FORM 10-K/A (Amendment No. 1)
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
------------------------------------------------------------------------
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
----------- ------------------------------------ ------------------
1-5324 NORTHEAST UTILITIES 04-2147929
(a Massachusetts voluntary association)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-0010
Telephone: (413) 785-5871
0-404 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
(a Connecticut corporation)
Selden Street
Berlin, Connecticut 06037-1616
Telephone: (203) 665-5000
1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
(a New Hampshire corporation)
1000 Elm Street
Manchester, New Hampshire 03105
Telephone: (603) 669-4000
0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
(a Massachusetts corporation)
174 Brush Hill Avenue1-21-21
West Springfield, Massachusetts 01090-0010
Telephone: (413) 785-5871
33-43508 NORTH ATLANTIC ENERGY CORPORATION 06-1339460
(a New Hampshire corporation)
1000 Elm Street
Manchester, New Hampshire 03105
Telephone: (603) 669-4000
- ----------------------------------------------------------------------------
THE SOLE PURPOSE OF THIS AMENDMENT IS TO REFLECT CERTAIN FORMAT ADJUSTMENTS
TO EXHIBITS 13.1 THROUGH 13.5 OF PART III OF THE REGISTRANTS' COMBINED ANNUAL
REPORT ON FORM 10-K FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MARCH
25, 1994. NO SUBSTANTIVE CHANGES TO THE MATERIAL CONTAINED IN THE FORM 10-K ARE
INCLUDED IN THIS AMENDMENT.
<PAGE>
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
NORTHEAST UTILITIES
-------------------
(Registrant)
Date: March 18, 1994 By /s/ William B. Ellis
-------------- ---------------------------
William B. Ellis
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
Date Title Signature
---- ----- ---------
March 18, 1994 Trustee and Chairman /s/ William B. Ellis
- -------------- of the Board -------------------------
William B. Ellis
March 18, 1994 Trustee, President /s/ Bernard M. Fox
- -------------- and Chief Executive -------------------------
Officer Bernard M. Fox
March 18, 1994 Executive Vice /s/ Robert E. Busch
- -------------- President and Chief -------------------------
Financial Officer Robert E. Busch
March 18, 1994 Vice President and /s/ John B. Keane
- -------------- Treasurer -------------------------
John B. Keane
March 18, 1994 Vice President and /s/ John W. Noyes
- -------------- Controller -------------------------
John W. Noyes
<PAGE>1
NORTHEAST UTILITIES
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 18, 1994 Trustee /s/ Cotton Mather Cleveland
- -------------- ---------------------------
Cotton Mather Cleveland
March 18, 1994 Trustee /s/ George David
- -------------- ---------------------------
George David
March 18, 1994 Trustee /s/ Donald J. Donahue
- -------------- ---------------------------
Donald J. Donahue
March 18, 1994 Trustee /s/ Eugene D. Jones
- -------------- ---------------------------
Eugene D. Jones
March 18, 1994 Trustee /s/ Elizabeth T. Kennan
- -------------- ---------------------------
Elizabeth T. Kennan
Trustee
- -------------- ---------------------------
Denham C. Lunt, Jr.
March 18, 1994 Trustee /s/ William J. Pape II
- -------------- ---------------------------
William J. Pape II
March 18, 1994 Trustee /s/ Robert E. Patricelli
- -------------- ---------------------------
Robert E. Patricelli
Trustee
- -------------- ---------------------------
Norman C. Rasmussen
Trustee
- -------------- ---------------------------
John F. Swope
<PAGE>2
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
(Registrant)
Date: March 18, 1994 By /s/ William B. Ellis
-------------- ---------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 18, 1994 Chairman and Director /s/ William B. Ellis
- -------------- --------------------------
William B. Ellis
March 18, 1994 Vice Chairman and /s/ Bernard M. Fox
- -------------- Director --------------------------
Bernard M. Fox
March 18, 1994 President and Director /s/ Hugh C. MacKenzie
- -------------- --------------------------
Hugh C. MacKenzie
March 18, 1994 Executive Vice /s/ Robert E. Busch
- -------------- President, Chief --------------------------
Financial Officer Robert E. Busch
and Director
March 18, 1994 Vice President and /s/ John W. Noyes
- -------------- Controller --------------------------
John W. Noyes
<PAGE>3
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
- ------------------- Director --------------------------
Robert G. Abair
March 18, 1994 Director /s/ John P. Cagnetta
- ------------------- --------------------------
John P. Cagnetta
March 18, 1994 Director /s/ William T. Frain, Jr.
- ------------------- --------------------------
William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise
- ------------------- -----------------------
Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane
- ------------------- -----------------------
John B. Keane
March 18, 1994 Director /s/ John F. Opeka
- ------------------- -----------------------
John F. Opeka
<PAGE>4
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------
(Registrant)
Date: March 18, 1994 By /s/ William B. Ellis
-------------- -------------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 18, 1994 Chairman and Director /s/ William B. Ellis
- -------------- --------------------------
William B. Ellis
March 18, 1994 Vice Chairman, Chief /s/ Bernard M. Fox
- -------------- Executive Officer and --------------------------
Director Bernard M. Fox
March 18, 1994 President, Chief /s/ William T. Frain, Jr.
- -------------- Operating Officer --------------------------
and Director William T. Frain, Jr.
March 18, 1994 Executive Vice /s/ Robert E. Busch
- -------------- President, Chief --------------------------
Financial Officer Robert E. Busch
and Director
March 18, 1994 Vice President and /s/ John W. Noyes
- -------------- Controller --------------------------
John W. Noyes
<PAGE>5
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 18, 1994 Director /s/ John C. Collins
- ------------------- --------------------------
John C. Collins
March 18, 1994 Director /s/ Gerald Letendre
- ------------------- --------------------------
Gerald Letendre
March 18, 1994 Director /s/ Hugh C. MacKenzie
- ------------------- --------------------------
Hugh C. MacKenzie
March 18, 1994 Director /s/ Jane E. Newman
- ------------------- --------------------------
Jane E. Newman
March 18, 1994 Director /s/ Dale S. Nitzschke
- ------------------- --------------------------
Dale S. Nitzschke
March 18, 1994 Director /s/ Robert P. Wax
- ------------------- --------------------------
Robert P. Wax
<PAGE>6
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
--------------------------------------
(Registrant)
Date: March 18, 1994 By /s/ William B. Ellis
-------------- --------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 18, 1994 Chairman and Director /s/ William B. Ellis
- -------------- --------------------------
William B. Ellis
March 18, 1994 Vice Chairman and /s/ Bernard M. Fox
- -------------- Director --------------------------
Bernard M. Fox
March 18, 1994 President and Director /s/ Hugh C. MacKenzie
- -------------- --------------------------
Hugh C. MacKenzie
March 18, 1994 Executive Vice /s/ Robert E. Busch
- -------------- President, Chief --------------------------
Financial Officer Robert E. Busch
and Director
March 18, 1994 Vice President and /s/ John W. Noyes
- -------------- Controller --------------------------
John W. Noyes
<PAGE>7
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
- ------------------- Director --------------------------
Robert G. Abair
March 18, 1994 Director /s/ John P. Cagnetta
- ------------------- --------------------------
John P. Cagnetta
March 18, 1994 Director /s/ William T. Frain, Jr.
- ------------------- --------------------------
William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise
- ------------------- -----------------------
Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane
- ------------------- -----------------------
John B. Keane
March 18, 1994 Director /s/ John F. Opeka
- ------------------- -----------------------
John F. Opeka
<PAGE>8
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTH ATLANTIC ENERGY CORPORATION
---------------------------------
(Registrant)
Date: March 18, 1994 By /s/ William B. Ellis
-------------- ---------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 18, 1994 Chairman and Director /s/ William B. Ellis
- -------------- --------------------------
William B. Ellis
March 18, 1994 Vice Chairman, Chief /s/ Bernard M. Fox
- -------------- Executive Officer and --------------------------
Director Bernard M. Fox
March 18, 1994 President, Chief /s/ Robert E. Busch
- -------------- Operating Officer --------------------------
and Director Robert E. Busch
March 18, 1994 Vice President and /s/ John W. Noyes
- -------------- Controller --------------------------
John W. Noyes
<PAGE>9
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 18, 1994 Director /s/ John P. Cagnetta
- -------------- --------------------------
John P. Cagnetta
- -------------- Director --------------------------
Ted C. Feigenbaum
March 18, 1994 Director /s/ William T. Frain. Jr.
- -------------- --------------------------
William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise
- -------------- --------------------------
Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane
- -------------- --------------------------
John B. Keane
March 18, 1994 Director /s/ Hugh C. MacKenzie
- -------------- --------------------------
Hugh C. MacKenzie
March 18, 1994 Director /s/ John F. Opeka
- -------------- --------------------------
John F. Opeka
<PAGE>10
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
<PAGE>17
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
<PAGE>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.
<PAGE>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.
<PAGE>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
<PAGE>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
<PAGE>22
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
===== ===== ===== ===== ===== ===== =====
<PAGE>23
<TABLE> CHANGE IN OPERATING REVENUE
<CAPTION>
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
<S> <C> <C> <C> <C> <C> <C>
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.
</TABLE>
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
<PAGE>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%
======
<PAGE>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
<PAGE>26
<TABLE>
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(Thousands of Dollars,except share information)
<S> <C> <C> <C>
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
============ ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>27
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C>
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
========== ========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>28
<TABLE>
CONSOLIDATED STATEMENTS OF INCOME TAXES
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
<F6>(Note 1)
-------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>29
<TABLE>
CONSOLIDATED BALANCE SHEETS
<CAPTION>
At December 31, 1993 1992
---- ----
(Thousands of Dollars)
<S> <C> <C>
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
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>30
<TABLE>
<CAPTION>
At December 31, 1993 1992
---- ----
(Thousands of Dollars)
<S> <C> <C>
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
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>31
<TABLE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
At December 31, 1993 1992
---- ----
(Thousands of Dollars)
<S> <C> <C>
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
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>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.
<PAGE>33
<TABLE>
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<CAPTION>
Deferred
Benefit
Capital Plan- Retained
Common Surplus, ESOP Earnings
Shares<F4>(a) Paid In <F12>(Note 7) <F5>(b) Total
------------ -------- -------- ---------- -----
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>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.
<PAGE>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
<PAGE>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
<PAGE>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
<PAGE>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.
<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
<PAGE>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.
<PAGE>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.
<PAGE>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
<PAGE>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.
<PAGE>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
<PAGE>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.
<PAGE>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.
<PAGE>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.
<PAGE>48
<TABLE>
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
<CAPTION>
QUARTER ENDED
1993 <F15>(a) March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(Thousands of Dollars, except per share data)
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
<TABLE>
CONSOLIDATED GENERAL OPERATING STATISTICS
<CAPTION>
1993 1992<F16>(b) 1991 1990 1989
---- ----------- ---- ---- ----
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>49
<TABLE>
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
1993 1992<F19>(a) 1991 1990
---- ------------ ---- ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>50
<TABLE>
<CAPTION> 1989 1988 1987 1986
---- ---- ---- ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C> <C> <C>
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
=========== =========== =========== ===========
</TABLE>
<PAGE>51.1
<TABLE>
<CAPTION>
1985 1984
---- ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C>
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
=========== ===========
</TABLE>
<PAGE>51.2
<TABLE>
CONSOLIDATED ELECTRIC OPERATING STATISTICS
<CAPTION>
1993 1992<F23>(a) 1991 1990
---- ------------ ---- ----
<S> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>52
<TABLE>
<CAPTION>
1989 1988 1987 1986
---- ---- ---- ----
<S> <C> <C> <C> <C>
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
</TABLE>
<PAGE>53.1
<TABLE>
<CAPTION>
1985 1984
---- ----
<S> <C> <C>
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
</TABLE>
<PAGE>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
<PAGE>54
Exhibit 13.2
1993
ANNUAL REPORT
---------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
1993 Annual Report
The Connecticut Light and Power Company
Index
Contents Page
- -------- ----
Balance Sheets. . . . . . . . . . . . . . . . . . . . . . 1-2
Statements of Income. . . . . . . . . . . . . . . . . . . 3
Statements of Cash Flows. . . . . . . . . . . . . . . . . 4
Statements of Common Stockholder's Equity . . . . . . . . 5
Notes to Financial Statements . . . . . . . . . . . . . . 6-30
Report of Independent Public Accountants. . . . . . . . . 31
Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 32-39
Selected Financial Data . . . . . . . . . . . . . . . . . 40
Statements of Quarterly Financial Data. . . . . . . . . . 40
Statistics. . . . . . . . . . . . . . . . . . . . . . . . 41
Preferred Stockholder and Bondholder Information. . . . . Back Cover
THE CONNECTICUT LIGHT AND POWER COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric......................................... $5,936,344 $ 5,822,783
Less: Accumulated provision for depreciation.. 2,010,962 1,827,024
----------- -----------
3,925,382 3,995,759
Construction work in progress.................... 121,177 110,081
Nuclear fuel, net................................ 156,878 167,816
----------- -----------
Total net utility plant...................... 4,203,437 4,273,656
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at cost.......... 147,657 121,888
Investments in regional nuclear generating
companies and subsidiary companies, at equity... 53,951 53,717
Other, at cost................................... 14,184 14,198
----------- -----------
215,792 189,803
----------- -----------
Current Assets:
Cash and special deposits <F2>(Note 1).......... 2,283 12,104
Receivables, less accumulated provision for
uncollectible accounts of $10,816,000 in 1993
and $8,358,000 in 1992......................... 210,805 231,614
Receivables from affiliated companies............ 29,687 4,804
Accrued utility revenues......................... 97,662 92,366
Fuel, materials, and supplies, at average cost... 60,247 72,199
Recoverable energy costs, net--current
portion <F2>(Note 1)........................... 9,985 77,002
Prepayments and other............................ 33,697 31,875
----------- -----------
444,366 521,964
----------- -----------
Deferred Charges:
Regulatory asset--income taxes <F2>(Note 1)..... 1,026,046 -
Deferred costs--nuclear plants <F2>(Note 1)...... 185,909 199,914
Unrecovered contract obligation-YAEC <F4>(Note 3) 84,526 98,559
Deferred conservation and load-management costs.. 111,442 87,487
Recoverable energy costs, net <F2>(Note 1)....... 26,311 82,423
Deferred DOE assessment <F2>(Note 1)............. 39,279 41,730
Unamortized debt expense......................... 8,971 10,497
Amortizable property investment.................. 6,228 8,720
Other............................................ 45,073 68,053
----------- -----------
1,533,785 597,383
----------- -----------
Total Assets................................. $6,397,380 $5,582,806
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>1
THE CONNECTICUT LIGHT AND POWER COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- ------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITES
- -----------------------------
Capitalization:
Common stock, $10 par value--authorized
24,500,000 shares; outstanding 12,222,930
shares in 1993 and 1992......................... $ 122,229 $ 122,229
Capital surplus, paid in........................... 630,271 634,851
Retained earnings.................................. 750,719 748,817
----------- -----------
Total common stockholder's equity............ 1,503,219 1,505,897
Cumulative preferred stock--
$50 par value--authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1993 and
5,123,925 in 1992
$25 par value--authorized 8,000,000 shares;
outstanding 5,000,000 shares in 1993 and
7,000,000 shares in 1992
Not subject to mandatory redemption <F6>(Note 5) 166,200 231,196
Subject to mandatory redemption <F7> (Note 6). 230,000 197,500
Long-term debt <F8>(Note 7)....................... 1,743,260 1,930,832
----------- -----------
Total capitalization...................... 3,642,679 3,865,425
----------- -----------
Obligations Under Capital Leases..................... 121,892 136,800
----------- -----------
Current Liabilities:
Notes payable to banks............................. 95,000 96,500
Notes payable to affiliated company................ 1,250 -
Commercial paper................................... - 109,240
Long-term debt and preferred stock--current
portion......................................... 314,020 159,604
Obligations under capital leases--current
portion......................................... 55,526 60,604
Accounts payable................................... 117,858 108,797
Accounts payable to affiliated companies........... 52,179 55,808
Accrued taxes...................................... 36,114 118,132
Accrued interest................................... 29,669 32,829
Other.............................................. 32,287 17,185
----------- -----------
733,903 758,699
----------- -----------
Deferred Credits:
Accumulated deferred income taxes <F2>(Note 1)..... 1,575,965 475,355
Accumulated deferred investment tax credits........ 154,701 165,710
Deferred contract obligation--YAEC <F4>(Note 3).... 84,526 98,559
Deferred DOE obligation <F2>(Note 1)............... 31,523 41,730
Other.............................................. 52,191 40,528
----------- -----------
1,898,906 821,882
----------- -----------
Commitments and Contingencies <F12>(Note 11)
Total Capitalization and Liabilities...... $6,397,380 $5,582,806
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>2
THE CONNECTICUT LIGHT AND POWER COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................ $2,366,050 $2,316,451 $2,275,737
----------- ----------- -----------
Operating Expenses:
Operation--
Fuel, purchased and net interchange
power....................................... 657,121 598,287 559,131
Other......................................... 641,402 605,675 614,440
Maintenance..................................... 180,403 197,460 184,727
Depreciation.................................... 219,776 209,884 198,597
Amortization of regulatory assets, net.......... 112,353 73,456 55,693
Federal and state income taxes
<F9>(Note 8).................................. 144,547 172,236 173,102
Taxes other than income taxes................... 170,353 171,642 166,212
----------- ----------- -----------
Total operating expenses..................... 2,125,955 2,028,640 1,951,902
----------- ----------- -----------
Operating Income.................................. 240,095 287,811 323,835
----------- ----------- -----------
Other Income:
Deferred nuclear plants return--
other funds.................................. 23,537 35,396 36,714
Equity in earnings of regional
nuclear generating companies.................. 6,193 8,014 8,021
Other, net...................................... (1,044) 6,964 9,226
Income taxes--credit............................ 4,859 11,171 13,004
----------- ----------- -----------
Other income, net............................ 33,545 61,545 66,965
----------- ----------- -----------
Income before interest charges............... 273,640 349,356 390,800
----------- ----------- -----------
Interest Charges:
Interest on long-term debt...................... 134,263 151,314 166,256
Other interest.................................. 9,654 4,205 1,542
Deferred nuclear plants return--
borrowed funds <F2>(Note 1)................... (13,979) (12,877) (17,816)
----------- ----------- -----------
Interest charges, net........................ 129,938 142,642 149,982
----------- ----------- -----------
Income before cumulative effect of
accounting change............................... 143,702 206,714 240,818
Cumulative effect of accounting change <F2>(Note 1) 47,747 - -
----------- ----------- -----------
Net Income........................................ $ 191,449 $ 206,714 $ 240,818
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>3
<TABLE>
The Connecticut Light and Power Company
STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------------------
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operations:
Net Income .............................................. $ 191,449 $ 206,714 $ 240,818
Adjusted for the following:
Depreciation............................................ 226,951 223,058 204,534
Deferred income taxes and investment tax credits, net... (20,188) 72,138 107,599
Deferred nuclear plants return, net of amortization..... 58,740 10,071 (3,529)
Deferred energy costs, net of amortization.............. 123,129 (22,408) (119,629)
Deferred conservation and load-management,
net of amortization.................................... (23,955) (31,989) (47,402)
Other sources of cash................................... 81,386 13,256 37,143
Other uses of cash...................................... (26,431) (66,494) (38,730)
Changes in working capital:
Receivables and accrued utility revenues............... (9,370) 245 (36,882)
Fuel, materials, and supplies.......................... 11,951 1,296 24,735
Accounts payable....................................... 5,433 (18,067) 52,029
Accrued taxes.......................................... (82,018) 15,344 (42,228)
Other working capital (excludes cash).................. 9,754 7,154 12,462
--------- --------- ---------
Net Cash Flows From Operations............................. 546,831 410,318 390,920
--------- --------- ---------
Cash Flows Used For Financing Activities:
Long-term debt........................................... 740,500 491,000 -
Preferred stock.......................................... 80,000 75,000 -
Financing expenses....................................... (2,393) (9,825) -
Net increase (decrease) in short-term debt............... (109,490) 15,240 108,385
Reacquisitions and retirements of long-term debt.........
and preferred stock.................................... (886,969) (523,123) (90,877)
Cash dividends on preferred stock........................ (29,182) (31,977) (34,541)
Cash dividends on common stock........................... (160,365) (164,277) (172,587)
--------- --------- ---------
Net cash flows used for financing activities............... (367,899) (147,962) (189,620)
--------- --------- ---------
Investment Activities:
Investment in plant (including capital leases):
Electric utility plant................................. (149,308) (225,901) (178,670)
Nuclear fuel........................................... (13,658) 3,139 (3,432)
--------- --------- ---------
Net cash flows used for investments in plant........... (162,966) (222,762) (182,102)
Other investment activities, net....................... (25,787) (32,181) (18,334)
--------- --------- ---------
Net cash flows used for investments........................ (188,753) (254,943) (200,436)
--------- --------- ---------
Net Increase (Decrease) In Cash for the Period............. (9,821) 7,413 864
Cash and special deposits - beginning of period........ 12,104 4,691 3,827
--------- --------- ---------
Cash and special deposits - end of period.............. $ 2,283 $ 12,104 $ 4,691
========= ========= =========
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized during
construction............................................. $ 130,592 $ 143,957 $ 162,760
========= ========= =========
Income taxes............................................. $ 149,056 $ 95,199 $ 92,884
========= ========= =========
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 40,140 30,948 14,713
========= ========= =========
Capital leases........................................... $ - - 10,500
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>4
THE CONNECTICUT LIGHT AND POWER COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In <F1>(a) Total
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1991.......... $122,229 $636,175 $ 705,303 $1,463,707
Net income for 1991............. 240,818 240,818
Cash dividends on preferred
stock......................... (34,541) (34,541)
Cash dividends on common stock.. (172,587) (172,587)
Capital stock expenses, net..... 1,027 1,027
--------- --------- ---------- -----------
Balance at December 31, 1991........ 122,229 637,202 738,993 1,498,424
Net income for 1992............. 206,714 206,714
Cash dividends on preferred
stock......................... (31,977) (31,977)
Cash dividends on common stock.. (164,277) (164,277)
Loss on the retirement of
preferred stock............... (636) (636)
Capital stock expenses, net..... (2,351) (2,351)
--------- --------- ---------- -----------
Balance at December 31, 1992........ 122,229 634,851 748,817 1,505,897
Net income for 1993............. 191,449 191,449
Cash dividends on preferred
stock......................... (29,182) (29,182)
Cash dividends on common stock.. (160,365) (160,365)
Capital stock expenses, net..... (4,580) (4,580)
--------- --------- ---------- -----------
Balance at December 31, 1993........ $122,229 $630,271 $ 750,719 $1,503,219
========= ========= ========== ===========
</TABLE>
<F1> (a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1993, these restrictions totaled
approximately $540.0 million.
The accompanying notes are an integral part of these financial statements.
<PAGE>5
THE CONNECTICUT LIGHT AND POWER COMPANY COMPANY
- ---------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS
- ---------------------------------------------------------------------
<F2>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
The Connecticut Light and Power Company (CL&P or the company), Western
Massachusetts Electric Company (WMECO), Holyoke Water Power Company (HWP),
Public Service Company of New Hampshire (PSNH), and North Atlantic Energy
Corporation (NAEC) are the operating subsidiaries comprising the Northeast
Utilities system (the system) and are wholly owned by Northeast Utilities
(NU).
Other wholly owned subsidiaries of NU provide substantial support services
to the system. Northeast Utilities Service Company (NUSCO) supplies
centralized accounting, administrative, data processing, engineering,
financial, legal, operational, planning, purchasing, and other services to
the system companies. Northeast Nuclear Energy Company (NNECO) acts as agent
for system companies in operating the Millstone nuclear generating
facilities. Commencing June 29, 1992, North Atlantic Energy Service
Corporation (NAESCO) began acting as agent for CL&P and NAEC in operating the
Seabrook 1 nuclear facility.
All transactions among affiliated companies are on a recovery of cost basis
which may include amounts representing a return on equity, and are subject to
approval by various federal and state regulatory agencies.
ACCOUNTING CHANGES
Property Taxes: CL&P 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, CL&P 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 payment and services provided by the
municipalities. This one-time change increased net income by approximately
$47.7 million for CL&P 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 <F2>
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 more information on this change, see
<F11> Note 10, "Postretirement Benefits Other Than Pensions."
ACCOUNTING RECLASSIFICATIONS
Certain amounts in the accompanying financial statements of CL&P for the
year ended December 31, 1992 and 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 a
holding company under the Public Utility Holding Company Act of 1935 (1935
Act), and it and its subsidiaries, including the company, 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
<PAGE>6
of utility property are subject to regulation by the Federal Energy
Regulatory Commission (FERC) and/or the SEC. The company is subject to
further regulation for rates and other matters by the FERC and the
Connecticut Department of Public Utility Control (DPUC), and follows 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 accrues an estimate
for the amount of energy delivered but unbilled.
SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P 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 $136.1 million,
including interest costs of $69.6 million. As of December 31, 1993,
approximately $134.5 million had been collected through rates.
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its
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, CL&P's remaining
share of these costs is estimated to be approximately $39.3 million. CL&P
has begun to recover these costs. Accordingly, CL&P has recognized these
costs as a regulatory asset, with a corresponding obligation, on its
Balance Sheets.
INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with the company's ownership interests, are:
- --------------------------------------------------------------------
Connecticut Yankee Atomic Power Company (CY). . . . . 34.5%
Yankee Atomic Electric Company (YAEC) . . . . . . . . 24.5
Maine Yankee Atomic Power Company (MY). . . . . . . . 12.0
Vermont Yankee Nuclear Power Corporation (VY) . . . . 9.5
- --------------------------------------------------------------------
CL&P's investments in the Yankee companies are accounted for on the equity
basis. The electricity produced by these facilities that are operating is
committed to the participants substantially on the basis
<PAGE>7
of their ownership interests and is billed pursuant to
contractual agreements. For more information on these agreements, see <F12>
Note 11, "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 <F4>
Note 3, "Nuclear Decommissioning."
Millstone 1: CL&P has an 81 percent joint-ownership interest in Millstone
1, a 660 MW nuclear generating unit. As of December 31, 1993, plant-in-
service and the accumulated provision for depreciation included approximately
$332 million and $130.8 million, respectively, for CL&P's share of Millstone
1. CL&P's share of Millstone 1 operating expenses is included in the
corresponding operating expenses on the accompanying Statements of Income.
Millstone 2: CL&P has an 81 percent joint-ownership interest in Millstone
2, a 875 MW nuclear generating unit. As of December 31, 1993, plant-in-
service and the accumulated provision for depreciation included
approximately $676 million and $151.5 million, respectively, for CL&P's
share of Millstone 2. CL&P's share of Millstone 2 operating expenses is
included in the corresponding operating expenses on the accompanying
Statements of Income.
Millstone 3: CL&P has a 52.93 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 $1.9 billion and $366.6 million, respectively, for CL&P's
share of Millstone 3. CL&P's share of Millstone 3 expenses is included in
the corresponding operating expenses on the accompanying Statements of
Income.
Seabrook: As of December 31, 1993, CL&P has a 4.06 percent joint-ownership
interest in Seabrook 1, a 1,150 MW nuclear generating unit. As of December
31, 1993, plant-in-service and the accumulated provision for depreciation
included approximately $173.4 million and $17.7 million, respectively, for
CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is included
in the corresponding operating expenses on the accompanying Statements of
Income.
DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency. Except for major facilities, depreciation factors are
applied to the average plant-in-service during the period. Major facilities
are depreciated from the time they are placed in service. When plant is
retired from service, the original cost of plant, including costs of removal,
less salvage, is charged to the accumulated provision for depreciation. For
nuclear production plants, the costs of removal, less salvage, that have been
funded through external decommissioning trusts will be paid with funds from
the trusts and charged to the accumulated reserve for decommissioning
included in the accumulated provision for depreciation over the expected
service life of the plants. See <F4> 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 3.8 percent in 1993, 3.7 percent in 1992, and
3.5 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
<PAGE>8
subject to tax) is accounted for in accordance with the ratemaking treatment
of the applicable regulatory commissions. See <F9> Note 8, "Income Tax
Expense," for the components of income tax expenses.
In 1992, the Financial Accounting Standards Board (FASB) issued SFAS 109.
SFAS 109 supersedes previously issued income tax accounting standards. The
company adopted SFAS 109, on a prospective basis, during the first quarter of
1993. At December 31, 1993, the deferred tax obligation relating to the
adoption of SFAS 109 approximated $1.0 billion. As it is probable that the
increase in deferred tax liabilities will be recovered from customers through
rates, CL&P 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. . . . . . . . . . . . . . . . . . $1,049,849
The tax effect of net regulatory assets. . . . . 434,894
Other. . . . . . . . . . . . . . . . . . . . . . 91,222
----------
$1,575,965
==========
ENERGY ADJUSTMENT CLAUSES
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 charges or credits proposed for the following month. Monthly FAC
rates are also subject to retroactive review and appropriate adjustment by
the 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 a specified composite nuclear generation capacity factor
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
would have 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 over-recoveries. The 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.
<PAGE>9
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.
For additional information see <F12> Note 11, "Commitments and Contingencies
"Nuclear Performance."
CONSERVATION AND LOAD MANAGEMENT COSTS
Conservation and Load Management (C&LM) costs are recovered through a
Conservation Adjustment Mechanism (CAM). The DPUC issued an order in April
1993, which allowed CL&P to recover C&LM expenditures over an eight-year
period 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, a reduction in the cost
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.
PHASE-IN PLANS
As discussed below, CL&P is phasing into rates the recoverable parts of its
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.
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 charges, has been recovered, and $24.0
million of the deferred return recorded to date, plus carrying charges,
remains to be recovered.
CASH AND SPECIAL DEPOSITS
Cash and special deposits at December 31, 1992 included $10 million in
special deposits that was used to redeem $10 million of CL&P's Pollution
Control Notes.
<F3>
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
<PAGE>10
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.
