Exhibit 13.1
1993
PORTIONS OF ANNUAL REPORT TO SHAREHOLDERS
NORTHEAST UTILITIES
FINANCIAL AND STATISTICAL SECTION
TABLE OF CONTENTS
Page 18-25
Management's Discussion And Analysis
Page 26
Company Report
Page 26
Report Of Independent Public Accountants
Page 27
Consolidated Statements Of Income
Page 28
Consolidated Statements Of Cash Flows
Page 29
Consolidated Statements Of Income Taxes
Page 30-31
Consolidated Balance Sheets
Page 32-33
Consolidated Statements Of Capitalization
Page 34
Consolidated Statements Of Common Shareholders' Equity
Page 35-48
Notes To Consolidated Financial Statements
Page 49
Consolidated Statements Of Quarterly Financial Data
Page 49
Consolidated General Operating Statistics
Page 50-51
Selected Consolidated Financial Data
Page 52-53
Consolidated Electric Operating Statistics
Page 54
Shareholder Information
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MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
Overview
Northeast Utilities' (NU or the company) earnings per common share were $2.02
in 1993, unchanged from 1992. The 1993 earnings per common share reflect a
decrease in net income and a decrease in the number of shares outstanding,
resulting from a change in accounting rules for Employee Stock Ownership
Plans (ESOP). The 1993 earnings also reflect the cumulative effect of a
change in the accounting for Connecticut municipal property taxes. Certain
subsidiaries of NU adopted a one-time change in the method of accounting for
Connecticut municipal property tax expense in the first quarter of 1993. This
change resulted in a one-time contribution to earnings of $51.7 million or
$0.42 per common share.
Earnings per common share before the cumulative effect of the change in
accounting for property taxes were $1.60 in 1993. The earnings decrease from
1992 is primarily attributable to one-time impacts of (a) an increase of
$0.19 per share in June 1992 for earnings associated with NU's acquisition of
Public Service Company of New Hampshire (PSNH), (b) a decrease of $0.14 per
share for the charge to earnings in the third quarter of 1993 for the costs
of the company's employee-reduction program, and (c) a decrease of $0.12 per
share for disallowances ordered by Connecticut regulators in The Connecticut
Light and Power Company (CL&P) rate case. Other items that affected earnings
in 1993 were the additional earnings from PSNH and North Atlantic Energy
Corporation (NAEC) reflecting a full year of merged operations, the approval
of an agreement with the state of New Hampshire that resolves certain issues
that had arisen under the PSNH rate agreement (the Global Settlement) in the
fourth quarter of 1993, increased revenues from recent rate increases in NU
subsidiaries' retail jurisdictions, and the company's continued cost-
management efforts. These increases were partially offset by higher costs
for the recovery of regulatory deferrals and the higher contribution in 1992
of energy transactions with other utilities.
The year 1993 was one of both challenge and success for the company. NU's
work force was reduced about 7 percent in 1993 through an employee-reduction
program that involved early retirements and involuntary terminations. The
1993 composite nuclear capacity factor of 80.8 percent was the highest level
the NU system has ever achieved and far above the national average.
Connecticut regulators approved a three-year rate plan that weakened 1993
earnings but will assure CL&P customers rate stability over the next few
years, which should help to improve CL&P's future earnings and competitive
position.
In 1994, NU will continue to face challenges associated with a lagging
economy and competition. Retail sales for 1993 were flat, as compared to
1992, as a result of a stagnant New England economy. NU's subsidiaries expect
retail sales growth of between 1 and 2 percent in 1994, based on some modest
improvement in the economy.
Competition within the electric utility industry is increasing. In response,
NU has developed, and is continuing to develop, a number of initiatives to
retain and continue to serve its existing customers and to expand its retail
and wholesale customer base. These initiatives are aimed at keeping customers
from either leaving NU's retail service territory or replacing NU's electric
service with alternative energy sources.
The cost of doing business, including the price of electricity, is higher in
the Northeast than in most other parts of the country. Relatively high state
and local taxes, labor costs, and other costs of doing business in New
England also contribute to competitive disadvantages for many industrial and
commercial customers of CL&P, PSNH, and Western Massachusetts Electric
Company (WMECO). These disadvantages have aggravated the pressures on
business customers in the current weakened regional economy. Since 1991,
CL&P and WMECO have worked actively with state development authorities to
package development incentives for a variety of retail and wholesale
customers. These economic development packages typically include both
electric rate discounts and incentive payments for energy-efficient
construction, as well as technical support and energy conservation services.
Targeted rate reductions in effect at the end of 1993 to a limited group of
large customers were successful in preserving NU system revenues of
approximately $50 million. The amount of discounts provided to customers is
expected to increase as each subsidiary intensifies its efforts to retain
existing customers and gain new customers.
As a result of very limited load growth throughout the Northeast and the
operation of several new generating plants in the past five years, wholesale
competition has grown, and a seller's market for electricity has turned into
a buyer's market. The prices the NU system has been able to receive for new
wholesale sales have generally been far lower than
18
the prices prevalent in 1988 and 1989. In future years, competition in the
Northeast is expected to increase, putting further downward pressure on
prices. However, the potential price decreases may be offset somewhat by an
improvement in the region's economy, as well as by the retirement of a number
of the region's existing generating facilities.
The ability of retail customers to select an electricity supplier and then
force the local electric utility to transmit the power to the customer's site
is known as "retail wheeling." While wholesale wheeling is mandated by the
Energy Policy Act of 1992 under certain circumstances, retail wheeling is
generally not required in any of the NU system's jurisdictions. Retail
wheeling is being investigated in some of the NU system's jurisdictions.
NU management has taken steps to make the company more competitive and
profitable in the changing utility environment. A system wide emphasis on
improved customer service is a central focus of the reorganization of NU that
became effective on January 1, 1994. The reorganization entails realignment
of the system into two new core business groups. The first core business
group is devoted to energy resource acquisition and wholesale marketing and
focuses on nuclear, fossil, and hydroelectric generation, wholesale power
marketing, and new business development. The second core business group
oversees all customer service, transmission and distribution operations, and
retail marketing in Connecticut, New Hampshire, and Massachusetts. These two
core business groups are served by various support functions.
In connection with NU's reorganization, the company has begun a corporate
reengineering process which should help it to identify opportunities to
become more competitive, while improving customer service and maintaining
excellent operational performance. NU has aggressive cost-reduction targets
over the next three years, which should enable the company to remain
competitive with vulnerable customers in particular.
To date, the NU system has not been materially affected by competition, and
it does not foresee substantial adverse effect in the near future, unless the
current regulatory structure is substantially altered. NU believes the steps
it is taking will have significant, positive effects in the next few years.
In addition, NU's subsidiaries benefit from a diverse retail base. The NU
system has no significant dependence on any one customer or industry. The NU
system's extensive transmission facilities and diversified generating
keepsake are strong positive factors in the regional wholesale power market.
NU serves about 30 percent of New England's electric needs and is one of the
20 largest electric utility systems in the country.
Achieving measurable improvement in earnings in 1994 will depend, in part, on
the success of NU's wholesale power marketing, customer retention, and
reengineering efforts. These efforts should help increase NU's earnings and,
thereby, lower the dividend payout ratio. (1993 dividends were equal to 87
percent of earnings.)
RATE MATTERS
Deferred charges at December 31, 1993 were $2.9 billion, which includes $1.2
billion for the adoption of Statement of Financial Accounting Standards
(SFAS) No. 109, Accounting for Income Taxes, and $769 million for the PSNH
regulatory asset. The PSNH regulatory asset was established under PSNH's
reorganization plan. A portion of the regulatory asset ($425 million) is
being recovered over a seven-year period, and the remainder is being
recovered over a twenty-year period. The system companies are currently
recovering some amounts of the remaining deferred charges from customers.
Management expects that substantially all of the deferred charges will be
recovered through future rates.
Under SFAS No.109, the company reflected a regulatory asset and a deferred
tax liability for the cumulative amount of income taxes associated with
timing differences for which deferred taxes had not been provided but are
expected to be recovered from customers in the future. The adoption of SFAS
No. 109 has not had a material effect on results of operations.
The company also adopted SFAS No. 106, Employer's Accounting for
Postretirement Benefits Other Than Pensions, in 1993. Adopting SFAS No. 106
has not had a material impact on financial condition or results of operations
because the system companies are currently recovering or expect to recover
these costs in the future.
See the "Notes To Consolidated Financial Statements" for further details on
deferred charges and recently adopted accounting standards.
CONNECTICUT
On June 16,1993, the Department of Public Utility Control (DPUC) issued a
final decision in CL&P's December 1992 retail rate case (the rate decision)
approving a multiyear rate plan which provides for annual rate increases of
$46 million, or 2.01 percent, in July 1993; $47.1 million, or 2.04 percent,
in July 1994; and $48.2 million, or 2.06 percent, in July 1995. The total
cumulative increase granted of $141.3 million, or 6.1 percent, was
approximately 42 percent of CL&P's updated request.
19
In light of the state of Connecticut's concern over economic development and
industrial and commercial rates, one important aspect of the rate decision
was that industrial and manufacturing rates will only rise by about 1.1
percent annually over the three-year period. Other significant aspects of
the rate decision included the reduction of CL&P's return on equity (ROE)
from 12.9 percent to 11.5 percent for the first year of the multiyear plan,
11.6 percent for the second year, and 11.7 percent for the third year, a 32-
month phase-in beginning in 1995 of CL&P's nonpension, postretirement benefit
costs required to be recognized under SFAS No. 106 with amortization of
deferred amounts over five years; the three-year phase-in of the Millstone 2
steam generators; the deferral of cogeneration expenses with carrying costs
of $42.1 million in fiscal year 1994 and $20.9 million in fiscal year 1995
with recovery over five years beginning July 1, 1996; and the full recovery
of the remaining costs of the Millstone 3 and Seabrook phase-ins (balance of
$185.9 million at December 31,1993).
The rate decision used $49 million of prior fuel over recoveries to offset a
similar amount of the unrecovered replacement power costs under CL&P's
Generation Utilization Adjustment Clause (GUAC). The GUAC has been in
operation since 1979 and was designed as a mechanism to recover or to refund
certain fuel costs if the nuclear units do not operate at a predetermined
capacity factor. In January 1994, the DPUC issued a decision ordering CL&P
not to include a GUAC amount in customers' bills through August 1994. The
DPUC found that CL&P overrecovered its fuel costs during the 1992-1993 GUAC
period and offset the amount of the over recovery against the unrecovered
GUAC balance. The effect of the order was a disallowance of $7.9 million.
The DPUC further ordered that any GUAC deferred charges subsequent to July
1993 will be offset by any fuel overrecoveries. There is an unrecovered GUAC
balance at December 31, 1993 of $13.7 million, but there is not expected to
be an unrecovered balance at the end of the GUAC period in August 1994. The
DPUC's decision creates some uncertainty about the future operation of the
GUAC. CL&P has requested further clarification of the decision, and has
appealed it, but does not expect that the decision will have a material
adverse effect on future results of operations.
The rate decision also required CL&P to allocate to customers a portion of
the property tax accounting change made in the first quarter of 1993, which
resulted in a charge against other income of $10.2 million in the second
quarter of 1993.
In August 1993, two appeals were filed from the DPUC's June 1993 rate
decision. CL&P appealed four issues from the rate decision. The second
appeal was filed by the Connecticut Office of Consumer Counsel (OCC) and the
city of Hartford. This appeal challenges the legality of the multiyear plan
accepted by the DPUC. CL&P has filed a motion to dismiss this appeal on
jurisdictional grounds. In addition, the Court rejected the city of
Hartford's and OCC's motion to stay implementation of the second and third
year of the rate plan pending the outcome of their appeal.
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 from the DPUC on
four of the reviews. The OCC has appealed decisions favorable to the company
in two dockets. 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 docket is $26 million. An
additional nuclear outage prudence docket before the DPUC is the docket
established to review the 1992 outage at Millstone 2 to replace the steam
generators. A decision is expected in late 1994. Management believes that
its actions with respect to all of these outages have been prudent, and it
does not expect the outcome of the prudence reviews to result in material
disallowances.
In April 1993, the DPUC issued an order approving a new Conservation
Adjustment Mechanism (CAM), which allowed CL&P to recover conservation and
load-management (C&LM) expenditures over an eight-year period (reduced from
ten years) and reaffirmed program performance incentives. In December 1993,
CL&P filed a proposed CAM settlement with the DPUC. The settlement proposes
1994 C&LM expenditures of $39 million, reduction in the recovery period from
8 to 3.85 years and other changes in program designs, performance incentives,
and cost recovery. Unrecovered C&LM costs at December 31, 1993 were $111.4
million.
NEW HAMPSHIRE
PSNH's rates are determined under a rate agreement executed by the Governor
and the Attorney General of New Hampshire in 1989 and subsequently approved
by the New Hampshire Public Utilities Commission (NHPUC) (the Rate
Agreement). The Rate Agreement sets out a comprehensive plan of rates for
PSNH, providing for seven base rate increases of 5.5 percent per year (the
fixed-rate period) and a comprehensive fuel and purchased power adjustment
clause (FPPAC). The base rate increases are effective annually on each June
1. The fourth base rate increase took place on June 1, 1993.
20
In June 1993, PSNH's base rates increased by 6.2 percent. The increase above
the 5.5 percent under the Rate Agreement reflected a temporary increase to
recover the increased costs associated with recently enacted tax legislation.
Concurrently, the FPPAC rate was lowered resulting in a net average rate
increase of 4.5 percent.
In November 1993, the NHPUC approved a 1.8 percent increase in PSNH's average
retail rates, effective on December 1, 1993, for an increased FPPAC rate.
The increase was attributed primarily to the anticipated costs of a refueling
outage at Seabrook scheduled to begin in March 1994. To mitigate the rate
increase, the NHPUC approved the collection of the refueling outage costs
over 18 months.
