642,742 $ 3,629,093 $ 3,216,874 $ 2,753,803
Net Income.......................<F3> 286,874 249,953(c) 256,054 236,709
Earnings per Common Share........<F3> $2.30 $2.02(c) $2.02 $2.12
Discontinued Gas Operations:
Operating Revenues................... $ -- $ -- $ -- $ --
Net Income........................... -- -- -- --
Earnings per Common Share ........... $ -- $ -- $ -- $ --
COMMON SHARE DATA:
Earnings per Share...............<F3> $2.30 $2.02(c) $2.02 $2.12
Dividends per Share ................. $1.76 $1.76 $1.76 $1.76
Payout Ratio (%)..................... 76.5 87.1 87.1 83.0
Number of Shares
Outstanding--Average............<F4> 124,678,192 123,947,631(d)130,403,488 111,453,550
Market Price--High................... $25 3/4 $28 7/8 $26 3/4 $24 3/8
Market Price--Low.................... $20 3/8 $22 $22 1/2 $19
Market Price--Closing Price
(end of year) ..................... $21 5/8 $23 3/4 $26 l/2 $23 5/8
Book Value per Share(end of year).... $18.47 $17.89 $16.24 $15.73
Rate of Return Earned on Average
Common Equity (%) ................. 12.7 11.4 12.7 13.0
Dividend Yield (end of year) (%) .... 8.1 7.4 6.6 7.4
Market-to-Book Ratio (end of year)... 1.2 1.3 1.6 1.5
Price-Earnings Ratio (end of year)... 9.4 11.8 13.1 11.1
CAPITALIZATION: <F2> (b)
Common Shareholders' Equity......... $ 2,309,086 2,224,088 $ 2,173,977 $ 1,876,074
Preferred Stock Not Subject
to Mandatory Redemption........... 234,700 239,700 304,696 394,695
Preferred Stock Subject to
Mandatory Redemption ............. 379,675 382,000 353,500 170,394
Long-Term Debt...................... 4,112,528 4,464,110 4,589,419 2,697,263
----------- ---------- ----------- -----------
Total Capitalization ............... $ 7,035,989 $7,309,898 $ 7,421,592 $ 5,138,426
=========== ========== =========== ===========
<FN>
<F1>(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.
<F2>(b) Includes portions due within one year.
<F3>(c) 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.
<F4>(d) Decrease in the number of shares results from a change in accounting for Employee Stock
Ownership Plan shares.
1990 1989 1988 1987
---- ---- ---- ----
(Thousands of Dollars, except percentages and share data)
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,265,168 $ 5,237,805 $ 5,267,629 $ 5,229,242
Discontinued Gas Plant .............. -- -- 254,587 237,903
Total Assets ........................ 6,601,371 6,523,202 6,764,608 6,663,794
Total Capitalization <F2>(b).......... 4,965,859 4,954,083 5,123,504 4,956,080
Obligations Under Capital Leases <F2>(b) 319,548 341,246 410,352 432,714
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 2,616,319 $ 2,473,571 $ 2,268,607 $ 2,038,554
Net Income........................... 211,007 203,225 224,844 214,529
Earnings per Common Share............ $1.94 $1.87 $2.07 $1.97
Discontinued Gas Operations:
Operating Revenues................... $ -- $ 124,229 $ 200,243 $ 202,816
Net Income........................... -- 5,858 9,078 14,616
Earnings per Common Share ........... $ -- $0.05 $0.08 $0.14
COMMON SHARE DATA:
Earnings per Share................... $1.94 $1.92 $2.15 $2.11
Dividends per Share ................. $1.76 $1.76 $1.76 $1.76
Payout Ratio (%)..................... 90.7 91.7 81.9 83.4
Number of Shares
Outstanding--Average................ 109,003,818 108,669,106 108,669,106 108,669,106
Market Price--High................... $22 5/8 $23 $23 1/8 $28
Market Price--Low.................... $17 7/8 $18 1/2 $18 1/4 $18
Market Price--Closing Price
(end of year) ..................... $20 $22 1/2 $19 7/8 $20 1/4
Book Value per Share(end of year).... $16.34 $16.13 $16.90 $16.53
Rate of Return Earned on Average
Common Equity (%) ................. 12.0 11.8 13.0 12.8
Dividend Yield (end of year) (%) .... 8.8 7.8 8.9 8.7
Market-to-Book Ratio (end of year)... 1.2 1.4 1.2 1.2