CL&P has 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. The following rental payments have been charged to operating
expense:
Capital Operating
Year Leases Leases
---- ------- ---------
1993. . . . . . . . . . $76,549,000 $24,355,000
1992. . . . . . . . . . 61,795,000 26,919,000
1991. . . . . . . . . . 50,998,000 26,320,000
Interest included in capital lease rental payments was $11,298,000 in 1993,
$14,782,000 in 1992, and $15,974,000 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 long-term noncancelable leases, as of
December 31, 1993, are approximately:
<PAGE>11
Capital Operating
Year Leases Leases
---- ------- ---------
(Thousands of Dollars)
1994. . . . . . . . . . . . $ 2,800 $ 20,800
1995. . . . . . . . . . . . 2,800 19,500
1996. . . . . . . . . . . . 2,800 17,900
1997. . . . . . . . . . . . 2,800 17,200
1998. . . . . . . . . . . . 2,800 12,300
After 1998. . . . . . . . . 45,000 75,700
------- --------
Future minimum lease
payments . . . . . . . . . 59,000 $163,400
========
Less amount of representing
interest . . . . . . . . . 38,300
-------
Present value of future
minimum lease payments
for other than nuclear
fuel . . . . . . . . . . . 20,700
Present value of future
nuclear fuel lease
payments . . . . . . . . . 156,700
-------
Total. . . . . . $177,400
========
<F4>
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 CL&P's ownership share of Millstone 1
and 2, in year-end 1993 dollars, is $312.5 million and $251.0 million,
respectively. At December 31, 1993, the estimated cost of decommissioning
CL&P's ownership share of Millstone 3 and Seabrook 1, in year-end 1993
dollars, is $223.0 million and $14.9 million, respectively. Nuclear
decommissioning costs are accrued over the expected service life of the
units and are included in depreciation expense on the Statements of Income.
Nuclear decommissioning costs amounted to $21.9 million in 1993 and 1992,
and $16.2 million in 1991. Nuclear decommissioning, as a cost of removal,
is included in the accumulated provision for depreciation on the Balance
Sheets.
CL&P has established independent decommissioning trusts for its portion of
the costs of decommissioning Millstone 1, 2, and 3. CL&P's portion of the
cost of decommissioning Seabrook 1 is paid to an independent decommissioning
financing fund managed by the state of New Hampshire.
<PAGE>12
As of December 31, 1993, CL&P has collected, through rates, $148.3 million,
toward the future decommissioning costs of its share of the Millstone
units, of which $116.8 million has been transferred to external
decommissioning trusts. As of December 31, 1993, CL&P has paid approximately
$860,000 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
$179.1 million.
Changes in requirements or technology, or adoption of a decommissioning
method other than immediate dismantlement, could change decommissioning
cost estimates. CL&P attempts to recover sufficient amounts through its
allowed rates to cover its expected decommissioning costs. Only the
portion of currently estimated total decommissioning costs that has been
accepted by the regulatory agencies is reflected in CL&P's rates.
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, along with other New England utilities, has 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 decommissioning
CL&P's ownership share of CY and MY, are $117.3 million and $38.8 million,
respectively. The cost to decommission VY is currently being re-estimated.
The cost of decommissioning CL&P's ownership share of VY is projected to
range from $28.5 million to $33.3 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 CL&P's cost of power.
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 (NRC) 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 CL&P's share was approximately $84.5 million.
Management expects that CL&P will continue to be allowed to recover such
FERC-approved costs from its customers. Accordingly, CL&P has recognized
these costs as a regulatory asset, with a corresponding obligation, on its
Balance Sheets. CL&P has a 24.5 percent equity investment, approximating
$5.9 million, in YAEC. CL&P had relied on YAEC for less than 1 percent of
its capacity.
<F5>
4. SHORT-TERM DEBT
The system companies have various credit lines, totaling $485 million.
NU, CL&P, WMECO, HWP, 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
<PAGE>13
commitment under the three-year portion of the facility, representing 75
percent of the total facility, plus .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 of borrowings under the facility, $5 million attributable to CL&P.
Certain subsidiaries of NU, including CL&P, are members of the Northeast
Utilities System Money Pool (Pool). The Pool provides a more efficient
use of the cash resources of the system, and reduces outside short-term
borrowings. NUSCO administers the Pool as agent for the member companies.
Short-term borrowing needs of the member companies are first met with
available funds of other member companies, including funds borrowed by NU
parent. NU parent may lend to the Pool but may not borrow. Investing and
borrowing subsidiaries receive or pay interest based on the average daily
Federal Funds rate. Funds may be withdrawn from or repaid to the Pool at
any time without prior notice. However, borrowings based on loans from NU
parent bear interest at NU parent's cost and must be repaid based upon the
terms of NU parent's original borrowing.
Maturities of CL&P's short-term debt obligations are for periods of three
months or less.
The amount of short-term borrowings that may be incurred by the company is
subject to periodic approval by the SEC under the 1935 Act. In addition,
the charter of CL&P contains provisions restricting the amount of short-
term borrowings. Under the SEC and/or charter restrictions, the company
was authorized, as of January 1, 1993, to incur short-term borrowings up
to a maximum of $375 million.
<PAGE>14
<F6>
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
<TABLE>
<CAPTION>
December 31, Shares
1993 Outstanding December 31,
Redemption December 31 --------------------------------
Description Price 1993 1993 1992 1991
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
$1.90 Series of 1947. . . . . $52.50 163,912 $ 8,196 $ 8,196 $ 8,196
$2.00 Series of 1947. . . . . 54.00 336,088 16,804 16,804 16,804
$2.04 Series of 1949. . . . . 52.00 100,000 5,000 5,000 5,000
$2.06 Series E of 1954. . . . 51.00 200,000 10,000 10,000 10,000
$2.09 Series F of 1955. . . . 51.00 100,000 5,000 5,000 5,000
$2.20 Series of 1949. . . . . 52.50 200,000 10,000 10,000 10,000
$3.24 Series G of 1968. . . . 51.84 300,000 15,000 15,000 15,000
$3.80 Series J of 1971. . . . - - - 20,000 20,000
$4.48 Series H of 1970. . . . - - - 15,000 15,000
$4.48 Series I of 1970. . . . - - - 20,000 20,000
$4.56 Series K of 1974. . . . - - - - 50,000
3.90% Series of 1949. . . . . 50.50 160,000 8,000 8,000 8,000
4.50% Series of 1956. . . . . 50.75 104,000 5,200 5,200 5,200
4.50% Series of 1963. . . . . 50.50 160,000 8,000 8,000 8,000
4.96% Series of 1958. . . . . 50.50 100,000 5,000 5,000 5,000
5.28% Series of 1967. . . . . 51.43 200,000 10,000 10,000 10,000
6.56% Series of 1968. . . . . 51.44 200,000 10,000 10,000 10,000
7.60% Series of 1971. . . . . - - - 9,996 9,996
9.36% Series of 1970. . . . . - - - - 10,000
9.60% Series of 1974. . . . . - - - - 14,999
1989 Adjustable Rate DARTS. . 25.00 2,000,000 50,000 50,000 50,000
------- ------- --------
Total preferred stock
not subject to mandatory
redemption. . . . . . . . . . $ 166,200 $ 231,196 $ 306,195
======== ======== ========
All or any part of each outstanding series of such preferred stock may be
redeemed by the company at any time at established redemption prices plus accrued dividends to the date
of redemption.
</TABLE>
<PAGE>15
<F7>
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
<TABLE>
<CAPTION>
December 31, Shares
1993 Outstanding December 31,
Redemption December 31 --------------------------------
Description Price* 1993 1993 1992 1991
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
$5.52 Series L of 1975 . . . . $ - $ - $ - $ - $ 1,926
10.48% Series of 1980 . . . . . - - - - 14,000
11.52% Series of 1975 . . . . . - - - - 966
9.10% Series of 1987 . . . . . - - - 50,000 50,000
9.00% Series of 1989 . . . . . 26.65 3,000,000 75,000 75,000 75,000
7.23% Series of 1992 . . . . . 52.41 1,500,000 75,000 75,000 -
5.30% Series of 1993 . . . . . 51.00 1,600,000 80,000 - -
-------- -------- --------
230,000 200,000 141,892
Less preferred stock to be
redeemed within on year . . . . - 2,500 2,500
-------- -------- --------
Total preferred stock
subject to mandatory
redemption . . . . . . . . . . $230,000 $197,500 $139,392
======== ======== ========
*Redemption prices reduce in future years.
</TABLE>
<TABLE>
The following table details redemption and sinking fund activity forpreferred stock subject to
mandatory redemption:
<CAPTION>
Minimum
Annual Shares Reacquired
Sinking-Fund ------------------------------------
Series Requirement 1993 1992 1991
- --------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
$5.52 Series L of 1975 $ - - 38,524 40,000
10.48% Series of 1980 - - 280,000 40,000
11.52% Series of 1975 - - 19,318 20,008
9.10% Series of 1987 - 2,000,000 - -
9.00% Series of 1989 (1) 3,750 - - -
7.23% Series of 1992 (2) 3,750 - - -
5.30% Series of 1993 (3) 16,000 - - -
(1) Sinking fund requirements commence October 1, 1995.
(2) Sinking fund requirements commence September 1, 1998.
(3) Sinking fund requirements commence October 1, 1999.
</TABLE>
<PAGE>16
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1994 through 1998, aggregate approximately $0 in
1994, $3,750,000 in 1995, 1996, and 1997, and $7,500,000 in 1998. In case
of default on sinking-fund payments or the payment of dividends, 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 the company
is in arrears in the payment of dividends on any outstanding shares of
preferred stock, the company would be prohibited from redemption or purchase
of less than all of the preferred stock outstanding. All or part of each of
the series named above may be redeemed by the company at any time at
established redemption prices plus accrued dividends to the date of
redemption, subject to certain refunding limitations.
<PAGE>17
<F8>
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
- -------------------------------------------------------------------------
December 31,
---------------
1993 1992
- -------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
4 1/4% Series 1963 due 1993 . . . . $ - $ 15,000
8 1/2% Series PP due 1993 . . . . - 125,000
4 1/2% Series 1964 due 1994 . . . . 12,000 12,000
4 1/4% Series WW due 1994 . . . . 170,000 170,000
5 5/8% Series 1967 due 1997 . . . . 20,000 20,000
6% Series S due 1997 . . . . 30,000 30,000
7 5/8% Series UU due 1997 . . . . 200,000 200,000
6 7/8% Series U due 1998 . . . . 40,000 40,000
7 1/8% Series 1968 due 1998 . . . . 25,000 25,000
6 1/2% Series T due 1998 . . . . 20,000 20,000
6 1/2% Series 1968 due 1998 . . . . 10,000 10,000
7 1/4% Series VV due 1999 . . . . 100,000 100,000
8 3/4% Series V due 2000 . . . . - 40,000
8 7/8% Series W due 2000 . . . . - 40,000
5 3/4% Series XX due 2000 . . . . 200,000 -
7 3/8% Series X due 2001 . . . . 30,000 30,000
7 5/8% Series 1971 due 2001 . . . . 30,000 30,000
7 1/2% Series 1972 due 2002 . . . . 35,000 35,000
7 5/8% Series Y due 2002 . . . . 50,000 50,000
7 5/8% Series Z due 2003 . . . . 50,000 50,000
7 1/2% Series 1973 due 2003 . . . . 40,000 40,000
8 3/4% Series AA due 2004 . . . . - 65,000
9 1/4% Series 1974 due 2004 . . . . - 30,000
8 7/8% Series DD due 2007 . . . . - 45,000
9 1/4% Series EE due 2008 . . . . - 40,000
9 3/8% Series 1978 due 2008 . . . . - 40,000
9 3/4% Series QQ due 2018 . . . . 75,000 75,000
9 1/2% Series RR due 2019 . . . . 75,000 75,000
9 3/8% Series SS due 2019 . . . . 75,000 75,000
7 3/8% Series TT due 2019 . . . . 20,000 20,000
7 1/2% Series YY due 2023 . . . . 100,000 -
7 3/8% Series ZZ due 2025 . . . . 125,000 -
---------- ----------
Total First Mortgage Bonds. . $1,532,000 $1,547,000
<PAGE>18
- ---------------------------------------------------------------------------
December 31,
---------------------------
1993 1992
- ---------------------------------------------------------------------------
(Thousands of Dollars)
Pollution Control Notes:
5.90%, due 1998. . . . . . . . . $ - $ 6,197
6.50%, due 2007. . . . . . . . . - 16,000
Variable rate, due 2013-2022 . . 46,400 350,100
Tax exempt, due 2028 . . . . . . . 315,500 -
Fees and interest due for spent fuel
disposal costs . . . . . . . . . 136,125 132,015
Other. . . . . . . . . . . . . . . 35,417 41,493
Less amounts due within one year . 314,020 157,104
Unamortized premium and
discount, net. . . . . . . . . . (8,162) (4,869)
---------- ----------
Long-term debt, net . . . . . $1,743,260 $1,930,832
========== ==========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1993 for the years 1994 through 1998 are
approximately: $189,020,000, $8,111,000, $9,372,000, $260,828,000, and
$95,011,000, respectively. Also, $125 million of first mortgage bonds
outstanding at December 31, 1993 had been called in December 1993 for
redemption in 1994. In addition, there are annual one percent sinking- and
improvement-fund requirements, currently amounting to $13,950,000 for the
year 1994, $12,250,000 for 1995, 1996, and 1997, and $9,750,000 for 1998.
Such sinking- and improvement-fund requirements may be satisfied by the
deposit of cash or bonds or by certification of property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which are
subject to certain refunding limitations during their respective initial
five-year redemption periods.
Essentially all of the company's utility plant is subject to the lien of its
first mortgage bond indenture. As of December 31, 1993, the company has
secured $315.5 million of pollution control notes with second mortgage liens
on Millstone 1, junior to the liens of its first mortgage bond indentures.
CL&P has entered into an interest-rate cap contract to reduce the potential
impact of upward changes in interest rates on certain variable-rate tax-
exempt pollution control revenue bonds. Approximately $340 million of total
outstanding long-term variable-rate debt is secured by this interest rate
cap. The total cost of the interest-rate cap for 1993 was approximately $2.9
million, the cost of which is amortized over the terms of the contract, which
is three years. The fair market value of the interest-rate cap contract as
of December 31, 1993 is approximately $388,000.
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
<F2> Note 1 of the accompanying Notes to Financial Statements.
<PAGE>19
<F9>
8. INCOME TAX EXPENSE
<TABLE>
The components of the federal and state income tax provisions charged to operations are:
<CAPTION>
- --------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992 1991
- --------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes:
Federal. . . . . . . . . . . . . . . . . $115,403 $ 61,773 $ 33,717
State. . . . . . . . . . . . . . . . . . 44,473 27,153 18,782
-------- -------- --------
Total current. . . . . . . . . . . . . 159,876 88,926 52,499
-------- -------- --------
Deferred income taxes, net:
Federal. . . . . . . . . . . . . . . . . 3,808 60,788 88,554
State. . . . . . . . . . . . . . . . . . (12,987) 11,833 26,430
-------- -------- --------
Total deferred . . . . . . . . . . . . (9,179) 72,621 114,984
-------- -------- --------
Investment tax credits, net . . . . . . (11,009) (6,230) (6,230)
-------- --------- ---------
Total income tax expense. . . . . . . $139,688 $155,317 $161,253
======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses. . . . . . . . . . . . . . . . $144,547 $172,236 $173,102
Income taxes associated with the
amortization of deferred nuclear
plants return - borrowed funds. . . . . - (15,157) (12,263)
Income taxes associated with AFUDC and
deferred nuclear plants return -
borrowed funds. . . . . . . . . . . . . - 9,409 13,418
Other income taxes - credit. . . . . . . (4,859) (11,171) (13,004)
-------- -------- ---------
Total income tax expense . . . . . . . . $139,688 $155,317 $161,253
======== ======== ========
<PAGE>20
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
- ----------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992 1991
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits, and disposal
costs. . . . . . . . . . . . . . . . . . $ 42,663 $ 43,715 $ 49,636
Conservation and load management. . . . . 9,156 13,506 22,594
Postretirement benefits accrual . . . . . (2,579) - -
Energy adjustment clauses . . . . . . . . (52,189) 12,627 47,483
AFUDC and deferred nuclear plants
return, net. . . . . . . . . . . . . . . (13,741) (5,748) 1,155
Early retirement program. . . . . . . . . (3,355) 3,988 (9,718)
Pension accrual . . . . . . . . . . . . . 3,553 885 (351)
Settlement, canceled independent
power plants . . . . . . . . . . . . . . - 7,251 -
Loss on bond redemption . . . . . . . . . 8,145 10 -
Other . . . . . . . . . . . . . . . . . . (832) (3,613) 4,185
--------- -------- --------
Deferred income taxes, net. . . . . . $ (9,179) $ 72,621 $114,984
========= ======== ========
A reconciliation between income tax expense and the expected tax expense at the applicable statutory
rate is as follows:
- ----------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992 1991
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income
for 1993 and 34 percent for
1992 and 1991. . . . . . . . . . . . . . $115,898 $123,091 $136,704
Tax effect of differences:
Depreciation differences . . . . . . . . 19,264 15,826 10,647
Deferred nuclear plants return -
other funds . . . . . . . . . . . . . . (8,294) (12,035) (12,483)
Amortization of nuclear plants return -
other funds . . . . . . . . . . . . . . 18,648 14,511 12,918
Property tax differences . . . . . . . . (12,320) (732) 502
Investment tax credit amortization . . . (11,009) (6,230) (6,230)
State income taxes, net of federal
benefit . . . . . . . . . . . . . . . . 20,466 25,730 29,987
Adjustment for prior years taxes . . . . (2,330) (3,500) (7,000)
Other, net . . . . . . . . . . . . . . . (635) (1,344) (3,792)
-------- -------- --------
Total income tax expense . . . . . . . $139,688 $155,317 $161,253
======== ======== ========
</TABLE>
<PAGE>21
<F10>
9. PENSION BENEFITS
The company participates in a uniform noncontributory defined benefit
retirement plan covering all regular system employees (the Plan). Benefits
are based on years of service and employees' highest eligible compensation
during five consecutive years of employment. The company's direct-allocated
portion of the system's pension cost, part of which was charged to utility
plant, approximated $7.6 million in 1993, ($1.7) million in 1992, and $10.8
million in 1991. The company's pension costs for 1993 and 1991 include
approximately $13.1 million and $10.0 million, respectively, related to work
force reduction programs.
Currently, the company funds annually an amount at least equal to that which
will satisfy the requirements of the Employment Retirement Income Security
Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets. Pension assets are invested
primarily in domestic and international equity securities and bonds.
The components of the Plan's net pension cost for the system (excluding PSNH
and NAESCO in 1992 and 1991) are:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . $ 59,068 $ 27,480 $ 48,738
Interest cost. . . . . . . . . . 81,456 69,746 71,041
Return on plan assets. . . . . . (176,798) (77,232) (198,437)
Net amortization . . . . . . . . 65,447 (16,266) 108,175
-------- -------- --------
Net pension cost . . . . . . . . $ 29,173 $ 3,728 $ 29,517
======== ======== ========
- ----------------------------------------------------------------------------
For calculating pension cost, the following assumptions were used:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- -----------------------------------------------------------------------------
Discount rate. . . . . . . . . . 8.00% 8.50% 9.00%
Expected long-term rate of
return. . . . . . . . . . . . . 8.50 9.00 9.70
Compensation/progression rate. . 5.00 6.75 7.50
- -----------------------------------------------------------------------------
<PAGE>22
The following table represents the Plan's funded status reconciled to the NU
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. CL&P's direct cost of the program, which
approximated $14.8 million, included pension, severance, and other benefits.
<F11>
10. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The company provides 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 company
who are otherwise eligible to retire and have met specified service
requirements. Through December 31, 1992, the company recognized the cost of
these benefits as
<PAGE>23
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 company adopted SFAS 106 on a prospective basis. Total health
care and life insurance cost, part of which were deferred or charged to
utility plant, approximated $23,170,000 in 1993, $8,791,000 in 1992, and
$7,525,000 in 1991.
On January 1, 1993, the accumulated postretirement benefit obligation (APBO)
represented the company's prior-service obligation upon the adoption of SFAS
106. As allowed by SFAS 106, the company is amortizing its APBO of
approximately $164 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.
During 1993, the company did not fund SFAS 106 postretirement costs through
external trusts. The company expects to fund annually amounts once they have
been rate recovered and which also are tax-deductible under the Internal
Revenue Code.
The following table represents the plan's funded status reconciled to the
Balance Sheet at December 31, 1993:
- ----------------------------------------------------------------- -----------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees . . . . . . . . . . . . . . $(119,520)
Fully eligible active employees. . . (288)
Active employees not eligible to
retire. . . . . . . . . . . . . . . (29,270)
---------
Total accumulated postretirement
benefit obligation. . . . . . . . . (149,078)
Unrecognized transition amount . . . 139,539
Unrecognized net gain. . . . . . . . (2,591)
---------
Accrued postretirement benefit
liability . . . . . . . . . . . . . $ (12,130)
=========
- ----------------------------------------------------------------------------
The components of health care and life insurance costs for the year ended
December 31, 1993 are:
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . $ 3,397
Interest cost. . . . . . . . . . . . 12,091
Net amortization . . . . . . . . . . 7,682
-------
Net health care and life insurance
costs . . . . . . . . . . . . . . . $23,170
=======
- ----------------------------------------------------------------- -----------
<PAGE>24
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 $10.5 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit cost for the
year then ended by $1.0 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 the long-term, high-quality corporate debt securities having a duration
comparable to that of the plan.
CL&P has received approval from the DPUC to defer and recover the incremental
SFAS 106 postretirement costs within eight years.
<F12>
11. 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.
CL&P currently forecasts construction expenditures (including AFUDC) of
approximately $741.8 million for the years 1994-1998, including $157.8
million for 1994. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $317.7 million for the years 1994-1998, including $74.6 million
for 1994. See <F3> 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.
ENVIRONMENTAL MATTERS
CL&P 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. CL&P 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
<PAGE>25
environmental requirements could hinder the construction of new fossil-fuel
environmental 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 CL&P's existing hydro, nuclear, and fossil-fuel
generating units, and transmission and distribution systems, and could raise
operating costs significantly. As a result, CL&P 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. CL&P may also encounter significantly increased
costs to remedy the environmental effects of prior waste handling and
disposal activities.
CL&P has recorded a liability for what it believes is, based upon information
currently available, the estimated environmental remediation costs for waste
disposal sites for which it expects 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 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 CL&P has been informed that it may be determined to be legally
liable by the federal or state environmental agencies. In addition, CL&P
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 CL&P's financial position or future
results of operations. At December 31, 1993, the liability recorded by CL&P
for its estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to $2.9
million. However, in the event that it becomes necessary to effect
environmental remedies that are currently not considered probable for the
sites for which CL&P has recorded a liability, it is reasonably possible
that, based on information currently available and management intent, that
the upper limit of CL&P's environmental liability range could increase to
approximately $5.8 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 CL&P's ownership interests in Millstone 1, 2,
and 3, and Seabrook 1, CL&P's maximum liability would be $173.6 million per
incident. In addition, through CL&P's power purchase contracts with the four
Yankee regional nuclear generating companies, CL&P would be responsible for
up to an additional $63.8 million per incident. Payments for CL&P's
ownership interest in nuclear generating facilities would be limited to a
maximum of $29.9 million per incident per year.
<PAGE>26
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 CL&P's ownership
interests in Millstone 1, 2, and 3, Seabrook 1, and CY; and (2) the cost of
repair, replacement, or decontamination or premature decommissioning of
utility property resulting from occurrences with respect to CL&P'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 CL&P, with respect to losses arising during current
policy years are approximately $9.7 million under the replacement power
policies and $18.9 million under the property damage, decontamination, and
decommissioning policies. Although CL&P 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 CL&P with respect to losses arising
during the current policy period are approximately $9.6 million.
FINANCING ARRANGEMENTS FOR THE REGIONAL NUCLEAR GENERATING COMPANIES
CL&P believes 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 has not been determined, CL&P may be
asked to provide direct or indirect financial support for one or more of
these companies.
PURCHASED POWER ARRANGEMENTS
CL&P purchases a portion of its electricity requirements pursuant to long-
term contracts with the Yankee companies. Under the terms of its agreements,
the company pays its ownership share (or entitlement share) 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 are recovered through the
company's rates. The total cost of purchases under these contracts for the
units that are operating amounted to $112.3 million in 1993, $103.2 million
in 1992, and $99.7 million in 1991. See <F2> Note 1, "Summary Of Significant
Accounting Policies - Investments and Jointly Owned Electric Utility Plant"
and <F4> Note 3, "Nuclear Decommissioning" for more information on the Yankee
companies.
CL&P has entered into various arrangements for the purchase of capacity and
energy from nonutility generators. Some of these arrangements generally have
terms from 10 to 30 years, and require the company to purchase the energy at
specified prices or formula rates. 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 $279.8 million in 1993, $267.3 million in 1992, and $237.6
million in 1991. These costs are eventually recovered through the company's
rates.
<PAGE>27
The estimated annual cost of CL&P's significant purchase power arrangements
is provided below:
(In Millions)
- --------------------------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
Yankee companies $106.6 $109.2 $121.5 $111.8 $126.5
Nonutility generators 293.7 303.3 313.1 318.6 324.9
- --------------------------------------------------------------------------
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
CY has a significant court appeal pending for its property tax assessment in
the town of Haddam, Connecticut, concerning production plant. The central
issue is the fair market value of utility property. The company believes
that a properly derived assessment that recognizes the effect of rate
regulation will result in a fair market value that approximates 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 Haddam advocate a method that approximates
reproduction cost. The company estimates that,for the Haddam assessment, the
change to a reproduction cost-methodology could result in a property tax
valuation approximately three times greater than a value approximating net
book cost. Although CY is currently paying property taxes based on the
higher assessment, to date, the higher assessment has not had a material
adverse effect on it 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 appeal and the
potential impact of an adverse court decision on property tax assessment
policy in Connecticut, the company cannot estimate the potential effect of an
adverse court decision 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
assessment prospectively beginning at the time new rates are established.
<PAGE>28
<F13>
12. 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 CL&P's fixed rate
securities is based upon the quoted market price for those issues or similar
issues. Adjustable rate securities are assumed to have a fair value equal to
their carrying value.
The carrying amounts of CL&P'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 . . . . . . . . . . . . . . . . . $ 166,200 $ 128,826
Preferred stock subject to mandatory
redemption . . . . . . . . . . . . . . . . . 230,000 240,400
Long-term debt:
First Mortgage Bonds . . . . . . . . . . . . 1,532,000 1,580,396
Other long-term debt . . . . . . . . . . . . 533,442 539,518
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
Carrying Fair
At December 31, 1992 Amount Value
- --------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to mandatory
redemption . . . . . . . . . . . . . . . . . $ 231,196 $ 184,910
Preferred stock subject to mandatory
redemption . . . . . . . . . . . . . . . . . 200,000 208,750
Long-term debt:
First Mortgage Bonds . . . . . . . . . . . . 1,547,000 1,594,643
Other long-term debt . . . . . . . . . . . . 545,805 545,805
- --------------------------------------------------------------------------
<PAGE>29
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, CL&P will adopt SFAS 115 on a prospective basis. CL&P
anticipates that the adoption of SFAS 115 will not have a material impact on
future results of operations or financial position.
<PAGE>30
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
Report of Independent Public Accountants
- -----------------------------------------------------------------------------
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying balance sheets of The Connecticut Light and
Power Company (a Connecticut corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1993 and 1992, and the related
statements of income, common stockholder's equity and cash flows 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 respects, the financial position of The Connecticut Light and
Power Company as of December 31, 1993 and 1992, and the results of its
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 discussed in <F2> Note 1 to the Financial Statements, "Summary of
Significant Accounting Policies-Accounting Changes," effective January 1, 1993,
The Connecticut Light and Power Company changed its methods of accounting for
property taxes, income taxes, and postretirement benefits other than
pensions.
/s/Arthur Andersen & Co.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
<PAGE>31
THE CONNECTICUT LIGHT AND POWER COMPANY
- -----------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -----------------------------------------------------------------------------
This section contains management's assessment of The Connecticut Light and
Power Company's (CL&P or the company) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This discussion should
be read in conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
The company's net income decreased to $191.4 million in 1993 from $206.7
million in 1992. The 1993 net income reflects the cumulative effect of a
change in the accounting for Connecticut municipal property taxes. The
company adopted a one-time change in the method of accounting for municipal
property tax expense in the first quarter of 1993. This change resulted in a
one-time contribution to net income of $47.7 million.
See the "Notes to Financial Statements" for further information on the
property tax accounting change.
Net income before the cumulative effect of the change in accounting for
property taxes was $143.7 million in 1993. The decrease from 1992 is
primarily attributable to one-time impacts of (a) disallowances ordered by
the Department of Public Utility Control (DPUC) in the 1993 rate case
decision and (b) the $10 million charge to earnings in the third quarter of
1993 for the costs of the company's employee reduction program. Other items
that affected net income in 1993 include increased revenues from the 1993
retail rate increase and the company's continued cost-management efforts.
These increases were 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. CL&P's
work force was reduced by about 11 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. The DPUC approved a three-year rate plan that weakened 1993
earnings but will assure CL&P customers rate stability over the next few
years which will help to improve CL&P's future earnings and competitive
position.
In 1994, CL&P 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 Connecticut economy. The company expects
retail sales growth of about two percent in 1994, based on some modest
improvement in the economy.
Competition within the electric utility industry is increasing. In response,
CL&P 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 CL&P's retail service territory or replacing
CL&P'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. These disadvantages have aggravated the
pressures on business customers in the current weakened
<PAGE>32
regional economy. Since 1991, the company has worked actively with the
Connecticut Department of Economic Development 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 reductions in effect at
the end of 1993 to a limited group of large customers were successful in
preserving CL&P revenues of approximately $28 million. The amount of
discounts provided to customers are expected to increase as the company
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 company has been able to receive for new
wholesale sales have generally been far lower than 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 the company's jurisdiction. In Connecticut, the
DPUC has begun an investigation into the viability of retail wheeling.
NU management has taken steps to make the NU system companies, including
CL&P, more competitive and profitable in the changing utility environment. A
systemwide 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, a corporate reengineering process has
begun which should help the company 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 by
reducing prices to vulnerable customers in particular.