In January 1994, the NHPUC approved the Global Settlement between PSNH, NAEC,
Northeast Utilities Service Company (NUSCO), and the Attorney General of the
state of New Hampshire. The Global Settlement addressed changes in tax
legislation in New Hampshire, accounting treatments resulting from adoption
of SFAS No. 106 and SFAS No. 109, and recovery for certain aspects of PSNH's
settlement with the Vermont Electric Generation and Transmission Cooperative,
Inc. (VEG&T), including the purchase by NAEC of VEG&T's approximate 0.4
percent share of Seabrook, among other results. The Global Settlement, as
approved, allowed the accelerated recognition of tax benefits, which will
result in moderate increases in PSNH's earnings in the next several years,
beginning in 1993.
The costs associated with purchases from certain small-power producers (SPPs)
over the level assumed in the Rate Agreement are deferred and recovered over
ten-year periods through the FPPAC. At December 31, 1993, SPP deferrals are
approximately $107.6 million. A majority of these purchases is under long-
term arrangements (20-30 years) at prices significantly higher than PSNH's
current or projected avoided costs. PSNH is attempting to renegotiate these
arrangements and must report to the NHPUC on the results of the negotiations.
In January 1994, PSNH filed agreements reached with certain SPPs with the
NHPUC, which call for PSNH to pay the SPPs a total of $91.8 million. In
return, PSNH would no longer be obligated to buy power from these SPPs, and
the SPPs are barred from attempting to provide service to any customers now
on the PSNH system or on the entire NU system. If approved by the NHPUC, the
agreements will provide benefits to customers over the terms of the
arrangements. Management expects to recover any payments from customers.
The NHPUC will be examining the prudence of PSNH's efforts and considering
the implementation of temporary rates for the SPPs that have not settled with
PSNH.
As prescribed by the Rate Agreement, NAEC is phasing in its $700-million
initial investment in Seabrook 1. As of December 31,1993, NAEC has included
in rates $385 million of its Seabrook investment. The remaining investment
($315 million) will be phased into rates over the next three years beginning
May 15, 1994. The deferred return associated with the amount of investment
that has not been included in rates is $136.3 million through December
31,1993. This amount and the additional deferred amounts associated with the
remaining phase-in will be recovered over the period May 1997 through 2001.
MASSACHUSETTS
As a result of a May 1992 Department of Public Utilities (DPU) decision,
WMECO's annual retail rates increased by approximately $11 million, or 2.7
percent, on July 1,1993. This increase is the second step of a two-year
settlement agreement proposed jointly by WMECO and the Massachusetts Attorney
General's Office and approved by the DPU. The first step went into effect on
July 1, 1992.
WMECO had incurred approximately $17 million in replacement-power costs
associated with Millstone outages that have been the subject of prudence
reviews in Connecticut. Recovery of prudently incurred replacement-power
costs is permitted through a retail fuel adjustment clause. The DPU reviews
the performance of WMECO's generating units on an annual basis. Management
believes that its actions with respect to these outages have been prudent and
does not expect the outcome of the DPU performance program reviews to have a
material adverse effect on WMECO's future earnings.
WMECO has a conservation charge (CC) in effect to recover the cost of C&LM
programs above or below the base rate recovery levels. WMECO filed a new CC
in February 1994. WMECO expects to spend about $14 million in 1994 on C&LM
programs.
ENVIRONMENTAL MATTERS
The company 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 NU 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
21
environmental remediation costs for the sites for which the system companies
expect to bear some liability have not been material with respect to the
earnings or financial position of the company. At December 31, 1993, 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 $4 million. However, while not probable,
it is reasonably possible, these costs could rise to much as $9 million. The
extent of additional future environmental cleanup costs is not estimable due
to factors such as the unknown magnitude of possible contamination and
changes in existing laws and regulatory practices.
The company expects that the implementation of Phase I of the 1990 Clean Air
Act Amendments will require only modest emissions reductions for the NU
system. CL&P's and WMECO's exposure is minimal because of the companies'
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 Phase II requirements. The costs for
meeting Phase II requirements cannot be estimated at this time because the
emission limits have not been determined.
The NU system companies' estimated cost to decommission their shares of
Millstone units 1,2, and 3 and Seabrook is approximately $1.1 billion in
year-end 1993 dollars. In addition, the system companies' estimated cost to
decommission their shares of the regional nuclear generating units is
estimated to be approximately $280-$290 million. These costs are being
recovered and recognized over the lives of the respective units. Yankee
Atomic Electric Company (YAEC) has begun decommissioning its nuclear
facility. The NU system companies' estimated obligation to YAEC has been
recorded on the Consolidated Balance Sheets. Managements expects that the
system companies will continue to be allowed to recover these costs.
For further information regarding nuclear decommissioning, environmental
matters, and other contingencies, see the "Notes To Consolidated Financial
Statements."
NUCLEAR PERFORMANCE
The composite capacity factor of the five nuclear generating units that the
NU system operates (including the Connecticut Yankee nuclear unit) was 80.8
percent for 1993, compared with 63.7 percent for 1992 and a national average
of 70.6 percent for 1993. The lower 1992 capacity factor was primarily the
result of the 1992 Millstone 2 steam generator replacement outage and some
unexpected technical and operating difficulties.
In 1993, NU was informed by the Nuclear Regulatory Commission (NRC) of three
apparent violations related to the circumstances surrounding the repair of a
leaking valve in the reactor coolant system at the Millstone 2 nuclear power
station. Millstone 2 was shut down on August 5, 1993 when extensive repair
efforts proved unsuccessful and the valve began to leak at a level beyond
operating requirements. NU was assessed and paid a civil penalty of $237,500
for the three violations that were identified during the NRC investigation.
NU has initiated a number of immediate and long-term actions designed to
further enhance the safe operation of all the NU nuclear plants. In an effort
to improve nuclear performance, NU management announced a reorganization of
its Connecticut-based nuclear organization in November 1993. The
reorganization, which is based on an overview of NU's future nuclear
operational needs, resulted in a number of personnel changes, including the
appointment of a new senior vice president of Millstone Station, realignment
of engineering operations along unit lines, and management consolidation. In
addition, centralization of the nuclear engineering function at the
generating stations is expected to occur during the summer of 1994. No
material expense will be incurred by the company in connection with the
reorganization.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations increased $258.7 million in 1993, compared with
the same period in 1992, primarily due to the contributions of PSNH and NAEC
and higher cash earnings from CL&P. Cash provided from financing activities
was $1.1 billion lower in 1993, compared with the same period in 1992,
primarily due to the financing activity in 1992 associated with the
acquisition of PSNH and a net decrease in short-term debt. Cash used for
investments was $835.4 million lower in 1993, compared with the same period
in 1992, primarily due to the acquisition of the net assets of PSNH in 1992.
The charts on the next page illustrate the sources and uses of cash
requirements for 1992 and 1993, and the projections for 1994 through 1998.
The NU system companies have been able to shift their focus to refinancing
outstanding high-cost securities. Internally generated cash has generally
been, and is projected to continue to be, more than sufficient to cover
construction costs. The forecast through 1998 shows additional financings
only in years with a large amount of securities maturing. CL&P may need up
to $200 million in 1994 to finance maturing debt and PSNH may need to finance
a buyout of some of its arrangements with the
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SPPs. The system companies are obligated to meet $1.5 billion of long-term
debt and preferred stock maturities and cash sinking-fund requirements for
the 1994 through 1998 period, including $295.3 million for 1994. Also, $125
million of First Mortgage Bonds outstanding at December 31, 1993 has been
called in December 1993 for redemption in 1994.
Aggressive refinancing of their outstanding high-cost securities has enabled
the system companies to lower their cost of debt. There was no new money
financing in 1993. To take advantage of favorable market conditions during
1993, the system companies refinanced $485 million of First Mortgage Bonds,
$110 million of preferred stock, and $414.1 million of pollution control
bonds, in addition to restructuring the system companies' various credit
lines. It is estimated that the 1993 refinancings and restructuring will
save the company approximately $17 million per year. The system companies
intend, if market conditions permit, to continue to refinance a portion of
their outstanding long-term debt and preferred stock at a lower effective
cost.
On February 17, 1994, CL&P issued two new First Mortgage Bonds, the $140
million 1994 Series A and the $140 million 1994 Series B Bonds, at annual
rates of 5.50 percent and 6.125 percent, respectively. The Series A Bonds
will mature on February 1, 1999 and the Series B Bonds will mature on
February 1, 2004. Proceeds from these issues, together with proceeds from
short-term debt, will be used to redeem $310 million of outstanding bonds
with interest rates ranging from 5.625 percent to 7.625 percent. Savings
from the refinancings are estimated to be approximately $4.7 million per year
in reduced interest rates.
The NU system's construction program expenditures, including Allowance for
Funds Used During Construction (AFUDC), for the period 1994 through 1998 are
estimated to be approximately $1.2 billion, including $267.5 million for
1994. 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 at least until the year 2007.
CL&P and WMECO utilize a nuclear fuel trust to finance nuclear fuel
requirements for Millstone 1, 2, and 3. Nuclear fuel requirements, including
nuclear fuel financed through the trust, are estimated to be $449.7 million
for the period 1994 through 1988, including $98.4 million for 1994.
RESULTS OF OPERATIONS
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. The fact that PSNH and NAEC were
not part of the NU system in 1991 but were for seven months of 1992, was a
primary contributor to changes in results of operations between 1991 and
1992.
The relative magnitude of the various expenditures incurred by the system's
continuing operations is illustrated in the chart on page 25.
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table on the next page.
Operating revenues increased $412.2 million from 1992 to 1993 primarily due
to the additional revenues of PSNH for a full year in 1993. Operating
revenues excluding PSNH increased $45.1 million from 1992 to 1993. Revenues
related to regulatory decisions increased in 1993, primarily
NORTHEAST UTILITIES
SOURCE & USE OF FUNDS
1992-1998
Use of Funds 1992 1993 1994 1995 1996 1997 1998
- ------------ ---- ---- ---- ---- ---- ---- ----
(Percentages)
Construction 15.4 16.2 36.8 46.2 33.8 25.2 34.4
Nuclear Fuel 1.7 4.7 8.8 13.2 18.3 5.5 19.5
Maturities and Sinking Fund 42.0 68.6 39.9 34.2 41.4 36.7 42.0
Repayment of Short-Term Debt 0.0 10.5 14.5 6.4 6.5 32.6 4.1
Acquisition of PSNH 40.9 0.0 0.0 0.0 0.0 0.0 0.0
----- ----- ----- ----- ----- ----- -----
Total Funds Required 100.0 100.0 100.0 100.0 100.0 100.0 100.0
===== ===== ===== ===== ===== ===== =====
Source of Funds 1992 1993 1994 1995 1996 1997 1998
- --------------- ---- ---- ---- ---- ---- ---- ----
(Percentages)
Internally Generated Funds 15.9 35.9 51.4 86.8 82.4 81.1 82.2
Nuclear Fuel Trust 1.7 3.9 8.0 10.6 15.6 4.4 17.8
Long-Term Debt and
Preferred Stock 60.0 59.0 40.6 0.0 0.0 8.8 0.0
Short-Term Debt 9.0 0.0 0.0 0.0 0.0 0.0 0.0
Common Stock 13.4 1.2 0.0 2.6 2.0 5.7 0.0
----- ----- ----- ----- ----- ----- -----
Total Source of Funds 100.0 100.0 100.0 100.0 100.0 100.0 100.0
===== ===== ===== ===== ===== ===== =====
23
CHANGE IN OPERATING REVENUE
Increase/(Decrease) Increase/(Decrease)
- -----------------------------------------------------------------------------
- ---------------
1993 vs. 1992(a) 1992 vs. 1991(b)
- -----------------------------------------------------------------------------
- ---------------
(Millions of Dollars) (Millions of Dollars)
NU Excl. PSNH Total NU Excl. PSNH
Total
PSNH NU PSNH
NU
Regulatory decisions $ 46.1 $ 8.6 $ 54.7 $ 95.1 $ 15.8
$110.9
Fuel, purchased power, and
FPPAC cost recoveries (14.9) 154.1 139.2 18.8 151.5
170.3
Sales volume 6.8 188.8 195.6 2.4 242.0
244.4
Other revenues 7.1 15.6 22.7 (91.6) 29.1
(62.5)
----- ------ ------ ----- ------
------
Total revenue change $ 45.1 $367.1 $ 412.2 $ 24.7 $ 438.4
$463.1
===== ====== ====== ===== ======
======
(a) The change in operating revenues from 1992 to 1993 was due primarily to
the inclusion of PSNH's operating revenues for a full year in 1993 and
only seven months in 1992.
(b) The change in operating revenues from 1991 to 1992 was due primarily to
the fact that PSNH was not part of the NU system in 1991 but was
included for seven months in 1992.
because of the effects of the June 1993 DPUC retail rate increase for CL&P
and the July 1992 and July 1993 DPU retail rate increases for WMECO. Fuel and
purchased-power 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.
Other revenues increased primarily because of the recognition by a nonutility
subsidiary of recoveries for 1993 conservation expenditures.
Operating revenues increased $463.1 million from 1991 to 1992 primarily due
to the addition of PSNH revenues for seven months in 1992. Operating
revenues excluding PSNH increased $24.7 million from 1991 to 1992. Revenues
related to regulatory decisions increased in 1992, primarily because of the
effects of the July 1991 and July 1992 DPU retail rate increases for WMECO
and the August 1991 DPUC retail rate increase for CL&P. Fuel and purchased-
power cost recoveries increased primarily due to timing in the recover of
fuel expenses under the provisions of CL&P's fuel adjustment clauses. Other
revenues decreased primarily because of 1992 sales to other utilities that
took place at lower prices per kilowatt-hour, the 1991 one-time reimbursement
of costs associated with the reactivation of fossil-generating units, and
lower 1992 WMECO recoveries associated with conservation, capacity, and
transmission costs.
FUEL, PURCHASED, AND NET INTERCHANGE POWER
Fuel, purchased, and net interchange power increased $145.2 million in 1993,
as compared to 1992, primarily due to the additional PSNH and NAEC expenses
($99.0 million), the timing in the recovery of fuel expenses under the
provisions of CL&P's fuel adjustment clauses 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.