Price-Earnings Ratio (end of year)... 10.3 11.7 9.2 9.6
CAPITALIZATION: <F2>(b)
Common Shareholders' Equity......... $ 1,790,758 $ 1,752,395 $ 1,837,034 $ 1,796,293
Preferred Stock Not Subject
to Mandatory Redemption........... 394,695 394,695 344,695 291,195
Preferred Stock Subject to
Mandatory Redemption ............. 176,892 181,892 111,832 205,832
Long-Term Debt...................... 2,603,514 2,625,101 2,829,943 2,662,760
----------- ----------- ------------ ------------
Total Capitalization ............... $ 4,965,859 $ 4,954,083 $ 5,123,504 $ 4,956,080
=========== =========== ============ ============
1986 1985
---- ----
(Thousands of Dollars, except percentages and share data)
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,120,812 $ 5,204,687
Discontinued Gas Plant .............. 224,581 214,115
Total Assets ......................... 6,299,755 6,147,720
Total Capitalization ................. 4,743,914 4,681,995
Obligations Under Capital Leases<F2>(b) 441,183 440,587
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 2,006,842 $ 1,969,225
Net Income........................... 171,234 277,768
Earnings per Common Share............ $1.58 $2.62
Discontinued Gas Operations:
Operating Revenues................... $ 203,814 $ 220,010
Net Income........................... 10,705 10,773
Earnings per Common Share ........... $0.10 $0.10
COMMON SHARE DATA:
Earnings per Share................... $1.68 $2.72
Dividends per Share ................. $1.68 $1.58
Payout Ratio (%)..................... 100.0 58.1
Number of Shares
Outstanding--Average............... 108,352,517 106,221,131
Market Price--High.................. $28 1/4 $18 3/4
Market Price--Low.................... $17 3/8 $13 3/4
Market Price--Closing Price
(end of year) ..................... $24 1/4 $17 3/4
Book Value per Share(end of year).... $16.24 $16.21
Rate of Return Earned on Average
Common Equity (%) ................. 10.4 17.4
Dividend Yield (end of year) (%) .... 6.9 8.9
Market-to-Book Ratio (end of year)... 1.5 1.1
Price-Earnings Ratio (end of year)... 14.4 6.5
CAPITALIZATION: <F2>(b)
Common Shareholders' Equity......... $ 1,765,090 $ 1,738,871
Preferred Stock Not Subject
to Mandatory Redemption........... 291,195 291,195
Preferred Stock Subject to
Mandatory Redemption ............. 166,832 185,833
Long-Term Debt...................... 2,520,797 2,466,096
------------ -----------
Total Capitalization ............... $ 4,743,914 $ 4,681,995
============ ===========
CONSOLIDATED ELECTRIC OPERATING STATISTICS
1994 1993 1992<F1>(a) 1991
---- ---- ----------- ----
SOURCE OF ELECTRIC ENERGY:
(kWh-millions) <F2>(b)
Nuclear--Steam........................ 19,444 22,965 15,520 11,062
Fossil--Steam......................... 8,292 7,676 6,784 6,179
Hydro--Conventional................... 1,239 1,140 1,076 994
Hydro--Pumped Storage................. 1,195 1,269 1,221 1,173
Internal Combustion................... 13 8 9 25
Energy Used for Pumping .............. (1,629) (1,749) (1,671) (1,605)
------ ------ ------ ------
Net Generation..................... 28,554 31,309 22,939 17,828
Purchased and Net Interchange......... 14,027 10,499 14,165 13,430
Company Use and Unaccounted for ...... (2,422) (2,591) (2,028) (1,958)
------ ------ ------ ------
Net Energy Sold.................... 40,159 39,217 35,076 29,300
====== ====== ====== ======
REVENUE: (thousands)
Residential........................... $1,437,764 $1,385,818 $1,213,140 $ 995,098
Commercial........................<F3> 1,174,658(c) 1,043,125 943,832 828,117
Industrial........................<F3> 560,086(c) 649,876 554,587 419,003
Other Utilities ...................... 330,511 383,129 346,791 366,231
Streetlighting and Railroads.......... 45,579 45,480 43,296 38,656
