FINANCIAL AND STATISTICAL
TABLE OF CONTENTS
12 Management's Discussion and Analysis
20 Company Report
20 Report of Independent Public Accountants
21 Consolidated Financial Statements
29 Notes to Consolidated Financial Statements
and related schedules
11
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
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OVERVIEW
Northeast Utilities' (NU) financial outlook improved in 1998 despite retail
rate decreases for each of the company's regulated subsidiaries. The improved
outlook is a result of the successful restart of the Millstone 3 nuclear power
plant, significant progress toward the restart of Millstone 2 and significant
reductions in operating expenses.
NU lost $1.12 a share in 1998, compared with a loss of $1.01 a share in 1997
and a profit of $0.30 a share in 1996. The loss was greater in 1998 as a result
of significant write-offs of The Connecticut Light and Power Company's (CL&P)
investment in the retired Millstone 1 nuclear power plant and the accelerated
amortization of regulatory assets as ordered by Connecticut state regulators in
CL&P's February 1999 retail rate decision.
Operation and maintenance (O&M) costs at Millstone Station declined to $392
million in 1998 from $551 million in 1997. That decline was driven primarily by
the decision to retire Millstone 1 and the return to service of Millstone 3.
Aside from Millstone, nonfuel O&M costs totaled $984 million in 1998,
compared with $1,055 million in 1997. That reduction continued a two-year trend
of declining costs at NU. In 1996, nonfuel O&M costs, not including Millstone
costs, totaled $1,170 million.
Partially offsetting the benefits from lower O&M was a 2 percent drop in
total revenues, which fell to $3.77 billion in 1998 from $3.83 billion in 1997.
The fall in revenues occurred, despite a 1.9 percent increase in retail
kilowatt-hour sales for the year, as a result of a series of retail rate
decreases implemented by regulators in the three states served by the NU system.
CL&P's annual revenues were reduced by a total of $68 million in 1998 as a
result of the removal of the Millstone units from rate base. A 10 percent
reduction in Western Massachusetts Electric Company (WMECO) rates occurred in
two steps in 1998, and a 6.87 percent reduction in Public Service Company of New
Hampshire (PSNH) base rates went into effect December 1, 1997.
Also offsetting the lower O&M were significant increases in certain noncash
expenses. Primarily as a result of Connecticut regulatory decisions,
amortization of regulatory assets totaled $203 million, up from $124 million in
1997.
NU's ability to improve its financial performance in 1999 will depend
primarily on its success in bringing Millstone 2 back on line and further
reducing its operating costs to help offset continued downward pressure on
retail revenues. CL&P will continue to be negatively affected by the $232
million reduction in revenue requirements ordered by Connecticut state
regulators in February 1999. WMECO's financial performance will be affected by
the carryover of 1998 rate reductions, plus another 5 percent rate reduction,
adjusted for inflation, that is scheduled to take effect September 1, 1999. A
final decision in PSNH's rate case and the resolution of New Hampshire
restructuring could have substantial impacts on both NU and PSNH if completed in
1999.
NU's financial performance also will be affected by the performance of
Select Energy, Inc. (Select), NU's unregulated marketing subsidiary. In December
1998, Select began serving two contracts covering a 13-month period with Boston
Edison that will provide approximately $300 million in revenues through December
31, 1999. Select has a number of other contracts in effect in 1999 with other
retail and wholesale customers. Select expects total revenues to exceed $600
million in 1999.
NU also expects that 1999 will be a pivotal year in implementing the
company's strategy of becoming one of the leading energy providers in the
Northeast United States. During the first quarter of 1999, NU established three
new subsidiaries: NU Enterprises, Inc., Northeast Generation Company and
Northeast Generation Services Company. These entities will engage in a variety
of energy-related activities, including the acquisition and management of
non-nuclear generating plants. The scope and success of NU's strategy, however,
will depend on many factors, including the outcome and timing of restructuring
decisions or settlements, its ability to successfully bid in auctions and to
finance the activities of its unregulated businesses and other factors affecting
the energy market that cannot be estimated at this time.
CL&P and WMECO are in the process of auctioning approximately 4,000
megawatts (MW) of fossil and hydroelectric generating capacity. Management also
hopes in 1999 to begin the process of securitizing stranded costs, a means of
monetizing the NU system companies' regulatory assets and certain other stranded
costs. The companies intend to use most of the proceeds from asset sales and
securitization to repay outstanding debt and preferred securities.