Fuel, purchased, and net interchange power increased $98.7 million in 1992,
as compared to 1991, primarily due to the addition of PSNH and NAEC expenses
($59.1 million), timing in the recovery of fuel expenses under the provisions
of CL&P's fuel adjustment clauses, and previously deferred replacement-power
costs that are not recoverable as a result of regulatory reviews in
Connecticut.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses increased $142.5 million in 1993, as
compared to 1992, primarily due to the additional PSNH and NAEC expenses
($105.2 million), the 1993 costs associated with the employee-reduction
program, the 1992 reimbursement of previously expended costs associated with
the PSNH acquisition, and 1993 SFAS No. 106 postretirement benefit costs,
partially offset by lower 1993 costs associated with the operation and
maintenance activities of the nuclear units.
Other operation and maintenance expenses increased $109.1 million in 1992, as
compared to 1991, primarily due to the addition of PSNH and NAEC expenses
($147.8 million) and higher 1992 costs of operation and maintenance
activities at the nuclear units, partially offset by the 1992 reimbursement
of previously expensed costs associated with the PSNH acquisition, the 1991
costs associated with a voluntary early
24
retirement program, and lower 1992 conservation expenses.
DEPRECIATION EXPENSES
Depreciation expenses increased $38.6 million in 1993, as compared to 1992,
and $44.2 million in 1992, as compared to 1991, primarily as a result of the
additional PSNH and NAEC depreciation expense ($26.8 million in 1993 and
$34.4 million in 1992, including Seabrook), higher depreciation rates, and
higher depreciable plant balance.
AMORTIZATION, OF REGULATORY ASSETS, NET
Amortization, of regulatory assets net increased $58.1 million in 1993, as
compared to 1992, and $69.8 million in 1992, as compared to 1991, primarily
because of the additional PSNH amortization of the regulatory asset as
provided for in the Rate Agreement ($37.7 million in 1993 and $51.8 in 1992),
and higher amortization of Millstone 3 and Seabrook deferred return and
expenses. The increase in 1993 is also attributable to the gross-up of taxes
due to SFAS No. 109, and the amortization in 1993 of costs paid by CL&P to
the developers of two wood-to-energy plants as allowed in the recent rate
decision, partially offset by the amortization of the regulatory liability
recognized as a result of the PSNH Global Settlement ($21.9 million).
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased $4.5 million in 1993, as compared to
1992, primarily because of an increase in flow-through depreciation combined
with the tax accounting associated with the PSNH Global Settlement partially
offset by the company's change in accounting for its ESOP.
Federal and state income taxes increased $33.8 million in 1992, as compared
to 1991, primarily because of the addition of PSNH and NAEC and higher book
income of the other NU companies.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $19.0 million in 1993, as compared to
1992, and $34.8 million in 1992, as compared to 1991, primarily due to the
additional PSNH and NAEC taxes ($20.2 million in 1993 and $27.4 million in
1992, including property taxes on Seabrook).
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return increased $18.7 million in 1993, as compared
to 1992, and $15.6 million in 1992, as compared to 1991, primarily because of
deferred return associated with NAEC's ownership share of Seabrook ($30.0
million in 1993 and $22.8 million in 1992), 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 $10.9 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 rate decision and
lower AFUDC.
INTEREST CHARGES
Interest on long-term debt increased $57.3 million in 1993, as compared to
1992, and $70.2 million in 1992, as compared to 1991, primarily because of
higher debt levels from the addition of PSNH and NAEC ($56.7 million in 1993
and $86.8 million in 1992), partially offset by lower average interest rates
as a result of the substantial refinancing activity. The increase in 1993 is
also due to the absence of an interest expense offset in 1993 for ESOP
dividends due to a change in accounting for ESOPs.
Other interest charges increased $9.6 million in 1993, as compared to 1992,
primarily because of higher interest on short-term borrowings, lower AFUDC,
and interest recognized for a potential Connecticut sales tax audit
assessment.
PREFERRED DIVIDENDS OF SUBSIDIARIES
Preferred dividends of subsidiaries increased $4.4 million in 1992, as
compared to 1991, primarily because of the addition of preferred dividends
for PSNH ($7.5 million), partially offset by lower preferred dividend rates.
TAX BENEFIT OF EMPLOYEE STOCK OWNERSHIP PLAN DIVIDENDS
Tax benefit of ESOP dividends of $7.3 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" for further information regarding ESOP.
1993 DISTRIBUTION OF REVENUE
Percent
-------
Energy Costs 25.4%
Other Operation and Maintenance Expenses 20.4%
Wages and Benefits 13.9%
Taxes 12.5%
Common and Preferred Dividends 7.3%
Other Operating Expenses and Other Income, Net 20.5%
------
Total Revenue Dollars 100.0%
======
25
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 & Co., 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 is 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, 1993 and 1992, 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,
1993. 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 aspects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting
principles.
As explained in <F6> Note 1 to the financial statements, "Summary of
Significant Accounting Policies-Accounting Changes," effective January 1,
1993, Northeast Utilities and subsidiaries changed their methods of
accounting for property taxes, postretirement benefits other than pensions,
income taxes, and employee stock ownership plans.
/S/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
26
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1993 1992
1991
---- ----
----
(Thousands of Dollars,except
share information)
OPERATING REVENUES ...................................$ 3,629,093 $ 3,216,874
$ 2,753,803
----------- -----------
-----------
OPERATING EXPENSES:
Operation--
Fuel, purchased and net interchange power........... 917,957 772,804
674,096
Other............................................... 979,403 828,345
763,610
Maintenance.......................................... 265,926 274,495
230,166
Depreciation......................................... 321,359 282,738
238,575
Amortization of regulatory assets, net............... 208,506 150,413
80,643
Federal and state income taxes (See Consolidated
Statements Of Income Taxes)<F6>(Note 1).............. 243,854 246,227
190,556
Taxes other than income taxes ....................... 240,413 221,422
186,645
----------- -----------
-----------
Total operating expenses............................ 3,177,418 2,776,444
2,364,291
----------- -----------
-----------
OPERATING INCOME...................................... 451,675 440,430
389,512
----------- -----------
-----------
OTHER INCOME:
Deferred nuclear plants return--other funds.......... 38,373 45,299
39,477
Equity in earnings of regional nuclear generating
and transmission companies........................ 12,980 15,357
14,431
Other, net........................................... 4,747 15,672
11,712
Income taxes--credit ................................ 29,948 36,787
14,873
----------- -----------
-----------
Other income, net .................................. 86,048 113,115
80,493
----------- -----------
-----------
Income before interest charges...................... 537,723 553,545
470,005
----------- -----------
-----------
INTEREST CHARGES:
Interest on long-term debt........................... 333,163 275,819
205,585
Other interest ...................................... 13,059 3,503
4,145
Deferred nuclear plants return--
borrowed funds <F6>(Note 1)......................... (54,462) (28,838)
(19,023)
----------- ---------
----------
Interest charges, net .............................. 291,760 250,484
190,707
-----------
- ---------- -----------
Income before cumulative effect of accounting change 245,963 303,061
279,298
CUMULATIVE EFFECT OF ACCOUNTING CHANGE <F6>(Note 1) .. 51,681 --
--
----------- -----------
-----------
Income before preferred dividends of subsidiaries 297,644 303,061
279,298
PREFERRED DIVIDENDS OF SUBSIDIARIES .................. 47,691 47,007
42,589
----------- -----------
-----------
NET INCOME ........................................... 249,953 256,054
236,709
Tax benefit of Employee Stock Ownership
Plan dividends <F12>(Note 7)........................ -- 7,348
--
----------- -----------
-----------
EARNINGS FOR COMMON SHARES ........................... $ 249,953 $ 263,402
$ 236,709
=========== ===========
===========
EARNINGS PER COMMON SHARE:
Before cumulative effect of accounting change ........ $ 1.60 $ 2.02
$ 2.12
Cumulative effect of accounting change <F6>(Note 1) .. .42 --
--
-----------
- ----------- -------------
TOTAL EARNINGS PER COMMON SHARE....................... $ 2.02 $ 2.02
$2.12
============
============= =============
COMMON SHARES OUTSTANDING (AVERAGE) <F12>(Note 7) .... 123,947,631 130,403,488
111,453,550
============
============= =============
The accompanying notes are an integral part of these financial statements.
27
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993 1992
1991
---- ----
----
(Thousands of
Dollars)
CASH FLOWS FROM OPERATIONS:
Income before preferred dividends of subsidiaries.......... $ 297,644 $
303,061 $ 279,298
Adjusted for the following:
Depreciation.............................................. 331,382
298,528 245,853
Deferred income taxes and investment tax credits, net..... 63,506
103,089 109,820
Deferred nuclear plants return, net of amortization ...... 18,189
(3,619) 4,687
Deferred energy costs, net of amortization ............... 90,063
(52,298) (128,047)
Amortization of regulatory asset--PSNH ................... 89,822
51,836 --
Deferred conservation and load-management,
net of amortization..................................... (23,955)
(31,989) (47,402)
Other sources of cash .................................... 141,766
111,036 60,530
Other uses of cash........................................ (32,694)
(94,192) (34,771)
Changes in working capital:
Receivables and accrued utility revenues................... 2,797
3,162 (57,289)
Fuel, materials, and supplies.............................. 10,126
(9,686) 33,191
Accounts payable........................................... (678)
(38,889) 83,891
Accrued taxes ............................................. (97,789)
(8,627) (46,208)
Other working capital (excludes cash) ..................... 30,010
30,109 29,369
----------
- ---------- ----------
Net cash flows from operations.............................. 920,189
661,521 532,922
----------
- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Common shares.............................................. 22,252
271,128 42,420
Long-term debt............................................. 924,650
1,141,995 197,207
Preferred stock............................................ 80,000
75,000 --
Financing expenses ........................................ (5,868)
(16,234) (2,067)
Net increase (decrease) in short-term debt ................ (179,240)
182,240 (125,615)
Reacquisitions and retirements of long-term debt........... (1,051,501)
(744,771) (112,990)
Reacquisitions and retirements of preferred stock ......... (116,496)
(106,893) (6,498)
Cash dividends on preferred stock.......................... (47,691)
(49,399) (42,589)
Cash dividends on common shares............................ (218,179)
(229,074) (195,056)
----------
- ---------- ----------
Net cash flows from (used for) financing activities......... (592,073)
523,992 (245,188)
----------
- ---------- ----------
INVESTMENT ACTIVITIES:
Investment in plant:
Electric and other utility plant.......................... (275,741)
(311,892) (237,416)
Nuclear fuel.............................................. (33,202)
3,498 (5,097)
----------
- ---------- ----------
Net cash flows used for investments in plant............... (308,943)
(308,394) (242,513)
Acquisition of the net assets of PSNH <F6>(Note 1)......... --
(828,237) --
Other investment activities, net........................... (32,811)
(40,507) (24,252)
----------
- ---------- ----------
Net cash flows used for investments ........................
(341,754)(1,177,138) (266,765)
----------
- ---------- ----------
NET INCREASE (DECREASE) IN CASH FOR THE PERIOD.............. (13,638)
8,375 20,969
Cash and special deposits--beginning of period.............. 45,646
37,271 16,302
----------
- ---------- ----------
Cash and special deposits--end of period ................. $ 32,008 $
45,646 $ 37,271
==========
========== ==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest, net of amounts capitalized during construction ..$ 325,552 $
218,515 $ 201,021
==========
========== ===========
Income taxes...............................................$ 142,669 $
96,821 $ 116,334
==========
========== ===========
Increase in obligations:
Niantic Bay Fuel Trust.....................................$ 49,509 $
38,172 $ 18,156
==========
========== ===========
Capital leases.............................................$ 4,696 $
2,985 $ 11,107
==========
========== ===========
The accompanying notes are an integral part of these financial statements.
28
CONSOLIDATED STATEMENTS OF INCOME TAXES
For the Years Ended December 31, 1993
1992 1991
<F6>(Note
1)
--------
- -------- --------
(Thousands of Dollars)
The components of the federal and state income tax provisions
charged to operations are:
Current income taxes:
Federal.............................................................$ 99,591
$ 74,768 $ 44,417
State............................................................... 50,809
31,583 21,446
---------
- --------- ---------
Total current ...................................................... 150,400
106,351 65,863
---------
- --------- ---------
Deferred income taxes, net:
Federal............................................................. 87,105
101,025 88,659
State............................................................... (10,058)
12,550 28,007
---------
- --------- ---------
Total deferred..................................................... 77,047
113,575 116,666
---------
- --------- ---------
Investment tax credits, net.......................................... (13,541)
(8,182) (7,869)
---------
- --------- ---------
Total income tax expense..............................................$ 213,906
$211,744 $174,660
=========
========= =========
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses ..........................$ 243,854
$246,227 $190,556
Income taxes associated with the amortization of
deferred nuclear plants return--borrowed funds...................... --
(17,566) (15,208)
Income taxes associated with the allowance
for funds used during construction (AFUDC)
and deferred nuclear plants return--borrowed funds ................. --
19,870 14,185
Other income taxes--credit .......................................... (29,948)
(36,787) (14,873)
---------
- --------- ---------
Total income tax expense..............................................$ 213,906
$211,744 $174,660
=========
========= =========
Deferred income taxes are comprised of the tax effects
of temporary differences as follows:
Depreciation, leased nuclear fuel, settlement credits,
and disposal costs..................................................$ 79,288
$ 66,683 $ 55,275
Energy adjustment clauses ........................................... (39,660)
22,484 48,892
Conservation and load management .................................... 8,117
13,635 22,175
Alternative minimum tax ............................................. 2,306
(13,462) --
Early retirement program ............................................ (7,715)
220 (11,612)
Organization costs................................................... --
10,042 (2,231)
Deferred tax asset associated with net operating losses.............. 25,438
9,335 --
Other................................................................ 9,273
4,638 4,167
---------
- -------- ---------
Deferred income taxes, net............................................$ 77,047
$113,575 $116,666
=========
========= =========
A reconciliation between income tax expense and the expected tax expense
at the applicable statutory rates is as follows:
Expected federal income tax at 35 percent of pretax income for
1993 and at 34 percent for 1992 and 1991............................$ 179,043
$175,033 $154,346
Tax effect of differences:
Depreciation differences............................................ 21,319
14,090 9,203
Deferred nuclear plants return--other funds ........................ (13,486)
(15,402) (13,422)
Amortization of deferred Millstone 3 return--other funds............ 21,988
17,367 15,793
Amortization of regulatory asset--PSNH ............................. 23,764
17,624 --
Seabrook intercompany loss ......................................... (19,176)
(11,903) --
Investment tax credit amortization.................................. (13,541)
(8,182) (7,869)
State income taxes, net of federal benefit.......................... 26,488
29,130 32,814
Property tax differences ........................................... (13,514)
(901) 502
Other, net.......................................................... 1,021
(5,112) (16,707)
---------
- --------- ---------
Total income tax expense..............................................$ 213,906
$211,744 $174,660
=========
========= =========
The accompanying notes are an integral part of these financial statements.