To date, the company 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. The company believes
the steps it is taking will have significant, positive effects in the next
few years. In addition, CL&P benefits from a diverse retail base. The
company has no significant dependence on any one customer or industry. The
NU system's extensive transmission facilities and diversified generating
capacity are all 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 the company's wholesale power marketing customer retention
and reengineering efforts.
<PAGE>33
RATE MATTERS
Deferred charges at December 31, 1993 were $1.5 billion, which includes $1.0
billion for the adoption in 1993 of Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes." Deferred charges,
excluding the regulatory asset for SFAS No. 109 decreased almost $90 million
in 1993. Recoveries for the deferred costs of Millstone 3, Seabrook, and the
Yankee Atomic Electric Company (YAEC) contract obligation and reductions in
deferred energy costs were partially offset by increased deferrals for
conservation and load management costs. The company is currently recovering
some amounts of its 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 company has received approval from the DPUC to defer
these costs and expects to recover these costs in the future.
See the "Notes To Financial Statements" for further details on deferred
charges and recently adopted accounting standards.
On June 16, 1993, the 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.
In light of the State of Connecticut's concern over economic development and
industrial and commercial rates, one important aspect of the rate case 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 overrecoveries 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 plants 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 overrecovery 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
<PAGE>34
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 decision. The second appeal
was filed by the Connecticut Office of Consumer Council (OCC) and the City of
Hartford. This appeal challenges the legality of the multi-year 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 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. The only remaining
nuclear outage prudence docket before the DPUC is the docket established to
review the 1992 nuclear 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.
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.
ENVIRONMENTAL MATTERS
The NU system devotes substantial resources to identify and then to meet the
multitude of environmental requirements it faces. The system 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 company is potentially liable for environmental cleanup costs at a number
of sites both inside and outside of its service territory. To date, the
future estimated environmental remediation costs for these sites for which
the company expects some legal liability have not been material with respect
to the earnings or financial position of CL&P. At December 31, 1993, the
liability recorded by CL&P for its estimated environmental remediation costs,
excluding any possible insurance recoveries or recoveries from third parties,
amounted to approximately $2.9 million. However, while not probable, it is
reasonably possible that these costs could rise to as much as $5.8 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. CL&P's
exposure is minimal because of its investment in nuclear energy in the 1970s
and 1980s and the burning of low-sulfur fuels. The costs for meeting the
Phase II requirements cannot be estimated at this time because the emission
limits have not been determined.
<PAGE>35
The company's estimated cost of decommissioning its shares of Millstone Units
1, 2, and 3 and Seabrook is approximately $801 million in year end 1993
dollars. In addition, the company's estimated cost to decommission its
shares of the regional nuclear units is estimated to be approximately $185 to
$189 million. Decommissioning costs are recovered and recognized over the
lives of the respective units. YAEC has begun decommissioning its nuclear
facility. The company's estimated obligation to YAEC has been recorded on
its Balance Sheets. Management expects that the company will continue to be
allowed to recover these costs.
For further information regarding nuclear decommissioning, environmental
matters, and other contingencies, see the "Notes to 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 in 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 shutdown 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 $136.5 million in 1993, compared with
the same period in 1992, primarily due to increased revenues in 1993 from the
rate increase and for the recovery of replacement power costs under the GUAC.
Cash used for financing activities was $219.9 million higher in 1993,
compared with the same period in 1992, primarily due to a net decrease in
short-term debt, long-term debt, and preferred stock. Cash used for
investments was $66.2 million lower in 1993, compared with the same period in
1992, primarily due to lower construction expenditures in 1993.
The company has been able to shift its financing 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 new
financings only in years with a large amount of securities maturing. CL&P
may issue up to $200 million in 1994 to finance maturing debt. The company
is obligated to meet $581 million of long-term debt and preferred stock
maturities and cash sinking-fund requirements for the 1994 through 1998
period, including $189 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 its outstanding high-cost securities has enabled
the company to lower its cost of debt. There was no new money financing in
1993. To take advantage of favorable market conditions during
<PAGE>36
1993, the company refinanced $425 million of First Mortgage Bonds, $110
million of preferred stock and $135.5 million of pollution control bonds, in
addition to restructuring the company's various credit lines. It is
estimated that the 1993 refinancings and restructuring will save the company
approximately $15 million per year. The company intends, if market
conditions permit, to continue to refinance a portion of its outstanding
long-term debt and preferred stock at 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 Bond
will mature on February 1, 1999, and the Series B Bond 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 $4.5 million per year
in reduced interest rates.
The company's construction program expenditures, including allowance for
funds used during construction (AFUDC), for the period 1994 through 1998 are
estimated to be approximately $742 million, including $158 million for 1994.
The construction program's main focus is maintaining and upgrading the
existing transmission and distribution system as well as the 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 approximately
$318 million for the period 1994 through 1998, including $75 million for
1994.
<PAGE>37
RESULTS OF OPERATIONS
Change in Operating Revenues
Increase/(Decrease)
- ----------------------------------------------------------------- ------
1993 vs. 1992 1992 vs. 1991
- ----------------------------------------------------------------- ------
(Millions of Dollars)
Regulatory decisions $34.2 $72.7
Fuel and purchased power
cost recoveries 1.9 20.0
Sales volume 3.0 5.4
Other revenues 10.5 (57.4)
----- ------
Total revenue change $49.6 $40.7
===== =====
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table above.
Operating revenues increased $49.6 million from 1992 to 1993. Revenues
related to regulatory decisions increased in 1993, primarily because of the
effects of the June 1993 DPUC retail rate increase and higher revenues under
the CAM. Retail sales were essentially flat in 1993. Other revenues
increased primarily because of higher 1993 capacity interchange sales.
Operating revenues increased $40.7 million from 1991 to 1992. Revenues
related to regulatory decisions increased in 1992 primarily because of the
effect of the August 1991 DPUC retail rate increase. Fuel and purchased-
power cost recoveries increased primarily due to the timing in the recovery
of fuel expenses under the provisions of CL&P's fuel adjustment clauses.
Retail sales in 1992 were slightly higher than 1991. Other revenues
decreased primarily because of 1992 capacity sales to other utilities that
took place at lower prices per kilowatt-hour and the 1991 one-time
reimbursement of costs associated with the reactivation of fossil-generating
units.
FUEL, PURCHASED, AND NET INTERCHANGE POWER
Fuel, purchased, and net interchange power increased $58.8 million in 1993,
as compared to 1992, primarily due to the timing in the recovery of fuel
expenses under the provisions of the company's fuel adjustment clauses and
disallowances of replacement power costs deferred under the GUAC, partially
offset by lower outside purchases due to better nuclear performance in 1993.
Fuel, purchased, and net interchange power increased $39.2 million in 1992,
as compared to 1991, primarily due to the timing in the recovery of fuel
expenses under the provisions of the company's fuel adjustment clauses, and
previously deferred replacement power costs that are not recoverable as a
result of regulatory reviews.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses increased $18.7 million in 1993, as
compared to 1992, primarily due to the one-time costs in 1993 associated with
the employee reduction program and 1993 SFAS No. 106 postretirement benefit
costs prior to the DPUC order allowing the deferral of these costs, partially
offset by lower 1993 costs associated with the operation and maintenance
activities of the nuclear units.
<PAGE>38
Other operation and maintenance expenses increased $4.0 million in 1992, as
compared to 1991, primarily due to higher 1992 costs of operation and
maintenance activities at nuclear units, partially offset by the 1991 costs
associated with a voluntary early retirement program, and lower 1992
conservation expenses.
DEPRECIATION EXPENSES
Depreciation expenses increased $9.9 million in 1993, as compared to 1992,
and $11.3 million in 1992, as compared to 1991, primarily as a result of
higher depreciation rates, higher depreciable plant balances, and higher
decommissioning levels in 1992 as compared to 1991.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased $38.9 million in 1993, as
compared to 1992, and $17.8 million in 1992, as compared to 1991, primarily
because of higher amortization of Millstone 3 and Seabrook deferred costs.
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. CL&P was allowed to collect and amortize $17.9 million of
previously deferred costs over the one-year period beginning July 1993.
FEDERAL AND STATE INCOME TAXES
Federal and State income taxes, net decreased $21.4 million in 1993, as
compared to 1992, primarily because of lower book taxable income and higher
investment tax credit amortization, partially offset by an increase in flow-
through depreciation.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5.4 million in 1992, as compared to
1991, primarily due to higher property taxes and higher Connecticut gross
earnings taxes due to higher revenues.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased $10.8 million in 1993, as compared
to 1992, and $6.3 million in 1992, as compared to 1991, primarily because of
a decrease in Millstone 3 deferred return because additional Millstone 3
investment was phased into rates.
OTHER INCOME, NET
Other income, net decreased $8.0 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 rate decision and lower
AFUDC.
INTEREST CHARGES
Interest on long-term debt increased $17.1 million in 1993, as compared to
1992 and $14.9 million in 1992, compared to 1991, primarily because of lower
average interest rates as a result of the substantial refinancing activity.
Other interest charges increased $5.4 million in 1993, as compared to 1992,
primarily because of higher interest on short-term borrowings, lower AFUDC
for borrowed funds and interest recognized for a potential Connecticut sales
tax assessment.
<PAGE>39
THE CONNECTICUT LIGHT AND POWER COMPANY
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Years Ended December 31, 1993 1992 1991 1990 1989
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Continuing Operations:
Operating Revenues. . . . . . $2,366,050 $2,316,451 $2,275,737 $2,170,087 $2,069,559
Operating Income. . . . . . . 240,095 287,811 323,835 320,641 327,220
Net Income. . . . . . . . . . 191,449 206,714 240,818 224,783 207,875
Discontinued Gas
Operations:
Operating Revenues . . . . . - - - - 124,229
Operating Income . . . . . . - - - - 12,563
Net Income . . . . . . . . . - - - - 6,630
Cash Dividends on
Common Stock. . . . . . . . . 160,365 164,277 172,587 179,921 155,972
Total Assets . . . . . . . . . 6,397,380 5,582,806 5,338,441 5,176,784 5,148,120
Long-Term Debt*. . . . . . . . 2,057,280 2,087,936 2,023,268 2,101,334 2,147,892
Preferred Stock Not
Subject to Mandatory
Redemption. . . . . . . . . . 166,200 231,196 306,195 306,195 306,195
Preferred Stock
Subject to Mandatory
Redemption* . . . . . . . . . 230,000 200,000 141,892 146,892 151,892
Obligations Under
Capital Leases* . . . . . . . 177,418 197,404 208,924 233,919 252,652
*Includes portions due within one year.
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- ----------------------------------------------------------------------------------------------------
Quarter Ended
- ----------------------------------------------------------------------------------------------------
1993 March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Revenues. . . . . . . $627,134 $559,894 $604,343 $574,679
======== ======== ======== ========
Operating Income. . . . . . . . $ 67,201 $ 47,775 $58,321 $ 66,798
======== ======== ======== ========
Net Income. . . . . . . . . . . $ 91,596 $ 13,775 $39,068 $ 47,010
======== ======== ======== ========
1992
- ----------------------------------------------------------------------------------------------------
Operating Revenues. . . . . . . $633,933 $547,010 $554,635 $580,873
======== ======== ======== ========
Operating Income. . . . . . . . $ 90,840 $ 58,892 $75,438 $ 62,641
======== ======== ======== ========
Net Income. . . . . . . . . . . $ 68,042 $ 40,615 $55,145 $ 42,912
======== ======== ======== ========
</TABLE>
<PAGE>40
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY
- ----------------------------------------------------------------------------------------------------
STATISTICS
- ----------------------------------------------------------------------------------------------------
<CAPTION>
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31,)
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1993 $6,214,399 26,107 8,519 1,078,925 2,676
1992 6,100,680 25,809 8,501 1,075,425 3,028
1991 5,986,269 24,992 8,435 1,069,912 3,364
1990 5,881,499 25,039 8,434 1,064,695 3,517
1989 5,732,850 25,078 8,570 1,054,055 3,556
</TABLE>
<PAGE>41
The Connecticut Light and Power Company
First and Refunding Mortgage Bonds
----------------------------------
Trustee and Interest Paying Agent
Bankers Trust Company, Corporate Trust and Agency Group
P.O. Box 318, Church Street Station, New York, New York 10015
Preferred Stock
---------------
Transfer Agent, Dividend Disbursing Agent and Registrar
Northeast Utilities Service Company Shareholder Services
P.O. Box 5006, Hartford, CT 06102-5006
1994 Dividend Payment Dates
5.28%, 5.30%, 9.00%, $3.24 Series -
January 1, April 1, July 1, and October 1
4.50% (1956), 4.96%, 6.56%
$1.90, $2.00, $2.04, $2.06, $2.09, and $2.20 Series -
February 1, May 1, August 1, and November 1
3.90%, 4.50% (1963), 7.23% Series -
January 12, March 1, June 1, September 1, and December 1
DARTS*
January 12, March 2, April 20, June 8, July 27,
September 14, November 2, December 21
Address General Correspondence in Care of:
Northeast Utilities Service Company
Investor Relations Department
P.O. Box 270
Hartford, Connecticut 06141-0270
Tel. (203) 665-5000
General Office
Selden Street, Berlin, Connecticut 06037-1616
_________________________
*Transfer and Paying Agent:
Bankers Trust Company, Corporate Trust and Agency Group
P.O. Box 318, Church Street Station, New York, New York 10015
The data contained in this Annual Report is submitted for the sole purpose of
providing information to present stockholders about the Company.
<PAGE>
Exhibit 13.3
1993
ANNUAL REPORT
WESTERN MASSACHUSETTS ELECTRIC COMPANY
1993 Annual Report
Western Massachusetts Electric Company
Index
Contents Page
- -------- ----
Balance Sheets . . . . . . . . . . . . . . . . . . . . 1-2
Statements of Income . . . . . . . . . . . . . . . . . 3
Statements of Cash Flows . . . . . . . . . . . . . . . 4
Statements of Common Stockholder's Equity. . . . . . . 5
Notes to Financial Statements. . . . . . . . . . . . . 6-25
Report of Independent Public Accountants . . . . . . . 26
Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 27-32
Selected Financial Data. . . . . . . . . . . . . . . . 33
Statements of Quarterly Financial Data . . . . . . . . 33
Statistics . . . . . . . . . . . . . . . . . . . . . . 34
Preferred Stockholder and Bondholder Information . . . Back Cover
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- ------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric......................................... $1,183,410 $1,158,160
Less: Accumulated provision for depreciation.. 395,190 364,702
----------- -----------
788,220 793,458
Construction work in progress.................... 23,790 18,522
Nuclear fuel, net................................ 35,727 37,704
----------- -----------
Total net utility plant...................... 847,737 849,684
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at cost.......... 49,155 41,986
Investments in regional nuclear generating
companies, at equity............................ 14,633 14,567
Other, at cost................................... 3,840 3,842
----------- -----------
67,628 60,395
----------- -----------
Current Assets:
Cash and special deposits........................ 185 165
Receivables, less accumulated provision for
uncollectible accounts of $1,997,000 in 1993
and $2,117,000 in 1992......................... 36,437 36,587
Receivables from affiliated companies............ 4,972 2,829
Accrued utility revenues......................... 17,362 15,627
Fuel, materials, and supplies, at average cost... 7,057 9,001
Prepayments and other............................ 9,613 7,572
----------- -----------
75,626 71,781
----------- -----------
Deferred Charges:
Regulatory asset--income taxes <F2>(Note 1)...... 94,414 -
Amortizable property investment--Millstone 3..... 28,001 39,201
Deferred costs--Millstone 3 <F2>(Note 1)......... 22,667 30,497
Unrecovered contract obligation--YAEC <F>(Note 3) 24,150 28,160
Deferred DOE assessment <F2>(Note 1)............. 8,908 9,630
Unamortized debt expense......................... 1,842 2,141
Other............................................ 33,669 39,195
----------- -----------
213,651 148,824
----------- -----------
Total Assets................................. $1,204,642 $1,130,684
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>1
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock,$25 par value--authorized and
outstanding 1,072,471 shares in 1993 and 1992... $ 26,812 $ 26,812
Capital surplus, paid in........................... 149,319 149,026
Retained earnings.................................. 97,627 91,077
----------- -----------
Total common stockholder's equity............ 273,758 266,915
Cumulative preferred stock--
$100 par value--authorized 1,000,000 shares;
outstanding 200,000 shares in 1993 and 1992;
$25 par value--authorized 3,600,000 shares;
outstanding 3,220,000 shares in 1993
3,280,000 shares in 1992
Not subject to mandatory redemption <F6>(Note 5) 73,500 73,500
Subject to mandatory redemption <F7>(Note 6).. 25,500 27,000
Long-term debt <F8>(Note 7)........................ 393,232 392,824
----------- -----------
Total capitalization...................... 765,990 760,239
----------- -----------
Obligations Under Capital Leases..................... 24,014 27,425
----------- -----------
Current Liabilities:
Notes payable to banks............................. 6,000 18,000
Commercial paper................................... - 23,500
Long-term debt and preferred stock--current
portion......................................... 1,500 1,652
Obligations under capital leases--current
portion......................................... 12,888 14,084
Accounts payable................................... 17,493 16,038
Accounts payable to affiliated companies........... 12,016 15,549
Accrued taxes...................................... 7,022 10,270
Accrued interest................................... 6,478 5,798
Refundable energy costs............................ 8,676 2,082
Other.............................................. 11,727 7,042
----------- -----------
83,800 114,015
----------- -----------
Deferred Credits:
Accumulated deferred income taxes <F2>(Note 1)..... 253,547 144,865
Accumulated deferred investment tax credits........ 36,083 37,512
Deferred contract obligation--YAEC <F4>(Note 3).... 24,150 28,160
Deferred DOE obligation <F2>(Note 1)............... 7,268 9,630
Other.............................................. 9,790 8,838
----------- -----------
330,838 229,005
----------- -----------
Commitments and Contingencies <F12>(Note 11)
Total Capitalization and Liabilities...... $1,204,642 $1,130,684
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>2
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................ $415,055 $410,720 $409,840
--------- --------- ---------
Operating Expenses:
Operation--
Fuel, purchased and net interchange
power...................................... 67,781 86,356 99,717
Other......................................... 142,273 126,060 114,231
Maintenance..................................... 34,259 39,303 36,795
Depreciation.................................... 35,751 34,257 35,636
Amortization of regulatory assets............... 29,700 26,321 24,950
Federal and state income taxes
<F9>(Note 8).................................. 28,173 20,926 22,856
Taxes other than income taxes................... 17,051 16,984 15,932
--------- --------- ---------
Total operating expenses..................... 354,988 350,207 350,117
--------- --------- ---------
Operating Income.................................. 60,067 60,513 59,723
--------- --------- ---------
Other Income:
Deferred Millstone 3 return--other
funds........................................ 1,439 2,119 2,763
Equity in earnings of regional
nuclear generating companies.................. 1,680 2,170 2,181
Other, net...................................... 2,966 2,628 1,895
Income taxes--credit............................ 304 810 1,969
--------- --------- ---------
Other income, net............................ 6,389 7,727 8,808
--------- --------- ---------
Income before interest charges............... 66,456 68,240 68,531
--------- --------- ---------
Interest Charges:
Interest on long-term debt...................... 29,979 31,694 33,557
Other interest.................................. 881 469 1,544
Deferred Millstone 3 return--
borrowed funds <F2>(Note 1)................... (1,076) (945) (1,207)
--------- --------- ---------
Interest charges, net........................ 29,784 31,218 33,894
--------- --------- ---------
Income before cumulative effect of
accounting change............................... 36,672 37,022 34,637
Cumulative effect of accounting change <F2>(Note 1) 3,922 - -
--------- --------- ---------
Net Income........................................ $ 40,594 $ 37,022 $ 34,637
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>3
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION> --------- --------- ---------
For the Years Ended December 31, 1993 1992 1991
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operations:
Net Income .............................................. $ 40,594 $ 37,022 $ 34,637
Adjusted for the following:
Depreciation............................................ 38,296 36,735 36,984
Deferred income taxes and investment tax credits, net... 918 (785) 3,767
Deferred return - Millstone 3, net of amortization...... 12,252 9,110 8,216
Deferred energy costs, net of amortization.............. 6,594 12,629 (8,418)
Other sources of cash................................... 27,745 24,113 18,977
Other uses of cash...................................... (5,142) (10,814) (9,662)
Changes in working capital:
Receivables and accrued utility revenues............... (3,728) 12,288 (7,216)
Fuel, materials, and supplies.......................... 1,944 490 3,870
Accounts payable....................................... (2,078) (5,355) 6,262
Accrued taxes.......................................... (3,248) (295) 344
Other working capital (excludes cash).................. 2,433 1,932 4,971
--------- --------- ---------
Net Cash Flows From Operations............................. 116,580 117,070 92,732
--------- --------- ---------
Cash Flows Used For Financing Activities:
Long-term debt........................................... 113,800 85,000 -
Financing expenses....................................... (359) (470) -
Net increase (decrease) in short-term debt............... (35,500) (3,250) 7,750
Reacquisitions and retirements of long-term debt
and preferred stock.................................... (115,770) (109,169) (21,650)
Cash dividends on preferred stock........................ (5,259) (7,485) (8,048)
Cash dividends on common stock........................... (28,785) (29,536) (31,499)
--------- --------- ---------
Net cash flows used for financing activities............... (71,873) (64,910) (53,447)
--------- --------- ---------
Investment Activities:
Investment in plant (including capital leases):
Electric utility plant................................. (34,592) (46,061) (32,775)
Nuclear fuel........................................... (2,926) 1,003 (570)
--------- --------- ---------
Net cash flows used for investments in plant........... (37,518) (45,058) (33,345)
Other investment activities, net....................... (7,169) (7,101) (5,917)
--------- --------- ---------
Net cash flows used for investments........................ (44,687) (52,159) (39,262)
--------- --------- ---------
Net Increase In Cash for the Period........................ 20 1 23
Cash and special deposits - beginning of period............ 165 164 141
--------- --------- ---------
Cash and special deposits - end of period.................. $ 185 $ 165 $ 164
========= ========== =========
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized during
construction............................................. $ 27,277 $ 30,758 $ 32,616
========= ========= =========
Income taxes............................................. $ 21,200 $ 17,711 $ 22,047
========= ========= =========
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 9,369 $ 7,224 $ 3,443
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>4
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In <F1>(a) Total
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1991............... $26,812 $148,401 $ 96,618 $271,831
Net income for 1991.................. 34,637 34,637
Cash dividends on preferred
stock.............................. (8,048) (8,048)
Cash dividends on common stock....... (31,499) (31,499)
Capital stock expenses, net.......... 295 295
-------- --------- --------- ---------
Balance at December 31, 1991............. 26,812 148,696 91,708 267,216
Net income for 1992.................. 37,022 37,022
Cash dividends on preferred
stock.............................. (7,485) (7,485)
Cash dividends on common stock....... (29,536) (29,536)
Loss on the retirement of preferred
stock.............................. (632) (632)
Capital stock expenses, net.......... 330 330
-------- --------- --------- ---------
Balance at December 31, 1992............. 26,812 149,026 91,077 266,915
Net income for 1993.................. 40,594 40,594
Cash dividends on preferred
stock.............................. (5,259) (5,259)
Cash dividends on common stock....... (28,785) (28,785)
Capital stock expenses, net.......... 293 293
-------- --------- --------- ---------
Balance at December 31, 1993............. $26,812 $149,319 $ 97,627 $273,758
======== ========= ========= =========
<F1> (a) The company has dividend restrictions imposed by its long-term debt agreements.
At December 31, 1993, these restrictions totaled approximately $71.1 million.
(/TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>5
WESTERN MASSACHUSETTS ELECTRIC COMPANY
- --------------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS
- --------------------------------------------------------------------------
<FN>
<F1>1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
Western Massachusetts Electric Company (WMECO or the company), The Connecticut
Light and Power Company (CL&P), Holyoke Water Power Company (HWP), Public
Service Company of New Hampshire (PSNH), and North Atlantic Energy Corporation
(NAEC) are the operating subsidiaries comprising the Northeast Utilities system
(the system) and are wholly owned by Northeast Utilities (NU).
Other wholly owned subsidiaries of NU provide substantial support services
to the system. Northeast Utilities Service Company (NUSCO) supplies centralized
accounting, administrative, data processing, engineering, financial, legal,
operational, planning, purchasing, and other services to the system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for system companies in
operating the Millstone nuclear generating facilities.
All transactions among affiliated companies are on a recovery of cost basis
which may include amounts representing a return on equity, and are subject to
approval by various federal and state regulatory agencies.
ACCOUNTING CHANGES
Property Taxes: 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 company accrued Connecticut property tax expense
over the period October 1 through September 30 based on the lien-date method.
During 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 payment and services provided by the
municipalities. This one-time change increased net income by approximately $3.9
million for WMECO 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 information on this change, see <F2> Note 1, "Summary of
Significant Accounting Policies - Income Taxes."
Postretirement Benefits Other Than Pensions: The company has 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 10,
"Postretirement Benefits Other Than Pensions."
ACCOUNTING RECLASSIFICATIONS
Certain amounts in the accompanying financial statements of WMECO for the years
ended December 31, 1992 and 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 a holding
company under the Public Utility Holding Company Act of 1935 (1935 Act), and it
and its subsidiaries, including the company, 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 company is subject to further
regulation for rates and other matters by the FERC and the
<PAGE>6
Massachusetts Department of Public Utilities (DPU), and follows the accounting
policies prescribed by these 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, WMECO accrues an estimate for the amount of
energy delivered but unbilled.
SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, WMECO 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 $31.9 million, including interest costs of
$16.3 million. As of December 31, 1993, approximately $32.3 million had been
collected through rates.
Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for its
proportionate share 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, WMECO's remaining share of these costs is estimated to be
approximately $8.9 million. WMECO has begun to recover these costs.
Accordingly, WMECO has recognized these costs as a regulatory asset, with a
corresponding obligation, on its Balance Sheets.
INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: WMECO owns common stock of four regional
nuclear generating companies (Yankee companies). The Yankee companies, with the
company's ownership interests, are:
Connecticut Yankee Atomic Power Company (CY) . . . . 9.5%
Yankee Atomic Electric Company (YAEC). . . . . . . . 7.0
Maine Yankee Atomic Power Company (MY) . . . . . . . 3.0
Vermont Yankee Nuclear Power Corporation (VY). . . . 2.5
WMECO's investments in the Yankee companies are accounted for on the equity
basis. The electricity produced by these facilities 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 <F12> Note 11, "Commitments and Contingencies - Purchased Power
Arrangements."
<PAGE>7
The 173-megawatt (MW) YAEC nuclear power plant was shut down permanently on
February 26, 1992. For more information on the Yankee companies, see <F4>
Note 3, "Nuclear Decommissioning."
Millstone 1: WMECO has a 19 percent joint-ownership interest in Millstone 1,
a 660-MW nuclear generating unit. As of December 31, 1993, plant-in-service and
the accumulated provision for depreciation included approximately $77.6 million
and $30.5 million, respectively, for WMECO's share of Millstone 1. WMECO's
share of Millstone 1 operating expenses is included in the corresponding
operating expenses on the accompanying Statements Of Income.
Millstone 2: WMECO has a 19 percent joint-ownership interest in Millstone 2,
an 875-MW nuclear generating unit. As of December 31, 1993, plant-in-service
and the accumulated provision for depreciation included approximately $158.1
million and $34.8 million, respectively, for WMECO's share of Millstone 2.
WMECO's share of Millstone 2 operating expenses is included in the corresponding
operating expenses on the accompanying Statements Of Income.
Millstone 3: WMECO has a 12.24 percent joint-ownership interest in
Millstone 3, an 1,149-MW nuclear generating unit. As of December 31, 1993,
plant-in-service and the accumulated provision for depreciation included
approximately $375.5 million and $72.9 million, respectively, for WMECO's
proportionate share of Millstone 3. WMECO's share of Millstone 3 expenses
is included in the corresponding operating expenses on the accompanying
Statements Of Income.
DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency. Except for major facilities, depreciation factors are
applied to the average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is retired
from service, the original cost of plant, including costs of removal, less
salvage, is charged to the accumulated provision for depreciation. For nuclear
production plants, the costs of removal, less salvage, that have been funded
through external decommissioning trusts will be paid with funds from the trusts
and will be charged to the accumulated reserve for decommissioning included in
the accumulated provision for depreciation over the expected service life of the
plants. See <F4> 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 3.1 percent in 1993, 3.0 percent in 1992, and
3.3 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 <F9> Note 8, "Income Tax Expense," 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. WMECO adopted
SFAS 109, on a prospective basis, during the first quarter of 1993. At December
31, 1993, the deferred tax obligation relating to the adoption of SFAS 109
approximated $94 million. As it is probable that the increase in deferred tax
liabilities will be recovered from customers through rates, WMECO also
established a regulatory asset. SFAS 109 does not permit net-of-tax accounting.
Accordingly, the company no longer utilizes net-of-tax
<PAGE>8
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 . . . . . . . . . $205,030
The tax effect of net regulatory assets. . . 37,258
Other. . . . . . . . . . . . . . . . . . . . 11,259
--------
$253,547
========
ENERGY ADJUSTMENT CLAUSE
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 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's 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 <F12> Note 11, "Commitments and
Contingencies--Nuclear Performance."
PHASE-IN PLAN
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.
<F3>2. LEASES
WMECO and CL&P 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. WMECO and CL&P 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
<PAGE>9
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 WMECO and CL&P.
WMECO has 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. The following
rental payments have been charged to operating expense:
Operating Capital
Year Leases Leases
1993. . . . . . . . . . . . $17,158,000 $6,367,000
1992. . . . . . . . . . . . 13,799,000 7,263,000
1991. . . . . . . . . . . . 11,599,000 6,790,000
Interest included in capital lease rental payments was $2,090,000 in 1993,
$2,895,000 in 1992, and $3,434,000 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.