Management expects a relatively modest portion of those proceeds to be used
to reduce common equity investment in the subsidiaries through payment of
special dividends to the parent company. Proceeds received by the parent company
could be used to repurchase common shares or to invest further in regulated
energy delivery businesses, unregulated generation or marketing ventures. In
1998, the Board of Trustees approved the repurchase of up to 10 million shares
through July 1, 2000.
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RESTRUCTURING
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Although the NU system companies continue to operate under cost-of-service based
regulation, future rates and the recovery of stranded costs are issues under
various restructuring plans in each of the NU system companies' service
territories. Stranded costs are expenditures or commitments that have been made
to meet public service obligations with the expectation that they would be
recovered from customers. However, under certain circumstances these costs might
not be recoverable from customers in a fully competitive electric utility
industry (i.e., the costs may result in above-market energy prices).
The NU system has exposure to stranded costs for its investments in
high-cost nuclear generating plants, state-mandated purchased-power obligations
and significant regulatory assets. As of December 31, 1998, the system
companies' net investment in nuclear generating plants, excluding its investment
in certain regional nuclear companies, was approximately $2.9 billion ($1.9
billion for CL&P, $83 million for PSNH, $365 million for WMECO and $591 million
for North Atlantic Energy Corporation [NAEC]) and its regulatory assets were
approximately $2.3 billion ($1.4 billion for CL&P, $610 million for PSNH and
$322 million for WMECO).
The NU system's financial strength and resulting ability to compete in a
restructured environment will be negatively affected if the NU system companies
are unable to recover their past investments and commitments.
CONNECTICUT
In April 1998, Connecticut enacted comprehensive electric utility restructuring
legislation. The act provides for rates to be capped at December 31, 1996,
levels until December 31, 1999. Retail choice will be phased in over six months
beginning January 1, 2000, and will extend to all retail customers by July 2000.
Customers not choosing an alternate supplier can continue to receive service
until January 2004 at a rate that is at least 10 percent less than 1996 rates.
The law allows for recovery of all prudently incurred stranded costs and
mandates the functional separation of competitive and regulated businesses. To
qualify for stranded cost recovery, CL&P must auction off all fossil and
hydroelectric generating facilities prior to January 2000 and its nuclear
generating assets prior to January 2004. CL&P also received regulatory approval
to auction any of its purchased-power contracts which cannot be renegotiated by
March 1999.
The Connecticut legislation allows the use of securitization after January
1, 2000, to further reduce the costs of the transition to a competitive
marketplace. The use of securitization is limited, however, to non-nuclear
generation-related regulatory assets and costs associated with the renegotiation
of purchased-power contracts. CL&P may not securitize nuclear stranded costs.
The Connecticut Department of Public Utility Control (DPUC) will initiate an
investigation into CL&P's stranded costs in the spring of 1999 with a final
decision expected before the end of the year.
As a result of the corporate unbundling and divestiture proposals, CL&P will
redefine itself as a distribution company under the restructuring legislation,
and will provide generation services only to the extent necessary to provide
standard offer, backup and default services as required by customers who have
not chosen an alternate energy supplier.
NEW HAMPSHIRE
Restructuring efforts in New Hampshire have resulted in numerous proceedings
within the federal and state court systems. The New Hampshire Public Utilities
Commission's (NHPUC) 1997 restructuring orders have been prevented from being
implemented as a result of various court actions pending the outcome of a full
trial in the U.S. District Court. The 1997 orders would have forced PSNH and
NAEC to write off substantially all of their regulatory assets. A trial is
expected to begin in mid to late 1999.
The litigation has caused New Hampshire to fall behind several other
Northeast states in implementing industry restructuring. PSNH believes that a
negotiated resolution of outstanding restructuring and rate issues would be in
the best interests of the state, PSNH and customers.
MASSACHUSETTS
In November 1997, Massachusetts enacted comprehensive electric utility industry
restructuring legislation. As required by that legislation, WMECO instituted a
10 percent rate reduction in 1998 and continues to work with the Massachusetts
Department of Telecommunications and Energy (DTE) on implementing WMECO's
restructuring plan. In September 1999, WMECO must institute another
5 percent rate reduction, adjusted for inflation.