29
CONSOLIDATED BALANCE SHEETS
At December 31, 1993
1992
----
----
(Thousands of
Dollars)
ASSETS
UTILITY PLANT, AT ORIGINAL COST:
Electric................................................ $ 9,119,285 $
8,951,305
Other................................................... 146,228
132,755
-----------
- -----------
9,265,513
9,084,060
Less: Accumulated provision for depreciation............. 3,021,987
2,749,034
-----------
- -----------
6,243,526
6,335,026
Construction work in progress ........................... 208,084
164,374
Nuclear fuel, net........................................ 218,051
220,252
-----------
- -----------
Total net utility plant.............................. 6,669,661
6,719,652
-----------
- -----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear decommissioning trusts, at cost.................. 206,179
170,058
Investments in regional nuclear generating
companies, at equity.................................... 81,029
80,619
Investments in transmission companies, at equity......... 26,536
27,655
Other, at cost........................................... 36,882
39,483
-----------
- -----------
350,626
317,815
-----------
- -----------
CURRENT ASSETS:
Cash and special deposits <F6>(Note 1) .................. 32,008
45,646
Receivables, less accumulated provision for uncollectible
accounts of $14,629,000 in 1993 and $13,255,000 in 1992. 357,449
370,834
Accrued utility revenues ................................ 150,794
140,206
Fuel, materials, and supplies, at average cost .......... 194,968
205,094
Recoverable energy costs, net--current portion <F6>(Note 1) 667
75,539
Prepayments and other.................................... 34,611
26,009
-----------
- -----------
770,497
863,328
-----------
- -----------
DEFERRED CHARGES:
Regulatory asset--income taxes, net <F6>(Note 1) ....... 1,183,716
--
Regulatory asset--PSNH <F6>(Note 1) .................... 769,498
868,716
Deferred costs--nuclear plants <F6>(Note 1)............. 294,004
253,212
Unrecovered contract obligation--YAEC <F9>(Note 3)...... 132,826
154,879
Recoverable energy costs, net <F6>(Note 1).............. 148,789
164,598
Deferred conservation and load-management costs......... 111,442
87,487
Deferred DOE assessment <F6>(Note 1).................... 53,476
56,715
Amortizable property investments........................ 34,229
47,921
Unamortized debt expense ............................... 37,444
44,874
Other................................................... 111,956
145,143
-----------
- -----------
2,877,380
1,823,545
-----------
- -----------
TOTAL ASSETS.............................................. $10,668,164 $
9,724,340
===========
===========
The accompanying notes are an integral part of these financial statements.
30
At December 31, 1993
1992
----
- ----
(Thousands of
Dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION: (See Consolidated Statements of Capitalization)
Common shareholders' equity (See Note <F4>(a)-Consolidated
Statements Of Common Shareholders' Equity):
Common shares, $5 par value-authorized 225,000,000 shares;
134,207,025 shares issued and 124,326,836 shares outstanding
in 1993 and 133,862,919 shares issued and outstanding in 1992 ..$ 671,035
$ 669,315
Capital surplus, paid in........................................ 901,740
897,317
Deferred benefit plan--employee stock ownership plan <F12>(Note 7) (228,205)
(240,399)
Retained earnings............................................... 879,518
847,744
-----------
-----------
Total common shareholders' equity ........................... 2,224,088
2,173,977
Preferred stock not subject to mandatory redemption............. 239,700
304,696
Preferred stock subject to mandatory redemption................. 380,500
349,500
Long-term debt.................................................. 4,045,468
4,316,678
-----------
-----------
Total capitalization......................................... 6,889,756
7,144,851
-----------
-----------
OBLIGATIONS UNDER CAPITAL LEASES................................ 171,004
188,094
-----------
-----------
CURRENT LIABILITIES:
Notes payable to banks ........................................ 173,500
220,000
Commercial paper .............................................. --
132,740
Long-term debt and preferred stock--current portion............ 420,142
276,741
Obligations under capital leases--current portion ............. 72,756
78,006
Accounts payable............................................... 229,118
229,796
Accrued taxes ................................................. 40,501
138,290
Accrued interest............................................... 69,682
72,749
Accrued pension benefits....................................... 82,513
53,340
Other.......................................................... 83,853
71,514
-----------
-----------
1,172,065
1,273,176
-----------
-----------
DEFERRED CREDITS:
Accumulated deferred income taxes <F6>(Note 1) ................ 1,911,981
567,353
Accumulated deferred investment tax credits.................... 201,635
215,255
Deferred contract obligation--YAEC <F9>(Note 3)................ 132,826
154,879
Deferred DOE obligation <F6>(Note 1)........................... 43,034
56,715
Other.......................................................... 145,863
124,017
-----------
-----------
2,435,339
1,118,219
-----------
-----------
COMMITMENTS AND CONTINGENCIES <F13>(Note 8)
TOTAL CAPITALIZATION AND LIABILITIES ........................... $10,668,164
$ 9,724,340
===========
===========
The accompanying notes are an integral part of these financial statements.
31
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31,
1993 1992
- ---- ----
(Thousands of Dollars)
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets).............
$2,224,088 $2,173,977
- ---------- ----------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value--authorized 36,600,000 shares at December 31, 1993 and 1992;
outstanding 13,220,000 shares in 1993 and 15,280,000 shares in 1992
$50 par value--authorized 9,000,000 shares at December 31, 1993 and 1992;
outstanding 5,424,000 shares in 1993 and 5,123,925 shares in 1992
$100 par value--authorized 1,000,000 shares at December 31, 1993 and 1992;
outstanding 200,000 shares in 1993 and 1992
Current Redemption Current Shares
Dividend Rates Prices <F1>(a) Outstanding
-------------- ------------------ --------------
NOT SUBJECT TO MANDATORY REDEMPTION:
$25 par value--Adjustable Rate $ 25.00 4,140,000.....
103,500 103,500
$50 par value--$1.90 to $4.48 $ 50.50 to $ 54.00 2,324,000.....
116,200 181,196
$100 par value--$7.72 $103.51 200,000.....
20,000 20,000
- ---------- ----------
Total Preferred Stock Not Subject to Mandatory Redemption...............
239,700 304,696
- ---------- ----------
SUBJECT TO MANDATORY REDEMPTION: <F2>(b)
$25 par value--$1.90 to $2.65 $ 25.00 to $ 26.14 9,080,000.....
227,000 278,500
$50 par value--$2.65 to $3.615 $ 51.00 to $ 52.41 3,100 000.....
155,000 75,000
- ---------- ----------
Total Preferred Stock Subject to Mandatory Redemption...................
382,000 353,500
Less: Preferred Stock to be redeemed within one year....................
1,500 4,000
- ---------- ----------
Preferred Stock Subject to Mandatory Redemption, Net....................
380,500 349,500
- ---------- ----------
LONG-TERM DEBT: <F3>(c)
First Mortgage Bonds--
Maturity Interest Rate
-------- -------------
1993 4.25% to 8.50% ..........................................
-- 140,000
1994 4.25% to 4.50% ..........................................
182,000 182,000
1995 9.25%....................................................
34,650 94,400
1996 8.875%...................................................
172,500 172,500
1997 5.63% to 7.63%...........................................
265,000 265,000
1998 6.50% to 9.17%...........................................
290,000 290,000
1999-2003 5.75% to 9.05% ..........................................
1,065,000 885,000
2004-2008 8.75% to 9.375% .........................................
-- 220,000
2016-2019 7.38% to 10.13% .........................................
303,569 304,235
2023-2025 7.38% to 7.50% ..........................................
225,000 --
- ---------- ----------
Total First Mortgage Bonds ..........................................
2,537,719 2,553,135
- ---------- ----------
Other Long-Term Debt--
Pollution Control Notes and Other Notes--
1996 Adjustable Rate..........................................
235,000 329,000
1998 5.9% ....................................................
-- 7,650
2000-2004 15.23% and Adjustable Rate...............................
205,000 220,000
2005-2007 6.5% to 8.58% ...........................................
245,000 266,000
2013-2017 Adjustable Rate..........................................
23,400 379,500
2018-2022 7.17% to 7.65% and Adjustable Rate.......................
602,785 577,785
2028 Adjustable Rate..........................................
369,300 --
- ---------- ----------
Total Pollution Control Notes and Other Notes........................
1,680,485 1,779,935
Fees and interest due for spent fuel disposal costs....................
168,055 162,981
Other..................................................................
86,731 98,716
- ---------- ----------
Total Other Long-Term Debt...........................................
1,935,271 2,041,632
- ---------- ----------
Unamortized premium and discount, net .................................
(8,880) (5,348)
- ---------- ----------
Total Long-Term Debt..................................................
4,464,110 4,589,419
Less amounts due within one year......................................
418,642 272,741
- ---------- ----------
Long-Term Debt, Net ..................................................
4,045,468 4,316,678
- ---------- ----------
TOTAL CAPITALIZATION....................................................
$6,889,756 $7,144,851
========== ==========
The accompanying notes are an integral part of these financial statements.
32
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
<F1> (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.
<F2> (b) Changes in Preferred Stock Subject to Mandatory Redemption:
(Thousands of Dollars)
Balance at January 1, 1991 . . . . . . $176,892
Reacquisitions and Retirements . . . (6,498)
--------
Balance at December 31, 1991 . . . . . 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
========
The minimum sinking-fund provisions of the series subject to mandatory
redemption aggregate approximately $1,500,000 in 1994, $5,300,000 in 1995
and 1996, $30,300,000 in 1997, and $34,000,000 in 1998. 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.
<F3>(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, 1993 for the years 1994 through 1998 are
approximately $293,800,000, $170,900,000, $265,100,000, $314,300,000,
and $329,700,000, respectively. Also, $125,000,000 of first mortgage
bonds outstanding at December 31, 1993 had been called in December 1993
for redemption in 1994. In addition, there are annual 1 percent sinking-
and improvement-fund requirements of approximately $17,100,000 for 1994,
$15,400,000 for 1995, $15,000,000 for 1996 and 1997, and $12,400,000 for
1998. 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 Northeast Utilities
(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, 1993, the principal amount outstanding under the Term Loan was
$235,000,000. At December 31, 1993, there were no borrowings under the
Revolving Credit Facility.
The system companies have entered into interest-rate cap contracts to
reduce the potential impact of upward changes in interest rates on
certain variable-rate tax-exempt pollution control revenue bonds held by
CL&P, PSNH, and WMECO, as well as a portion of the PSNH Variable-Rate
Term Loan. Approximately $617,000,000 of total outstanding long-term
variable-rate debt is secured by these interest-rate caps. The total
cost of the interest-rate caps for 1993 was approximately $4,100,000, the
costs of which are amortized over the terms of the contracts, which are
from one to three years. The fair market value of outstanding interest-
rate cap contracts as of December 31, 1993 is approximately $605,000.
Concurrent with the issuance of PSNH's Series A and B First Mortgage
Bonds, PSNH entered into financing arrangements with the Industrial
Development Authority of the state of New Hampshire (IDA). Pursuant to
these arrangements, the IDA issued five series of Pollution Control
Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31,
1993, $516,500,000 of the PCRBs were outstanding. PSNH's obligation to
repay each series of PCRBs is secured by a series of First Mortgage Bonds
that were issued under its indenture. Each such series of First Mortgage
Bonds contains terms and provisions with respect to maturity, principal
payment, interest rate, and redemption that correspond to those of the
applicable series of PCRBs; for financial reporting purposes, these bonds
would not be considered outstanding unless PSNH fails to meet its
obligations under the PCRBs.
Fees and interest due for spent fuel disposal costs are scheduled to be
paid to the United States Department of Energy just prior to the first
delivery of prior-period spent fuel, which is anticipated to be in 1998.
Until such payment is made, the outstanding balance will continue to
accrue interest at the three-month Treasury Bill Yield Rate. For
additional information, see <F6> Note 1 of the accompanying Notes To
Consolidated Financial Statements.
33
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
Deferred
Benefit
Capital Plan-
Retained
Common Surplus, ESOP
Earnings
Shares<F4>(a) Paid In <F12>(Note 7)
<F5>(b) Total
------------ -------- --------
- ---------- -----
(Thousands of Dollars)
BALANCE AT JANUARY 1, 1991............ $ 548,080 $ 469,647 $ -- $
773,031 $ 1,790,758
Net income for 1991..................
236,709 236,709
Cash dividends on common shares--
$1.76 per share....................
(195,056) (195,056)
Issuance of 7,608,695 common shares,
$5 par value, to Employee Stock
Ownership Plan (ESOP) Trust....... 38,043 136,957 (175,000)
--
Issuance of 2,029,504 common shares,
$5 par value....................... 10,148 32,272
42,420
Capital stock expenses, net.......... 1,243
1,243
--------- --------- ----------
- -------- ----------
BALANCE AT DECEMBER 31, 1991.......... 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 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
========= ========= =========
========== ===========
<F4>(a) Northeast Utilities (NU), as part of its acquisition of Public Service
Company of New
Hampshire (PSNH), 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 December 31, 1993,
455,394 shares had been
purchased through the exercise of warrants.