<PAGE>10
Future minimum rental payments, excluding annual nuclear fuel lease payments and
executory costs, such as property taxes, state use taxes, insurance, and
maintenance, under long-term noncancelable leases, as of December 31, 1993, are
approximately:
Capital Operating
Year Leases Leases
---- ------- ---------
(Thousands of Dollars)
1994. . . . . . . . . . . . $ 40 $4,900
1995. . . . . . . . . . . . 40 4,600
1996. . . . . . . . . . . . 40 4,200
1997. . . . . . . . . . . . 40 4,100
1998. . . . . . . . . . . . 40 3,100
After 1998. . . . . . . . . 220 36,300
------- -------
Future minimum lease
payments . . . . . . . . . 420 $57,200
=======
Less amount of representing
interest . . . . . . . . . 120
-------
Present value of future
minimum lease payments
for other than nuclear
fuel . . . . . . . . . . . 300
Present value of future
nuclear fuel lease
payments . . . . . . . . . 36,600
-------
Total. . . . . . $36,900
=======
<F4>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. Decommissioning studies are
reviewed and updated periodically to reflect changes in decommissioning
requirements, technology, and inflation.
The estimated cost of decommissioning WMECO's ownership share of Millstone 1,
2, and 3, in year-end 1993 dollars, is $73.3 million, $58.9 million, and $51.6
million, respectively. Nuclear decommissioning costs are accrued over the
expected service life of the units and are included in depreciation expense on
the Statements Of Income. Nuclear decommissioning costs amounted to $4.6
million in 1993, 1992, and 1991. Nuclear decommissioning, as a cost of removal,
is included in the accumulated provision for depreciation on the Balance Sheets.
WMECO has established independent decommissioning trusts for its portion of the
costs of decommissioning Millstone 1, 2, and 3. As of December 31, 1993, WMECO
has collected, through rates, $37.6 million toward the future decommissioning
costs of its share of the Millstone units, all of which has been transferred to
external decommissioning trusts. 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 $49.2 million.
<PAGE>11
Changes in requirements or technology, or adoption of a decommissioning method
other than immediate dismantlement, could change decommissioning cost estimates.
WMECO attempts to recover sufficient amounts through 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 company. 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.
WMECO, along with other New England utilities, has 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 decommissioning WMECO's
ownership share of CY and MY are $32.3 million, and $9.7 million, respectively.
The cost to decommission VY is currently being reestimated. The cost of
decommissioning WMECO's ownership share of VY is projected to range from $7.5
million to $8.75 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 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 WMECO's share was approximately $24.1 million. Management expects that
WMECO will continue to be allowed to recover such FERC-approved costs from its
customers. Accordingly, WMECO has recognized these costs as a regulatory asset,
with a corresponding obligation, on its Balance Sheets. WMECO has a 7.0 percent
equity investment, approximating $1.7 million, in YAEC. WMECO had relied on
YAEC for less than 1 percent of its capacity.
<F5>4. SHORT-TERM DEBT
The system companies have various credit lines, totaling $485 million. NU,
CL&P, WMECO, HWP, 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 .20 percent of each bank's total commitment under the three-year
portion of the facility, representing 75 percent of the total facility, plus
.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 of borrowings under the facility, of which WMECO has
no outstanding borrowings.
Certain subsidiaries of NU, including WMECO, are members of the Northeast
Utilities System Money Pool (Pool). The Pool provides a more efficient use
of the cash resources of the system, and reduces outside short-term borrowings.
NUSCO administers the Pool as agent for the member companies.
<PAGE>12
Short-term borrowing needs of the member companies are first met with available
funds of other member companies, including funds borrowed by NU parent.
NU parent may lend to the Pool but may not borrow. Investing and borrowing
subsidiaries receive or pay interest based on the average daily Federal
Funds rate. Funds may be withdrawn from or repaid to the Pool at any time
without prior notice. However, borrowings based on loans from NU parent
bear interest at NU parent's cost and must be repaid based upon the terms of
NU's original borrowing.
Maturities of WMECO's short-term debt obligations are for periods of three
months or less.
The amount of short-term borrowings that may be incurred by the company is
subject to periodic approval by the SEC under the 1935 Act. In addition,
the charter of WMECO contains provisions restricting the amount of short-term
borrowings. Under the SEC and/or charter restrictions, as of January 1, 1993,
the company was authorized to incur short-term borrowings up to a maximum of $75
million.
<PAGE>13
</TABLE>
<TABLE>
<F6>5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
<CAPTION>
December 31, Shares
1993 Outstanding December 31,
Redemption December 31 --------------------------------
Description Price 1993 1993 1992 1991
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
9.60% Series A of 1970 . . . . . $ - - $ - $ - $15,000
7.72% Series B of 1971 . . . . . 103.51 200,000 20,000 20,000 20,000
1988 Adjustable Rate DARTS . . . 25.00 2,140,000 53,500 53,500 53,500
------- ------- -------
Total preferred stock not subject
to mandatory redemption . . . . $73,500 $73,500 $88,500
======= ====== ======
All or any part of each outstanding series of preferred stock may be redeemed by the company at any time
at established redemption prices plus accrued dividends to the date of redemption.
</TABLE>
<TABLE>
<F7>6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
<CAPTION>
December 31, Shares
1993 Outstanding December 31,
Redemption December 31 --------------------------------
Description Price* 1993 1993 1992 1991
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
7.60% Series of 1987 . . . . . . $26.14 1,080,000 $27,000 $28,500 $28,502
Less preferred stock to be
redeemed within one year,
net of reacquired stock . . . . 1,500 1,500 2
------- ------- -------
Total preferred stock subject to mandatory redemption $25,500 $27,000 $28,500
======= ======= =======
*Redemption price reduces in future years.
</TABLE>
The minimum sinking-fund provisions of the 1987 Series subject to mandatory
redemption at December 31, 1993, for the years 1994 through 1998, are $1.5
million per year. 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 the company is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, the company would be prohibited from redemption or purchase of less than
<PAGE>14
all of the preferred stock outstanding. All or part of the 7.60% Series of 1987
may be redeemed by the company at any time at an established redemption price
plus accrued dividends to the date of redemption except that during the initial
five-year redemption period it is subject to certain refunding limitations.
<F8>7. LONG-TERM DEBT
Details of long-term debt outstanding are:
- -------------------------------------------------------------------------
December 31,
-----------------
1993 1992
- -------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
9 1/4% Series S, due 1995 . . . . . $ - $ 59,400
9 1/4% Series U, due 1995 . . . . . 34,650 35,000
5 3/4% Series F, due 1997 . . . . . 15,000 15,000
7 3/8% Series H, due 1998 . . . . . 15,000 15,000
6 3/4% Series G, due 1998 . . . . . 10,000 10,000
7 3/4% Series J, due 2002 . . . . . 30,000 30,000
7 3/4% Series V, due 2002 . . . . . 85,000 85,000
9 3/4% Series R, due 2016 . . . . . 24,750 25,000
10 1/8% Series T, due 2018 . . . . . 33,819 34,235
6 7/8% Series W, due 2000 . . . . . 60,000 -
-------- --------
Total First Mortgage Bonds . . 308,219 308,635
Pollution Control Notes:
Tax Exempt Series A, due 2028. . . . . . 53,800 -
Variable rate, due 2014-2015 . . . . . . - 52,400
5.9%, due 1998. . . . . . . . . . . . . - 1,454
Fees and interest due for spent fuel
disposal costs. . . . . . . . . . . . . 31,930 30,966
Less: Amounts due within one year . . . - 152
Unamortized premium and discount, net. . (717) (479)
-------- --------
Long-term debt, net. . . . . . . . . . . $393,232 $392,824
======== ========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1993 for the years 1994 through 1998 are
approximately: $0 in 1994, $34,650,000 in 1995, $0 in 1996, $15,000,000 in
1997, and $25,000,000 in 1998. In addition, there are annual 1 percent
sinking- and improvement-fund requirements, currently amounting to $3,100,000
in 1994 and 1995, $2,750,000 in 1996 and 1997, and $2,600,000 in 1998. Such
sinking- and improvement-fund requirements may be satisfied by the deposit of
cash or bonds or by certification of property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which are
subject to certain refunding limitations during their respective initial
five-year redemption periods.
<PAGE>15
Essentially all of the company's utility plant is subject to the liens of its
first mortgage bond indentures. As of December 31, 1993, the company has
secured $53.8 million of pollution control notes with second mortgage liens
on Millstone 1, junior to the liens of its first mortgage bond
indentures.
WMECO has entered into an interest rate cap contract to reduce the potential
impact of upward changes in interest rates on certain variable-rate
tax-exempt pollution control revenue bonds held by WMECO. Approximately $52
million of total outstanding long-term variable-rate debt is secured by this
interest rate cap. The total cost of the interest rate cap for 1993 was
approximately $442,000, the cost of which is amortized over the term of the
contract, which is for three years. The fair market value of the outstanding
interest-rate cap contract as of December 31, 1993 is approximately $59,000.
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
<F2> Note 1 of the accompanying Notes to Financial Statements.
<PAGE>16
<TABLE>
<F9>8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
<CAPTION>
- --------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 <F2>(Note 1) 1992 1991
- --------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes:
Federal. . . . . . . . . . . . . . . . . $22,239 $16,736 $13,550
State. . . . . . . . . . . . . . . . . . 4,712 4,165 3,570
------- ------- -------
Total current. . . . . . . . . . . . . 26,951 20,901 17,120
------- ------- -------
Deferred income taxes, net:
Federal. . . . . . . . . . . . . . . . . 1,683 (1,466) 1,581
State. . . . . . . . . . . . . . . . . . 664 117 1,259
------- ------- -------
Total deferred . . . . . . . . . . . . 2,347 (1,349) 2,840
------- ------- -------
Investment tax credits, net . . . . . . (1,429) (1,251) (1,251)
------- -------- -------
Total income tax expense. . . . . . . $27,869 $18,301 $18,709
======= ======= =======
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses. . . . . . . . . . . . . . . . $28,173 $20,926 $22,856
Income taxes associated with the
amortization of deferred Millstone 3
return - borrowed funds . . . . . . . . - (2,410) (2,945)
Income taxes associated with AFUDC and
deferred Millstone 3 return -
borrowed funds. . . . . . . . . . . . . - 595 767
Other income taxes - credit. . . . . . . (304) (810) (1,969)
------- ------- -------
Total income tax expense . . . . . . . . $27,869 $18,301 $18,709
======= ======= =======
<PAGE>17
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
- --------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- --------------------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits, and disposal costs . $6,852 $ 4,070 $ 5,911
Construction overheads . . . . . . . . . . - - (979)
Energy adjustment clause . . . . . . . . . (2,627) (4,663) 1,409
AFUDC and Deferred Millstone 3 return,
net . . . . . . . . . . . . . . . . . . . (2,191) (1,815) (2,178)
Deferred refueling cost. . . . . . . . . . 413 666 6
Early retirement program . . . . . . . . . (544) 775 (1,809)
Loss on bond redemption. . . . . . . . . . 1,561 18 527
Conservation and load management . . . . . (712) 394 (419)
Other. . . . . . . . . . . . . . . . . . . (405) (794) 372
------ ------- -------
Deferred income taxes, net . . . . . . . $2,347 $(1,349) $ 2,840
====== ======= =======
A reconciliation between income tax expense and the expected tax expense at the applicable statutory
rates:
- --------------------------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- --------------------------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income for
1993 and 34 percent for 1992
and 1991. . . . . . . . . . . . . . . . . $23,962 $18,810 $18,138
Tax effect of differences:
Depreciation differences . . . . . . . 1,784 (1,584) (9)
Deferred Millstone 3 return -
other funds . . . . . . . . . . . . . (504) (721) (940)
Amortization of deferred Millstone 3
return - other funds. . . . . . . . . 3,341 2,856 2,876
Construction overheads . . . . . . . . - - (979)
Investment tax credit amortization . . (1,429) (1,251) (1,251)
State income taxes, net of federal
benefit . . . . . . . . . . . . . . . 3,494 2,829 3,215
Adjustment for prior years taxes . . . - (1,500) (1,000)
Other, net . . . . . . . . . . . . . . (2,779) (1,138) (1,341)
------- ------- -------
Total income tax expense. . . . . $27,869 $18,301 $18,709
======= ======= =======
<PAGE>18
</TABLE>
<F10>9. PENSION BENEFITS
The company participates in a uniform noncontributory-defined benefit retirement
plan covering all regular system employees (the Plan). Benefits are based on
years of service and employees' highest eligible compensation during five
consecutive years of employment. The company's direct-allocated portion of the
system's pension cost, part of which was charged to utility plant, approximated
$1.2 million in 1993, ($504,000) in 1992, and $1.9 million in 1991. The
company's pension costs for 1993 and 1991 included approximately $2.7 million,
and $1.9 million, respectively, related to work force reduction programs.
Currently, the company funds annually an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income Security Act
and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets. Pension assets are invested
primarily in domestic and international equity securities and bonds.
The components of the Plan's net pension cost for the system (excluding PSNH and
North Atlantic Energy Service Corporation in 1992 and 1991) are:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . $ 59,068 $ 27,480 $ 48,738
Interest cost. . . . . . . . . . 81,456 69,746 71,041
Return on plan assets. . . . . . (176,798) (77,232) (198,437)
Net amortization . . . . . . . . 65,447 (16,266) 108,175
-------- --------- --------
Net pension cost . . . . . . . . $ 29,173 $ 3,728 $ 29,517
======== ========= ========
For calculating pension cost, the following assumptions were used:
- ----------------------------------------------------------------------------
For the Years Ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------
Discount rate . . . . . . . . . . 8.00% 8.50% 9.00%
Expected long-term rate
of return . . . . . . . . . . . 8.50 9.00 9.70
Compensation/progression rate . . 5.00 6.75 7.50
<PAGE>19
The following table represents the Plan's funded status reconciled to the NU
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. WMECO's direct cost of the program, which
approximated $3.0 million, included pension, severance, and other benefits.
<F11>10. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The company provides 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 company
who are otherwise eligible to retire and have met specified service
requirements. Through December 31, 1992, the company 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
<PAGE>20
eligible employees render service.
Effective January 1, 1993, the company adopted SFAS 106 on a prospective basis.
Total health care and life insurance cost, part of which were deferred or
charged to utility plant, approximated $5,038,000 in 1993, $2,174,000 in 1992,
and $1,567,000 in 1991.
On January 1, 1993, the accumulated postretirement benefit obligation (APBO)
represented the company's prior-service obligation upon the adoption of SFAS
106. As allowed by SFAS 106, the company is amortizing its APBO of
approximately $36 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.
During 1993, the company did not fund SFAS 106 postretirement costs through
external trusts. The company expects to fund annually amounts once they have
been rate recovered and which also are tax-deductible under the Internal Revenue
Code.
The following table represents the plan's funded status reconciled to the
Balance Sheet at December 31, 1993:
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees. . . . . . . . . . . . . . . . $(27,685)
Fully eligible active employees . . . . (38)
Active employees not eligible
to retire . . . . . . . . . . . . . . . (5,488)
--------
Total accumulated postretirement
benefit obligation . . . . . . . . . . (33,211)
Unrecognized transition amount. . . . . 31,183
Unrecognized net gain . . . . . . . . . (587)
---------
Accrued postretirement benefit
liability. . . . . . . . . . . . . . . $ (2,615)
=========
The components of health care and life insurance costs for the year ended
December 31, 1993 are:
(Thousands of Dollars)
Service cost. . . . . . . . . . . . . . $ 659
Interest cost . . . . . . . . . . . . . 2,676
Net amortization. . . . . . . . . . . . 1,703
--------
Net health care and life insurance
costs. . . . . . . . . . . . . . . . . $ 5,038
=======
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 $2.4
<PAGE>21
million and the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for the year then ended by $227,000.
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 the long-term, high-quality corporate debt securities having a duration
comparable to that of the Plan.
WMECO has received approval from the DPU to defer the incremental SFAS 106
postretirement costs. All deferred costs are expected to be recovered within
ten years.
<F12>11. 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 company currently forecasts construction expenditures (including AFUDC) of
$170.1 million for the years 1994-1998, including $37.5 million for 1994. In
addition, the company estimates that nuclear fuel requirements, including
nuclear fuel financed through the NBFT, will be $72.7 million for the years
1994-1998, including $17.2 million for 1994. See <F3> Note 2, "Leases" for
additional information about the financing of nuclear fuel.
NUCLEAR PERFORMANCE
WMECO has 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.
ENVIRONMENTAL MATTERS
WMECO 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. WMECO 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 environmental 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 WMECO's existing hydro, nuclear, and fossil-fuel
generating units, and transmission and distribution systems, and could raise
operating costs significantly. As a result, WMECO 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
<PAGE>22
and wastes. WMECO may also encounter significantly increased costs to remedy
the environmental effects of prior waste handling and disposal activities.
WMECO has recorded a liability for what it believes is, based upon information
currently available, the estimated environmental remediation costs for waste
disposal sites for which it expects 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 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 WMECO may be determined to
be legally liable by the federal or state environmental agencies. In addition,
WMECO 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 WMECO's financial position or
future results of operations. At December 31, 1993, the liability recorded by
WMECO for its estimated environmental remediation costs, excluding any possible
insurance recoveries from third parties, amounted to $600,000. 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
WMECO's environmental liability range could increase to approximately $1.5
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 WMECO's
ownership interests in Millstone 1, 2, and 3, WMECO's maximum liability would
be $39.8 million per incident. In addition, through WMECO's power purchase
contracts with the four Yankee regional nuclear generating companies, WMECO
would be responsible for up to an additional $17.5 million per incident.
Payments for WMECO's ownership interest in nuclear generating facilities would
be limited to a maximum of $7.2 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 WMECO's ownership interests in
Millstone 1, 2, and 3, and CY, and (2) the cost of repair, replacement, or
decontamination or premature decommissioning of utility property resulting from
insured occurrences with respect to WMECO's ownership interests in Millstone 1,
2, and 3, 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 WMECO with respect to losses
arising during current policy years are approximately $2.3 million under the
replacement power policies and $4.5 million under the property damage,
decontamination, and decommissioning policies.
Although WMECO
<PAGE>23
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 WMECO with respect to losses arising
during the current policy period are approximately $2.3 million.
FINANCING ARRANGEMENTS FOR THE REGIONAL NUCLEAR GENERATING COMPANIES
The company believes that the regional nuclear generating companies may require
additional external financing in the next several years for construction
expenditures, nuclear fuel, and other purposes. Although the ways in which each
regional nuclear generating company will attempt to finance these expenditures
have not been determined, the company expects that it may be asked to provide
direct or indirect financial support for one or more of these companies.
PURCHASED POWER ARRANGEMENTS
WMECO purchases a portion of its electricity requirements pursuant to long-term
contracts with the Yankee companies. Under the terms of its agreements, the
company pays its ownership share (or entitlement share) 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 are recovered through the company's
rates. The total cost of purchases under these contracts for the units that are
operating amounted to $30.2 million in 1993, $29.2 million in 1992, and $27.9
million in 1991. See <F2> Note 1, "Summary Of Significant Accounting Policies
- - Investments and Jointly Owned Electric Utility Plant" and <F4> Note 3,
"Nuclear Decommissioning" for more information on the Yankee companies.
WMECO has entered into two arrangements for the purchase of capacity and energy
from nonutility generators. These arrangements have terms of 15 and 25 years,
and require the company to purchase the energy at specified prices or at formula
rates. 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 the company's purchases under these arrangements amounted to $13.6 million
in 1993, $4.8 million in 1992, and $3.7 million in 1991. These costs are
recovered through the company's rates.
The estimated annual cost of the significant purchase power arrangements is
provided below:
- --------------------------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(Millions of Dollars)
Yankee companies. . . . . . $29.5 $30.1 $33.7 $30.9 $35.0
Nonutility generators . . . 27.4 28.7 29.9 31.5 33.1
HYDRO-QUEBEC
Along with other New England utilities, WMECO, CL&P, PSNH, and HWP entered into
agreements to support transmission and terminal facilities to import electricity
from the Hydro-Quebec system in Canada. The company is obligated to pay, over
a 30-year period, its proportionate share of the annual
<PAGE>24
operation, maintenance, and capital costs of these facilities. WMECO's share of
Hydro-Quebec costs are currently forecast to be $19.9 million for the years
1994-1998, including $4.3 million for 1994.
PROPERTY TAXES
CY has a significant court appeal pending for its property tax assessment in the
town of Haddam, Connecticut, concerning production plant. The central issue is
the fair market value of utility property. The company believes that a properly
derived assessment that recognizes the effect of rate regulation will result in
a fair market value that approximates 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 Haddam
advocate a method that approximates reproduction cost. The company estimates
that, for the Haddam assessment, the change to a reproduction cost-methodology
could result in a property tax valuation approximately three times greater than
a value approximating net book cost. Although CY is currently paying property
taxes based on the higher assessment, to date, the higher assessment has not had
a material adverse effect on it 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 appeal and the
potential impact of an adverse court decision on property tax assessment
policy in Connecticut, the company cannot estimate the potential effect of an
adverse court decision 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
assessment prospectively beginning at the time new rates are established.
<F13>12. 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 amount
approximates fair value.
Preferred stock and long-term debt: The fair value of WMECO's fixed-rate
securities is based upon the quoted market price for those issues or similar
issues. WMECO's adjustable rate preferred stock is assumed to have a fair value
equal to its carrying value.
The carrying amount of WMECO's financial instruments and the estimated fair
values are as follows:
<PAGE>25
- ----------------------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption . . . . . . . . . . . . . $ 73,500 $ 74,000
Preferred stock subject to
mandatory redemption . . . . . . . . . . . . . 27,000 28,215
Long-term debt -
First Mortgage Bonds . . . . . . . . . . . . . 308,219 319,213
Other long-term debt . . . . . . . . . . . . . 85,012 85,012
- ----------------------------------------------------------------------------
Carrying Fair
At December 31, 1992 Amount Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption . . . . . . . . . . . . . $ 73,500 $ 72,600
Preferred stock subject to
mandatory redemption . . . . . . . . . . . . . 28,500 29,355
Long-term debt -
First Mortgage Bonds . . . . . . . . . . . . . 308,635 325,661
Other long-term debt . . . . . . . . . . . . . 84,820 84,820
The fair values shown above have been reported to meet the 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, WMECO will adopt
SFAS 115 on a prospective basis. WMECO anticipates that the adoption of SFAS
115 will not have a material impact on future results of operations or financial
position.
<PAGE>26
WESTERN MASSACHUSETTS ELECTRIC COMPANY
- -----------------------------------------------------------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- -----------------------------------------------------------------------------
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying balance sheets of Western Massachusetts
Electric Company (a Massachusetts corporation and a wholly owned subsidiary
of Northeast Utilities) as of December 31, 1993 and 1992, and the related
statements of income, common stockholder's equity, and cash flows 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 respects, the financial position of Western Massachusetts
Electric Company as of December 31, 1993 and 1992, and the results of its
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 discussed in <F2> Note 1 to the Financial Statements, "Summary of Significant
Accounting Policies - Accounting Changes," effective January 1, 1993, Western
Massachusetts Electric Company changed its methods of accounting for property
taxes, income taxes, and postretirement benefits other than pensions.
/s/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
<PAGE>27
Western Massachusetts Electric Company
- ----------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- ----------------------------------------------------------------------------
This section contains management's assessment of Western Massachusetts Electric
Company's (WMECO or the company) financial condition and the principal factors
having an impact on the results of operations. The company is a wholly owned
subsidiary of Northeast Utilities (NU). This discussion should be read in
conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
The company's net income increased to $40.6 million in 1993 from $37.0 million
in 1992. The 1993 net income includes the impact of a change, in the first
quarter of 1993, in the method of accounting for Connecticut municipal property
taxes. This change resulted in a one-time contribution to net income of $3.9
million. (See the "Notes to Financial Statements" for further information about
this accounting change.)
Net income before the cumulative effect of accounting change was $36.7 million
in 1993. The decrease in net income from 1992 is mainly attributable to a
one-time charge in the third quarter of 1993 for the costs of the company's
employee-reduction program. This one-time charge lowered net income by about
$2 million.
The year 1993 was one of both challenge and success for the company. WMECO's
work force was reduced by about 12 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.
In 1994, the company 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 Massachusetts economy. WMECO expects retail sales
growth of about 1.5 percent in 1994, based on some expected modest improvement
in the economy.
Competition within the electric utility industry is increasing. In response,
the company 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 WMECO's retail service territory or replacing
WMECO'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 WMECO. These disadvantages have aggravated the pressures on
business customers in the current weakened regional economy. Since 1991, the
company has worked actively with the Massachusetts Office of Business
Development 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 revenues of approximately $7
million for the company. The amount of discounts provided to customers is
expected to increase as the company intensifies its efforts to retain existing
customers and gain new customers.
<PAGE>28
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 company has been able to receive for new
wholesale sales have generally been far lower than 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 the company's jurisdiction. In Massachusetts, bills being reviewed
by legislative committees would permit limited retail wheeling in economically
distressed areas and to municipal and state-owned facilities.
NU management has taken steps to make the NU system companies, including WMECO,
more competitive and profitable in the changing utility environment. A
systemwide 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
Massachusetts, Connecticut, and New Hampshire. 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 company 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. The company believes the
steps it is taking will have significant, positive effects in the next few
years. In addition, WMECO benefits from a diverse retail base. The company
has no significant dependence on any one customer or industry. The NU system's
extensive transmission facilities and diversified generating capacity are all
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 the company's wholesale power marketing, customer retention,
and reengineering efforts. These efforts should help increase WMECO's earnings
and improve the company's competitive position.
RATE MATTERS
Deferred charges at December 31, 1993 were approximately $214 million, which
includes $94 million for the adoption in 1993 of Statement of Financial
Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Deferred
charges, excluding the regulatory asset for SFAS No. 109, decreased by
approximately $30 million in 1993, primarily as a result of recoveries for the
deferred costs of Millstone 3 and the Yankee Atomic Electric Company (YAEC)
contract obligation. The company is currently recovering some amounts of its
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
<PAGE>29
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
company has received approval to defer these costs and expects to recover these
costs in the future.
See the "Notes To Financial Statements" for further details on deferred charges
and recently adopted accounting standards.
As a result of a May 1992 Department of Public Utilities (DPU) decision, the
company'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 has incurred approximately $17 million in replacement- power costs
associated with Millstone outages that occurred over the period October 1990
through February 1992 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
Conservation and Load Management (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. The DPU issued a decision
approving the new CC rate effective March 1.
ENVIRONMENTAL MATTERS
The NU system devotes substantial resources to identify and then to meet the
multitude of environmental requirements it faces. The system 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 company is potentially liable for environmental cleanup costs at a number
of sites both inside and outside its service territories. To date, the
future estimated environmental remediation costs for the sites for which the
company expects to bear some liability have not been material with respect to
the earnings or financial position of WMECO. At December 31, 1993, the
liability recorded by WMECO for its estimated environmental remediation
costs, excluding any possible insurance recoveries or recoveries from third
parties, amounted to approximately $600,000. However, while not probable, it
is reasonably possible, these costs could rise as much as $1.5 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 minimal emissions reductions. WMECO's exposure is
minimal because of the company's investment in nuclear energy in the 1970s and
1980s and the burning of low-sulfur fuels. The costs of meeting the Phase II
requirements cannot be estimated at this time because the emission limits have
not been determined.
The company's estimated cost to decommission its share of Millstone Units 1, 2,
and 3, in year-end 1993 dollars is $184 million. In addition, the company's
estimated cost to decommission its share of the regional nuclear generating
<PAGE>30
units is estimated to be approximately $50 million. These costs are being
recovered and recognized over the lives of the respective units. YAEC has begun
decommissioning its nuclear facility. The company's estimated obligation to
YAEC has been recorded on its balance sheets. Management expects that the
company will continue to be allowed to recover these costs.
For further information regarding nuclear decommissioning, environmental
matters, and other contingencies, see the "Notes To 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 in 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 decreased $0.5 million in 1993, compared with the
same period in 1992. Cash used for financing activities was $7.0 million higher
in 1993, compared with the same period in 1992, primarily due to higher
repayment of short-term debt partially offset by a net increase in long-term
debt. Cash used for investments was $7.5 million lower in 1993, compared with
the same period in 1992 due to lower construction expenditures.
The company has been able to shift its financing 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 new
financings only in years with a large amount of securities maturing. The
company is obligated to meet $82.2 million of long-term debt and preferred
stock maturities and cash sinking-fund requirements for the 1994 through 1988
period, including $1.5 million in 1994. No new financings are planned for
1994.
Aggressive refinancing of its outstanding high-cost securities has enabled the
company to lower its cost of debt, thus lowering electric rates. There was no
new money financing in 1993. To take advantage of favorable market
conditions during 1993, the company refinanced $60 million of First Mortgage
Bonds and $53.8 million of pollution control bonds, in addition to
restructuring the company's various credit lines. The company intends, if
market conditions permit, to continue to refinance a portion of their
outstanding long-term debt and preferred stock at a lower effective cost.
<PAGE>31
The company's construction program expenditures, including allowance for funds
used during construction (AFUDC), for the period 1994 through 1998 are estimated
to be approximately $170 million, including $37.5 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 until at least the year 2007.
The company and The Connecticut Light and Power Company utilize a nuclear fuel
trust to finance nuclear fuel requirements for their share of Millstone Units
1, 2, and 3. Nuclear fuel requirements for WMECO's share of Millstone Units 1,
2 and 3 of $72.7 million for the years 1994 through 1998, including $17.2
million for 1994, are expected to be financed by the trust.
RESULTS OF OPERATIONS
The components of the change in operating revenues for the past two years are
provided in the table below.
Change in Operating Revenues
(Increase/Decrease)
- -----------------------------------------------------------------------
1993 vs. 1992 1992 vs. 1991
- -----------------------------------------------------------------------
(Millions of Dollars)
Regulatory decisions $12.0 $22.5
Fuel and purchased power
cost recoveries (18.9) (18.3)
Sales volume 3.7 (3.2)
Other revenues 7.5 (0.1)
----- -----
Total revenue change $ 4.3 $ 0.9
===== =====
OPERATING REVENUES
Operating revenues increased $4.3 million from 1992 to 1993. Revenues related
to regulatory decisions increased primarily because of the effects of the
July 1992 and July 1993 retail rate increases. Fuel and purchased-power cost
recoveries decreased primarily due to lower energy costs. Retail sales in
1993 were flat. Other revenues increased primarily because of higher capacity
interchange revenues.
Operating revenues increased $0.9 million from 1991 to 1992. Revenues related
to regulatory decisions increased primarily because of the effects of the July
1991 and July 1992 retail rate increases. Fuel and purchased power cost
recoveries decreased primarily because of lower energy sales to other utilities.