In January 1999, WMECO announced the sale of approximately 290 MW of fossil
and hydroelectric generating capacity to Consolidated Edison Energy, Inc. for
$47 million. The sale price is approximately 3.8 times greater than the assets'
1997 book value of $12.5 million. WMECO hopes to close on that transaction in
midsummer and expects to use the majority of the proceeds to repay outstanding
debt. The sale of these assets and future asset sales will be used to reduce
WMECO's stranded costs. WMECO will auction another 270 MW of pumped storage and
conventional hydroelectric plant later in 1999. WMECO has notified the DTE that
it will seek to auction its ownership in the Millstone units.
The rate reductions caused WMECO's annual revenues to decline to $393
million in 1998 from $426 million in 1997. WMECO's ability to improve financial
performance in 1999 will be driven by containing operating costs and using the
proceeds from asset sales and securitization to reduce financing costs. WMECO
expects to seek approval to securitize up to $500 million in stranded costs.
Following the sale of its generating assets, WMECO will continue to operate
and maintain the transmission and local distribution network and deliver
electricity to its customers.
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RATE MATTERS
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CONNECTICUT
In February 1999, the DPUC issued a final order in CL&P's retail rate proceeding
reducing CL&P's revenue requirements by approximately $232 million retroactive
to September 28, 1998. To implement that reduction, the DPUC ordered CL&P to
reduce its retail base rates by approximately $96 million annually and to
increase its amortization of regulatory assets by $136 million annually. The
rate order allowed CL&P to earn a return on equity of 10.3 percent. The DPUC
also said it would allow CL&P to recover only $126 million of its investment in
Millstone 1 undepreciated plant and related assets. As a result of this
decision, CL&P reflected in 1998 a one-time pretax charge of $116.5 million and
began amortizing its remaining Millstone 1 investment over three years.
In a February 1998 decision, the DPUC removed Millstone 2 from CL&P's rate
base effective May 1, 1998, and Millstone 3 effective July 1, 1998. On July 18,
1998, Millstone 3 returned to rate base. Millstone 1 previously had been removed
from CL&P's rate base effective March 1, 1998, with customers receiving a
temporary credit of approximately 1.4 percent, or $30 million annually, on their
bills.
The removal of Millstone 2 reduced CL&P's noncash revenues by approximately
$3 million a month. This reduction was increased in the 1999 rate order to
nearly $6.6 million per month to reflect lower fuel costs. Actual fuel costs
are subject to true-up in the Energy Adjustment Clause.
NEW HAMPSHIRE
In May 1998, the NHPUC approved slightly more than a 1 percent net increase in
PSNH's fuel and purchased-power adjustment clause (FPPAC) rate for the period
June through November 1998. As part of this proceeding, PSNH agreed to offset in
base rates the scheduled reduction in acquisition premium amortization with the
scheduled amortization of the Seabrook deferred return.
On December 1, 1998, the NHPUC approved a Stipulation and Settlement
executed by PSNH, the NHPUC staff, and the Governor's Office of Energy and
Community Services. They recommended that PSNH's currently effective FPPAC rate
be continued for another six-month period -- December 1, 1998, through May 31,
1999. The FPPAC rate currently in effect will produce an estimated $80 million
underrecovery as of May 31, 1999. All other FPPAC costs are being recovered on a
current basis.
A PSNH rate case has been pending at the NHPUC since May 1997 but was
delayed in connection with various restructuring proceedings. In November 1997,
the NHPUC ordered a temporary rate reduction of 6.87 percent effective December
1, 1997. A final rate case decision currently is scheduled to be issued by June
1, 1999, the same date when PSNH's FPPAC rate is scheduled to be set for the
second half of 1999. The final decision will be reconciled to July 1, 1997.
PSNH's ongoing settlement negotiations with the state of New Hampshire could
resolve both the rate case and FPPAC issues discussed above.
MILLSTONE NUCLEAR UNITS
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The NU system owns 100 percent of Millstone 2 and approximately 68 percent of
Millstone 3. NU's poor financial performance from 1996 through 1998 was due
primarily to the lengthy outages at Millstone. Costs peaked in 1997 when
replacement power costs and operation and maintenance costs totaled nearly $900
million. In 1998, Millstone-related costs fell significantly as Millstone 3
returned to service and Millstone 1 began to prepare for decommissioning.
After a 27-month outage, Millstone 3 received Nuclear Regulatory Commission
(NRC) permission to restart in June 1998 and reached full power in July. The
unit achieved a capacity factor of approximately 70 percent in the second half
of 1998. NU's share of the operation, maintenance and replacement power costs
associated with Millstone 3 totaled approximately $164 million in 1998, down
from $304 million in 1997. The unit remains on the NRC's watch list with a
Category 2 designation, which means that it will continue to be subject to
heightened NRC oversight. A refueling and maintenance outage is scheduled to
begin in May 1999.