<F5>(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, 1993, these restrictions totaled
approximately $609.3
million.
The accompanying notes are an integral part of these financial statements.
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<F6>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
Northeast Utilities (NU or the company) 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 Public Service Company of New
Hampshire (PSNH). As part of this transaction, PSNH transferred its 35.6
percent ownership interest in the Seabrook nuclear power plant to North
Atlantic Energy Corporation (NAEC). PSNH and NAEC are now both wholly owned
subsidiaries of NU. On June 29, 1992, North Atlantic Energy Service
Corporation (NAESCO), a wholly owned subsidiary of NU, began management of
the Seabrook 1 power plant as agent for the Seabrook joint owners. The
acquisition of PSNH has been accounted for, in accordance with generally
accepted accounting principles, as a purchase. 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 statements of cash flows for PSNH and NAEC. For the 12
months ended December 31, 1993, PSNH and NAEC increased NU's consolidated
operating revenues and earnings for common shares by $805.5 million and $65.0
million, respectively. For the 12 months ended December 31, 1992, PSNH and
NAEC increased NU's consolidated operating revenues and earnings for common
shares by $438.4 million and $34.6 million, respectively.
ACCOUNTING CHANGES
PROPERTY TAXES: Certain subsidiaries of NU, including The Connecticut Light
and Power Company (CL&P) and Western Massachusetts Electric Company (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. Prior to January 1,
1993, the NU 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 shares by approximately $51.7 million and $0.42,
respectively, in 1993.
INCOME TAXES: The company adopted the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes (SFAS 109),"
effective January 1, 1993. For more information on this change, see <F6>
Note 1, "Summary of Significant Accounting Policies - Income Taxes."
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: The company adopted the
provisions of Statement of Financial Accounting Standards No. 106,
"Employer's Accounting for Postretirement Benefits Other Than Pensions (SFAS
106)," effective January 1, 1993. For information on this change, see <F11>
Note 6, "Postretirement Benefits Other Than Pensions."
EMPLOYEE STOCK OWNERSHIP PLAN: The company adopted the provisions of
Statement of Position 93-6, "Employers' Accounting for Employee Stock
Ownership Plans (SOP 93-6)." For information on this change, see <F12>
Note 7, "Employee Stock Ownership Plan."
ACCOUNTING RECLASSIFICATIONS
Certain amounts in the accompanying consolidated financial statements of the
company for the year ended December 31, 1992 and December 31, 1991 have been
reclassified to conform with the December 31, 1993 presentation.
PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as 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 and other matters by the FERC and/or
applicable state regulatory commissions, and they follow the accounting
policies prescribed by the respective commissions.
REVENUES
Other than special contracts, 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.
35
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. At December 31, 1993, fees
due to the DOE for the disposal of prior-period fuel were approximately
$168.1 million, including interest costs of $85.9 million. As of December
31, 1993, approximately $166.8 million had been collected through rates.
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 operated by the DOE (D&D
assessment). The Energy Act imposes an overall cap of $2.25 billion on the
obligation of the commercial power industry and limits the annual special
assessment to $150 million each year over a 15-year period beginning in 1993.
The Energy Act also requires that regulators treat D&D assessments as a
reasonable and necessary cost of fuel, to be fully recovered in rates, like
any other fuel cost. The cap and annual recovery amounts will be adjusted
annually for inflation. The D&D assessment is allocated among utilities
based upon services purchased in prior years. At December 31, 1993, the
system's remaining share of these costs is estimated to be approximately
$53.5 million. CL&P, PSNH, WMECO, and NAEC have begun to recover these
costs. Accordingly, NU has recognized these costs as a regulatory asset,
with a corresponding obligation, on its Consolidated Balance Sheets.
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. 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. For more information on these
agreements, see <F13> Note 8, "Commitments And Contingencies-Purchased Power
Arrangements."
The 173-megawatt (MW) YAEC nuclear power plant was shut down permanently on
February 26, 1992. For more information on the Yankee companies, see <F8>
Note 3, "Nuclear Decommissioning."
MILLSTONE 3: CL&P, PSNH, and WMECO have a 68.02 percent joint-ownership
interest in Millstone 3, a 1,149-MW nuclear generating unit. As of December
31, 1993, plant-in-service and the accumulated provision for depreciation
included approximately $2.4 billion 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: As of December 31, 1993, CL&P and NAEC have a 39.63 percent joint-
ownership interest in Seabrook 1, a 1,150-MW nuclear generating unit. NAEC
sells all of its share of the power generated by Seabrook 1 to PSNH under a
long-term contract. As of December 31, 1993, plant-in-service and the
accumulated provision for depreciation included approximately $877.3 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. In
February 1994, NAEC purchased a 0.4 percent share of Seabrook 1. See <F13>
Note 8, "Commitments and Contingencies-PSNH Rate Agreement" for additional
information.
HYDRO-QUEBEC: NU has a 22.66 percent equity-ownership interest,
approximating $26.5 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 <F13> Note 8,
"Commitments and Contingencies-Hydro-Quebec" for additional information about
Hydro-Quebec.
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
36
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.
In 1993, an adjustment related to certain liabilities associated with the
acquisition reduced the regulatory asset-PSNH by approximately $9.4 million.
At December 31, 1993, the balance of the regulatory asset-PSNH was $769.5
million.
DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on the 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 <F8> 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 3.6 percent in 1993, 3.5 percent in
1992, and 3.6 percent in 1991.
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 29 for the
components of income tax expense.
In 1992, the Financial Accounting Standards Board (FASB) issued 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.
At December 31, 1993, the net deferred tax obligation relating to the
adoption of SFAS 109 approximated $1.2 billion. A valuation reserve was not
established. As it is probable that the increase in deferred tax liabilities
will be recovered from customers through rates, NU also established a
regulatory asset. SFAS 109 does not permit net-of-tax accounting.
Accordingly, the company no longer utilizes net-of-tax accounting for the
deferred nuclear plants return-borrowed funds and allowance for funds used
during construction (AFUDC)--borrowed funds.
The temporary differences which give rise to the accumulated deferred tax
obligation at December 31, 1993, are as follows:
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences . . . . . . . . $1,472,509
Net operating loss carryforwards . . . . . . (270,612)
The tax effect of net regulatory assets. . . 555,342
Other. . . . . . . . . . . . . . . . . . . . 154,742
----------
$1,911,981
==========
At December 31, 1993, PSNH has a net operating loss (NOL) carryforward of
approximately $788 million, and an Alternative Minimum Tax (AMT) NOL
carryforward of $600 million, both to be used against PSNH's federal taxable
income and expiring between the years 1999 and 2007. PSNH also had
Investment Tax Credit (ITC) carryforwards of $66 million, which expire
between the years 1994 and 2005. The reorganization of PSNH under Chapter 11
of the United States Bankruptcy Code limits its ability to use its NOL and
ITC carryforwards so that some portion may expire unused. Of the
carryforward amounts indicated above, approximately $323 million of the NOL,
$274 million of the AMT NOL, and $35 million of the ITC carryforwards are
available for use subject to applicable limits of the Internal Revenue Code.
ENERGY ADJUSTMENT CLAUSES
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. Administrative proceedings are required each month to
approve the FAC
37
charges or credits proposed for the following month. Monthly FAC rates are
also subject to retroactive review and appropriate adjustments by the
Connecticut Department of Public Utility Control (DPUC) each quarter after
public hearings.
Beginning in 1979, the DPUC approved the use of a generation utilization
adjustment clause (GUAC), which defers the effect on fuel costs caused by
variations from specified composite nuclear generation capacity factors
embedded in base rates. Generally, at the end of a 12-month period ending
July 31 of each year, these deferrals are refunded to, or collected from,
customers over the subsequent 11-month period beginning in September. Should
the annual composite nuclear capacity factor fall below the 55 percent GUAC
floor, CL&P has to apply to the DPUC for permission to recover the additional
fuel expense associated with nuclear performance below 55 percent.
On January 5, 1994, the DPUC issued a decision which ordered CL&P to offset
GUAC deferred charges against prior fuel overrecoveries. This disallowance
resulted in a zero GUAC rate for the period September 1993 through August
1994. CL&P is considering an appeal of this decision.
The DPUC further ordered that any GUAC deferrals subsequent to July 1993 will
be offset by any fuel overrecoveries whenever the composite nuclear capacity
factor is below the level embedded in base rates. For the period August 1993
to December 1993, there have been no further adjustments necessary as a
result of the DPUC's decision.
The January 5, 1994 DPUC decision creates some uncertainty about the future
operation of the GUAC. CL&P has requested the DPUC to clarify the portion of
the decision related to future calculation of the GUAC rate. Management does
not expect the decision to have a material adverse impact on CL&P's future
results of operations.
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).
WMECO: In Massachusetts, all retail fuel costs are collected on a current
basis by means of a separate fuel-charge billing rate. As permitted by the
Massachusetts Department of Public Utilities (DPU), WMECO defers the
difference between forecasted and actual fuel cost recoveries until it is
recovered or refunded quarterly under a retail fuel adjustment clause.
Massachusetts law requires the establishment of an annual performance program
related to fuel procurement and use. The program establishes performance
standards for plants owned and operated by WMECO or plants in which WMECO has
a life-of-unit contract. Therefore, revenues collected under the WMECO
retail fuel adjustment clause are subject to refund pending review by the
DPU. To date, there have been no significant adjustments as a result of this
program.
For additional information, see <F13> Note 8, "Commitments And
Contingencies--Nuclear Performance."
PHASE-IN PLANS
As discussed below,the system's operating companies are phasing into rates
the recoverable portions of their investments in Millstone 3 and Seabrook 1.
All plans are in compliance with Statement of Financial Accounting Standards
No. 92, "Regulated Enterprises--Accounting for Phase-in Plans."
CL&P: As allowed by the DPUC, CL&P is phasing into rate base its allowed
investment in Millstone 3. The DPUC has provided for full deferred earnings
and carrying charges on the portion of CL&P's allowed investment in Millstone
3 not included in rate base. Through December 31, 1993, CL&P had placed into
rate base $1.58 billion, or 90 percent, of its allowed investment in
Millstone 3. The remaining $175.7 million, or 10 percent, is to be phased
into rate base annually in two 5-percent steps beginning January 1, 1994.
The amortization and recovery of deferrals through rates began January 1,
1988 and will end no later than December 31, 1995. As of December 31, 1993,
$349.6 million of the deferred return, including carrying charges, has been
recovered, and $161.9 million of the deferred return to date, plus carrying
charges, remains to be recovered.
As allowed by the DPUC, CL&P phased into rate base its allowed investment in
Seabrook 1. The DPUC provided for full deferred earnings and carrying
charges on the portion of CL&P's allowed investment in Seabrook 1 not
included in rate base. Through December 31, 1993, CL&P has placed into rate
base its full allowed investment in Seabrook 1. The amortization and
recovery of deferrals through rates began September 1, 1991 and will end no
later than August 31, 1996. As of December 31, 1993, $15.8 million of the
deferred return, including carrying
38
charges, has been recovered, and $24.0 million of the deferred return
recorded to date, plus carrying charges,remains to be recovered.
WMECO: As of December 31, 1991, all of WMECO's recoverable investment in
Millstone 3 was in rate base. Beginning in 1986, the DPU has permitted WMECO
to recover the portion of its Millstone 3 investment representing the amount
currently determined to be "unuseful" by the DPU ($23.6 million at December
31, 1993) over a ten-year period, without earning a return. On June 30,
1987, WMECO also began recovering the deferred return, including carrying
charges, on the recoverable but not yet phased-in portion of its investment
in Millstone 3. This recovery is taking place over a nine-year period. As
of December 31, 1993, $65.4 million of the deferred return, including
carrying charges, has been recovered, and $22.7 million of the deferred
return, including carrying charges, remains to be recovered over the period
ending June 30, 1995.
NAEC: As prescribed by the Rate Agreement, NAEC is phasing in its $700-
million initial investment in Seabrook 1 (Initial Investment). As of
December 31, 1993, the portion of the Initial Investment on which NAEC is
entitled to earn a cash return was 55 percent and will increase by 15 percent
in each of the next three years beginning May 15, 1994. Between the
Reorganization Date and the Acquisition Date, PSNH recorded $50.9 million of
deferred return on its investment in Seabrook 1. In accordance with the Rate
Agreement, PSNH transferred the $50.9 million deferred return balance to NAEC
along with the other Seabrook assets. NAEC recorded the $50.9 million as
part of utility plant. From the Acquisition Date through December 31, 1993,
NAEC recorded an additional $85.4 million of deferred return, which is
recorded in deferred costs--nuclear plants on the Consolidated Balance
Sheets. The deferred return on the excluded portion of the Initial
Investment, including the $50.9 million, 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 15, 2001.
CASH AND SPECIAL DEPOSITS
Cash and special deposits at December 31, 1992 included $25 million in
special deposits that was used to redeem $15 million of Holyoke Water Power
Company's (HWP) Pollution Control Notes and $10 million of CL&P's Pollution
Control Notes in 1993.
<F7>
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 share 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 substation equipment, 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 $105,623,000
in 1993, $81,376,000 in 1992, and $69,876,000 in 1991. Interest included in
capital lease rental payments was $16,525,000 in 1993, $20,581,000 in 1992,
and $22,677,000 in 1991. Operating lease rental payments charged to
operating expense were $22,630,000 in 1993, $27,451,000 in 1992, and
$23,571,000 in 1991.
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 the long-term noncancelable leases, as of December 31,
1993, are provided on the next page.