Retail sales decreased 1.6 percent in 1992 as compared to 1991.
FUEL, PURCHASED, AND NET INTERCHANGE POWER
Fuel, purchased, and net interchange power decreased $18.6 million in 1993, as
compared to 1992, primarily because of lower outside purchases as a result of
better nuclear performance in 1993.
Fuel, purchased, and net interchange power decreased $13.4 million in 1992, as
compared to 1991, primarily because of lower interchange purchases.
<PAGE>32
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses increased $11.2 million in 1993, as
compared to 1992, primarily due to higher capacity interchange charges,
increased conservation expenses, and the 1993 one-time costs associated with the
employee-reduction program, partially offset by lower 1993 costs associated with
the operation and maintenance activities of the nuclear units.
Other operation and maintenance expenses increased $14.3 million in 1992, as
compared to 1991, primarily due to higher 1992 costs of operation and
maintenance activities at nuclear and fossil units, partially offset by the 1991
costs associated with a voluntary early retirement program.
AMORTIZATION OF REGULATORY ASSETS
Amortization of regulatory assets increased $3.4 million in 1993, as compared
to 1992, and $1.4 million in 1992, as compared to 1991, primarily because of
higher amortization of Millstone 3 deferred costs. The increase in 1993 is also
attributable to the gross-up of taxes due to SFAS No. 109.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased $7.8 million in 1993, as compared to
1992, primarily because of higher book taxable income and one-time
adjustments in 1992 causing 1992 taxes to be lower than would otherwise be
expected.<PAGE>33
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
- ----------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------
<CAPTION>
- ----------------------------------------------------------------------------------------------------
1993 1992 1991 1990 1989
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Operating Revenues . . . . . . . $ 415,055 $ 410,720 $ 409,840 $ 375,456 $ 348,720
Operating Income . . . . . . . . 60,067 60,513 59,723 57,448 55,483
Net Income . . . . . . . . . . . 40,594 37,022 34,637 35,191 38,578
Cash Dividends on
Common Stock . . . . . . . . . 28,785 29,536 31,499 34,459 28,974
Total Assets . . . . . . . . . . 1,204,642 1,130,684 1,119,593 1,134,986 1,135,096
Long-Term Debt*. . . . . . . . . 393,232 392,976 401,095 419,527 418,093
Preferred Stock Not Subject to
Mandatory Redemption . . . . . 73,500 73,500 88,500 88,500 88,500
Preferred Stock Subject to
Mandatory Redemption<F14>* . . 27,000 28,500 28,502 30,000 30,000
Obligations Under Capital
Leases<F14>*. . . . . . . . . . 36,902 41,509 44,134 52,370 56,730
<F14>*Includes portions due within one year.
</TABLE>
<TABLE>
- ----------------------------------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- ----------------------------------------------------------------------------------------------------
<CAPTION>
Quarter Ended
-----------------------------------------------------------------
1993 March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues. . . . . . . $108,950 $92,383 $105,510 $108,212
======== ======= ======== ========
Operating Income. . . . . . . . $ 17,659 $13,529 $ 13,045 $ 15,834
======== ======= ======== ========
Net Income. . . . . . . . . . . $ 15,350 $ 7,316 $ 7,182 $ 10,746
======== ======= ======== ========
1992
- ----------------------------------------------------------------------------------------------------
Operating Revenues. . . . . . . $112,897 $95,231 $ 99,524 $103,068
======== ======= ========= =========
Operating Income. . . . . . . . $ 20,965 $ 9,276 $ 11,849 $ 18,423
======== ======= ========= =========
Net Income. . . . . . . . . . . $ 14,427 $ 3,518 $ 6,312 $ 12,765
======== ======= ========= ========
</TABLE>
<PAGE>34
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
<CAPTION>
- ----------------------------------------------------------------------------------------------------
STATISTICS
- ----------------------------------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31,)
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1993 $1,242,927 4,715 7,351 192,542 657
1992 1,214,386 4,155 7,433 191,920 739
1991 1,199,362 3,780 7,494 191,692 797
1990 1,184,285 3,874 7,619 191,759 826
1989 1,147,780 3,975 7,878 190,217 849
</TABLE>
<PAGE>35
Western Massachusetts Electric Company
First Mortgage Bonds
--------------------
Trustee and Interest Paying Agent
The First National Bank of Boston, Corporate Trust Department
P.O. Box 1897, Boston, Massachusetts 02105
Preferred Stock
Transfer Agent, Dividend Disbursing Agent and Registrar
Northeast Utilities Service Company Shareholder Services
P.O. Box 5006, Hartford, CT 06102-5006
1994 Dividend Payment Dates
7.72% Series B -
January 1, April 1, July 1 and October 1
7.60% Series -
February 1, May 1, August 1 and November 1
DARTS*
February 8, March 29, May 17, July 6, August 23,
October 11, and November 29
Address General Correspondence in Care of:
Northeast Utilities Service Company
Investor Relations Department
P.O. Box 270
Hartford, Connecticut 06141-0270
Tel. (203) 665-5000
General Office
174 Brush Hill Avenue, West Springfield, Massachusetts, 01090-0010
_______________________________
*Transfer and Paying Agent:
Bankers Trust Company, Corporate Trust and Agency Group
P.O. Box 318, Church Street Station, New York, New York 10015
The data contained in this Report is submitted for the sole purpose of
providing information to present stockholders about the Company.
<PAGE>
Exhibit 13.4
1993
ANNUAL REPORT
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
<PAGE>
1993 Annual Report
Public Service Company of New Hampshire
Index
Contents Page
Balance Sheets ......................................... 1-2
Statements of Income ................................... 3
Statements of Cash Flows ............................... 4
Statements of Common Equity ............................ 5
Notes to Financial Statements .......................... 6-27
Report of Independent Public Accountants/
Independent Auditors' Report .................... 28-29
Management's Discussion and Analysis of Financial
Condition and Results of Operations ................... 30-35
Selected Financial Data ................................ 37-38
Statistics ............................................. 39
Statements of Quarterly Financial Data ................. 39
Preferred Stockholder and Bondholder Information ....... Back Cover
<PAGE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- -------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric......................................... $1,980,050 $1,887,659
Less: Accumulated provision for depreciation.. 441,076 410,026
----------- -----------
1,538,974 1,477,633
Construction work in progress.................... 8,573 4,363
Nuclear fuel, net................................ 2,107 2,337
----------- -----------
Total net utility plant...................... 1,549,654 1,484,333
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at cost.......... 1,486 1,147
Investments in regional nuclear generating
companies and subsidiary company, at equity..... 19,816 19,917
Other, at cost................................... 429 422
----------- -----------
21,731 21,486
----------- -----------
Current Assets:
Cash and special deposits........................ 5,995 2,328
Receivables, less accumulated provision for
uncollectible accounts of $1,816,000 in 1993
and of $2,780,000 in 1992...................... 76,665 75,094
Receivables from affiliated companies............ 859 2,827
Accrued utility revenues......................... 35,770 32,213
Fuel, materials, and supplies, at average cost... 41,187 45,123
Prepayments and other............................ 10,429 9,261
----------- -----------
170,905 166,846
----------- -----------
Deferred Charges:
Regulatory asset--rate agreement <F1>(Note 1).... 769,498 868,716
Regulatory asset--income taxes, net <F1>(Note 1). 54,250 -
Unrecovered contract obligation--YAEC <F4>(Note 4) 24,150 28,160
Energy adjustment clause <F1>(Note 1)............ 122,478 82,175
Unamortized debt expense......................... 19,643 24,679
Deferred taxes, net.............................. - 66,670
Deferred receivable from affiliated company...... 33,284 32,909
Other............................................ 8,918 17,794
----------- -----------
1,032,221 1,121,103
----------- -----------
Total Assets................................. $2,774,511 $2,793,768
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>1
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock, $1 par value--authorized
and outstanding 1,000 shares in 1993 and 1992....... $ 1 $ 1
Capital surplus, paid in............................. 421,245 420,762
Retained earnings.................................... 60,840 21,853
----------- -----------
Total common equity......................... 482,086 442,616
Cumulative preferred stock subject to mandatory
redemption--$25 par value--authorized 25,000,000 shares;
outstanding 5,000,000 shares in 1993 and 1992.. 125,000 125,000
Long-term debt....................................... 999,985 1,093,985
----------- -----------
Total capitalization........................ 1,607,071 1,661,601
----------- -----------
Obligations Under Seabrook Power Contract
and Other Capital Leases <F2>(Note 2)............... 815,553 752,866
----------- -----------
Current Liabilities:
Notes payable to banks............................... - 35,000
Notes payable to affiliated company.................. 2,500 8,500
Long-term debt--current portion...................... 94,000 94,000
Obligations under Seabrook Power Contract and
other capital leases--current portion <F2>(Note 2).. 41,006 34,960
Accounts payable..................................... 27,119 28,406
Accounts payable to affiliated companies............. 17,576 19,183
Accrued taxes........................................ 122 1,725
Accrued interest..................................... 11,142 11,281
Accrued pension benefits............................. 31,890 30,683
Other................................................ 22,014 23,727
----------- -----------
247,369 287,465
----------- -----------
Deferred Credits:
Accumulated deferred income taxes <F1>(Note 1)....... 18,076 -
Accumulated deferred investment tax credits.......... 6,174 6,740
Deferred contract obligation--YAEC <F4>(Note 4)...... 24,150 28,160
Deferred revenue from affiliated company <F11>(Note 11) 33,284 32,909
Other................................................ 22,834 24,027
----------- -----------
104,518 91,836
----------- -----------
Commitments and Contingencies <F11>(Note 11)
Total Capitalization and Liabilities........ $ 2,774,511 $ 2,793,768
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>2
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Jan. 1, June 5, Jan. 1, May 16, Jan. 1,
1993 1992 1992 1991 1991
to to to to to
Dec. 31, Dec. 31, June 4, Dec. 31, May 15,
For the Periods 1993 1992 1992 1991 1991
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
| |
<S> <C> <C> | <C> <C> | <C>
Operating Revenues.................... $864,415 $492,559 |$381,769 $539,827 |$ 246,281
--------- ---------|--------- ---------|----------
Operating Expenses: | |
Operation-- | |
Fuel, purchased and net | |
interchange power................ 208,023 105,346 | 123,784 139,166 | 95,261
Other............................. 301,534 176,679 | 103,250 119,296 | 80,231
Maintenance......................... 35,427 20,535 | 22,520 42,335 | 19,936
Depreciation........................ 38,580 21,526 | 25,183 36,590 | 28,269
Amortization of regulatory | |
assets, net........................ 67,379 51,143 | 36,528 53,554 | -
Federal and state income | |
taxes <F8>(Note 8)................. 73,263 39,197 | 16,449 38,316 | (12,769)
Taxes other than income taxes....... 34,675 16,927 | 19,805 27,815 | 13,737
--------- ---------|--------- ---------|----------
Total operating expenses........ 758,881 431,353 | 347,519 457,072 | 224,665
--------- ---------|--------- ---------|----------
Operating Income...................... 105,534 61,206 | 34,250 82,755 | 21,616
--------- ---------|--------- ---------|----------
Other Income: | |
Deferred Seabrook return--other | |
funds.............................. - - | 12,101 15,578 | -
Equity in earnings of regional | |
nuclear generating companies | |
and subsidiary company............. 1,371 1,031 | 869 1,426 | 681
Bankruptcy related expenses......... - - | (5,084) (2,574)| (9,314)
Gain on generating projects......... - - | 6,498 - | 12,446
Other, net.......................... 1,041 2,519 | 63 8,706 | 3,359
Income taxes - credit............... 23,044 14,254 | 12,814 20,665 | (12,495)
--------- ---------|--------- ---------|----------
Other income, net............... 25,456 17,804 | 27,261 43,801 | (5,323)
--------- ---------|--------- ---------|----------
Income before interest charges.. 130,990 79,010 | 61,511 126,556 | 16,293
--------- ---------|--------- ---------|----------
Interest Charges: | |
Interest on long-term debt.......... 77,842 47,625 | 54,125 87,620 | 32,423
Post-petition interest.............. - - | - - | 42,101
Other interest...................... 911 1,987 | 3,913 130 | 3,238
Deferred Seabrook return--borrowed | |
funds, net of income taxes........ - - | (9,305) (13,888)| -
--------- ---------|--------- ---------|----------
Interest charges, net........... 78,753 49,612 | 48,733 73,862 | 77,762
--------- ---------|--------- ---------|----------
Income (Loss) before extraordinary | |
loss................................ 52,237 29,398 | 12,778 52,694 | (61,469)
Extraordinary loss from | |
reorganization...................... - - | - - | (39,322)
--------- ---------|--------- ---------|----------
Net Income (Loss)..................... $ 52,237 $ 29,398 |$ 12,778 $ 52,694 |$(100,791)
========= =========|========= =========|==========
</TABLE>
PSNH was reorganized on May 16, 1991 and became a wholly owned subsidiary of
Northeast Utilities on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
<PAGE>3
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Jan. 1, June 5, Jan. 1, May 16, Jan. 1,
1993 1992 1992 1991 1991
to to to to to
Dec. 31, Dec. 31, June 4, Dec. 31, May 15,
For the Periods 1993 1992 1992 1991 1991
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Cash Flows From Operations:
Net income (loss)..........................$ 52,237 $ 29,398 |$ 12,778 $ 52,694 |$ (100,791)
Adjusted for the following: | |
Depreciation.............................. 38,665 21,561 | 25,183 36,590 | 28,269
Deferred income taxes and investment | |
tax credits, net........................ 50,027 22,543 | 3,141 17,591 | (294)
Deferred return - Seabrook................ - - | (21,406) (29,466)| -
Deferred energy costs, net of amortization (39,660) (42,520)| 1,469 (38,909)| -
Amortization of regulatory asset<F1>(Note 1)89,822 51,836 | 36,528 53,554 | -
Other sources of cash..................... 15,394 12,088 | 15,967 3,899 | 2,362
Other uses of cash........................ (12,042) (4,825)| (4,355) (47,117)| (11,364)
Changes in working capital: | |
Receivables and accrued utility revenues. (3,161) (18,314)| 34,432 44,976 | 7,962
Fuel, materials, and supplies.......... 3,936 459 | (4,945) (23,187)| 4,482
Accounts payable....................... (2,894) 5,083 | (8,189) (23,769)| 39,299
Accrued taxes.......................... (1,602) (17,323)| 20,409 (22,693)| 25,232
Other working capital (excludes cash).. (2,224) 12,610 | (26,056) (55,114)| 27,761
--------- --------|--------- --------|-----------
Net cash flows from (used for) operations... 188,498 72,596 | 84,956 (30,951)| 22,918
--------- --------|--------- --------|-----------
Cash Flows From Financing Activities: | |
Common shares.............................. - 425,000 | - 846 | -
Long-term debt............................. 44,800 75,000 | - - | 1,331,785
Preferred stock............................ - - | - - | 125,000
Financing expenses......................... (267) - | (45) (7,734)| (21,132)
Net increase(decrease) in short-term debt.. (41,000) (64,500)| - 87,200 | (292)
Reacquisitions and retirements of | |
long-term debt...........................(138,800)(171,000)| (27,000) - | -
Cash dividends on preferred | |
stock<F6>(Note 6)........................ (13,250) (9,938)| (3,312) (8,282)| -
Acquisition settlement <F1>(Note 1)........ - (841,466)| - - | -
Settlement of bankruptcy claims............ - - | - (14,412)|(1,505,373)
--------- --------|--------- --------|-----------
Net cash flows from (used for) | |
financing activities.................(148,517)(586,904)| (30,357) 57,618 | (70,012)
-------- ---------|--------- --------|-----------
Investment Activities: | |
Investments in plant: | |
Electric utility plant................... (35,360) (15,352)| (25,266) (22,683)| (19,852)
Nuclear fuel............................. (614) (552)| (9,990) (3,125)| 3,386
-------- --------|--------- --------|-----------
Net cash flows used for investments in plant (35,974) (15,904)| (35,256) (25,808)| (16,466)
Sale of Seabrook assets to NAEC............ - 504,265 | - - | -
Other investment activities, net .......... (340) (180)| - 30 | (3)
--------- --------|--------- --------|-----------
Net cash flows from (used for) investments.. (36,314) 488,181 | (35,256) (25,778)| (16,469)
--------- --------|--------- --------|-----------
Net Incr.\(Decr.) In Cash for the Period.... 3,667 (26,127)| 19,343 889 | (63,563)
Cash and special deposits - | |
beginning of period..................... 2,328 28,455 | 9,112 8,223 | 71,786
--------- --------|--------- --------|-----------
Cash and special deposits - end of period...$ 5,995 $ 2,328 |$ 28,455 $ 9,112 |$ 8,223
========= ========|========= ========|===========
Supplemental Cash Flow Information: | |
Cash paid during the periods for: | |
Interest, net of amounts capitalized | |
during construction......................$ 75,609 $ 35,405 |$ 53,427 $ 71,909 |$ 349,663
========= ========|========= ========|===========
Income taxes..............................$ 2,390 $ 410 |$ 909 $ 60 |$ 20
========= ========|========= ========|===========
Increase in obligations: | |
Seabrook Power Contract...................$ 84,796 $ 37,490 |$ - $ - |$ -
======== =========|========= ========|===========
Capital leases............................$ 4,696 $ - |$ - $ - |$ -
========= ========|========= ========|===========
PSNH was reorganized on May 16, 1991 and became a wholly owned subsidiary of Northeast Utilities
on June 5, 1992.
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>4
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF COMMON EQUITY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Capital
Common Surplus, Retained
Stock Paid In Earnings Total
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1991.............. $210,773 $435,420 $(742,207) $ (96,014)
Net loss............................ (61,469) (61,469)
--------- --------- ---------- ----------
Balance at May 15, 1991................. $210,773 $435,420 $(803,676) $(157,483)
========= ========= ========== ==========
_________________________________________________________________________________________
Balance at May 16, 1991................. $ 31,982 $607,366 $ - $ 639,348
Net income.......................... 52,694 52,694
Cash dividends on preferred stock... (8,282) (8,282)
Stock dividends on common stock..... 5,470 38,310 (43,780) -
Issuance of 42,313 shares of
common stock, $1 par value........ 42 622 664
--------- --------- ---------- ----------
Balance at December 31, 1991............ 37,494 646,298 632 684,424
Net income.......................... 12,778 12,778
Cash dividends on preferred stock... (5,704) (5,704)
Stock dividends on common stock..... 1,962 16,456 (18,418) -
Capital stock expenses, net......... (2) (2)
--------- --------- ---------- ----------
Balance at June 4, 1992................. $ 39,456 $662,752 $ (10,712) $ 691,496
========= ========= ========== ==========
_________________________________________________________________ ________________________
Balance at June 5, 1992................. $ - $ - $ - $ -
Net income.......................... 29,398 29,398
Cash dividends on preferred stock... (7,545) (7,545)
Issuance of 1,000 shares of common
stock, $1 par value............... 1 1
Premium on common stock............. 424,999 424,999
Capital stock expenses, net......... (4,237) (4,237)
--------- --------- ---------- ----------
Balance at December 31, 1992............ 1 420,762 21,853 442,616
Net income.......................... 52,237 52,237
Cash dividends on preferred stock... (13,250) (13,250)
Capital stock expenses, net......... 483 483
--------- --------- ---------- ----------
Balance at December 31, 1993............ $ 1 $421,245 $ 60,840 $ 482,086
========= ========= ========== ==========
PSNH was reorganized on May 16, 1991 and became a wholly owned subsidiary of Northeast Utilities
on June 5, 1992.
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>5
NOTES TO FINANCIAL STATEMENTS
<F1>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
EMERGENCE FROM BANKRUPTCY AND MERGER WITH NORTHEAST UTILITIES
On January 28, 1988, Public Service Company of New Hampshire (PSNH or
the company) filed a petition for reorganization under Chapter 11 of
the Bankruptcy Code.
On January 2, 1990, Northeast Utilities Service Company (NUSCO) filed
a plan of reorganization (the Plan) on behalf of Northeast Utilities
(NU), the Creditors Committee, the Equity Committee, and various PSNH
bondholders, with the support of the state of New Hampshire. On
April 20, 1990, following a vote by all classes of creditors and equity
security holders of PSNH and hearings in the Bankruptcy Court,the Plan was
confirmed by the Bankruptcy Court. From April 30, 1990 until the June 5,
1992 acquisition date, NUSCO managed PSNH in accordance with a management
services agreement approved by the Bankruptcy Court.
On May 16, 1991 (Reorganization Date) the company emerged from
bankruptcy pursuant to the Plan as a stand-alone company, subject to
a merger agreement (Merger Agreement) with NUSCO and NU Acquisition
Corp. (NUAC). On the Reorganization Date, the company's then existing
security holders and creditors were entitled to receive distributions of cash
and new PSNH securities.
Under the Plan, a distribution totaling approximately $2.3 billion in
cash and securities was made as of May 16, 1991 to former creditors
and equity security holders of the company. Former holders of secured claims
received cash in the full amount of their claims for principal and unpaid
interest. Former holders of unsecured claims received a distribution in the
amount of their claims for principal plus pre-petition interest, less any
applicable original issue discount unamortized at the petition date, and a
total of $110.6 million of post-petition interest. Approximately $593
million of such distribution was made in cash and the balance in shares of
new common stock. Former holders of shares of preferred and common stock of
the company received $205 million principal amount of 15.23 percent Notes,
shares of new common stock and certificates entitling the holder to receive
warrants to purchase NU common shares. Former holders of the company's
outstanding warrants received a total of $1.3 million in cash.
The company accounted for the reorganization using fresh start accounting.
Accordingly, all assets and liabilities were restated to their reorganization
value, which approximated fair value at the Reorganization Date.
On June 5, 1992 (Acquisition Date), NU completed its acquisition of PSNH when
NUAC was merged into PSNH pursuant to the Merger Agreement and the company
became a wholly owned operating subsidiary of NU. In a related transaction,
PSNH's 35.6 percent share of the Seabrook 1 nuclear power plant (Seabrook 1)
and other Seabrook-related assets were transferred to North Atlantic Energy
Corporation (NAEC), another new NU subsidiary, for approximately $504 million
in cash and the assumption of the company's obligations under the $205
million, 15.23 percent Notes.
The total cash required to effect the acquisition of PSNH was approximately
$941 million. The sources of the $941 million were a $425 million equity
investment by NU into PSNH, a $161 million equity investment by NU into NAEC,
and NAEC's issuance and sale of $355 million principal amount of First
Mortgage Bonds. The proceeds were used (a) to make a distribution of $20 per
share, or approximately $789 million in the aggregate, to the holders of the
approximately 39.5 million outstanding shares of the company's new common
stock, (b) to reimburse $45 million of NU acquisition expenses under the
Plan,
<PAGE>6
(c) to provide $49 million to reduce PSNH's Term Loan, (d) to provide
$7 million to meet the tax on the transfer of Seabrook to NAEC, and (e) to
reduce PSNH's short-term borrowings with the balance of funds. The Plan also
called upon NU to issue to former PSNH equity security holders warrants
entitling the holders to purchase approximately 8.4 million NU common shares
at an exercise price of $24 per share. The warrants expire on June 5, 1997.
In accordance with generally accepted accounting principles, the acquisition
of PSNH has been accounted for as a purchase.
On June 29, 1992, PSNH's New Hampshire Yankee Division (NHY) was dissolved
and North Atlantic Energy Service Corporation (NAESCO), a wholly owned
subsidiary of NU, with the approval of the Securities and Exchange Commission
(SEC) and the Nuclear Regulatory Commission (NRC), began management of the
Seabrook 1 power plant as agent for the Seabrook joint owners. On June 29,
1992, all NHY employees became employees of NAESCO.
GENERAL
PSNH, The Connecticut Light and Power Company, Western Massachusetts Electric
Company, NAEC, and Holyoke Water Power Company are the operating subsidiaries
comprising the Northeast Utilities system (the system)and are wholly owned by
NU.
Other wholly owned subsidiaries of NU provide substantial support services to
the system. NUSCO supplies centralized accounting, administrative, data
processing, engineering, financial, legal, operational, planning, purchasing,
and other services to the system companies. Northeast Nuclear Energy Company
acts as agent for system companies in constructing and operating the
Millstone nuclear generating facilities.
All transactions among affiliated companies are on a recovery of cost basis
which may include amounts representing a return on equity, and are subject to
approval by various federal and state regulatory agencies.
ACCOUNTING CHANGES
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 information on this change, see <F1>Note 1,
"Summary of Significant Accounting Policies - Income Taxes."
Postretirement Benefits Other Than Pensions: PSNH 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 <F10>Note 10,
"Postretirement Benefits Other Than Pensions."
ACCOUNTING RECLASSIFICATIONS
For periods prior to December 31, 1993, certain amounts in the accompanying
financial statements of PSNH have been reclassified to conform with the
December 31, 1993 presentations.
PUBLIC UTILITY REGULATION
NU is registered with the SEC as a holding company under the Public Utility
Holding Company Act of 1935 (1935 Act), and it and its
subsidiaries, including PSNH, are subject to the provisions of the 1935 Act.
Arrangements among the system companies, outside agencies, and other
utilities covering
<PAGE>7
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 company is subject to further
regulation for rates and other matters by the FERC and the New Hampshire
Public Utilities Commission (NHPUC), and follows the accounting policies
prescribed by the 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, PSNH accrues an estimate for the amount of
energy delivered but unbilled.
For additional information see <F11> Note 11, "Commitments and Contingencies
- - PSNH Rate Agreement."
INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: PSNH owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with PSNH's ownership interests, are:
Connecticut Yankee Atomic Power Company (CY)....... 5.0%
Yankee Atomic Electric Company (YAEC) ............. 7.0
Maine Yankee Atomic Power Company (MY) ............ 5.0
Vermont Yankee Nuclear Power Corporation (VY) ..... 4.0
PSNH'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 <F11>Note 11, "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 <F4>
Note 4, "Nuclear Decommissioning."
Millstone 3: The company has a 2.85 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 $118.1 million and $21.1 million, respectively, for PSNH's
proportionate share of Millstone 3. PSNH's share of Millstone 3 expenses is
included in the corresponding operating expenses on the accompanying
Statements of Income.
Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman Unit 4
(Wyman), a 620 MW oil-fired generating unit. At December 31, 1993,
plant-in-service and the accumulated provision for depreciation included
approximately $6.0 million and $3.1 million, respectively, for PSNH's share
of Wyman. PSNH's share of Wyman expenses are included in the corresponding
operating expenses on the accompanying Statements of Income.
<PAGE>8
REGULATORY ASSET
The regulatory asset represents the aggregate value placed by the rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets
in excess of the net book value of PSNH's non-Seabrook assets and the $700
million value assigned to Seabrook by the Rate Agreement. The regulatory
asset 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 with a return each year on the
unamortized portion of the asset. The Rate Agreement provides that $425
million of the regulatory asset be amortized over the first seven years after
the 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 by approximately $9.4 million. In accordance with the Rate
Agreement, approximately $265 million of the remaining regulatory asset is
scheduled to be amortized and recovered through rates by 1998, and the
balance of approximately $504 million is scheduled to be amortized and
recovered through rates by 2011.
DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the NHPUC.
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 Millstone 3, the costs of
removal, less salvage, that have been funded through an external
decommissioning trust will be paid with funds from the trust and charged to
the accumulated reserve for decommissioning included in the accumulated
provision for depreciation over the expected service life of the plant. See
<F4> Note 4, "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 for the year ended December
31, 1993, 3.5 percent for the six-month and twenty-six day period ending
December 31, 1992, 3.4 percent for the five-month and four-day period ending
June 4, 1992, 3.4 percent for the seven and one-half months ended December
31, 1991, and 3.1 percent for the four and one-half months ended May 15,
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 <F8> Note 8, "Income Tax Expense," 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. PSNH
adopted SFAS 109, on a prospective basis, during the first quarter of 1993.
The adoption of SFAS 109 has not had a material effect on the net income or
on the balance sheet of the company. As a result of the adoption of SFAS
109, the company has increased the deferred tax asset for
net-operating-losses (NOLs) previously not recognized. A valuation reserve
was not established. As it is probable that the increase in deferred tax
liabilities will be recovered from customers through rates, PSNH also
established a regulatory asset. SFAS 109 does not permit net-of-tax
accounting.
<PAGE>9
The temporary differences which give rise to the accumuated deferred tax
obligation at December 31, 1993, are as follows:
(Thousands of Dollars)
Net operating loss carryforwards ........... $(270,612)
Accelerated depreciation and
other plant-related differences .......... 150,238
The tax effect of net regulatory assets .... 80,922
Other....................................... 57,528
---------
$ 18,076
=========
At December 31, 1993, PSNH had a 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 remaining 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 CLAUSE
The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail
customers, for a ten-year period, the retail portion of differences between
the fuel and purchased power costs assumed in the Rate Agreement and PSNH's
actual costs, which include the costs under the Seabrook Power Contract. The
cost components of the FPPAC are subject to a prudence review by the NHPUC.
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, unrecovered SPP
deferrals are $107.6 million. A majority of these purchases are under
long-term arrangements (20-30 years) at prices significantly higher than the
company's current or projected avoided costs.
For additional information, see <F2> Note 2, "Seabrook Power Contract" and
Note 11, "Commitments and Contingencies - Purchased Power Arrangements."
<F2>
2. SEABROOK POWER CONTRACT
On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract
(Contract), under which PSNH is obligated to buy from NAEC, and NAEC is
obligated to sell to PSNH, all of NAEC's 35.6 percent ownership share of the
capacity and output of Seabrook 1 for a period equal to the length of the
NRC's full power operating license for Seabrook 1. Accordingly, PSNH has
included its right to buy power from NAEC on its Balance Sheets as part of
utility plant with a corresponding obligation. At December 31, 1993, this
right was valued at approximately $852.2 million. Under the Contract, PSNH
is unconditionally
<PAGE>10
obligated to pay NAEC's cost of service during this period whether or not
Seabrook 1 is operating. NAEC's cost of service includes all of its
Seabrook-related costs, including operation and maintenance expense,
fuel expense, property tax expense, depreciation expense, and certain
overhead and other costs.
The Contract establishes the value of the initial investment in Seabrook
(Initial Investment) at $700 million and the initial investment in nuclear
fuel at $0. NAEC is depreciating its Initial Investment on a straight line
basis over the remaining term of Seabrook's full power operating license.