Millstone 2 remains on the NRC watch list with a Category 3 designation,
meaning that NRC commissioners must formally vote to allow restart. Key steps
before restart include final verification that the unit is in conformance with
its design and licensing basis; that management processes support safe and
conservative operations; and that the employees are effective at identifying and
correcting deficiencies at the unit. Millstone 2 is on schedule for a spring
1999 restart following final NRC review and approval. Millstone 2's return is
expected to restore $6.6 million a month in noncash revenues to CL&P, reduce
fuel and purchased-power expense by approximately $8 million a month, and
significantly reduce the unit's operation and maintenance expenses, which
totaled $220 million in 1998. In a July 1998 filing with the DPUC, management
concluded that Millstone 2 had over $400 million of economic value over the 17
years remaining on its license life. In its February rate decision, the DPUC
concurred that the unit was economic for customers and ordered it to be restored
to CL&P rate base once it operates at 75 percent or more power for 100
consecutive hours.
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SEABROOK
The NU system owns 40 percent of the Seabrook nuclear unit. Seabrook's capacity
factor was 82.8 percent in 1998. The unit operated well, except for two
unplanned outages, one in late 1997 through early 1998 and the other in
mid-1998, to repair the control building's air-conditioning system. Seabrook is
scheduled to begin a refueling outage in March 1999.
LIQUIDITY
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The NU system successfully refinanced more than $1 billion in expiring debt
obligations and bank commitments in 1998 despite a significant reported loss.
CL&P, PSNH and WMECO converted a total of $535 million variable-rate tax exempt
debt to fixed-rate tax exempt debt carrying interest rates of 5.85 to 6.0
percent. Niantic Bay Fuel Trust (NBFT), which finances CL&P's and WMECO's
nuclear fuel at Millstone, converted $180 million of maturing notes and bank
lines to five-year 8.59 percent notes. Also, PSNH successfully extended $190
million in credit ($75 million in bank credit lines and $115 million in letters
of credit).
The success in refinancing the NU system obligations was due primarily to
the progress shown in 1998 by returning Millstone 3 to service and improved cash
flows. Net cash flows from operations totaled approximately $689 million in
1998, up sharply from $377 million in 1997. Approximately $321 million of net
cash flow was used for investment activities, including construction
expenditures and investments in nuclear decommissioning trusts, compared with
$330 million in 1997. Another $26 million was used to pay preferred dividends,
compared with $62 million in common and preferred dividends in 1997. The
majority of the balance of cash used for financing activities, approximately
$351 million, was used to pay off long-term debt, short-term debt and preferred
stock, a significant shift from 1997 when net debt and preferred stock levels
were reduced by only $43 million.
The return to service of Millstone 3 and resulting reduction in costs
stabilized the NU system's credit ratings in mid-1998 after repeated downgrades
in 1996 and 1997. Moody's Investors Service, which had downgraded CL&P, WMECO
and NU debt in April 1998, upgraded those same ratings in July 1998 and
established a "positive" outlook. Also in July, Standard & Poor's (S&P) removed
the NU system from "CreditWatch--negative" for the first time in more than two
years. In September 1998, S&P upgraded CL&P, WMECO and PSNH first mortgage
bonds.
The rating agency actions also were due in part to the NU system's success
in 1998 in maintaining access to its various credit lines. Key covenants on a
$313.75 million revolving credit line primarily serving CL&P and WMECO were
adjusted in the fall. The CL&P rate decision resulted in the need for a waiver
of the revolver's equity test in the fourth quarter, which was negotiated with
banks in March 1999. PSNH renegotiated a one-year extension of a $75 million
revolving credit line in April 1998 and NU currently is seeking to extend a $25
million credit line that expires in March 1999.
The $313.75 million revolving credit line will expire on November 21, 1999.
As of February 23, 1999, CL&P and WMECO had $165 million and $60 million,
respectively, outstanding under that line. CL&P met a $140 million bond maturity
on February 1, 1999. Management expects those borrowings to increase in the
first half of 1999 as CL&P pays off a $74 million bond issue that matures July
1, 1999, and WMECO pays off a $40 million issue that matures March 1, 1999. In
1999, the NU system faces nearly $400 million of maturities and sinking-fund
payments, all of which it expects to meet through cash on hand, operating cash
flows and borrowings through its short-term facilities.