Miscellaneous......................... 36,134 60,008 59,465 49,539
---------- ---------- ---------- ----------
Total Electric ................... 3,584,732 3,567,436 3,161,111 2,696,644
Other............................. 58,010 61,657 55,763 57,159
---------- ---------- ---------- ----------
Total............................. $3,642,742 $3,629,093 $3,216,874 $2,753,803
========== ========== ========== ==========
SALES: (kWh-millions)
Residential.......................... 12,322 11,988 10,839 9,518
Commercial.......................<F3> 11,666(c) 10,304 9,608 8,900
Industrial.......................<F3> 6,738(c) 7,572 6,593 5,208
Other Utilities ..................... 9,121 9,046 7,733 5,388
Streetlighting and Railroads......... 312 307 303 286
------ ------ ------ ------
Total............................ 40,159 39,217 35,076 29,300
====== ====== ====== ======
CUSTOMERS: (average)
Residential......................... 1,513,987 1,503,182 1,351,019 1,150,357
Commercial......................<F3> 154,703(c) 155,487 132,680 102,867
Industrial......................<F3> 7,813(c) 6,272 5,774 5,067
Other............................... 3,818 3,793 3,581 3,305
--------- --------- --------- ---------
Total............................ 1,680,321 1,668,734 1,493,054 1,261,596
========= ========= ========= =========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 8,152 7,987 8,129 8,285
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $951.19 $923.32 $909.80 $866.20
AVERAGE REVENUE PER kWh:
Residential......................... 11.67 cents 11.56 cents 11.19 cents 10.45 cents
Commercial.......................... 10.07 10.12 9.82 9.30
Industrial.......................... 8.31 8.58 8.41 8.05
<FN><F1>(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.
<F2>(b) Generated in system and regional nuclear generating plants.
<F3>(c) Effective January 1, 1994, approximately 1,300 former commercial customers were reclassified
as industrial customers.
1990
----
SOURCE OF ELECTRIC ENERGY:
(kWh-millions)<F2> (b)
Nuclear--Steam........................ 17,724
Fossil--Steam......................... 6,829
Hydro--Conventional................... 1,174
Hydro--Pumped Storage................. 1,250
Internal Combustion................... 11
Energy Used for Pumping .............. (1,688)
------
Net Generation..................... 25,300
Purchased and Net Interchange......... 6,249
Company Use and Unaccounted for ...... (1,938)
------
Net Energy Sold.................... 29,611
======
REVENUE: (thousands)
Residential........................... $ 938,032
Commercial............................ 788,478
Industrial............................ 410,125
Other Utilities ...................... 346,087
Streetlighting and Railroads.......... 37,195
Miscellaneous......................... 42,882
----------
Total Electric ................... 2,562,799
Other................................. 53,520
----------
Total............................. $2,616,319
==========
SALES: (kWh-millions)
Residential.......................... 9,500
Commercial........................... 8,981
Industrial........................... 5,448
Other Utilities ..................... 5,394
Streetlighting and Railroads......... 288
------
Total............................ 29,611
======
CUSTOMERS: (average)
Residential......................... 1,145,142
Commercial.......................... 102,900
Industrial.......................... 5,114
Other............................... 3,283
---------
Total............................ 1,256,439
=========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 8,304
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $819.94
AVERAGE REVENUE PER kWh:
Residential......................... 9.87 cents
Commercial.......................... 8.78
Industrial.......................... 7.53