39
- -----------------------------------------------------------------------------
Capital Operating
Year Leases Leases
- -----------------------------------------------------------------------------
(Thousands of Dollars)
1994 ......................... $ 9,800 $ 23,800
1995 ......................... 9,400 21,900
1996 ......................... 8,500 19,100
1997 ......................... 7,800 17,800
1998 ......................... 7,700 9,900
After 1998 ................... 57,000 34,000
------- --------
Future minimum lease
payments ................... 100,200 $126,500
========
Less amount representing
interest ................... 49,800
-------
Present value of future
minimum lease payments
for other than nuclear fuel. 50,400
Present value of future nuclear
fuel lease payments ........ 193,400
--------
Total ................... $243,800
========
<F8>
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 1991
Seabrook decommissioning study also confirmed that complete and immediate
dismantlement at retirement is the most viable and economic method of
decommissioning Seabrook 1. Decommissioning studies are reviewed and updated
periodically to reflect changes in decommissioning requirements, technology,
and inflation.
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1993
dollars, is $385.8 million and $309.9 million, respectively. The estimated
cost of decommissioning the system's ownership share of Millstone 3 and
Seabrook 1, in year-end 1993 dollars, is $286.6 million and $145.1 million,
respectively. 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
$29.4 million in 1993, $28.1 million in 1992, and $20.8 million in 1991.
Nuclear decommissioning, as a cost of removal, is included in the accumulated
provision for depreciation on the Consolidated Balance Sheets.
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. Under the terms of the Rate Agreement, PSNH
is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if
the unit is shut down prior to the expiration of its operating license. CL&P's
and NAEC's portion of the cost of decommissioning Seabrook 1 is paid to an
independent decommissioning financing fund managed by the state of New
Hampshire.
As of December 31, 1993, CL&P and WMECO have collected, through rates, $148.3
million and $37.6 million, respectively, toward the future decommissioning costs
of their share of the Millstone units, of which $154.4 million has been
transferred to external decommissioning trusts. As of December 31, 1993, PSNH
has collected, through rates, approximately $1.2 million toward the future
decommissioning costs of its share of Millstone 3, which has been transferred
to an external decommissioning trust. As of December 31, 1993, CL&P and NAEC
(including pre-Acquisition Date payments made by PSNH) have paid approximately
$860,000 and $7.3 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. At December 31, 1993, the balance in the accumulated reserve
for decommissioning amounted to $237.7 million.
Changes in requirements or technology, or adoption of a decommissioning method
other than immediate dismantlement, could 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. Although
allowances for decommissioning have increased significantly in recent years,
ratepayers in future years will 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 estimated costs, in year-end 1993 dollars, of
40
decommissioning the system's ownership share of CY and MY are $166.6 million and
$64.7 million, respectively. The cost to decommission VY is currently being
reestimated. The cost of decommissioning the system's ownership share of VY is
projected to range from $48 million to $56 million. As discussed in the
following paragraph, YAEC's owners voted to permanently shut down the YAEC unit
on February 26, 1992. 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 decommissioning its nuclear facility. On June 1, 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 operating license. The bulk of these costs has been agreed to by the
YAEC joint owners and approved, as a settlement, by FERC. At December 31, 1993,
the estimated remaining costs amounted to $345.0 million, of which the NU
system's share was approximately $132.8 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. The
system has a 38.5-percent equity investment, approximating $9.3 million, in
YAEC. The system had relied on YAEC for less that 1 percent of its capacity.
<F9>
4. SHORT-TERM DEBT
The system companies have various credit lines, totaling $485 million. NU,
CL&P, WMECO, HWP, Northeast Nuclear Energy Company (NNECO), and The Rocky
River Realty Company (RRR) have established a revolving-credit facility with
a group of 17 banks. Under this facility, the participating companies may
borrow up to an aggregate of $360 million. Individual borrowing limits are
$175 million for NU, $360 million for CL&P, $75 million for WMECO, $8 million
for HWP, $60 million for NNECO, and $25 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 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
of each bank's total commitment under the 364-day portion of the facility,
representing 25 percent of the total facility. At December 31, 1993, there
were $22.5 million in borrowings under the facility.
PSNH has credit lines totaling $125 million available through a revolving-
credit agreement with a group of 22 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, 1993, there were
no borrowings under the agreement.
Maturities of the system companies' 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, 1993, to
incur short-term borrowings up to a maximum of $175 million, $375 million,
$125 million, $75 million, and $50 million, respectively.
<F10>
5. 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 $29,173,000 in 1993, $9,681,000 in
1992, and $29,517,000 in 1991. Pension costs for 1993 and 1991 include
approximately $27,718,000 and $19,831,000, 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.
41
The components of net pension cost are:
- -----------------------------------------------------------------------------
For the Years Ended
December 31, 1993 1992 1991
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost ................. $ 59,068 $ 32,662 $ 48,738
Interest cost ................ 81,456 78,092 71,041
Return on plan assets ........ (176,798) (83,371) (198,437)
Net amortization ............. 65,447 (17,702) 108,175
--------- -------- ---------
Net pension cost.............. $ 29,173 $ 9,681 $ 29,517
========= ======== =========
- -----------------------------------------------------------------------------
For calculating pension costs, the following assumptions were used:
- -----------------------------------------------------------------------------
For the Years Ended
December 31, 1993 1992 1991
- -----------------------------------------------------------------------------
Discount rate ................ 8.00% 8.41% 9.00%
Expected long-term rate
of return .................. 8.50 9.00 9.70
Compensation/progression
rate ....................... 5.00 6.56 7.50
- -----------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
- -----------------------------------------------------------------------------
At December 31, 1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $817,421,000 of vested
benefits at December 31, 1993 and
$719,608,000 of vested benefits at
December 31, 1992 ................. $ 898,788 $ 764,432
========== ==========
Projected benefit obligation......... $1,141,271 $1,055,295
Less: Market value of
plan assets ....................... 1,340,249 1,226,468
---------- ----------
Market value in excess of projected
benefit obligation 198,978 171,173
Unrecognized transition amount ...... (16,735) (18,277)
Unrecognized prior service costs.... 10,287 8,658
Unrecognized net gain ............... (275,043) (214,894)
---------- ----------
Accrued pension liability ........... $ (82,513) $ (53,340)
========== ===========
- -----------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plan's year-
end funded status:
- -----------------------------------------------------------------------------
At December 31, 1993 1992
- -----------------------------------------------------------------------------
Discount rate .......................... 7.75% 8.00%
Compensation/progression rate .......... 4.75 5.00
- -----------------------------------------------------------------------------
The discount rate for 1993 was determined by analyzing the interest rates, as
of December 31, 1993, of long-term, high-quality corporate debt securities
having a duration comparable to the 13.8-year duration of the plan.
During 1993, NU's work force was reduced by approximately 7 percent through a
work force-reduction program that involved an early retirement program and
involuntary terminations. The cost of the program, which approximated $38
million, included pension, severance, and other benefits.
<F11>
6. 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. Through December 31, 1992, the system recognized the cost of
these benefits as they were paid. In December 1990, the FASB issued SFAS
106. This new standard requires that the expected cost of postretirement
benefits, primarily health and life insurance benefits, must be charged to
expense during the years that eligible employees render service. Effective
January 1, 1993, the system adopted SFAS 106 on a prospective basis. Total
health care and life insurance cost, part of which was deferred or charged to
utility plant, approximated $50,140,000 in 1993, $15,557,000 in 1992, and
$10,815,000 in 1991.
On January 1, 1993, the accumulated postretirement benefit obligation (APBO)
represented the system's prior-service obligation upon the adoption of
SFAS 106. As allowed by SFAS 106, the system is amortizing its APBO of
approximately $338 million over a 20-year period. For current employees and
certain retirees, the total SFAS 106 benefit is limited to two times the 1993
health care costs. The SFAS 106 obligation has been calculated based on this
assumption.
42
During 1993, certain subsidiaries of NU began 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 Sheet at December 31, 1993:
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees .......................... $(242,889)
Fully eligible active employees ... (540)
Active employees not eligible to
retire ............................ (67,955)
---------
Total accumulated postretirement
benefit obligation .................. (311,384)
Less: Market value of plan assets .... 12,642
---------
Accumulated postretirement benefit
obligation in excess of plan assets.. (298,742)
Unrecognized transition amount ........ 287,551
Unrecognized net gain ................. (5,150)
---------
Accrued postretirement benefit liability $ (16,341)
==========
- -----------------------------------------------------------------------------
The components of health care and life insurance costs for the year ended
December 31, 1993 are:
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost .......................... $ 9,175
Interest cost ......................... 25,330
Return on plan assets ................. (220)
Net amortization ...................... 15,855
-------
Net health care and life insurance costs $50,140
=======
- ----------------------------------------------------------------------------
For measurement purposes, an 11.1-percent annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1993; the rate
was assumed to decrease to 5.4 percent for 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, 1993 by $22.6 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit cost for the
year then ended by $2.3 million.
The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 7.75 percent. The discount rate for
1993 was determined by analyzing the interest rates, as of December 31, 1993,
of long-term, high-quality corporate debt securities having a duration
comparable to that of the plan. The trust holding the plan assets is subject
to federal income taxes at a 35-percent tax rate. The expected long-term
rate of return on plan assets after estimated taxes was 5.00 percent for
health assets and 8.50 percent for life assets.
CL&P and WMECO have received approval from their respective regulators to
defer SFAS 106 postretirement costs. All deferred costs are expected to be
recovered within ten years. PSNH is currently recovering SFAS 106 costs.
<F12>
7. EMPLOYEE STOCK OWNERSHIP PLAN
During December 1991 and March 1992, NU issued a total of $250 million
principal amount of unsecured and amortizing notes. The proceeds of the
notes were loaned to the trustee of the Employee Stock Ownership Plan (ESOP)
in exchange for the ESOP's notes. The ESOP trustee used the proceeds to buy
approximately 10.8 million newly issued NU common shares from the company.
These shares are allocated to employees at the same rate as the principal and
interest on the ESOP notes is being paid. Pursuant to the ESOP trust
agreement, Northeast Utilities Service Company, a wholly owned subsidiary of
NU, directs the ESOP trustee as to the timing, amount, and source of
principal and interest payments on the ESOP notes. Beginning January 1,
1992, NU common shares held by the ESOP trust were allocated to employees
based upon participation in the system's 401(k) plan to a previously
established tax-credit-based employee stock ownership plan (tax credit plan)
using dividend reinvestment. Regular system employees of the company's
subsidiaries are eligible to participate in the 401(k) plan. The tax-credit
plan was merged into the 401(k) plan on March 9, 1992. For the 12-month
period ending December 31, 1993, the ESOP issued approximately 530,000 NU
common shares, with a cost of approximately $14.0 million to the 401(k) plan
and to the tax-credit plan. As of December 31, 1993, the total number of
allocated and unallocated ESOP shares is 899,284 and 9,880,189, respectively,
with a corresponding fair market value of approximately $234.7 million on
unallocated ESOP shares.
During 1993, NU made an additional contribution of approximately $7.6 million
to the ESOP trust. The ESOP trust used approximately $23.7 million in
dividends paid on NU common shares and the $7.6 million contribution from NU
to
43
meet the principal and interest payments on the ESOP notes. During the
12-month period ending December 31, 1993, the ESOP trust incurred
approximately $20.9 million in interest expense.
In November 1993, the American Institute of Certified Public Accountants
issued SOP 93-6. This SOP is effective as of January 1, 1994 and has
significantly changed the accounting for leveraged ESOP plans. This new
standard requires that (1) any income tax benefits associated with the ESOP
be offset directly against income tax expense, (2) dividends on allocated
ESOP shares be charged directly to retained earnings, (3) dividends on
unallocated ESOP shares be excluded from dividends for financial reporting
purposes and, (4) unallocated ESOP shares be excluded from the earnings-per-
common-share calculation.
In the fourth quarter of 1993, NU opted for early implementation of this SOP,
effective as of January 1, 1993. The adoption of SOP 93-6 did not have a
material impact on 1993 earnings per common share; however, 1993 earnings for
common shares decreased by approximately $19.9 million as a result of
adopting the SOP. Had the provisions of SOP 93-6 been applied to 1992
results of operations, the impact on earnings per common share would not have
been material; however, 1992 earnings for common shares would have decreased
by approximately $16.0 million.
<F13>
8. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision. Actual
construction expenditures may vary from such 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
AFUDC) of approximately $1.2 billion for the years 1994-1998, including
$267.5 million for 1994. In addition, the system companies estimate that
nuclear fuel requirements, including nuclear fuel financed through the NBFT,
will be $449.7 million for the years 1994-1998, including $98.4 million for
1994. See <F7> Note 2, "Leases," for additional information about the
financing of nuclear fuel.
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 four of the
reviews. The Office of Consumer Counsel has appealed decisions favorable to
the company in two dockets. 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 docket is $26
million. The only remaining nuclear outage prudence docket before the DPUC
is the docket established to review the 1992 outage at Millstone 2 to replace
the steam generators. A decision is expected in late 1994. Management
believes that its actions with respect to these outages have been prudent,
and it does not expect the outcome of the prudence reviews to result in
material disallowances.
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 four increases were put into
effect on January 1, 1990, May 16, 1991, June 1, 1992, and June 1, 1993,
respectively. The remaining three increases are scheduled to be put into
effect annually beginning on June 1, 1994. PSNH's base rates, as adjusted to
reflect the 5.5 percent annual increases, are intended to recover assumed
increases in PSNH's costs and to provide PSNH with a reasonable cumulative
return on investment over the Fixed-Rate Period. As discussed in <F6>
Note 1, "Summary of Significant Accounting Policies--Energy Adjustment
Clauses-- 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 future retail rates, 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.
44
In January 1994, the NHPUC approved a Memorandum of Understanding (the
Memorandum) between PSNH, NAEC, Northeast Utilities Service Company, and the
Attorney General of the state of New Hampshire relating to certain issues
which had arisen under the Rate Agreement. The Memorandum addressed, among
other things, the tax legislation in New Hampshire, accounting treatments
resulting from adoption of SFAS No. 106 and SFAS No. 109, and recovery for
certain aspects of PSNH's settlement with the Vermont Electric Generation and
Transmission Cooperative, Inc. (VEG&T), including the purchase by NAEC of
VEG&T's 0.4 percent share of Seabrook. The Memorandum also provides for the
establishment of a regulatory liability attributable to significant NOL
carryforwards and establishes that such liability should be amortized over a
six-year period beginning on May 1, 1993.