PSNH's $75 million revolving credit agreement expires on April 22, 1999, and
the company currently does not intend to renew it. PSNH will fund its needs
through operating cash flows or other short-term credit arrangements which may
be negotiated later in the year. PSNH has had no borrowings under that line
since October 1998. PSNH expects to renew the bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control bonds.
Those letters of credit also expire April 22, 1999.
CL&P and WMECO also have arranged financing agreements through the sale of
their accounts receivables. CL&P can finance up to $200 million and WMECO up to
$40 million through these facilities. As of December 31, 1998, CL&P had
financed $105 million through its accounts receivable line and WMECO had
financed $20 million.
CL&P is party to an operating lease with General Electric Capital
Corporation related to the use of four turbine generators having an installed
cost of approximately $70 million and a stipulated loss value of $59 million.
CL&P must meet certain financial covenants that are substantially similar to the
revolving credit line. CL&P has received a waiver of these tests for the fourth
quarter of 1998 as a result of the CL&P rate decision.
The permanent shutdown of Millstone 1 in July 1998 could require CL&P and
WMECO to immediately repay the NBFT approximately $80 million of capital lease
obligations. The companies are seeking consents from the note holders to amend
the lease so that they will not be obligated to make this payment. As
consideration for the note holders' consent, the companies intend to issue an
additional $80 million of first mortgage bonds in mid-1999.
NU has provided credit assurance in the form of guarantees of a letter of
credit, performance guarantees and other assurances for the financial and
performance obligations of certain of its unregulated subsidiaries. NU currently
is limited by the Securities and Exchange Commission (SEC) to an aggregate of
$75 million of such credit assurance arrangements. It is expected that NU will
seek to increase this limitation in the future.
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NUCLEAR DECOMMISSIONING
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The staff of the SEC has questioned certain current accounting practices of the
electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) had agreed to review the accounting for closure and
removal costs, including decommissioning. If current electric utility industry
accounting practices for nuclear power plant decommissioning are changed, the
annual provision for decommissioning could increase relative to 1998, and the
estimated cost for decommissioning could be recorded as a liability (rather than
as accumulated depreciation), with recognition of an increase in the cost of the
related nuclear power plant. As management believes decommissioning costs will
continue to be recovered through rates, changes to the accounting practices will
not affect net income.
MILLSTONE 1
CL&P and WMECO have ownership interests of 81 percent and 19 percent,
respectively, in Millstone 1. Based on a continued unit operation study filed
with the Connecticut DPUC in July 1998, CL&P and WMECO decided to retire
Millstone 1 and begin decommissioning activities. Subsequently, Millstone 1 was
removed from the NRC's watch list.
The total estimated decommissioning costs for Millstone 1, which have been
updated to reflect the early shutdown of the unit, are approximately $692.0
million in December 1998 dollars. CL&P and WMECO use external trusts to fund the
decommissioning costs. In 1998, CL&P recorded a charge of approximately $143.2
million for the write-off of its investment in Millstone 1 as a result of the
February 1999 rate decision and an earlier settlement with the Connecticut
Municipal Electric Energy Cooperative (CMEEC). At December 31, 1998, the NU
system had unrecovered plant and related assets for Millstone 1 of $190 million
and an unrecovered decommissioning obligation of $386 million. These amounts
have been recorded as a regulatory asset, while decommissioning and closure
obligations have been recorded as a liability. CL&P has been allowed to recover
its remaining investment in Millstone 1 over three years beginning October 1998.
The rate decision also stated that CL&P would be allowed to recover its
decommissioning costs and could defer pre-decommissioning costs commencing July
1, 1999, for future recovery. Management expects the DTE to decide on the
recovery of WMECO's share of Millstone 1 investment and decommissioning
liability as part of the ongoing restructuring docket.
YANKEE COMPANIES
The NU system has a 49 percent ownership interest in the Connecticut Yankee
Atomic Power Company (CYAPC), a 38.5 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 20 percent ownership interest in Maine Yankee Atomic
Power Company (MYAPC) and a 16 percent ownership interest in Vermont Yankee
Nuclear Power Corporation (VYNPC). The nuclear plants owned by YAEC, CYAPC and
MYAPC were shut down permanently on February 26, 1992, December 4, 1996, and
August 6, 1997, respectively.