Any subsequent additions to Seabrook 1 will be depreciated on a straight-line
basis over the remaining term of the Contract at the time the additions are
brought into service. The Contract provides that NAEC's return on its
allowed investment in Seabrook 1 (its investment in working capital, fuel,
capital additions after the date of commercial operation of Seabrook 1 and a
portion of the Initial Investment) is calculated based on NAEC's actual
capitalization from time to time over the term of the Contract, which
includes its actual debt and preferred equity costs, and a common equity cost
of 12.53 percent for the first ten years of the Contract, and thereafter at
an equity rate of return to be fixed in a filing with FERC. The portion of
the Initial Investment which is included in the allowed investment was 40
percent at the Acquisition Date and will increase by 15 percent in each of
the following four years beginning May 15, 1993. 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 of deferred return balance to
NAEC along with the other Seabrook assets. NAEC has 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. The
deferred return on the excluded portion of the Initial Investment, including
the $50.9 million, will be recovered with carrying charges by NAEC through
the Contract beginning six months after the end of PSNH's Fixed Rate Period
and will be fully recovered by May 15, 2001.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license term, PSNH will be unconditionally required to pay NAEC termination
costs for 39 years, less the period during which Seabrook 1 has operated.
These costs are designed to reimburse NAEC for its share of Seabrook 1
shut-down and decommissioning costs and to pay NAEC a return of and on any
undepreciated balance of its Initial Investment in the plant over the
then-remaining term of the Contract, and the return of and on any capital
additions to the plant made after the Acquisition Date over a period of five
years after shut down (net of any tax benefits to NAEC attributable to such
cancellation).
Contract payments charged to operating expense were $123 million, including
$33 million return on investment, for the year ended December 31, 1993.
On February 15, 1994, NAEC acquired Vermont Electric Generation and
Transmission Cooperative Inc.'s (VEG&T) 0.4 percent ownership interest of
Seabrook for approximately $6.4 million. NAEC will sell the output from the
Seabrook interest purchased from VEG&T on February 15, 1994 to PSNH under an
agreement that has been approved by the FERC and is substantially similar to
the Seabrook Power Contract between PSNH and NAEC that was effective on the
Acquisition Date.
<PAGE>11
Future minimum payments, excluding executory costs, such as property taxes,
state use taxes,insurance, and maintenance, under the terms of the Contract,
as of December 31, 1993, are approximately:
Seabrook Power Contract
-----------------------
(Thousands of Dollars)
1994 . . . . . . . . . . . . . . . $ 63,200
1995 . . . . . . . . . . . . . . . 72,300
1996 . . . . . . . . . . . . . . . 81,200
1997 . . . . . . . . . . . . . . . 91,100
1998 . . . . . . . . . . . . . . . 169,700
After 1998 . . . . . . . . . . . . 1,509,700
----------
Future minimum payments. . . . . . 1,987,200
Less amount representing interest and
return on equity . . . . . . . . 1,135,000
----------
Present value of Seabrook Power
Contract
payments . . . . . . . . . . . . . $ 852,200
==========
<F3>
3. LEASES
PSNH has entered into lease agreements, for the use of substation equipment,
data processing and office equipment, vehicles, and office space. The
provisions of these lease agreements generally provide for renewal options.
Operating lease rental payments charged to operating expense were $6,197,000
in 1993, $8,511,000 in 1992, and $6,875,000 in 1991.
Future minimum rental payments, excluding executory costs, such as property
taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, as of December 31, 1993, are approximately:
Operating Leases
----------------
(Thousands of Dollars)
1994 . . . . . . . . . . . . . . . . . . $ 7,700
1995 . . . . . . . . . . . . . . . . . . 7,100
1996 . . . . . . . . . . . . . . . . . . 6,100
1997 . . . . . . . . . . . . . . . . . . 5,200
1998 . . . . . . . . . . . . . . . . . . 4,100
After 1998 . . . . . . . . . . . . . . . 6,000
-------
Future minimum payments. . . . . . . . . $36,200
=======
<F4>
4. NUCLEAR DECOMMISSIONING
A 1992 decommissioning study concluded that complete and immediate
dismantlement at retirement continues to be the most viable and economic
method of decommissioning Millstone 3. 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.
<PAGE>12
Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, technology, and inflation.
The estimated cost of decommissioning PSNH's ownership share of Millstone 3
and NAEC's 36.0 percent share of Seabrook 1, in year-end 1993 dollars, is
$12.0 million and $131.7 million, respectively. PSNH's Millstone 3
decommissioning costs are accrued over the expected service life of the unit
and are included in depreciation expense on its Statements of Income.
Nuclear decommissioning related to PSNH's share of Millstone 3 amounted to
$0.3 million in 1993 and $0.2 million in 1992. Nuclear decommissioning
costs, as a cost of removal, are included in the accumulated provision for
depreciation on PSNH's Balance Sheets.
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. Accordingly, NAEC bills PSNH directly for its
share of the costs of decommissioning Seabrook. PSNH records its Seabrook
decommissioning costs as a component of purchased power expense on its
Statement of Income. Under the Rate Agreement, PSNH's Seabrook
decommissioning costs are recovered through base rates.
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 the external decommissioning
trust. 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 company's
accumulated reserve for decommissioning amounted to $1.5 million.
As of December 31, 1993, NAEC (including pre-Acquisition Date payments made
by PSNH) has paid approximately $7.3 million, into Seabrook 1's
decommissioning financing fund.
Changes in requirements or technology, or adoption of a decommissioning
method other than immediate dismantlement, could change decommissioning cost
estimates. PSNH attempts to recover sufficient amounts through its allowed
rates to cover its expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
regulatory agencies is reflected in rates of PSNH. 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.
PSNH, along with other New England utilities, has 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 decommissioning
PSNH's ownership share of CY and MY are $17.0 million and $16.2 million,
respectively. The cost to decommission VY is currently being re-estimated.
The cost of decommissioning PSNH's ownership share of VY is projected to
range from $12 million to $14 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 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 PSNH.
<PAGE>13
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 NRC 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 PSNH's share was
approximately $24.1 million. Management expects that PSNH will continue
to be allowed to recover such FERC-approved costs from its customers.
Accordingly, PSNH has recognized these costs as a regulatory asset, with a
corresponding obligation, on its Balance Sheets. PSNH has a 7.0 percent
equity investment, approximating $1.7 million, in YAEC. PSNH had relied on
YAEC for less than one percent of its capacity.
<F5>
5. SHORT-TERM DEBT
The system companies have various credit lines totaling $485 million. 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. The company intends to negotiate a two
year extension of the $125 million revolving credit agreement, which is
scheduled to mature on May 14, 1994.
Certain subsidiaries of NU, including PSNH, are members of the Northeast
Utilities System Money Pool (Pool). The Pool provides a more efficient use
of the cash resources of the system, and reduces outside short-term
borrowings. NUSCO administers the Pool as agent for the member companies.
Short-term borrowing needs of the member companies are first met with
available funds of other member companies, including funds borrowed by NU
parent. NU parent may lend to the Pool but may not borrow. Investing and
borrowing subsidiaries receive or pay interest based on the average daily
Federal Funds rate. Funds may be withdrawn from or repaid to the Pool at any
time without prior notice. However, borrowings based on loans from NU parent
bear interest at NU parent's cost and must be repaid based upon the terms of
NU parent's original borrowing.
Maturities of PSNH's short-term debt obligations were for periods of three
months or less.
The amount of short-term borrowings that may be incurred by PSNH is subject
to periodic approval by the SEC under the 1935 Act. Under the SEC
restrictions, PSNH was authorized, as of January 1, 1993, to incur short-term
borrowings up to a maximum of $125 million.
<PAGE>14
<F6>
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1993 Outstanding
Redemption December 31, December 31,
Description Price 1993 1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
10.60% Series A
of 1991. . . . . $25.00 5,000,000 $125,000 $125,000
======== ========
In case of default on dividends or 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 PSNH is in arrears in the
payment of dividends on any outstanding shares of preferred stock, PSNH would
be prohibited from redemption or purchase of less than all of the preferred
stock outstanding. The Series A Preferred Stock is not subject to optional
redemption by PSNH. It is subject to a sinking fund beginning on June 30, 1997,
sufficient to retire annually 1,000,000 shares at $25 per share.
<F7>
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
- -----------------------------------------------------------------------------
December 31,
-------------------------
1993 1992
- -----------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
8 7/8% Series A due 1996. . . . . . . . . $172,500 $ 172,500
9.17% Series B due 1998. . . . . . . . . 170,000 170,000
-------- ----------
Total First Mortgage Bonds. . . . . . . . . . . 342,500 342,500
Term Loan/Notes:
Variable Rate due 1996. . . . . . . . . . . . . 235,000 329,000
Pollution Control Revenue Bonds:
7.65% Series A due 2021. . . . . . . . . 66,000 66,000
7.50% Series B due 2021. . . . . . . . . 108,985 108,985
7.65% Series C due 2021. . . . . . . . . 112,500 112,500
Adjustable Rate Series D due 2021 . . . . . . . 39,500 39,500
Adjustable Rate Series E due 2021 . . . . . . . 69,700 114,500
Adjustable Rate, Tax-Exempt, Series D due 2021. 75,000 75,000
Adjustable Rate,Tax-Exempt, Series E due 2021 . 44,800 -
Less: Amounts due within one year. . . . . . . 94,000 94,000
-------- ----------
Long-term debt, net . . . . . . . . . . . . . . $999,985 $1,093,985
======== ==========
<PAGE>15
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1993 for the years 1994 through 1998 are
approximately $94,000,000 in 1994 and 1995, $219,500,000 in 1996, $0 in 1997,
and $170,000,000 in 1998. Also, there are annual renewal and replacement
fund requirements equal to 2.25 percent of the average of net depreciable
property owned by PSNH at the Reorganization Date, plus cumulative gross
property additions thereafter. PSNH expects to meet its future fund
requirements by certifying property additions. Any deficiency would need to
be satisfied the deposit of cash or bonds.
Essentially, all utility plant of PSNH is subject to the liens of its first
mortgage bond indenture. PSNH's two bank facilities, the Term Loan and
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 million. At December 31, 1993, there were no borrowings
under the Revolving Credit Facility.
The Series A and B First Mortgage Bonds are not redeemable prior to their
maturity except in limited circumstances. The Pollution Control Revenue
Bonds, except for Series D and E, are redeemable on or after May 1, 2001, at
the option of the company with accrued interest and at specified premiums.
Under current interest rate elections by PSNH, the Series D and E Pollution
Control Revenue Bonds are redeemable, at par plus accrued interest at the end
of each interest rate period. Future interest rate elections by PSNH could
significantly defer or eliminate the availability of optional redemptions by
PSNH and could affect costs as well.
PSNH has entered into interest rate cap agreements to reduce the potential
impact of upward changes in interest rates on certain variable rate tax
exempt pollution control revenue bonds and on a portion of its variable rate
Term Loan. At December 31, 1993, $50 million and $100 million of PSNH's
$235 million Term Loan was capped at 4.5 percent and 5 percent, respectively.
$75 million of its taxable Pollution Control Revenue Bonds was capped at 4.5
percent. The total cost of interest rate caps for 1993 was approximately
$836,000, 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
$158,000.
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, $516.5
million of the PCRBs were outstanding. PSNH's obligation to repay each
series of PCRBs is secured by a series of First Mortgage Bonds that were
issued under its indenture. Each such series of First Mortgage Bonds
contains terms and provisions with respect to maturity, principal payment,
interest rate and redemption that correspond to those of the applicable
series of PCRBs; for financial reporting purposes, these bonds would not be
considered outstanding unless PSNH fails to meet its obligation under the
PCRBs.
<PAGE>16
<F8>
8. INCOME TAX EXPENSE
The components of federal and state income tax provisions are:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 May 16, 1991 Jan. 1, 1991
to to to to to
For the Periods Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991 May 15, 1991
- --------------------------------------------------------------------------------------------------
<F1>(Note 1) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Current income taxes:
Federal . . . . . . . . . $ (937) $ 2,400 $ 415 $ - $ -
State . . . . . . . . . . 1,183 - 79 60 20
-------- -------- --------- -------- ---------
Total current. . . . . 246 2,400 494 60 20
-------- -------- --------- -------- ---------
Deferred income taxes, net:
Federal . . . . . . . . . 47,407 23,086 8,703 25,342 111
State . . . . . . . . . . 3,131 - - - -
-------- -------- --------- -------- ---------
Total deferred . . . . 50,538 23,086 8,703 25,342 111
-------- -------- --------- -------- ---------
Investment tax credits, net (565) (326) (341) (498) (294)
-------- -------- --------- -------- ---------
Total income tax expense $50,219 $25,160 $ 8,856 $24,904 $ (163)
======== ======== ========= ======== =========
The components of total income tax expense are classified as follows:
Income taxes charged to
operating expenses . . $73,263 $39,197 $16,449 $38,316 $(12,769)
Income taxes associated
with the deferred return
on Seabrook . . . . . . . - - 4,793 7,155 -
Income taxes associated
with allowance for funds used
during construction (AFUDC)
and the deferred return on
New Hampshire Electric
Cooperative (NHEC)
deferred costs. . . . . . - 217 428 98 111
Other income taxes - credit (23,044) (14,254) (12,814) (20,665) 12,495
--------- -------- -------- -------- ---------
Total income tax expense $50,219 $25,160 $ 8,856 $24,904 $ (163)
========= ======== ======== ======= =========
</TABLE>
<PAGE>17
<TABLE>
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
<CAPTION>
- -----------------------------------------------------------------------------------------------------
Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 May 16, 1991 Jan. 1, 1991
to to to to to
For the Periods Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991 May 15, 1991
- -----------------------------------------------------------------------------------------------------
<F1>(Note 1) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Depreciation . . . . . . . .$ 4,549 $ 1,629 $12,333 $21,450 $17,289
Energy adjustment clauses. . 15,155 14,520 (1,359) 14,476 4,628
Deferred tax asset
associated with NOL. . . . 25,438 9,335 (2,317) (17,149) (81,002)
Alternative minimum tax. . . 1,056 (2,441) (394) - -
Amortization of prepaid
deferred taxes . . . . . . 7,667 - - - -
Seabrook unsecured interest. - - - - 52,058
Deferred return on Seabrook. - - 4,793 7,155 -
Severance benefits . . . . . - 254 (1,020) - -
Other . . . .. . . . . . . . (3,327) (211) (3,333) (590) 7,138
-------- -------- --------- -------- ---------
Deferred income taxes, net $50,538 $23,086 $ 8,703 $25,342 $ 111
======== ======== ========= ======== =========
</TABLE>
<TABLE>
A reconciliation between income tax expense and the expected tax expense at the applicable statutory
rates is as follows:
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 May 16, 1991 Jan. 1, 1991
to to to to to
For the Periods Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991 May 15, 1991
- ---------------------------------------------------------------------------------------------------------
<F1>(Note 1) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Expected
federal income
tax at 35 percent pretax
income for 1993 and 34
percent for 1992 and 1991. .$35,860 $18,550 $ 7,356 $26,383 $ (34,324)
Tax effect of differences:
Depreciation differences . 1,593 1,032 (8,314) (12,455) 1,524
Amortization of Regulatory
Asset - Rate Agreement . . 23,765 17,624 12,477 18,294 -
Seabrook intercompany loss . (19,176) (11,903) - - -
Reorganization expenses. . . - 22 1,728 795 5,179
Deferred investment return . - - (3,832) (5,231) -
Unused book NOL. . . . . . . - - - - 22,058
State tax, net of federal
benefit . . . . . . . . . 2,804 - - - -
Amortization of prepaid
deferred taxes . . . . . . 7,667 - - - -
Other, net . . . . . . . . . (2,294) (165) (559) (2,882) 5,400
-------- -------- -------- -------- -----------
Total income tax expense . . $50,219 $25,160 $ 8,856 $24,904 $ (163)
======== ======== ======== ======== ===========
</TABLE>
<PAGE>18
<F9>
9. PENSION BENEFITS
The company participates in a uniform noncontributory defined benefit
retirement plan covering all regular system employees (the Plan). Benefits
are based on years of service and employees' highest eligible compensation
during five consecutive years of employment. Effective January 1993, PSNH's
plan was merged into the NU system's uniform noncontributory defined benefit
plan. The company's direct allocated portion of the system's pension cost,
part of which was charged to utility plant, approximated $6,626,000 in 1993,
$4,422,000 for the period January 1, 1992 to June 4, 1992 and $3,467,000 for
the period June 5, 1992 to December 31, 1992 and $13,220,000 in 1991. The
pension cost for June 5, 1992 to December 31, 1992 excludes employees of NHY,
who are now employees of NAESCO. Pension costs for 1993 included
approximately $3,359,000 related to work force reduction programs.
Currently, PSNH funds 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.
<TABLE>
The components of net pension cost for PSNH are:
<CAPTION>
- ---------------------------------------------------------------------------------------
Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 Jan. 1, 1991
to to to to
For the Periods Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Service cost . . . . . . $ 7,539 $ 2,889 $ 3,850 $ 8,382
Interest cost. . . . . . 11,180 6,810 6,200 12,771
Return on plan assets. . (19,308) (5,026) (4,561) (45,157)
Net amortization . . . . 7,215 (1,206) (1,067) 37,224
-------- -------- -------- --------
Net pension cost . . . . $ 6,626 $ 3,467 $ 4,422 $13,220
======== ======== ======== ========
</TABLE>
For calculating pension cost, the following assumptions were used:
- -------------------------------------------------------------------------------
Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 Jan. 1, 1991
to to to to
For the Periods Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991
- --------------------------------------------------------------------------------
Discount rate. . . . . 8.00% 8.00% 8.00% 8.00%
Expected long-term
rate of return . . . 8.50 9.00 9.00 8.50
Compensation/
progression rate . . . 5.00 6.00 6.00 6.00
- --------------------------------------------------------------------------------
PAGE>19
The following table represents the Plan's funded status reconciled to the
Balance Sheets:
- -----------------------------------------------------------------------
At December 31, 1993 1992
- -----------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $111,691,000 of vested
benefits at December 31, 1993 and
$112,507,000 of vested benefits at
December 31, 1992 . . . . . . . . . . $122,429 $113,485
======== ========
Projected benefit obligation (PBO). . $156,475 $175,891
Less: Market value of plan assets. . 145,536 166,456
--------- ---------
PBO in excess of plan assets. . . . . (10,939) (9,435)
Unrecognized transition amount. . . . 5,338 6,741
Unrecognized prior service costs. . . 4,890 4,870
Unrecognized net gain . . . . . . . . (31,179) (32,859)
--------- ---------
Accrued pension liability . . . . . . $(31,890) $(30,683)
========= =========
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 a 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 a voluntary early retirement program
and involuntary terminations. PSNH's direct cost of the program, which
approximated $4.9 million, included pension, severance, and other
benefits.
<F10>
10. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The company provides 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 company
who are otherwise eligible to retire and have met specified service
requirements. Through December 31, 1992, the company 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 company adopted SFAS 106 on a prospective basis. Total
health care and life insurance costs, part of which was deferred or charged
to utility plant, approximated $9,106,000 in 1993, $3,290,000 in 1992, and
$2,783,000 in 1991.
<PAGE>20
On January 1, 1993, the accumulated postretirement benefit obligation (APBO)
represented the company's prior-service obligation upon the adoption of SFAS
106. As allowed by SFAS 106, the company is amortizing its APBO of
approximately $63 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.
During 1993, the company began funding SFAS 106 postretirement costs through
external trusts. The company is 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
Balance Sheet at December 31, 1993:
(Thousands of Dollars)
Accumulated postretirement benefit obligation of:
Retirees . . . . . . . . . . . . . . . . . . . . . . . $(51,832)
Fully eligible active employees. . . . . . . . . . . . (99)
Active employees not eligible to retire . . . . . . . (7,888)
---------
Total accumulated postretirement benefit obligation. . (59,819)
Less: Market value of plan assets . . . . . . . . . . 2,387
---------
Accumulated postretirement benefit
obligation in excess of plan assets . . . . . . . . . . (57,432)
Unrecognized transition amount. . . . . . . . . . . . . 55,870
Unrecognized net gain . . . . . . . . . . . . . . . . . (1,065)
---------
Accrued postretirement benefit liability. . . . . . . . $ (2,627)
=========
The components of health care and life insurance costs for the year ended
December 31, 1993 are:
- -------------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . . $1,260
Interest cost. . . . . . . . . . . . . . 4,800
Net amortization . . . . . . . . . . . . 3,046
------
Net health care and life insurance costs $9,106
======
- -------------------------------------------------------------------------
<PAGE>21
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 $5.1 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit cost for the
year then ended by $476,000.
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.
PSNH is currently recovering SFAS 106 costs.
<F11>
11. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision. Actual
construction expenditures may vary from estimates due to factors such as
revised load estimates, inflation, revised nuclear safety regulations,
delays, difficulties in the licensing process, the availability and cost of
capital, and the granting of timely and adequate rate relief by regulatory
commissions, as well as actions by other regulatory bodies.
PSNH currently forecasts construction expenditures (including AFUDC) of $172.5
million for the years 1994-1998, including $37.5 million for 1994. In addition,
PSNH estimates that nuclear fuel requirements, for its share of Millstone 3,
will be $5.7 million for the years 1994-1998, including $1.7 million for 1994.
PSNH RATE AGREEMENT
The Rate Agreement provided the financial basis for 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 <F1>Note 1, "Summary of Significant Accounting
Policies-Energy Adjustment Clause," the FPPAC protects PSNH form 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.
<PAGE>22
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 106 and SFAS 109, and recovery for certain
aspects of PSNH's settlement with the VEG&T, including the purchase by NAEC
of VEG&T's 0.4 percent share of Seabrook. The Memorandum 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
PSNH 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. PSNH 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 PSNH's
existing hydro, nuclear, and fossil-fuel generating units, and transmission
and distribution systems, and could raise operating costs significantly. As
a result, PSNH 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 waste. PSNH may also
encounter significantly increased costs to remedy the environmental effects
of prior waste handling and disposal activities.
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 PSNH
may be determined to be legally liable by federal or state environmental
agencies. In addition, PSNH 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 PSNH's financial position or future results of operations.
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. Under the terms of the Contract with NAEC, PSNH would
<PAGE>23
be obligated to pay for any assessment charged to NAEC as a "cost of
service." At December 31, 1993, based on PSNH's ownership interests in
Millstone 3, and NAEC's ownership interests in Seabrook 1, PSNH's maximum
liability would be $30.4 million per incident. In addition, through PSNH's
purchased power contracts with the four Yankee regional nuclear generating
companies, PSNH would be responsible for up to an additional $16.7 million
per incident. These payments for PSNH's ownership interest in nuclear
generating facilities and costs resulting from the Contract with NAEC would
be limited to a maximum of $5.9 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 PSNH's 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 PSNH's ownership interests in Millstone 3, CY,
MY, and VY; and NAEC's ownership interest in Seabrook. All companies insured
with NEIL are subject to retroactive assessments if losses exceed the
accumulated funds available to NEIL. The maximum potential assessments
against PSNH (including costs resulting from PSNH's Contract with NAEC) with
respect to losses arising during current policy years are approximately $1.9
million under the replacement power policies and $1.9 million under the
property damage, decontamination, and decommissioning policies. Although
PSNH 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 PSNH (including costs resulting from
PSNH's Contract with NAEC) with respect to losses arising during the current
policy period are approximately $1.9 million.
FINANCING ARRANGEMENTS FOR THE REGIONAL NUCLEAR GENERATING COMPANIES
PSNH believes 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, PSNH may be
asked to direct or indirect financial support for one or more of these
companies.
PURCHASED POWER ARRANGEMENTS
PSNH purchases a portion of its electricity requirements pursuant to
long-term contracts with the Yankee companies. Under the terms of its
agreements, the company pays its ownership share (or entitlement share) 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 company's rates. The total cost of purchases under these
contracts for the units that are operating amounted to $26.5 million in 1993,
$24.8 million in 1992, and $23.9 million in 1991. See <F1>Note 1, "Summary
Of Significant Accounting Policies-Investments and Jointly Owned Electric
Utility Plant" and <F4>Note 4, "Nuclear Decommissioning" for more information
on the Yankee companies.
PSNH has entered into various arrangements for the purchase of capacity and
energy from nonutility generators. Some of these arrangements generally have
terms from 20 to 30 years, and require the
<PAGE>24
company to purchase the energy at specified prices or formula rates. 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 the
company's purchases under these arrangements amounted to $133.4 million in
1993, $92.1 million in 1992, and $105.7 million in 1991. These costs are
eventually recovered through the company's rates.
In an effort to control cost and price increases from nonutility generators,
PSNH is in the process of attempting to renegotiate new rate orders 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 through the FPPAC and part is deferred for future collection in
accordance with the Rate Agreement. In connection with the agreement, NHEC
agreed to continue as a firm-requirements customer of PSNH for 15 years.
The estimated annual cost of PSNH's significant purchased power arrangements
is provided below:
- ----------------------------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(Millions of Dollars)
Yankee companies. . $ 26.5 $ 29.7 $ 32.2 $ 29.4 $ 34.0
Nonutility
generators. . . . 142.7 145.4 148.9 152.5 156.1
NHEC. . . . . . . . 14.6 15.2 16.2 24.4 32.4
- ----------------------------------------------------------------------------
HYDRO-QUEBEC
Along with other New England utilities, PSNH entered into agreements to
support transmission and terminal facilities to import electricity from the
Hydro-Quebec system in Canada. PSNH is obligated to pay, over a 30-year
period, its proportionate share of the annual operation, maintenance, and
capital costs of these facilities, which are currently forecast to be $53.8
million for the years 1994-1998, including $11.6 million for 1994.
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
<PAGE>25
higher assessments, to date, the higher assessments have not had a material
adverse effect on CY 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.
DEFERRED RECEIVABLE FROM AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with
the phase-in under the Rate Agreement, it began accruing a deferred return on
a portion of its Seabrook investment. From May 16, 1991 to the Acquisition
Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition
Date, PSNH sold the $50.9 million deferred return to NAEC as part of the
Seabrook-related assets.
At the time PSNH transferred the deferred return to NAEC, it realized, for
income tax purposes, a gain that is deferred under the consolidated income
tax rules. This gain will be restored for income tax purposes when the
deferred return of $50.9 million, and the associated income taxes of $32.9
million, are collected by NAEC through the Contract. When NAEC recovers the
$32.9 million in years eight through ten of the Rate Agreement, it is
obligated to make corresponding payments to PSNH.
On the Acquisition Date, PSNH recorded the $32.9 million of income taxes
associated with the deferred return as a deferred receivable from NAEC, with
a corresponding entry to deferred revenue, on its Balance Sheet. In 1993,
due to changes in tax rates, this amount was adjusted to $33.3 million.
<F12>
12. 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 PSNH's 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.
<PAGE>26
The carrying amounts of PSNH's financial instruments and the estimated fair
values are as follows:
- ----------------------------------------------------------------------------
At December 31, 1993 Carrying Amount Fair Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption . . . . . . $125,000 $139,375
Long-term debt -
First Mortgage Bonds . . . . . . 342,500 359,878
Other long-term debt . . . . . . 751,485 783,389
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
At December 31, 1992 Carrying Amount Fair Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption . . . . . . $125,000 $140,625
Long-term debt -
First Mortgage Bonds. . . . . . . 342,500 385,747
Other long-term debt. . . . . . . 845,485 861,297
- ----------------------------------------------------------------------------
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, PSNH will adopt SFAS 115 on a prospective basis. PSNH
anticipates that the adoption of SFAS 115 will not have a material impact on
future results of operations or financial position.
<PAGE>27
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Public Service Company of New Hampshire:
We have audited the accompanying balance sheets of Public Service Company of
New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1993 and 1992, and the related
statements of income, common equity and cash flows for the year ended
December 31, 1993 and the periods from January 1, 1992 to June 4, 1992 and
June 5, 1992 to December 31, 1992. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Public Service Company of
New Hampshire as of December 31, 1993 and 1992, and the results of its
operations and cash flows for the year ended December 31, 1993 and the
periods from January 1, 1992 to June 4, 1992 and June 5, 1992 to December 31,
1992, in conformity with generally accepted accounting principles.
As discussed in <F1>Note 1 to the financial statements, "Summary of
Significant Accounting Policies - Accounting Changes," effective January 1,
1993, Public Service Company of New Hampshire changed its methods of
accounting for income taxes and postretirement benefits other than pensions.
/S/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
<PAGE>28
INDEPENDENT AUDITOR'S REPORT
The Board of Directors
Public Service Company of New Hampshire
We have audited the balance sheet and statement of capitalization of Public
Service Company of New Hampshire as of December 31, 1991 (not presented
herein), and the related statements of income, cash flows and common stock
equity for the periods January 1, 1991 to May 15, 1991, and May 16, 1991 to
December 31, 1991. These financial statements are the responsibility of
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 assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Public Service Company of
New Hampshire at December 31, 1991 and the results of its operations and its
cash flows for the periods January 1, 1991 to May 15, 1991 and May 16, 1991
to December 31, 1991.
/S/ KPMG Peat Marwick
KPMG Peat Marwick
Boston, Massachusetts
February 7, 1992
<PAGE>29
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section contains management's assessment of Public Service Company of
New Hampshire's (the company or PSNH) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This discussion
should be read in conjunction with the company's financial statements and
footnotes.
FINANCIAL CONDITION
Overview
On June 5, 1992 (the Acquisition Date), NU and PSNH completed an affiliation,
which represented the second step of a two-step bankruptcy court approved plan
(the Plan) that was devised in 1989 to return the then-bankrupt company to
financial health. The first step took place on May 16, 1991 (the Reorganization
Date) when PSNH emerged from bankruptcy as a stand-alone company, subject to a
Merger Agreement (the Merger Agreement) with NU's subsidiaries Northeast
Utilities Service Company and NU Acquisition Corporation (NUAC).