ENVIRONMENTAL MATTERS
The system is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling and 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 program
to prevent, detect, and remedy noncompliance with environmental laws or
regulations and believes that it is in substantial compliance with current
environmental laws and regulations. Changing environmental requirements
could hinder the construction of new fossil-fuel generating units,
transmission and distribution lines, substations, and other facilities. The
cumulative long-term, economic cost impact of increasingly stringent
environmental requirements cannot be estimated. Changing environmental
requirements could also require extensive and costly modifications to the
system's existing hydro, nuclear, and fossil-fuel 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 and disposal
activities.
The system has recorded a liability for what it believes is, based upon
information currently available, its estimated environmental remediation
costs for waste disposal sites for which the system's subsidiaries expect to
bear legal liability. To date, these costs have not been material with
respect to the earnings or financial position of the company. In most cases,
the extent of additional future environmental cleanup costs is not reasonably
estimable due to factors such as the unknown magnitude of possible
contamination, the appropriate remediation method, the possible effects of
future legislation and regulation, the possible effects of technological
changes related to future cleanup, and the difficulty of determining future
liability, if any, for the cleanup of sites at which a system company may be
determined to be legally liable by the federal or state environmental
agencies. In addition, the system cannot estimate the potential liability
for future claims that may be brought against it by private parties.
However, considering known facts and existing laws and regulatory practices,
management does not believe that such matters will have a material adverse
effect on the system's financial position or future results of operations.
At December 31, 1993, 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 $4 million.
However, in the event that it becomes necessary to effect environmental
remedies that are currently not considered probable, it is reasonably
possible that, based on information currently available and management
intent, that the upper limit of the system's environmental liability range
could increase to approximately $9 million.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $9.4 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 $8.8 billion
would be provided by an assessment of $75.5 million per incident, levied on
each of the 116 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 $437.9 million in total, for all 116 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 $243.9
million per incident. In addition, through power purchase contracts with the
four
45
Yankee regional nuclear generating companies, the system would be responsible
for up to an additional $97.9 million per incident. Payments for the
system's ownership interest in nuclear generating facilities would be limited
to a maximum of $43.1 million per incident per year.
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 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 $13.9 million under the replacement power policies and
$29.9 million under the 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 companies insured under this coverage are
subject to retrospective assessments of $3.2 million per reactor. The
maximum potential assessments against the system with respect to losses
arising during the current policy period are approximately $13.9 million.
FINANCING ARRANGEMENTS FOR THE REGIONAL NUCLEAR GENERATING COMPANIES
CL&P, PSNH, and WMECO believe that the regional nuclear generating companies
may require additional external financing in the next several years for
construction expenditures, nuclear fuel, possible refinancings, and other
purposes. Although the ways in which each regional nuclear generating
company will attempt to finance these expenditures have not been determined,
CL&P, PSNH, and WMECO may be asked to provide direct or indirect financial
support for one or more of these companies.
PURCHASED POWER ARRANGEMENTS
CL&P, PSNH, and WMECO purchase a portion 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, 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 $169.0 million
in 1993, $145.4 million in 1992, and $127.5 million in 1991. See <F6>
Note 1, "Summary of Significant Accounting Policies--Investments And Jointly
Owned Electric Utility Plant" and <F8> 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. For the 12 months ended
December 31, 1993, 14 percent of NU system load requirements was met by
cogenerators and small-power producers. The total cost of purchases under
these arrangements amounted to $426.8 million in 1993, $323.8 million in
1992, and $241.4 million in 1991. These costs are eventually recovered
through the companies' rates.
In an effort to control cost and price increases from nonutility generators,
PSNH is in the process of attempting to negotiate contract buyouts with 13
nonutility generators. Settlement agreements have been reached with certain
nonutility generators and have been filed with the NHPUC for approval.
Negotiations continue with the remaining nonutility generators.
PSNH entered into a buy-back agreement to purchase the capacity and energy of
the New Hampshire Electric Cooperative, Inc. (NHEC) 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 $14.4 million in 1993, $13.8
million in 1992, and $11.6 million in 1991. 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.
46
The estimated annual cost of the system's significant purchase power
arrangements is provided below:
- -----------------------------------------------------------------------------
1994 1995 1996 1997 1998
- -----------------------------------------------------------------------------
(Millions of Dollars)
Yankee
Companies ............ $162.5 $169.0 $187.4 $172.2 $195.5
Nonutility
Generators ........... 463.2 477.4 491.9 502.7 514.2
NHEC ................. 14.6 15.2 16.2 24.4 32.4
- -----------------------------------------------------------------------------
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 share of the annual operation, maintenance, and capital costs
of these facilities, which are currently forecast to be $172.1 million for
the years 1994-1998, including $37.2 million for 1994.
GREAT BAY POWER CORPORATION
CL&P and The United Illuminating Company, an unaffiliated company, have
agreed to make certain advances up to $20 million to cover shortfalls in the
funding of the 12.13 percent ownership interest in Seabrook 1 of Great Bay
Power Corporation, an unaffiliated company. CL&P's share of this commitment
is limited to 60 percent of the advances, or $12 million. As of December 31,
1993, $1,047,000 of advances from CL&P were outstanding under this agreement.
PROPERTY TAXES
PSNH and CY have significant court appeals pending for property tax
assessments in the towns of Bow, New Hampshire, and Haddam, Connecticut,
respectively, concerning production plant. In each case, the central issue
is the fair market value of utility property. The company believes that
properly derived assessments that recognize the effect of rate regulation
will result in fair market values that approximate net book cost. This is
the assessment level that taxing authorities are predominantly using
throughout Connecticut, Massachusetts, and some of New Hampshire. However,
towns such as Bow and Haddam advocate a method that approximates reproduction
cost. The company estimates that, for the assessments in the towns where the
appeals are pending, the change to a reproduction cost-methodology could
result in property tax valuations approximately three times greater than
values approximating net book cost. Although PSNH and CY are currently
paying property taxes based on the higher assessments, to date, the higher
assessments have not had a material adverse effect on them or the company.
The company believes that assessment levels that approximate net book cost
accurately reflect the fair market value of regulated utility property.
However, because of uncertainties associated with the court appeals and the
potential impact of adverse court decisions on property tax assessment policy
in New Hampshire and Connecticut, the company cannot estimate the potential
effects of adverse court decisions on future results of operations or
financial condition. However, the company believes that, based upon past
regulatory practices, it would be allowed to recover any increased property
tax assessments prospectively beginning at the time new rates are
established.
<F14>
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, SPECIAL DEPOSITS, AND NUCLEAR DECOMMISSIONING TRUSTS: The carrying
amounts approximate fair value.
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.
47
The carrying amounts of the system's financial instruments and the estimated
fair values are as follows:
- -----------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------
Carrying Fair
At December 31, 1992 Amount Value
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ................. $ 304,696 $ 257,510
Preferred stock subject to
mandatory redemption ................. 353,500 378,730
Long-term debt --
First Mortgage Bonds ................. 2,553,135 2,675,251
Other long-term debt ................. 2,041,632 2,141,154
- -----------------------------------------------------------------------------
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts that those
obligations would be settled at.
In May 1993, the FASB issued Statement of Financial Accounting Standards No.
115, "Accounting for Certain Investments in Debt and Equity Securities
(SFAS 115)." SFAS 115 requires companies to disclose the classification of
investments in debt or equity securities based on management's intent and
ability to hold the security. SFAS 115 also requires disclosure of the
aggregate fair value, gross unrealized holding gains, gross unrealized
holding losses and amortized cost basis by major security type. Effective
January 1, 1994, the system will adopt SFAS 115 on a prospective basis. NU
anticipates that the adoption of SFAS 115 will not have a material impact on
future results of operations or financial position.
48
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED
1993 <F15>(a) March 31 June 30 September 30
December 31
-------- ------- ------------
- -----------
(Thousands of Dollars, except per share
data)
Operating Revenues .............. $958,192 $853,769 $915,239
$901,893
======== ======== ========
========
Operating Income................. $125,079 $ 89,510 $l02,725
$134,361
======== ======== ========
========
Net Income....................... $112,447 $ 14,759 $ 46,421 $
76,326
======== ======== ========
========
Earnings Per Common Share ....... $ 0.91 $ 0.12 $ 0.37 $
0.62
======== ======== ========
========
1992 <F16>(b)
Operating Revenues .............. $762,730 $718,746 $847,873
$887,525
======== ======== ========
========
Operating Income................. $112,690 $104,291 $115,077
$108,372
======== ======== ========
========
Net Income ...................... $ 75,018 $ 64,426 $ 61,355 $
55,255
======== ======== ========
========
Earnings Per Common Share........ $ 0.63 $ 0.50 $ 0.47 $
0.43
======== ======== ========
========
CONSOLIDATED GENERAL OPERATING STATISTICS
1993 1992<F16>(b) 1991 1990 1989
---- ----------- ---- ---- ----
System Capability-MW (c)<F17>.. 7,795.3 7,823.2 5,916.2 5,909.6
5,963.7
System Peak Demand-MW.......... 6,191.0 5,781.0 4,999.8 4,753.9
4,858.0
Nuclear Capacity-MW(c)<F17>.... 3,110.0 2,981.1 2,380.0 2,459.5
2,397.1
Nuclear Capacity Factor(%)(d)<F18> 80.8 63.7 50.6 69.4
68.6
Nuclear Contribution to Total
Energy Requirements (%) (c)<F17> 62.1 48.5 43.5 57.5
56.8
<F15>(a) Amounts have been restated from those previously reported due to the
adoption in the fourth
quarter of 1993 of a change in accounting for the company's ESOP,
effective January 1,1993.
<F16>(b) Effective with the June 5, 1992 acquisition of PSNH, the consolidated
financial and
statistical information of NU includes, on a prospective basis, the
operations of PSNH and
NAEC.
<F17>(c) Includes the system's entitlements in regional nuclear generating
companies, net of capacity
sales and purchases.
<F18>(d) Represents the average capacity factor for the nuclear units operated
by the NU system.
49
SELECTED CONSOLIDATED FINANCIAL DATA
1993 1992<F19>(a) 1991
1990
---- ------------ ----
----
(Thousands of Dollars, except percentages
and share data)
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 6,669,661 $ 6,719,652 $ 5,257,567
$ 5,265,168
Discontinued Gas Plant .............. -- -- --
--
Total Assets ......................... 10,668,164 9,724,340 6,781,746
6,601,371
Total Capitalization <F20>(b)......... 7,309,898 7,421,592 5,138,426
4,965,859
Obligations Under Capital Leases <F20>(b) 243,760 266,100 279,729
319,548
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 3,629,093 $ 3,216,874 $ 2,753,803
$ 2,616,319
Net Income.......................<F21> 249,953(c) 256,054 236,709
211,007
Earnings per Common Share........<F21> $2.02(c) $2.02 $2.12
$1.94
Discontinued Gas Operations:
Operating Revenues................... $ -- $ -- $ --
$ --
Net Income........................... -- -- --
--
Earnings per Common Share ........... $ -- $ -- $ --
$ --
COMMON SHARE DATA:
Earnings per Share...............<F21> $2.02(c) $2.02 $2.12
$1.94
Dividends per Share ................. $1.76 $1.76 $1.76
$1.76
Payout Ratio (%)..................... 87.1 87.1 83.0
90.7
Number of Shares
Outstanding--Average............<F22> 123,947,631(d)130,403,488 111,453,550
109,003,818
Market Price--High................... $28 7/8 $26 3/4 $24 3/8
$22 5/8
Market Price--Low.................... $22 $22 1/2 $19
$17 7/8
Market Price--Closing Price
(end of year) ..................... $23 3/4 $26 l/2 $23 5/8
$20
Book Value per Share(end of year).... $17.89 $16.24 $15.73
$16.34
Rate of Return Earned on Average
Common Equity (%) ................. 11.4 12.7 13.0
12.0
Dividend Yield (end of year) (%) .... 7.4 6.6 7.4
8.8
Market-to-Book Ratio (end of year)... 1.3 1.6 1.5
1.2
Price-Earnings Ratio (end of year)... 11.8 13.1 11.1
10.3
CAPITALIZATION: <F20> (b)
Common Shareholders' Equity......... $ 2,224,088 $ 2,173,977 $ 1,876,074
$ l,790,758
Preferred Stock Not Subject
to Mandatory Redemption........... 239,700 304,696 394,695
394,695
Preferred Stock Subject to
Mandatory Redemption ............. 382,000 353,500 170,394
176,892
Long-Term Debt...................... 4,464,110 4,589,419 2,697,263
2,603,514
----------- ----------- -----------
-----------
Total Capitalization ............... $ 7,309,898 $ 7,421,592 $ 5,138,426
$ 4,965,859
=========== =========== ===========
===========
<F19>(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.
<F20>(b) Includes portions due within one year.
<F21>(c) Includes the cumulative effect of change in accounting for municipal
property tax expense.
<F22>(d) Decease in the number of shares results from a change in accounting for
Employee Stock
Ownership Plan shares.