At December 31, 1998, the NU system's share of its estimated remaining
contract obligations, including decommissioning, amounted to approximately
$418.8 million: $244.3 million for CYAPC, $143.0 million for MYAPC and $31.5
million for YAEC. Under the terms of the contracts with the Yankee companies,
CL&P, PSNH and WMECO are responsible for their proportionate share of the costs
of the units including decommissioning. Management expects to recover these
costs from customers. Accordingly, NU system companies have recognized these
costs as regulatory assets, with corresponding obligations on their balance
sheets.
The NU system companies have exposure for their investment in CYAPC as a
result of an initial decision at the Federal Energy Regulatory Commission
(FERC). Additionally, in January 1999, MYAPC filed an offer of settlement
which, if accepted by the FERC, will resolve all the issues in the FERC
decommissioning rate case proceeding. NU management cannot predict the ultimate
outcome of the FERC proceedings at this time, but believes that the associated
regulatory assets are probable of recovery. For further information on Yankee
companies see "Notes to Consolidated Financial Statements," Note 7B.
The NU system's ownership share of estimated costs, in year-end 1998
dollars, of decommissioning the nuclear plant owned by VYNPC is approximately
$84.8 million.
MILLSTONE 2, 3 AND SEABROOK 1
NU's estimated cost to decommission its shares of Millstone 2, Millstone 3 and
Seabrook 1 is approximately $974 million in year-end 1998 dollars. These costs
are being recognized over the lives of the respective units with a portion
currently being recovered through rates. As of December 31, 1998, the market
value of the contributions already made to the decommissioning trusts, including
their investment returns, was approximately $350 million. See the "Notes to
Consolidated Financial Statements," Note 2, for further information on nuclear
decommissioning.
YEAR 2000 ISSUES
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The NU system has established an action plan by which identified processes must
be completed by certain dates in order to ensure its operating systems,
including nuclear systems, and reporting systems are able to properly recognize
the year 2000. This action plan has three phases: the inventory phase, the
detailed assessment phase and the remediation phase. The inventory phase, which
has been completed, identified operating and reporting systems which may need
to be fixed. The detailed assessment phase, which has been completed,
determined exactly what needed to be done in order to ensure that the systems
identified
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during the inventory phase are able to recognize properly and process the year
2000. The final phase is the remediation phase. By the end of this phase,
mission critical systems (systems that are related to safety, keeping the lights
on, regulatory requirements, and other systems that could have a significant
financial impact) will be year 2000 ready; that is, these systems will perform
their business functions properly in the year 2000. This phase includes making
modifications, testing and validating changes and verifying that the year 2000
issues have been resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment and, if
needed, remediation. NU system purchasing policies require newly purchased
software and devices to be year 2000 compliant. None of these newly identified
items are expected to materially impact completion of the remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450 device
types containing date-sensitive computer chips. As of December 31, 1998, 73
percent of the software systems and 81 percent of the hardware were year 2000
ready, as follows:
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Percentage Complete Software Hardware
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Generation
Fossil/Hydro 58% 86%
Millstone Nuclear 76% 85%
Seabrook Nuclear 77% 81%
Transmission/Distribution 84% 70%
Other Business Systems 56% 92%
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The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems to be
completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and
business partners to determine their ability to manage the year 2000 problem
successfully. The NU system is adjusting its inventories, working with suppliers
to provide backup inventories, and changing suppliers as needed to provide for
an adequate supply of materials needed to conduct business into the year 2000.
The NU system also has worked actively with the Independent System Operator
(ISO) New England, the operator of the New England power grid, and with the
North American Electric Reliability Council to provide for the year 2000
readiness of the New England power grid.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program is $30
million. The total estimated remaining cost is $18 million, which is being
funded through operating cash flows. The majority of these costs will be
expensed as incurred in 1999. Since 1996, the NU system has incurred and
expensed approximately $12 million related to year 2000 readiness efforts. Total
expenditures related to the year 2000 are not expected to have a material effect
on the operations or financial condition of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best estimates,
which were derived utilizing numerous assumptions of future events, including
the continued availability of certain resources, third-party modification plans
and other factors. However, there can be no guarantee that these estimates will
be achieved, and actual results could differ materially from those plans. If the
NU system's remediation plans or those of third parties are not successful,
there could be a significant disruption of the NU system's operations. The most
likely worst case scenario is a limited number of localized interruptions to
electric service which can be restored within a few hours. As a precautionary
measure, NU is formulating contingency plans that will evaluate alternatives
that could be implemented if our remediation efforts are not successful. The
contingency plans are being developed by enhancing existing emergency operating
procedures to include year 2000 issues. In addition, the NU system plans to have
staff available to respond to any year 2000 situations that might arise. The
contingency plan is expected to be available by July 30, 1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other operations
to be compatible with the new millennium.