The final step in the affiliation plan occurred on June 5, 1992, when NUAC was
merged into the company pursuant to the Merger Agreement and the company became
a wholly owned operating subsidiary of NU. In a related transaction, the
company's 35.6 percent share of the Seabrook 1 nuclear power plant (Seabrook)
and other Seabrook-related assets were transferred to North Atlantic Energy
Corporation (NAEC), another wholly owned subsidiary of NU. On June 29, 1992,
PSNH's New Hampshire Yankee division was dissolved and North Atlantic Energy
Service Corporation, a wholly owned subsidiary of NU, received approval to
manage Seabrook as agent for the Seabrook joint owners.
At the Acquisition Date, the company and NAEC entered into the Seabrook Power
Contract, under which the company is obligated to buy from NAEC, and NAEC is
obligated to sell to the company, all of NAEC's capacity and output of Seabrook
for a period equal to the length of the Nuclear Regulatory Commission full-power
operating license for Seabrook (through 2026). Under the contract, the company
is unconditionally obligated to pay NAEC's "cost of service" during the period
whether or not Seabrook is operating and without regard to the cost of
alternative sources of power. In addition, the company will be obligated to pay
decommissioning and project cancellation costs after the termination of the
operating license.
NAEC's "cost of service" includes all of its prudently incurred Seabrook-related
costs, including operation and maintenance expense, fuel expense, property tax
expense, depreciation expense, certain overhead and other costs, and a phased-in
return on its Seabrook investment. The Seabrook Power Contract established the
initial recoverable investment at Seabrook at $700 million (Initial Investment),
plus any capital additions, net of depreciation.
The company's net income for the 12 months ended December 31, 1993 was $52.2
million. The 1993 net income reflects a one-time $3 million charge to income
in the third quarter of 1993 for the costs of an employee reduction program.
The company's workforce was reduced by about 18 percent in 1993 through an
employee reduction program that involved early retirements and involuntary
terminations.
Retail sales for 1993 increased 1.4 percent as compared to 1992, as a result of
warmer summer weather which offset the effects of a sluggish New Hampshire
economy. The company expects retail sales growth of about 1 percent in 1994,
based on some expected improvement in the economy.
<PAGE>30
In 1994, the company will continue to face challenges associated with a lagging
economy and competition. Competition within the electric utility industry is
increasing. In response, the company 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 customer base. These initiatives are aimed
at keeping customers from either leaving the company's retail service territory
or replacing the company'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 energy and
other costs of doing business in New England also contribute to competitive
disadvantages for many industrial and commercial customers of PSNH. These
disadvantages have aggravated the pressures on business customers in the current
weakened regional economy. The company is working with the New Hampshire Office
of Business and Industrial Development to package development incentives for a
variety of retail and wholesale customers. These economic development packages
may include electric rate discounts, 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 company
revenues of approximately $15 million. The amount of discounts provided to
customers may increase in the future as the company intensifies its efforts to
retain existing customers and gain new customers.
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 limited circumstances, retail wheeling is not required in the
company's jurisdictions. In New Hampshire, there have been no legislative
proposals on retail wheeling to date.
NU management has taken steps to make the NU system companies, including
PSNH, more competitive and profitable in the changing utility environment. A
systemwide 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 New
Hampshire, Connecticut, and Massachusetts. These two core business groups
are served by various support functions.
In connection with NU's reorganization, the system companies have begun a
corporate reengineering process which should help PSNH 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 help enable PSNH to remain competitive.
To date, PSNH has not been materially affected by competition and it does not
foresee substantial adverse effects in the near future unless the current
regulatory structure is substantially altered. The company believes the steps
it is taking will have significant, positive effects in the next few years. In
addition, PSNH benefits from a diverse retail base. The company has no
significant dependence on any one customer or industry. The NU system's
extensive transmission facilities and diversified generating capacity are all
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 improvements in earnings in 1994 will depend in part on
the success of the company's wholesale power marketing, customer retention
and reengineering efforts. These efforts should help increase earnings and
improve the company's competitive position.
<PAGE>31
Rate Matters
Deferred charges at December 31, 1993 were $1.0 billion, which includes
$769.5 million for the regulatory asset under the rate agreement with the
state of New Hampshire and $122.5 million for costs deferred under PSNH's
energy adjustment clause. The regulatory asset was established under PSNH's
reorganization plan. The Rate Agreement provides for the recovery of $425
million of the regulatory asset over the seven-year period ending May 1998
with the remaining amount to be amortized over a 20 year period. Management
expects that substantially all of the deferred charges will be recovered
through future rates.
The company adopted Statement of Financial Accounting Standards (SFAS) No.
109, Accounting for Income Taxes, in 1993. Under SFAS No. 109, the company
reflected a regulatory asset of $54.3 million 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, Employers' 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 company is currently recovering these costs from customers.
See the "Notes To Financial Statements" for further details on deferred
charges and recently adopted accounting standards.
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 fourth base rate increase took place on June 1, 1993.
The remaining three base rate increases are scheduled to be put into effect
annually on each June 1.
The FPPAC recovers or refunds the difference between actual prudent energy
and purchased power costs, including the costs incurred under the Seabrook
Power Contract and the costs included in base rates. The FPPAC is reviewed by
the NHPUC every six months and adjusted to reflect actual fuel and purchased
power costs and to anticipate expenditures for the next six-month period.
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 eighteen months.
In January 1994, the NHPUC approved a Memorandum of Understanding 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 Global Settlement). 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 approximately 0.4 percent share of Seabrook among other results. NAEC
will sell the output from the Seabrook interest purchased from VEG&T to PSNH
under an agreement that is substantially similar to the Seabrook Power
Contract. The Global
<PAGE>32
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 its
customers. The NHPUC will be examining the prudence of PSNH's efforts and
will consider 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. 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 billed to PSNH and recovered through the Seabrook
Power Contract over the period 1997 through 2001.
Environmental Matters
The NU system devotes substantial resources to identify and then to meet the
multitude of environmental requirements it faces. PSNH 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.
PSNH is potentially liable for environmental cleanup costs at a number of
sites both inside and outside of its service territory. To date the future
estimated environmental remediation costs for the sites, which the company
expects to bear legal liability have not been material with respect to the
earnings or financial position of the company. 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 1 of the 1990 Clean Air
Act Amendments will require only minimal emissions reductions for PSNH. The
company has more exposure for stringent emission limits for nitrogen oxides
within the next five years. The costs for meeting Phase II requirements
cannot be estimated at this time because the emission limits have not been
determined.
The estimated cost of decommissioning PSNH's share of Millstone 3 and NAEC's
share of Seabrook is approximately $12 million and $131.7 million,
respectively, in year-end 1993 dollars. Under the terms of the Rate
Agreement, the company 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. In addition, the company's estimated cost to
decommission its share of the regional nuclear generating units is
estimated to be approximately $46 million. These costs are being recovered
and recognized over the lives of the units. Yankee Atomic Electric Company
(YAEC) has begun decommissioning its nuclear facility. PSNH's estimated
obligation to YAEC has been recorded on the Balance Sheets. Management
expects that the company will continue to be allowed to recover these costs.
<PAGE>33
See the "Notes to Financial Statements" for further information regarding
nuclear decommissioning and other environmental matters.
Seabrook Performance
The Seabrook plant operated at 89.8 percent of capacity for the year ended
December 31, 1993 compared with 77.9 percent in 1992 and a national average
of 70.6 percent for 1993. Seabrook began commercial operation on June 30,
1990. The unit was shut down on September 7, 1992, for refueling and
maintenance and returned to service on November 13, 1992. The next refueling
and maintenance outage is scheduled for March 1994.
Liquidity And Capital Resources
Cash flows from operations provided the primary source of funds for the
period ended December 31, 1993, while the reacquisition and retirement of
long-term debt, repayment of short-term debt, and investment in utility plant
were the primary uses of funds.
As a result of the transactions established by the Plan, the company has a
more leveraged capital structure than most other investor-owned public
utilities and is required to make substantial interest payments. The
company's indebtedness under the Term Loan, Revolving Credit Facility, and
some of the company's pollution control revenue bonds bear interest at
floating rates to be set periodically, causing the company to be sensitive to
prevailing interest rates. The company has entered into interest rate cap
agreements to reduce the potential impact of upward changes in interest rates
on a portion of its variable rate long-term debt. To take advantage of favor
able market conditions during 1993, the company refinanced $45 million of
Pollution Control Bonds. The company expects to refinance a substantial
portion of its Series A and B bonds when they mature in 1996 and 1998,
respectively. In addition, the company's Term Loan must be repaid in 16
quarterly installments of $23.5 million that commenced in August 1992.
PSNH's Series A preferred stock has an annual sinking fund of $25 million
beginning in 1997.
The company's construction program expenditures, including allowance for
funds used during construction (AFUDC), for the period 1994 through 1998 are
estimated to be approximately $172.5 million, including $37.5 million for
1994. The construction program's main focus is maintaining and upgrading the
existing transmission and distribution system, and nuclear and
fossil-generating facilities. The company does not foresee the need for new
major generating facilities until at least the year 2007.
Management believes that, as a result of the annual rate increases provided
for by the Rate Agreement and the FPPAC, cash flow from operations should be
sufficient to cover its cash requirements. The company expects to meet cash
requirements not covered by cash from operations through borrowings under
the Revolving Credit Facility and/or the NU system Money Pool. The Revolving
Credit Facility's final maturity is May 14, 1994. At December 31, 1993,
there were no borrowings under the Revolving Credit Facility and $2.5 million
in borrowings outstanding under the Money Pool. The company may need to
issue new debt in 1994 to finance a buyout of some of its arrangements with
the SPPs.
See the "Notes to Financial Statements" for further information regarding the
Revolving Credit Facility and the Money Pool.
Results of Operations
PSNH's results of operations for the 12 months ended December 31, 1993 and
for the period June 5, 1992 through December 31, 1992 reflect the results
after the acquisition. PSNH's results of operations for the period January
1, 1992 to June 4,1992 and May 16, 1991 to December 31, 1991 reflect the
results of the reorganized
<PAGE>34
company. Prior to May 16, 1991, PSNH was in bankruptcy. The results for each
of these periods are not comparable because of the significant impacts on the
company of the acquisition and reorganization.
Operating Revenues
Operating revenues for the year ended December 31, 1993 decreased $9.9
million, compared to the same period in 1992, primarily due to lower
short-term power sales to other utilities as a result of the
elimination, effective with the acquisition, of sales to NU, and the one-time
impact in 1992 of $15.8 million of revenues released from escrow at the
acquisition date. These decreases were partially offset by increases under
the Rate Agreement and FPPAC. The third and fourth steps of the Rate
Agreement were effective June 1, 1992 and 1993. Retail sales increased 1.4
percent in 1993 over 1992 sales levels.
Operating revenues for the year ended December 31, 1992 increased $88.2
million, compared to the same period in 1991, primarily due to increases
under the Rate Agreement and FPPAC and increased short-term
power sales. Operating revenues for the year ended December 31, 1992,
include $125.4 million in short-term sales, of which $96.0 million was sold
to NU compared to $108.2 million, of which $97.0 million was sold to NU in
1991. In addition, retail sales increased approximately 2 percent.
Operating revenues for the period June 5, 1992 to December 31, 1992, also
include the one-time impact of $15.8 million of revenues released from
escrow.
Fuel, purchased and net interchange power expense decreased $21.1 million for
the year ended December 31, 1993, compared to the same period in 1992,
primarily due to the timing in the recovery of fuel expenses under the FPPAC.
The payments made by PSNH to NAEC under the Seabrook Power Contract
(excluding fuel expense) are reflected as purchased power capacity costs and
are included in other operation expenses. The year ended December 31, 1993,
and the period June 5, 1992 to December 31, 1992, include $115.0 million and
$76.0 million, respectively, of costs associated with the "cost of service"
under the Seabrook Power Contract. Maintenance, depreciation, and taxes
other than income taxes for these periods do not reflect any Seabrook costs
as a result of the transfer of the company's investment in Seabrook to NAEC
and the inclusion of such costs in the Seabrook Power Contract.
Amortization of regulatory assets, net decreased $20 million for the year
ended December 31, 1993 as compared to the same period in 1992 due to the
amortization of the regulatory liability recognized from the PSNH Global
Settlement. Approximately $128 million of pre-acquisition losses are being
amortized over six years.
The company has not recorded a deferred Seabrook return after June 4, 1992
because the company's investment in Seabrook was transferred to NAEC at the
Acquisition Date. Prior to the transfer of Seabrook to NAEC, a deferred
return was calculated on the portion of the Seabrook investment not
reflected in rate base in accordance with the Rate Agreement.
Bankruptcy-related expenses for the period prior to June 5, 1992, represent
costs associated with PSNH's bankruptcy. In 1988, PSNH filed a petition for
reorganization under Chapter 11 of the Bankruptcy Code.
The gain on generating projects of $6.5 million for the period prior to June
5, 1992, represents a first quarter 1992 adjustment related to the settlement
of a Seabrook contractor dispute and a Seabrook property tax abatement.
Interest on long-term debt and other interest are lower for the year ended
December 31, 1993, as compared to the same period in 1992, due to the
assumption by NAEC, at the acquisition date, of the company's obligations
under the 15.23 percent Notes, paydown of the Term Loan and a reduction in
borrowings under the revolving credit facility.
<PAGE>35
(This page left intentionally blank)
<PAGE>36
<TABLE>
<CAPTION>
SELECTED FINANCIAL DATA
- -----------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------
January 1, 1993 June 5, 1992<F14>* January 1, 1992 May 16, 1991<F15>**
to to to to
For the Periods December 31, 1993 December 31, 1992 June 4, 1992 December 31, 1991
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Revenues. . . . $864,415 $492,559 $381,769 $539,827
Operating Income. . . . . 105,534 61,206 34,250 82,755
Net Income (Loss) . . . . 52,237 29,398 12,778 52,694
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
At December 31, 1993 December 31, 1992 June 4, 1992<F14>* December 31, 1991
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<C> <C> <C> <C>
Total Assets. . . . . . . . $2,774,511 $2,793,768 $2,693,414 $2,636,525
Long-Term Debt <F13>(a) . . 1,093,985 1,187,985 1,488,985 1,515,985
Liabilities Subject to
Settlement <F13>(a) . . - - - -
Preferred Stock Subject to
Mandatory Redemption <F13>(a) 125,000 125,000 125,000 125,000
Preferred Stock Not Subject
to Mandatory Redemption . - - - -
Obligations Under Seabrook
Power Contract and Other
Capital Leases <F13>(a) . 856,559 787,826 - -
<F13>(a)Includes portions due within one year.
<F14>*PSNH was acquired by NU on June 5, 1992 - See <F1>Note 1 of Notes to Financial Statements.
<F15>**PSNH was reorganized on May 16, 1991 - See <F1>Note 1 of Notes to Financial Statements.
</TABLE>
<PAGE>37
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
January 1, 1991 January 1, 1990 January 1, 1989
to to to
For the Periods May 15, 1991 December 31, 1990 December 31, 1989
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues. . . . $246,281 $660,122 $624,137
Operating Income. . . . . 21,616 63,059 98,126
Net Income (Loss) . . . . (100,791) (210,012) (203,237)
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
At May 15, 1991<F15>** December 31, 1990 December 31, 1989
- --------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Total Assets. . . . . . . . $2,502,237 $2,490,534 $2,447,521
Long-Term Debt<F13>(a). . . - - -
Liabilities Subject to
Settlement<F13>(a). . . 1,901,803 1,864,681 1,681,199
Preferred Stock Subject to
Mandatory Redemption<F13>(a) - 420,613 420,613
Preferred Stock Not Subject
to Mandatory Redemption . - 48,587 48,587
Obligations Under Seabrook
Power Contract and Other
Capital Leases<F13>a). . - - -
</TABLE>
<PAGE>38
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
- -----------------------------------------------------------------------------------------------------
STATISTICS
- -----------------------------------------------------------------------------------------------------
<CAPTION>
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31,)
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1993 1,990,730 11,146 6,817 397,277 1,426
1992<F16>* 1,894,359 12,294 6,874 394,046 1,680
1991 1,782,894 11,377 7,184 390,793 2,639
1990 2,585,890 8,324 7,015 336,720 2,766
1989 2,555,404 7,656 7,311 383,497 2,786
</TABLE>
<TABLE>
- -----------------------------------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- -----------------------------------------------------------------------------------------------------
<CAPTION>
- -----------------------------------------------------------------------------------------------------
1993 March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Revenues. . . . . $224,705 $192,360 $222,717 $224,633
======== ======== ======== ========
Operating Income. . . . . . $ 30,411 $ 17,133 $ 19,678 $ 38,312
======== ======== ======== ========
Net Income (Loss) . . . . . $ 15,558 $ 2,995 $ 8,583 $ 25,101
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
April 1 - June 5 -
1992<F16>* March 31 June 4 June 30 Sept. 30 Dec. 31
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Operating Revenues. . . . . $252,707 $129,062 $ 74,182 $204,161 $214,216
======== ======== ======== ======== ========
Operating Income. . . . . . $ 34,094 $ 156 $ 17,112 $ 22,452 $ 21,642
======== ======== ======== ======== ========
Net Income (Loss) . . . . . $ 27,810 $(15,032) $ 12,478 $ 10,379 $ 6,541
======== ======== ======== ======== ========
<F16>*PSNH was acquired by NU on June 5, 1992 - See <F1>Note 1 of Notes to Financial Statements.
</TABLE>
<PAGE>39
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
First Mortgage Bonds
--------------------
Trustee and Interest Paying Agent
First Fidelity Bank, N.A., New Jersey
765 Broad Street
Newark, NJ 07102
Preferred Stock
---------------
Transfer Agent, Dividend Disbursing Agent and Registrar
Northeast Utilities Service Company Shareholder Services
P.O. Box 5006, Hartford, Connecticut 06102-5006
1994 Dividend Payment Dates
10.60% Series A
March 31, June 30, September 30, and December 31
Address General Correspondence in Care of:
Northeast Utilities Service Company
Investor Relations Department
P.O. Box 270
Hartford, Connecticut 06141-0270
Tel. (203) 665-5000
General Office
1000 Elm Street
P.O. Box 330
Manchester, New Hampshire 03105
_______________________________
The data contained in this Report is submitted for the sole purpose of
providing information to present stockholders about the Company.
<PAGE>
Exhibit 13.5
1993
ANNUAL REPORT
NORTH ATLANTIC ENERGY CORPORATION
<PAGE>
1993 Annual Report
North Atlantic Energy Corporation
Index
Contents Page
- -------- ----
Balance Sheets . . . . . . . . . . . . . . . . . 1-2
Statements of Income . . . . . . . . . . . . . . 3
Statements of Cash Flows . . . . . . . . . . . . 4
Statements of Common Stockholder's Equity. . . . 5
Notes to Financial Statements. . . . . . . . . . 6-16
Report of Independent Public Accountants . . . . 17
Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . 18-22
Selected Financial Data. . . . . . . . . . . . . 23
Statistics . . . . . . . . . . . . . . . . . . . 23
Statement of Quarterly Financial Data. . . . . . 23
Bondholder Information . . . . . . . . . . . . . Back Cover
<PAGE>
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992<F1>(a)
- --------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric............................................ $ 758,170 $ 756,806
Less: Accumulated provision for depreciation..... 56,649 36,327
------------ ------------
701,521 720,479
Construction work in progress....................... 7,618 4,775
Nuclear fuel, net................................... 23,339 13,339
------------ ------------
Total net utility plant......................... 732,478 738,593
------------ ------------
Other Property and Investments:
Nuclear decommissioning trust, at cost.............. 7,881 5,037
------------ ------------
Current Assets:
Cash and special deposits........................... 8,404 6,264
Receivables......................................... 3,677 349
Receivables from affiliated companies............... 20,304 22,842
Materials and supplies, at average cost............. 7,353 5,362
Prepayments and other............................... 4,183 4,157
------------ ------------
43,921 38,974
------------ ------------
Deferred Charges:
Deferred costs--Seabrook <F4>(Note 1)............... 85,428 22,801
Regulatory asset--income taxes <F4>(Note 1)......... 19,432 -
Unamortized debt expense............................ 5,507 6,179
Deferred DOE assessment <F4>(Note 1)................ 4,905 4,965
Other............................................... 1,269 1,574
------------ ------------
116,541 35,519
------------ ------------
Total Assets.................................... $ 900,821 $ 818,123
============ ============
</TABLE>
<F1>(a) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
<PAGE>1
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
At December 31, 1993 1992<F1>(a)
- --------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock, $1 par value--authorized
and outstanding 1,000 shares....................... $ 1 $ 1
Capital surplus, paid in............................ 160,999 160,999
Retained earnings................................... 38,701 12,703
------------ -----------
Total common stockholder's equity.......... 199,701 173,703
Long-term debt <F7>(Note 4)......................... 560,000 560,000
------------ -----------
Total capitalization....................... 759,701 733,703
------------ -----------
Current Liabilities:
Notes payable to affiliated company................. - 18,500
Accounts payable.................................... 3,999 760
Accounts payable to affiliated companies............ 2,389 602
Accrued interest.................................... 18,288 18,288
Accrued taxes....................................... 127 1
Deferred DOE obligation--current portion <F4>(Note 1) 845 -
------------ ------------
25,648 38,151
------------ ------------
Deferred Credits:
Accumulated deferred income taxes <F4>(Note 1)...... 74,772 8,395
Deferred obligation to affiliated company <F9>(Note 6) 33,284 32,909
Deferred DOE obligation <F4>(Note 1)................ 3,941 4,965
Deferred Seabrook tax settlement obligation......... 3,475 -
------------ ------------
115,472 46,269
------------ ------------
Commitments and Contingencies <F10>(Note 7)
Total Capitalization and Liabilities............ $ 900,821 $ 818,123
============ ============
</TABLE>
<F1>(a) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
<PAGE>2
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
January 1, 1993 June 5, 1992
to to
December 31, December 31,
For the Periods 1993 1992<F1>(a)
- ---------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Operating Revenues........................... $ 125,408 $ 78,444
---------------- -------------
Operating Expenses:
Operation--
Fuel..................................... 7,067 1,688
Other.................................... 35,656 25,305
Maintenance................................ 7,858 9,413
Depreciation............................... 22,642 12,905
Federal and state income taxes <F8>(Note 5) 5,673 2,583
Taxes other than income taxes.............. 12,794 10,428
---------------- -------------
Total operating expenses............. 91,690 62,322
---------------- -------------
Operating Income............................. 33,718 16,122
---------------- -------------
Other Income:
Deferred Seabrook return--other funds...... 13,397 7,784
Other, net................................. 1,891 200
Income taxes-credit........................ 1,653 10,428
---------------- -------------
Other income, net.................... 16,941 18,412
---------------- -------------
Income before interest charges....... 50,659 34,534
---------------- -------------
Interest Charges:
Interest on long-term debt................. 64,022 36,647
Other interest............................. 45 200
Deferred Seabrook return--borrowed funds,
<F4>(Note 1)............................ (39,406) (15,016)
---------------- -------------
Interest charges, net................ 24,661 21,831
---------------- -------------
Net Income .................................. $ 25,998 $ 12,703
================ =============
</TABLE>
<F1>(a) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
<PAGE>3
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Periods January 1, 1993 June 5, 1992
to to
December 31, December 31,
1993 1992 <F1>(a)
- -------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S>
Cash Flows From Operations: <C> <C>
Net Income .............................................. $ 25,998 $ 12,703
Adjusted for the following:
Depreciation........................................... 22,861 13,009
Deferred income taxes and investment tax credits, net.. 37,121 8,505
Deferred return - Seabrook............................. (52,803) (22,802)
Other sources of cash.................................. 8,767 5,387
Other uses of cash..................................... (964) (8,102)
Changes in working capital:
Receivables and accrued utility revenues.............. (790) (20,736)
Materials and supplies................................ (1,990) (2,288)
Accounts payable...................................... 5,026 1,362
Accrued taxes......................................... 126 (4,970)
Other working capital (excludes cash)................. 822 2,330
------------- -------------
Net cash flows from (used for) operations.................. 44,174 (15,602)
------------- -------------
Cash Flows From Financing Activities:
Common shares............................................ - 161,000
Long-term debt........................................... - 355,000
Net increase (decrease) in short-term debt............... (18,500) 18,500
------------- -------------
Net cash flows from (used for) financing activities........ (18,500) 534,500
------------- -------------
Investment Activities:
Investment in plant:
Investment in Seabrook assets, net..................... - (504,265)
Electric utility plant................................. (6,707) (6,307)
Nuclear fuel........................................... (13,983) (511)
------------- -------------
Net cash flows used for investments in plant............. (20,690) (511,083)
Other investment activities, net......................... (2,844) (1,551)
------------- -------------
Net cash flows used for investments........................ (23,534) (512,634)
------------- -------------
Net Increase In Cash for the Period........................ 2,140 6,264
Cash and special deposits - beginning of period............ 6,264 -
------------- -------------
Cash and special deposits - end of period.................. $ 8,404 $ 6,264
============= =============
Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Interest, net of amounts capitalized during
construction................................ $ 63,393 $ 18,166
============= =============
Income taxes.............................................. $ (32,350) $ (16,000)
============= =============
<F1>(a)NAEC began operations on June 5, 1992.
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>4
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In <F2>(a) Total
- -------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at June 5, 1992 <F3>(b)......... $ - $ - $ - $ -
Net income for 1992................. 12,703 12,703
Issuance of 1,000 shares of common
stock, $1 par value............... 1 1
Premium on common stock............. 160,999 160,999
----------- ---------- --------------------
Balance at December 31, 1992............ 1 160,999 12,703 173,703
Net income for 1993................. 25,998 25,998
----------- ---------- --------------------
Balance at December 31, 1993............ $ 1 $ 160,999 $ 38,701 $199,701
=========== ========== ====================
<F2>(a) The company had dividend restrictions imposed by its long-term debt agreement
and was effectively prohibited by the agreement from the distribution of any
dividends through May 1993. After that time, all retained earnings are
available plus an allowance of $10 million.
<F3>(b) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>5
NORTH ATLANTIC ENERGY CORPORATION
- ----------------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS
- ----------------------------------------------------------------------------
<F4>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
North Atlantic Energy Corporation (NAEC or the Company) is a wholly owned
subsidiary of Northeast Utilities (NU). NAEC was incorporated on September
20, 1991 for the purpose of acquiring Public Service Company of New
Hampshire's (PSNH) ownership interest in the Seabrook nuclear project
(Seabrook). The company has no employees. Upon NU's acquisition of PSNH on
June 5, 1992 (Acquisition Date), PSNH's 35.6 percent share of the Seabrook
nuclear power plant (Seabrook 1) and other Seabrook-related assets were
transferred to NAEC for approximately $504 million in cash and the
assumption of PSNH's obligations under the $205 million, 15.23 percent Notes
originally issued by PSNH. The sources of cash were a $161 million equity
investment by NU into NAEC, and NAEC's issuance and sale of $355 million of
9.05 percent First Mortgage Bonds, both of which took place on June 5, 1992.
NAEC also acquired PSNH's 35.6 percent interest in the nuclear fuel for
Seabrook 1 and the cancelled Seabrook 2. In addition, it acquired from PSNH
ownership of the approximately 719 acres of exclusion area land which
surrounds the location of the two Seabrook units. NAEC will not operate
Seabrook 1, which at the Acquisition Date, was being operated by the New
Hampshire Yankee Division (NHY) of PSNH. Effective June 29, 1992, North
Atlantic Energy Service Corporation (NAESCO, another newly formed, wholly
owned, subsidiary of NU), replaced NHY as the managing agent and represents
the Seabrook joint owners, including NAEC, in the operation of Seabrook 1.
On June 29, 1992, all NHY employees became employees of NAESCO.
On February 15, 1994, NAEC acquired Vermont Electric Generation and
Transmission Cooperative, Inc.'s (VEG&T) 0.4 percent ownership interest of
Seabrook for approximately $6.4 million.
The company, The Connecticut Light and Power Company, PSNH, Western
Massachusetts Electric Company, and Holyoke Water Power Company are the
operating subsidiaries comprising the Northeast Utilities system (the system)
and are wholly owned by NU. Other wholly owned subsidiaries of NU provide
substantial support services to the system. Northeast Utilities Service
Company (NUSCO) supplies centralized accounting, administrative, data
processing, engineering, financial, legal, operational, planning, purchasing,
and other services to the system companies. Northeast Nuclear Energy Company
acts as agent for system companies in constructing and operating the
Millstone nuclear generating facilities.
All transactions among affiliated companies are on a recovery of cost basis
which may include amounts representing a return on equity, and are subject to
approval by various federal and state regulatory agencies.
ACCOUNTING CHANGES
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 information on this change, see <F4> Note 1,
"Summary of Significant Accounting Policies - Income Taxes."
ACCOUNTING RECLASSIFICATIONS
Certain amounts in the accompanying financial statements of the company for
the period June 5, 1992 through December 31, 1992 have been classified to
conform with December 31, 1993 presentation.
<PAGE>6
PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935 (1935
Act), and it and its subsidiaries, including NAEC, 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 company
is subject to further regulation for rates and other matters by the FERC and
the New Hampshire Public Utilities Commission (NHPUC), and follows the
accounting policies prescribed by the commissions.
SEABROOK POWER CONTRACT
On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract
(Contract), under which PSNH is obligated to buy from NAEC, and NAEC is
obligated to sell to PSNH, all of NAEC's 35.6 percent ownership share of the
capacity and output of Seabrook 1 for a period equal to the length of the
Nuclear Regulatory Commission's (NRC) full power operating license for
Seabrook 1. The Contract is included as part of the rate agreement between
PSNH and the state of New Hampshire (the Rate Agreement). Under the
Contract, PSNH is unconditionally obligated to pay NAEC's cost of service
during this period whether or not Seabrook 1 is operating. NAEC's cost of
service includes all of its Seabrook-related costs, including operation and
maintenance expense, fuel expense, property tax expense, depreciation
expense, and certain overhead and other costs.
The Contract established the value of the initial investment in Seabrook at
$700-million (Initial Investment) and the initial investment in nuclear fuel
at $0. NAEC is depreciating its Initial Investment on a straight-line basis
over the remaining term of Seabrook 1's full power operating license. Any
subsequent additions to Seabrook 1 will be depreciated on a straight-line
basis over the remaining term of the Contract at the time the additions are
brought into service. The Contract provides that NAEC's return on its
allowed investment in Seabrook 1 (its investment in working capital, fuel,
capital additions after the date of commercial operation of Seabrook 1 and a
portion of the Initial Investment) is calculated based on NAEC's actual
capitalization from time to time over the term of the Contract, which
includes its actual debt and preferred equity costs, and a common equity cost
of 12.53% for the first ten years of the Contract, and thereafter at an
equity rate of return to be fixed in a filing with FERC.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license term, PSNH will be unconditionally required to pay NAEC termination
costs for 39 years, less the period during which Seabrook 1 has operated.