50
1989 1988 1987
1986
---- ---- ----
----
(Thousands of Dollars, except percentages
and share data)
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,237,805 $ 5,267,629 $ 5,229,242
$ 5,120,812
Discontinued Gas Plant .............. -- 254,587 237,903
224,581
Total Assets ......................... 6,523,202 6,764,608 6,663,794
6,299,755
Total Capitalization <F20>(b)......... 4,954,083 5,123,504 4,956,080
4,743,914
Obligations Under Capital Leases <F20>(b) 341,246 410,352 432,714
441,183
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 2,473,571 $ 2,268,607 $ 2,038,554
$ 2,006,842
Net Income........................... 203,225 224,844 214,529
171,234
Earnings per Common Share............ $1.87 $2.07 $1.97
$1.58
Discontinued Gas Operations:
Operating Revenues................... $ 124,229 $ 200,243 $ 202,816
$ 203,814
Net Income........................... 5,858 9,078 14,616
10,705
Earnings per Common Share ........... $0.05 $0.08 $0.14
$0.10
COMMON SHARE DATA:
Earnings per Share................... $1.92 $2.15 $2.11
$1.68
Dividends per Share ................. $1.76 $1.76 $1.76
$1.68
Payout Ratio (%)..................... 91.7 81.9 83.4
100.0
Number of Shares
Outstanding--Average................ 108,669,106 108,669,106 108,669,106
108,352,517
Market Price--High................... $23 $23 1/8 $28
$28 1/4
Market Price--Low.................... $18 1/2 $18 1/4 $18
$17 3/8
Market Price--Closing Price
(end of year) ..................... $22 1/2 $19 7/8 $20
1/4 $24 1/4
Book Value per Share(end of year).... $16.13 $16.90 $16.53
$16.24
Rate of Return Earned on Average
Common Equity (%) ................. 11.8 13.0 12.8
10.4
Dividend Yield (end of year) (%) .... 7.8 8.9 8.7
6.9
Market-to-Book Ratio (end of year)... 1.4 1.2 1.2
1.5
Price-Earnings Ratio (end of year)... 11.7 9.2 9.6
14.4
CAPITALIZATION: <F20>(b)
Common Shareholders' Equity......... $ 1,752,395 $ 1,837,034 $ 1,796,293
$ l,765,090
Preferred Stock Not Subject
to Mandatory Redemption........... 394,695 344,695 291,195
291,195
Preferred Stock Subject to
Mandatory Redemption ............. 181,892 111,832 205,832
166,832
Long-Term Debt...................... 2,625,101 2,829,943 2,662,760
2,520,797
----------- ----------- -----------
-----------
Total Capitalization ............... $ 4,954,083 $ 5,123,504 $ 4,956,080
$ 4,743,914
=========== =========== ===========
===========
51.1
1985 1984
---- ----
(Thousands of Dollars, except percentages and share
data)
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,204,687 $ 4,650,428
Discontinued Gas Plant .............. 214,115 204,187
Total Assets ......................... 6,147,720 5,507,040
Total Capitalization ................. 4,681,995 4,319,404
Obligations Under Capital Leases<F20>(b) 440,587 392,593
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 1,969,225 $ 2,030,557
Net Income........................... 277,768 276,615
Earnings per Common Share............ $2.62 $2.73
Discontinued Gas Operations:
Operating Revenues................... $ 220,010 $ 224,430
Net Income........................... 10,773 12,323
Earnings per Common Share ........... $0.10 $0.12
COMMON SHARE DATA:
Earnings per Share................... $2.72 $2.85
Dividends per Share ................. $1.58 $1.48
Payout Ratio (%)..................... 58.1 51.9
Number of Shares
Outstanding--Average............... 106,221,131 101,398,235
Market Price--High.................. $18 3/4 $14 3/4
Market Price--Low.................... $13 3/4 $10 5/8
Market Price--Closing Price
(end of year) ..................... $17 3/4 $14 1/4
Book Value per Share(end of year).... $16.21 $15.07
Rate of Return Earned on Average
Common Equity (%) ................. 17.4 19.8
Dividend Yield (end of year) (%) .... 8.9 10.4
Market-to-Book Ratio (end of year)... 1.1 0.9
Price-Earnings Ratio (end of year)... 6.5 5.0
CAPITALIZATION: <F20>(b)
Common Shareholders' Equity......... $ 1,738,871 $ 1,575,705
Preferred Stock Not Subject
to Mandatory Redemption........... 291,195 291,195
Preferred Stock Subject to
Mandatory Redemption ............. 185,833 186,978
Long-Term Debt...................... 2,466,096 2,265,526
----------- -----------
Total Capitalization ............... $ 4,681,995 $ 4,319,404
=========== ===========
51.2
CONSOLIDATED ELECTRIC OPERATING STATISTICS
1993 1992<F23>(a) 1991
1990
---- ------------ ----
----
SOURCE OF ELECTRIC ENERGY:
(kWh-millions) <F24>(b)
Nuclear--Steam........................ 22,965 15,520 11,062
17,724
Fossil--Steam......................... 7,676 6,784 6,179
6,829
Hydro--Conventional................... 1,140 1,076 994
1,174
Hydro--Pumped Storage................. 1,269 1,221 1,173
1,250
Internal Combustion................... 8 9 25
11
Energy Used for Pumping .............. (1,749) (1,671) (1,605)
(1,688)
------ ------ ------
------
Net Generation..................... 31,309 22,939 17,828
25,300
Purchased and Net Interchange......... 10,499 14,165 13,430
6,249
Company Use and Unaccounted for ...... (2,591) (2,028) (1,958)
(1,938)
------ ------ ------
------
Net Energy Sold.................... 39,217 35,076 29,300
29,611
====== ====== ======
======
REVENUE: (thousands)
Residential........................... $1,385,818 $1,213,140 $ 995,098
$ 938,032
Commercial............................ 1,043,125 943,832 828,117
788,478
Industrial............................ 649,876 554,587 419,003
410,125
Other Utilities ...................... 383,129 346,791 366,231
346,087
Streetlighting and Railroads.......... 45,480 43,296 38,656
37,195
Miscellaneous......................... 60,008 59,465 49,539
42,882
---------- ---------- ----------
----------
Total Electric ................... 3,567,436 3,161,111 2,696,644
2,562,799
Other................................. 61,657 55,763 57,159
53,520
---------- ---------- ----------
----------
Total............................. $3,629,093 $3,216,874 $2,753,803
$2,616,319
========== ========== ==========
==========
SALES: (kWh-millions)
Residential.......................... 11,988 10,839 9,518
9,500
Commercial........................... 10,304 9,608 8,900
8,981
Industrial........................... 7,572 6,593 5,208
5,448
Other Utilities ..................... 9,046 7,733 5,388
5,394
Streetlighting and Railroads......... 307 303 286
288
------ ------ ------
------
Total............................ 39,217 35,076 29,300
29,611
====== ====== ======
======
CUSTOMERS: (average)
Residential......................... 1,503,182 1,351,019 1,150,357
1,145,142
Commercial.......................... 155,487 132,680 102,867
102,900
Industrial.......................... 6,272 5,774 5,067
5,114
Other............................... 3,793 3,581 3,305
3,283
--------- --------- ---------
---------
Total............................ 1,668,734 1,493,054 1,261,596
1,256,439
========= ========= =========
=========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 7,987 8,129 8,285
8,304
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $923.32 $909.80 $866.20
$819.94
AVERAGE REVENUE PER kWh:
Residential......................... 11.56 cents 11.19 cents 10.45cents
9.87 cents
Commercial.......................... 10.12 9.82 9.30
8.78
Industrial.......................... 8.58 8.41 8.05
7.53
<F23>(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.
<F24>(b) Generated in system and regional nuclear generating plants.
52
1989 1988 1987
1986
---- ---- ----
----
SOURCE OF ELECTRIC ENERGY:
(kWh-millions)<F24> (b)
Nuclear--Steam........................ 17,119 19,146 18,019
16,624
Fossil--Steam......................... 8,956 8,805 7,912
9,048
Hydro--Conventional................... 956 825 866
895
Hydro--Pumped Storage................. 1,194 1,111 973
950
Internal Combustion................... 77 84 39
33
Energy Used for Pumping .............. (1,629) (1,509) (1,322)
(1,293)
------ ------ ------
------
Net Generation..................... 26,673 28,462 26,487
26,257
Purchased and Net Interchange......... 5,178 2,456 2,585
3,328
Company Use and Unaccounted for ...... (2,304) (2,333) (2,082)
(2,050)
------ ------ ------
------
Net Energy Sold.................... 29,547 28,585 26,990
27,535
====== ====== ======
======
REVENUE: (thousands)
Residential........................... $ 898,471 $ 838,011 $ 780,866
$ 741,838
Commercial............................ 734,709 673,819 630,678
602,924
Industrial............................ 391,661 366,517 353,394
350,310
Other Utilities ...................... 301,045 227,653 203,642
234,222
Streetlighting and Railroads.......... 35,499 33,151 32,318
34,741
Miscellaneous......................... 64,282 82,169 (18,146)
(2,464)
---------- ---------- ----------
----------
Total Electric ................... 2,425,667 2,221,320 1,982,752
1,961,571
Other................................. 47,904 47,287 55,802
45,271
---------- ---------- ----------
----------
Total............................. $2,473,571 $2,268,607 $2,038,554
$2,006,842
========== ========== ==========
==========
SALES: (kWh-millions)
Residential.......................... 9,594 9,412 8,825
8,274
Commercial........................... 8,757 8,585 8,151
7,676
Industrial........................... 5,557 5,535 5,449
5,394
Other Utilities ..................... 5,351 4,771 4,284
5,883
Streetlighting and Railroads......... 288 282 281
308
------ ------ ------
------
Total............................ 29,547 28,585 26,990
27,535
====== ====== ======
======
CUSTOMERS: (average)
Residential......................... 1,134,588 1,117,356 1,091,539
1,063,998
Commercial.......................... 101,301 98,095 94,164
90,924
Industrial.......................... 5,090 5,063 5,084
5,102
Other............................... 3,277 3,222 3,120
3,096
--------- --------- ---------
---------
Total............................ 1,244,256 1,223,736 1,193,907
1,163,120
========= ========= =========
=========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 8,460 8,418 8,061
7,746
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $792.28 $749.54 $713.24
$694.51
AVERAGE REVENUE PER kWh:
Residential......................... 9.36 cents 8.90 cents 8.85cents
8.97 cents
Commercial.......................... 8.39 7.85 7.74
7.85
Industrial.......................... 7.05 6.62 6.49
6.49
53.1
1985 1984
---- ----
SOURCE OF ELECTRIC ENERGY:
(kWh-millions) <F24>(b)
Nuclear--Steam........................ 11,453 13,711
Fossil--Steam......................... 8,325 9,065
Hydro--Conventional................... 726 840
Hydro--Pumped Storage................. 925 875
Internal Combustion................... 16 34
Energy Used for Pumping .............. (1,287) (1,199)
------ ------
Net Generation..................... 20,158 23,326
Purchased and Net Interchange......... 5,398 2,916
Company Use and Unaccounted for ...... (1,859) (1,793)
------ ------
Net Energy Sold.................... 23,697 24,449
====== ======
REVENUE: (thousands)
Residential........................... $ 750,076 $ 754,075
Commercial............................ 606,414 589,898
Industrial............................ 371,079 381,289
Other Utilities ...................... 165,071 216,227
Streetlighting and Railroads.......... 34,899 32,252
Miscellaneous......................... 9,698 29,340
---------- ----------
Total Electric ................... 1,937,237 2,003,081
Other................................. 31,988 27,476
---------- ----------
Total............................. $1,969,225 $2,030,557
========== ==========
SALES: (kWh-millions)
Residential.......................... 7,837 7,804
Commercial........................... 7,185 6,904
Industrial........................... 5,286 5,374
Other Utilities ..................... 3,094 4,113
Streetlighting and Railroads......... 295 254
------ ------
Total............................ 23,697 24,449
====== ======
CUSTOMERS: (average)
Residential......................... 1,041,254 1,021,871
Commercial.......................... 88,031 85,658
Industrial.......................... 5,087 5,022
Other............................... 3,067 3,025
--------- ---------
Total............................ 1,137,439 1,115,576
========= =========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 7,492 7,596
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $717.06 $734.00
AVERAGE REVENUE PER kWh:
Residential......................... 9.57 cents 9.66 cents
Commercial.......................... 8.44 8.54
Industrial.......................... 7.02 7.10
53.2
SHAREHOLDER INFORMATION
SHAREHOLDERS
As of January 31, 1994, there were 144,741 common shareholders of
record of Northeast Utilities holding an aggregate of 134,207,604
common shares.
COMMON SHARE INFORMATION
The common shares of Northeast Utilities are listed on the New York Stock
Exchange. The ticker symbol is "NU," although it is frequently presented
as "Noeast Util" in various financial publications. The high and low sales
prices and dividends paid for the past two years, by quarters, are shown
below:
- -------------------------------------------------------
Quarterly
Dividend
Year Quarter High Low Per Share
- -------------------------------------------------------
1993 First $28 7/8 $25 1/2 $0.44
Second 28 3/4 25 1/4 0.44
Third 28 1/8 26 1/4 0.44
Fourth 27 3/8 22 0.44
1992 First $24 7/8 $22 1/2 $0.44
Second 24 3/4 22 3/4 0.44
Third 26 5/8 23 7/8 0.44
Fourth 26 3/4 24 7/8 0.44
- -------------------------------------------------------
DIVIDEND REINVESTMENT PLAN
The company has a Dividend Reinvestment Plan under which common shareholders
may use their dividends to purchase additional common shares.
Northeast Utilities Service Company, Shareholder Services, P.O. Box 5006,
Hartford, Connecticut 06102-5006, is the company's dividend-paying agent and
administers its Dividend Reinvestment Plan.
ANNUAL MEETING
The annual meeting of shareholders of Northeast Utilities will be held on
Tuesday, May 24, 1994, at 10 a.m., at La Renaissance, East Windsor,
Connecticut, which is located at Exit 44 (East Windsor) of Interstate 91.
TRANSFER AGENTS AND REGISTRARS
Northeast Utilities Service Company
Shareholder Services
P.O. Box 5006
Hartford, Connecticut 06102-5006
State Street Bank and Trust Company
Corporate Stock Transfer Department
P.O. Box 8200
Boston, Massachusetts 02266-8200
FORM 10-K
Northeast Utilities will provide shareholders a copy of its 1993
Annual Report to the Securities and Exchange Commission on Form
10-K, including the financial statements and schedules thereto,
without charge, upon receipt of a written request sent to:
Theresa H. Allsop
Assistant Secretary
Northeast Utilities
P.O. Box 270
Hartford, Connecticut 06141-0270
54