RISK-MANAGEMENT INSTRUMENTS
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The following discussion about the NU system's risk-management activities
includes forward looking statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the forward looking
statements.
This analysis presents the hypothetical loss in earnings related to the NU
system's fuel price and interest rate market risks at December 31, 1998. The NU
system uses swaps and collars to manage the market risk exposures associated
with changes in fuel prices and variable interest rates. The NU system uses
these instruments to reduce risk by essentially creating offsetting market
exposures. Based on the derivative instruments which currently are being
utilized by NU system companies to hedge some of their fuel price and interest
rate risks, there will be an impact on earnings upon adoption of Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, which management cannot estimate at this time. For more
information on NU's use of risk-management instruments, see the "Notes to
Consolidated Financial Statements," Notes 1N and 8.
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FUEL-PRICE RISK-MANAGEMENT INSTRUMENTS
In the generation of electricity, the most significant segment of the variable
cost component is the cost of fuel. Typically, most of CL&P's fuel purchases are
protected by a regulatory fuel price adjustment clause. However, for a
specific, well-defined volume of fuel that is excluded from the fuel price
adjustment clause, CL&P employs fuel-price risk-management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks are primarily created by
the sale of long-term, fixed-price electricity contracts to wholesale
customers.
At December 31, 1998, CL&P had outstanding fuel-price management instrument
agreements with a total notional value of approximately $422 million and a
negative mark-to-market position of approximately $45 million. A hypothetical 10
percent decrease in average 1998 fuel prices during 1999 may result in a $10
million decrease in the fair value of the fuel-price risk-management
instruments. Because these instruments are used to hedge the fuel price risk
created by the sale of long-term, fixed-price electricity contracts, it is
expected that the hypothetical decrease in fuel prices during 1999 would result
in a corresponding increase in the fair value of these contracts.
This analysis is based on the assumption that the amount of fuel-price
risk-management instruments and the amount of long-term, fixed-price
electricity sales contracts to wholesale customers will not fluctuate during
1999. This analysis is subject to change as these assumptions change.
INTEREST-RATE RISK-MANAGEMENT INSTRUMENTS
Several NU subsidiaries hold variable-rate long-term debt, exposing the NU
system to interest rate risk. In order to hedge some of this risk, interest-rate
risk-management instruments have been entered into on NAEC's $200 million
variable-rate note, effectively fixing the interest on this note at 7.823
percent. As of December 31, 1998, NAEC had outstanding agreements with a total
notional value of approximately $200 million and a negative mark-to-market
position of approximately $2.3 million. The remaining variable-rate debt is
unhedged.
At December 31, 1998, NU had $210 million of long-term, variable-rate debt
which is not hedged and is subject to actual market rates for 1999. A 10 percent
increase in market interest rates above the 1998 weighted average variable rate
during 1999 would result in an immaterial impact on interest expense. The
difference is no longer material, primarily as a result of converting $535
million variable-rate debt to fixed-rate debt during 1998.
See the "Notes to Consolidated Financial Statements," Note 10, for the fair
value of NU's financial instruments.
ENVIRONMENTAL MATTERS
NU's subsidiaries are potentially liable for environmental cleanup costs at a
number of sites inside and outside their service territories. To date, the
future estimated environmental remediation liability has not been material with
respect to the earnings or financial position of the NU system. At December 31,
1998, NU's subsidiaries had recorded an environmental reserve of approximately
$21.5 million. See the "Notes to Consolidated Financial Statements," Note 7D,
for further information on environmental matters.
RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
The components of significant income statement variances for the past two years
are provided in the table below. The relative magnitude of how revenues earned
in 1998 were used by NU's continuing operations in 1998 is illustrated in the
chart on page 19.