These costs are designed to reimburse NAEC for its share of Seabrook 1
cancellation and decommissioning costs and to pay NAEC a return of and on any
undepreciated balance of its Initial Investment in the plant over the
then-remaining term of the Contract, and the return of and on any capital
additions to the plant made after the Acquisition Date over a period of five
years after shut down (net of any tax benefits to NAEC attributable to such
shut down).
The portion of NAEC's Initial Investment included in rates is prescribed by
the Contract. The deferred return on the excluded portion of the Initial
Investment will become a component of NAEC's cost of service beginning in the
first year after the end of PSNH's fixed rate period (the Fixed Rate Period),
which continues through May 1997. See <F4> Note 1, "Summary of Significant
Accounting Policies - Phase-In Plan," below, for additional information
regarding NAEC's phase-in plan.
<PAGE>7
NAEC will sell the output from the 0.4 percent Seabrook interest purchased
from VEG&T on February 15, 1994 to PSNH under an agreement that has been
approved by the FERC and is substantially similar to the Seabrook Power
Contract between PSNH and NAEC that was effective on the Acquisition Date.
NUCLEAR FUEL AND SPENT NUCLEAR FUEL DISPOSAL COSTS
The cost of nuclear fuel is amortized to operation expense using a
units-of-production method at rates based on estimated kilowatt-hours of
energy provided.
Under the Nuclear Waste Policy Act of 1982, NAEC must pay the United States
Department of Energy (DOE) for the disposal of spent nuclear fuel and
high-level radioactive waste. Fees are billed currently to customers and
paid to the DOE on a quarterly basis.
Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for its
proportionate share 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. As of December 31, 1993, NAEC's remaining
share of these costs is estimated to be approximately $4.9 million. NAEC has
begun to recover these costs. Accordingly, NAEC recognized these costs as a
regulatory asset with a corresponding obligation on its Balance Sheet.
JOINTLY OWNED UTILITY PLANT
As of December 31, 1993, NAEC has a 35.6 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. As of December 31, 1993,
plant-in-service and the accumulated provision for depreciation included
approximately $758.1 million and $56.6 million, respectively, for NAEC's
share of Seabrook 1. NAEC's share of Seabrook 1 expenses is included in the
operating expenses on the accompanying Statement of Income. In February
1994, NAEC purchased an additional 0.4 share of Seabrook 1 from VEG&T.
DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the FERC.
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 Seabrook 1, 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 plant. See <F5> Note 2,
"Nuclear Decommissioning," for additional information.
The depreciation rates for the several classes of electric plant-in-service
are equivalent to a composite rate of 3.2 percent in 1993 and 1992.
<PAGE>8
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 FERC. See <F8>
Note 5, "Income Tax Expense," for the components of income tax expense.
When NU acquired PSNH on June 5, 1992, PSNH and NAEC became parties to the
Tax Allocation Agreement among the members of the NU system. The Tax
Allocation Agreement requires each member of the NU system to pay to NU the
amount, if any, that would have been its federal income tax liability if it
had filed a separate return, with certain adjustments, and requires NU to
distribute the excess of the sum of such payments over the NU system's
consolidated federal income tax liability among those members of the NU
system that had tax items that reduced the NU system's current consolidated
tax liability. A substantial portion of NAEC's cash flow for the first few
years of operations is expected to consist of payments made by NU to NAEC
under the Tax Allocation Agreement. The amount of such payments will
decrease over time but is expected to remain substantial during the first few
years of operations when NAEC is expected to incur losses for tax purposes
due to the accelerated tax depreciation of Seabrook 1. Under the Tax
Allocation Agreement, NAEC's tax losses may be utilized to offset taxable
income of the NU system and NU is required, under the Tax Allocation
Agreement, to pay NAEC for the use of such tax benefits. Such tax losses, if
not fully utilized in the taxable year in which they were incurred, may be
carried back to each of the three taxable years of the NU system preceding
the taxable year in which they are incurred. If the NU system does not have
enough taxable income in the taxable year in which such losses are incurred
or in the preceding taxable years to permit it to take full advantage of such
tax losses, or if the NU system is in an alternative minimum tax position in
any such year, then the amount of payments under the Tax Allocation Agreement
to NAEC will be decreased and NAEC's cash flow will be adversely affected.
No assurance can be given that NAEC's cash flow will not be adversely
affected in subsequent years by the inability of the other members of the NU
system to utilize fully the tax losses expected to be incurred by NAEC.
In 1992, the Financial Accounting Standards Board (FASB) issued SFAS 109.
SFAS 109 supersedes previously issued income tax accounting standards. NAEC
adopted SFAS 109, on a prospective basis, during the first quarter of 1993.
The adoption of SFAS 109 has not had a material effect on the net income or
on the balance sheet of the company. As of December 31, 1993, the deferred
tax obligation related to the adoption of SFAS 109 was approximately $19
million. As it is probable that the increase in deferred tax liabilities
will be recovered from customers through rates, NAEC 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 associated with Seabrook 1.
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. . . . . . . . . . . $46,184
The tax effect of net regulatory assets . . . . 6,801
Other. . . . . . . . . . . . . . . . . . . . . . 21,787
-------
$74,772
=======
<PAGE>9
PHASE-IN PLAN
As described below, NAEC is phasing into rates its Initial Investment in
Seabrook 1. The plan is in compliance with Statement of Financial Accounting
Standards No. 92, "Regulated Enterprises - Accounting for Phase-In Plans."
As prescribed by the Rate Agreement, NAEC is phasing in its 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 May 16, 1991 reorganization date of PSNH (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. On the Acquisition Date, NAEC recorded
the $50.9 million deferred return and $32.9 million of income taxes
associated with the deferred return 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 - Seabrook on
the Balance Sheet. 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, 1993 and 1992 included $7.3 million
and $6.0 million, respectively, in special deposits that will be used to fund
the company's share of future Seabrook operational costs.
<F5>
2. NUCLEAR DECOMMISSIONING
A 1991 Seabrook decommissioning study 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 NAEC's 36.0 ownership share of Seabrook
1, in year-end 1993 dollars, is $131.7 million. Nuclear decommissioning
costs are accrued over the expected service life of the unit and are included
in depreciation expense on the Statements of Income. Nuclear decommissioning
costs amounted to $2.6 million in 1993 and $1.4 million in 1992. Nuclear
decommissioning, as a cost of removal, is included in the accumulated
provision for depreciation on the Balance Sheets.
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. 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, NAEC (including pre-Acquisition Date payments made
by PSNH) has paid approximately $7.3 million 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 $7.9 million.
<PAGE>10
Changes in requirements or technology, or adoption of a decommissioning
method other than immediate dismantlement, could change decommissioning cost
estimates. 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.
<F6> 3. SHORT-TERM DEBT
NAEC is a limited participant in the Northeast Utilities System Money Pool
(Pool). As a limited participant, NAEC is limited to borrowing funds
provided by NU parent. The Pool provides a more efficient use of the cash
resources of the system, and reduces outside short-term borrowings. NUSCO
administers the Pool as agent for the member companies. Short-term borrowing
needs of the member companies are first met with available funds of other
member companies, including funds borrowed by NU parent. NU parent may lend
to the Pool but may not borrow. However, borrowings based on loans
from NU parent bear interest at NU parent's cost and must be repaid based
upon the terms of NU parent's original borrowing. Funds may be withdrawn
from or repaid to the Pool at any time without prior notice. Investing and
borrowing subsidiaries receive or pay interest based on the average daily
Federal Funds rate.
Maturities of NAEC's 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.
Under the SEC restrictions, NAEC was authorized, as of January 1, 1993, to
incur short-term borrowings up to a maximum of $50 million.
<F7>
4. LONG-TERM DEBT
Details of long-term debt outstanding are:
- -------------------------------------------------------------------------
December 31,
---------------
1993 1992
- -------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
9.05% Series A, due 2002. . . . . . . . $355,000 $355,000
Notes:
15.23% due 2000. . . . . . . . . . . . . 205,000 205,000
-------- --------
Long-term debt, net $560,000 $560,000
======== ========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1993 for the years 1994 through 1998 are
approximately $0 in 1994 and $20,000,000 for 1995-1998.
The Series A Bonds are not redeemable prior to maturity except out of
proceeds of sales of property subject to the lien of the Series A First
Mortgage Bond Indenture (Indenture), at general redemption prices established
by the Indenture, and out of condemnation or insurance proceeds and through
the operation of the sinking fund discussed above.
Essentially all of NAEC's utility plant is subject to the lien of its
Indenture.
<PAGE>11
<F8>
5. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
- -----------------------------------------------------------------------------
January 1, June 5,
to to
For the Periods December 31, 1993 December 31, 1992
<F4>(Note 1)
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Current income taxes:
Federal. . . . . . . . . . . . $(33,225) $(16,350)
State. . . . . . . . . . . . . 124 -
--------- ---------
Total current . . . . . . . . (33,101) (16,350)
--------- ---------
Deferred income taxes, net:
Federal . . . . . . . . . . . . 37,199 16,240
State . . . . . . . . . . . . . (78) 1,979
--------- ---------
Total deferred . . . . . . . . 37,121 18,219
--------- ---------
Total income tax expense . . . $ 4,020 $ 1,869
========= =========
The components of total income tax expense are classified as follows:
Income taxes charged to
operating expenses. . . . . . . $ 5,673 $ 2,583
Income taxes associated with
allowance for funds used
during construction (AFUDC)
and deferred Seabrook 1
return - borrowed funds. . . . . - 9,714
Other income taxes - credit . . . (1,653) (10,428)
--------- ---------
Total income tax expense. . . . . $ 4,020 $ 1,869
========= =========
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
- -----------------------------------------------------------------------------
January 1, to June 5,
to to
For the Periods December 31, 1993 December 31, 1992
<F4>(Note 1)
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation. . . . . . . . . . . $23,000 $16,146
Alternative minimum tax . . . . . 1,250 (7,641)
AFUDC and deferred Seabrook
return, net. . . . . . . . . . . 13,792 9,714
Property taxes. . . . . . . . . . (1,003) -
Other . . . . . . . . . . . . . . 82 -
------- -------
Deferred income taxes, net. . . . $37,121 $18,219
======= =======
<PAGE>12
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rate is as follows:
- -----------------------------------------------------------------------------
January 1, June 5,
to to
For the Periods December 31, 1993 December 31, 1992
<F4>(Note 1)
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income for
1993 and at 34 percent for
1992 . . . . . . . . . . . . . . $10,506 $ 4,954
Tax effect of differences:
Depreciation differences. . . . . (1,481) (1,546)
Deferred Seabrook return -
other funds. . . . . . . . . . . (4,689) (2,647)
State income taxes, net of federal
benefit. . . . . . . . . . . . . 30 1,306
Other, net. . . . . . . . . . . . (346) (198)
------- -------
Total income tax expense . . $ 4,020 $ 1,869
======= =======
<F9> 6. DEFERRED OBLIGATION - AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with
the phase-in under the Contract, it began accruing a deferred return on a
portion of its Seabrook investment. From May 16, 1991 to the Acquisition
Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition
Date, PSNH transferred the $50.9 million deferred return to NAEC as part of
the Seabrook-related assets.
At the time PSNH sold the deferred return to NAEC, it realized, for income
tax purposes, a gain that is deferred under the consolidated income tax
rules. This gain will be restored for income tax purposes when the deferred
return of $50.9 million, and the associated income taxes of $32.9 million,
are collected by NAEC through the Contract. When NAEC recovers the $32.9
million in years eight through ten of the Rate Agreement, it is obligated to
make corresponding payments to PSNH.
On the Acquisition Date, NAEC recorded the $32.9 million of income taxes
associated with the deferred return as an adjustment to the purchase price of
the Seabrook-related assets, with a corresponding obligation to PSNH, on its
Balance Sheet. In 1993, due to changes in tax rates, this amount was
adjusted to $33.3 million.
<F10>
7. COMMITMENTS AND CONTINGENCIES
SEABROOK 1 CONSTRUCTION PROGRAM
The construction program for Seabrook 1 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 other actions taken by regulatory bodies.
<PAGE>13
NAEC currently forecasts construction expenditures (including AFUDC) for its
share of Seabrook 1 to be $37.8 million for the years 1994-1998, including
$8.2 million for 1994. In addition, NAEC estimates that its share of
Seabrook 1 nuclear fuel requirements will be $53.5 million for the years
1994-1998, including $4.9 million for 1994.
ENVIRONMENTAL MATTERS
NAEC 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. NAEC 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 future construction. 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 NAEC's existing investment in Seabrook 1 and
could raise operating costs significantly. As a result, NAEC may incur
significant additional environmental costs, greater than amounts included in
cost of removal and other reserves, in connection with the generation of
electricity and the storage, transportation, and disposal of by-products and
wastes. NAEC may also encounter significantly increased costs to remedy the
environmental effects of prior waste handling and disposal activities.
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 NAEC
may be determined to be legally liable by the federal or state environmental
agencies. In addition, NAEC 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 NAEC's financial position or future results of operations.
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. At December 31, 1993, based on NAEC's ownership
interest in Seabrook 1, the maximum liability would be $28.2 million per
incident. Payments for NAEC's ownership interest in Seabrook 1 would be
limited to a maximum of $3.6 million per incident per year.
<PAGE>14
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL)
to cover the cost of repair, replacement, or decontamination or premature
decommissioning of utility property resulting from insured occurrences with
respect to NAEC's ownership interest in Seabrook 1. All companies insured
with NEIL are subject to retroactive assessments if losses exceed the
accumulated funds available to NEIL. The maximum potential assessments
against NAEC with respect to losses arising during current policy years
are approximately $4.6 million under the property damage, decontamination,
and decommissioning policies. Although NAEC 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 NAEC with respect to losses arising
during the current policy period are approximately $1.2 million.
Under the terms of the Contract, any nuclear insurance assessments described
above would be passed on to PSNH as a "cost of service."
<F11>
8. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash, special deposits and nuclear decommissioning trust: The carrying
amounts approximate fair value.
Long-term debt: The fair value of NAEC's long-term debt is based upon the
quoted market price for those issues or similar issues.
The carrying amounts of NAEC's financial instruments and the estimated fair
values are as follows:
- ----------------------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds. . . . . . . . . . $355,000 $373,496
Other long-term debt. . . . . . . . . . 205,000 254,057
- ----------------------------------------------------------------------------
Carrying Fair
At December 31, 1992 Amount Value
- ----------------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds. . . . . . . . . . . $355,000 $369,200
Other long-term debt. . . . . . . . . . . 205,000 262,400
<PAGE>15
The fair values shown above have been reported to meet the 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, NAEC will adopt SFAS 115 on a prospective basis. NAEC
anticipates that the adoption of SFAS 115 will not have a material impact on
future results of operations or financial position.
<PAGE>16
NORTH ATLANTIC ENERGY CORPORATION
- -----------------------------------------------------------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- -----------------------------------------------------------------------------
To the Board of Directors
of North Atlantic Energy Corporation:
We have audited the accompanying balance sheets of North Atlantic Energy
Corporation (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1993 and 1992, and the related
statements of income, common stockholder's equity, and cash flows for the
year ended December 31, 1993 and the period from June 5, 1992 to December 31,
1992. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of North Atlantic Energy
Corporation as of December 31, 1993 and 1992, and the results of its
operations and cash flows for the year ended December 31, 1993 and the period
from June 5, 1992 to December 31, 1992, in conformity with generally accepted
accounting principles.
As discussed in <F4> Note 1 to the Financial Statements, "Summary of
Significant Accounting Policies - Accounting Changes," effective January 1,
1993, North Atlantic Energy Corporation changed its method of accounting for
income taxes.
/s/Arthur Andersen & Co.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut
February 18, 1994
<PAGE>17
NORTH ATLANTIC ENERGY CORPORATION
- ----------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- ----------------------------------------------------------------------------
This section contains management's assessment of North Atlantic Energy
Corporation (the company or NAEC) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This section should be
read in conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
Overview
On June 5, 1992 (the Acquisition Date), NU and Public Service Company of New
Hampshire (PSNH) completed an affiliation, which represented the second step
of a two-step bankruptcy court approved plan (the Plan) that was devised in
1989 to return then-bankrupt PSNH to financial health. The first step took
place on May 16, 1991 (the Reorganization Date) when PSNH emerged from
bankruptcy as a stand-alone company, subject to a Merger Agreement (the
Merger Agreement) with NU's subsidiaries Northeast Utilities Service Company
and NU Acquisition Corporation (NUAC). The final step in the affiliation
plan occurred on June 5, 1992, when NUAC merged into PSNH pursuant to the
Merger Agreement and PSNH became a wholly owned operating subsidiary of NU.
In a related transaction, PSNH's 35.6 percent share of the Seabrook 1 nuclear
power plant (Seabrook) and other Seabrook-related assets were transferred to
the company. On June 29, 1992, North Atlantic Energy Service Corporation,
another wholly owned subsidiary of NU, received approval to manage Seabrook
as agent for the Seabrook joint owners.
At the Acquisition Date, PSNH and the company entered into the Seabrook Power
Contract, under which PSNH is obligated to buy from the company, and the
company is obligated to sell to PSNH, all of the company's capacity and
output of Seabrook for a period equal to the length of the Nuclear Regulatory
Commission full-power operating license for Seabrook (through 2026). Under
the contract, PSNH is unconditionally obligated to pay the company's "cost of
service" during the period whether or not Seabrook is operating and without
regard to the cost of alternative sources of power. In addition, PSNH will
be obligated to pay decommissioning and project cancellation costs after the
termination of the operating license.
The company's "cost of service" includes all of its prudently incurred
Seabrook-related costs, including operation and maintenance expense, fuel
expense, property tax expense, depreciation expense, certain overhead and
other costs, and a phased-in return on its Seabrook investment. The Seabrook
Power Contract established the initial recoverable investment in Seabrook at
$700 million (Initial Investment), plus any capital additions, net of
depreciation.
The company's only assets are Seabrook and other Seabrook-related assets and
its only source of revenue is the Seabrook Power Contract. PSNH's
obligations under the Seabrook Power Contract are solely its own and
have not been guaranteed by NU. The Seabrook Power Contract contains no
provisions entitling PSNH to terminate its obligations. If, however, PSNH
were to fail to perform its obligations under the Seabrook Power Contract,
the company would be required to find other purchasers for Seabrook power.
Under the Seabrook Power Contract, the company is not entitled to earn an
immediate cash return on the full amount of its Initial Investment in
Seabrook, but instead is required to phase-in its return on the Initial
Investment. The portion of the Initial Investment on which the company is
entitled to earn a return is 20 percent in the first year after the
Reorganization Date, increasing by 20 percent in the second year and by 15
percent in each of the next
<PAGE>18
four years, resulting in 100 percent recovery in the sixth and each succeeding
year. The company is entitled to earn a noncash deferred return on the portion
of the Initial Investment not yet phased into rates. The company is currently
earning a return on 55 percent of its Seabrook investment.
When PSNH emerged from bankruptcy on May 16, 1991, in accordance with the
phase-in under the Seabrook Power Contract, it began accruing a deferred
return on a portion of its Seabrook investment. From May 16, 1991
to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On
the Acquisition Date, PSNH transferred the $50.9 million deferred return to
the company as part of the Seabrook-related assets. NAEC recorded the $50.9
million as an adjustment to 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--Seabrook on the 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.
At the time PSNH transferred the deferred return to NAEC, it realized, for
income tax purposes, a gain that is deferred under the consolidated income
tax rules. This gain will be restored for income tax purposes when the
deferred return of $50.9 million, and the associated income taxes of
$32.9 million, are collected by NAEC from PSNH through the Seabrook Power
Contract over the period beginning six months after the end of PSNH's fixed
rate period through May 15, 2001. When NAEC recovers the $32.9 million, it
is obligated to make corresponding payments to PSNH. On the Acquisition
Date, NAEC recorded on its balance sheet the $32.9 million as an adjustment
to the purchase price of the Seabrook-related assets, with a corresponding
obligation to PSNH.
In 1992, the company recorded a deferred assessment and obligation for the
estimated costs for the company's Seabrook share of an assessment for costs
for the decontamination and decommissioning of uranium enrichment plants
operated by the United States Department of Energy (DOE). The company
expects to recover these amounts from PSNH as part of the cost of Seabrook
fuel.
In 1993, the company adopted Statement of Financial Accounting Standards
(SFAS) No. 109, "Accounting for Income Taxes." 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.
See the "Notes to Financial Statements" for further details on deferred
charges and recently adopted accounting standard.
RATE MATTERS
PSNH's rate agreement with the State of New Hampshire (the Rate Agreement)
provides the financial basis for the affiliation plan. It 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 first of these base rate
increases was put in effect on January 1, 1990. The remaining three
increases are effective annually on each June 1 beginning in 1994.
The FPPAC allows PSNH to recover from its customers the difference between
actual prudent energy and purchased power costs, including the costs incurred
under the Seabrook Power Contract, and the costs included in base rates.
In January 1994, the NHPUC approved a Memorandum of Understanding between
PSNH, NAEC, Northeast Utilities Service Company (NUSCO), and the Attorney
General of the State of New Hampshire relating to certain issues which had
arisen under the Rate Agreement (the Global Settlement). The Global
Settlement addressed changes in tax legislation in New Hampshire, accounting
treatments for PSNH resulting from adoption of SFAS
<PAGE>19
No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions"
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.
NAEC became the purchaser of the VEG&T's 0.4 percent share of Seabrook and
entered into a separate power contract with PSNH, under which PSNH is
obligated to buy from NAEC all of the capacity and output of Seabrook
attributable to such interest for a period equal to the length of the NRC
full power operating license for Seabrook. On January 7, 1994, the NRC
approved the transfer of VEG&T's ownership share of Seabrook to NAEC. All
regulatory approvals for NAEC's purchase have been received and the closing
was effective in February 1994.
On April 16, 1993, the Governor of New Hampshire signed into law legislation
that implemented the settlement of a suit concerning a property tax on
Seabrook station (the Seabrook Tax) that was filed with the United States
Supreme Court by Attorneys General of Connecticut, Massachusetts, and Rhode
Island. The legislation made various changes to New Hampshire tax laws. The
change in the tax law required the State of New Hampshire to refund to the
joint owners of Seabrook a total of $8.8 million in each of 1993 and 1994.
NAEC has recognized a receivable and an obligation to PSNH for PSNH and
NAEC's share of the refund. The tax refund is being refunded to PSNH through
the FPPAC.
SEABROOK PERFORMANCE
In 1993 Seabrook operated at a capacity factor of 89.8 percent as compared to
77.9 percent for the same period in 1992 and a national average of 70.6
percent for 1993. The unit was shutdown on September 7, 1992 for refueling
and maintenance and returned to service on November 13, 1992. The unit is
scheduled to begin a 56-day refueling and maintenance outage on March 26,
1994.
NAEC could be affected by the ability of other Seabrook joint owners to fund
their shares of Seabrook costs. Great Bay Power Corporation, an owner of a
12.13 percent entitlement in Seabrook is operating under bankruptcy
protection of Chapter 11 of the Federal Bankruptcy Code. It is expected that
Great Bay or certain companies that Great Bay has agreements with will have
funds sufficient to fund the upcoming Seabrook outage.
ENVIRONMENTAL MATTERS
NAEC 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 cumulative long-term economic cost impact of
increasingly stringent environmental requirements cannot be estimated.
However, NAEC has an active environmental auditing program to detect and
remedy noncompliance with environmental laws or regulations. NAEC may incur
significant additional costs, greater than amounts included in cost of
removal and other reserves, in connection with the generation of electricity
and the storage, transportation, and disposal of by-products and wastes.
NAEC may also encounter significantly increased costs to remedy the
environmental effects of prior waste handling and disposal practices.
The estimated cost of decommissioning NAEC's 36.0 ownership share of
Seabrook, in year-end 1993 dollars, is $131.7 million. Nuclear
decommissioning costs are accrued over the expected service life of the unit
and are included in depreciation expense on the Statements of Income.
Nuclear decommissioning costs amounted to $2.6 million in 1993 and $1.4
million in 1992. Nuclear decommissioning, as a cost of removal, is included
in the accumulated provision for depreciation on the Balance Sheets.
See "Notes to Financial Statements" for further information regarding nuclear
decommissioning and other environmental matters.
<PAGE>20
LIQUIDITY AND CAPITAL RESOURCES
Cash flows from operations provided the primary source of funds for the
period ended December 31, 1993, while repayment of short-term debt and
investment in nuclear fuel and plant were the primary uses of funds. Nuclear
fuel expenditures for the period are high due to higher purchases in 1993 in
preparation for a March 1994 refueling and maintenance outage.
The company had negative cash flow from operations for the period June 5,
1992 through December 31, 1992 due to a substantial portion of its earnings
being noncash.
At the Acquisition Date, NAEC assumed PSNH's obligations under the $205
million of 15.23 percent notes (the Notes) and paid $504 million to PSNH for
the purchase of PSNH's interest in Seabrook. The company financed these
requirements out of the proceeds from the sale of $355 million Series A First
Mortgage Bonds and the sale of its common stock to NU for $161 million. As a
result of these transactions and the assumption of the Notes, the company's
initial capitalization is approximately 78 percent debt and 22 percent common
equity. In addition, the company borrowed amounts under the NU system Money
Pool for ongoing cash requirements. As of December 31, 1993, there are no
borrowings under the Money Pool. (See "Notes to Financial Statements" for
information regarding the Money Pool.)
The company will have ongoing cash requirements for Seabrook-related capital
expenditures, nuclear fuel expenditures, interest and operating expenses.
Capital expenditures for the period 1994 through 1998 are expected to be
approximately $37.8 million (including AFUDC), including $8.2 million for
1994. Nuclear fuel expenditures for the same period are expected to be
approximately $53.5 million (excluding AFUDC), including $4.9 million for
1994. Such cash requirements are expected to be met from payments under the
Seabrook Power Contract and the Tax Allocation Agreement, except that to the
extent some or all of the capital expenditures and nuclear fuel expenditures
may have to be financed, the company expects to borrow under the Money Pool.
A substantial portion of the company's cash flow for the first few years is
expected to consist of payments made by NU to the company under a Tax
Allocation Agreement that the company entered into with NU at the time of
the acquisition. The amount of such payments will decrease over time but is
expected to remain substantial during the first few years when the company is
expected to incur losses for tax purposes due to accelerated tax depreciation
of Seabrook. The company received approximately $33 million from NU for the
period ended December 31, 1993 under this agreement. No assurance can be
given, however, as to the extent of the future benefits, if any, that will
actually accrue to the company under the Tax Allocation Agreement. (See
"Notes to Financial Statements" for further information regarding the Tax
Allocation Agreement.)
RESULTS OF OPERATIONS
The company has no historical results prior to June 5, 1992. Therefore, the
Statements of Income for the periods June 5, 1992 to December 31, 1992 and
January 1, 1993 to December 31, 1993 are not comparable.
Operating revenues represent amounts from PSNH under the terms of the
Seabrook Power Contract and billings to PSNH for decommissioning expense.
Operating expenses represent the costs incurred for the operation of Seabrook
including fuel expense.
The deferred Seabrook return represents the investment return not recovered
currently on the portion of the Seabrook investment not reflected in rate
base.
Income taxes included in other income represent the tax benefits related to
the portion of the Seabrook investment not reflected in rate base.
<PAGE>21
Interest on long-term debt and other interest reflects the interest expenses
on the debt incurred and assumed at the acquisition.
<PAGE>22
NORTH ATLANTIC ENERGY CORPORATION
- -----------------------------------------------------------------------------
SELECTED FINANCIAL DATA
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
1993 1992<F12>*
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues . . . . . . . . $125,408 $ 78,444
======== ========
Operating Income . . . . . . . . . $ 33,718 $ 16,122
======== ========
Net Income . . . . . . . . . . . . $ 25,998 $ 12,703
======== ========
Total Assets . . . . . . . . . . . $900,821 $818,123
======== ========
Long-Term Debt . . . . . . . . . . $560,000 $560,000
======== ========
- -----------------------------------------------------------------------------
STATISTICS 1993 1992<F12>*
- -----------------------------------------------------------------------------
Gross Electric Utility Plant
December 31,
(Thousand of Dollars). . . . . . . $789,127 $774,920
======== ========
kWh Sales (Millions) . . . . . . . 3,218 1,268
======== ========
- -----------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- -----------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------------
1993 March 31 June 30<F13>** September 30 December 31
- -----------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues . . $29,153 $29,952 $31,845 $34,458
======= ======= ======= =======
Operating Income . . . $ 6,541 $ 7,964 $ 9,657 $ 9,556
======= ======= ======= =======
Net Income . . . . . . $ 5,185 $ 5,985 $ 7,491 $ 7,337
======= ======= ======= =======
1992
- -----------------------------------------------------------------------------
Operating Revenues . . $ - $ 8,785 $32,439 $37,220
======== ======= ======= =======
Operating Income . . . $ - $ 2,010 $ 6,988 $ 7,124
======== ======= ======= =======
Net Income . . . . . . $ - $ 1,119 $ 6,822 $ 4,762
======== ======= ======= =======
<F12> *The company began commercial operations on June 5, 1992. Information
presented for 1992 covers the period June 5, 1992 through December 31,
1992.
<F13>**In 1992, represents the period June 5, 1992 through June 30,
1992.
<PAGE>23
North Atlantic Energy Corporation
First Mortgage Bonds
--------------------
Trustee and Interest Paying Agent
United States Trust Company of New York
114 West 47th Street
New York, New York 10036
15.23% Notes
------------
Trustee and Interest Paying Agent
United States Trust Company of New York
114 West 47th Street
New York, New York 10036
Address General Correspondence in Care of:
Northeast Utilities Service Company
Investor Relations Department
P.O. Box 270
Hartford, Connecticut 06141-0270
Tel. (203) 665-5000
General Office
1000 Elm Street
P.O. Box 330
Manchester, New Hampshire 03105
_______________________________
<PAGE>