- --------------------------------------------------------------------------------------------------------------------------------
Income Statement Variances
(Millions of Dollars)
- --------------------------------------------------------------------------------------------------------------------------------
1998 over/(under) 1997 1997 over/(under) 1996
---------------------- ----------------------
Amount Percent Amount Percent
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues $(67) (2)% $ 43 1%
Fuel, purchased and net interchange power 3 -- 154 13
Other operation (127) (12) 10 1
Maintenance (103) (20) 86 21
Depreciation (22) (6) (5) (1)
Amortization of regulatory assets, net 79 64 1 1
Federal and state income taxes 4 (a) (94) (98)
Millstone 1 unrecoverable costs (143) (100) -- --
Other income, net 19 50 (69) (a)
Net loss (17) (13) (169) (a)
- --------------------------------------------------------------------------------------------------------------------------------
(a) Percentage greater than 100.
18
OPERATING REVENUES
Retail revenues decreased by $199 million in 1998 due to retail rate reductions
for CL&P, PSNH and WMECO and the accounting impact of Millstone 2 and Millstone
3 being removed from CL&P's rates. Wholesale revenues decreased by $32 million
primarily as a result of the terminated contract with CMEEC. Other revenues
decreased approximately $50 million due to lower billings to outside companies
for reimbursable costs and price differences among customer classes. These
decreases were partially offset by higher fuel recoveries and higher retail
sales volumes. Fuel recoveries increased by $166 million primarily due to higher
fuel revenues for PSNH as a result of a higher FPPAC rate. Retail kilowatt-hour
sales were 1.9 percent higher and contributed $48 million to nonfuel revenues in
1998 primarily as a result of economic growth in all three states.
Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $32
million, primarily due to higher fuel revenues for CL&P as a result of a lower
fuel rate in 1996. Conservation recoveries increased by $17 million, primarily
due to a 1996 reserve for overrecoveries of CL&P demand-side management costs.
Retail kilowatt-hour sales were 0.3 percent lower in 1997 as a result of mild
winter weather.
FUEL, PURCHASED AND NET INTERCHANGE POWER
The change in fuel, purchased and net interchange power expense in 1998 was not
significant.
Fuel, purchased and net interchange power expense increased in 1997,
primarily due to replacement power costs associated with the Millstone outages
and the expensing in 1997 of replacement power costs incurred in 1996.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses decreased in 1998, primarily due to
lower costs at the Millstone nuclear units ($159 million), lower costs at the
Seabrook and Yankee nuclear units ($50 million), the recognition of
environmental insurance proceeds ($27 million), and lower administrative and
general expenses ($26 million). These decreases were offset partially by higher
recognition of nuclear refueling outage costs primarily as a result of the 1996
CL&P rate settlement ($29 million).
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($216 million), higher
costs as a result of Seabrook outages ($23 million) and higher capacity charges
from MYAPC ($16 million). These were partially offset by lower recognition of
nuclear refueling outage costs primarily as a result of the 1996 CL&P rate
settlement ($72 million), lower capacity charges from CYAPC ($35 million)
primarily as a result of a property tax refund, and lower administrative and
general expenses ($41 million) primarily due to lower pension and benefit costs,
and lower storm expenses.
DEPRECIATION
Depreciation decreased in 1998, primarily due to the retirement of Millstone 1.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 1998, primarily due to
accelerated amortizations in accordance with regulatory decisions for CL&P, the
amortization of NAEC's Seabrook deferred return and the beginning of the
amortization of CL&P's Millstone 1 investment. These increases were partially
offset by the lower amortization of the PSNH acquisition premium.
Amortization of regulatory assets, net increased in 1997, primarily due to
the completion of the CL&P cogeneration deferrals in 1996, increased
amortization in 1997, and the beginning of the amortization of NAEC's Seabrook
deferred return in December 1997. This was partially offset by the completion of
CL&P's Seabrook amortization and WMECO's Millstone 3 amortization in 1996.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased in 1998, primarily due to higher book
taxable income, partially offset by an increase in income tax credits primarily
due to the Millstone 1 write-off of unrecoverable costs as a result of the
February 1999 CL&P rate decision.
Federal and state income taxes decreased in 1997, primarily due to lower
book taxable income.
MILLSTONE 1 UNRECOVERABLE COSTS
Millstone 1 unrecoverable costs represents the write-off of the Millstone 1
entitlement formerly held by CMEEC and the write-off of unrecoverable costs as
a result of the February 1999 CL&P rate decision.
OTHER INCOME, NET
Other income, net increased in 1998, primarily due to the proceeds resulting
from the shareholder derivative suit.
Other income, net decreased in 1997, primarily due to a $25 million reserve
for anticipated losses on the sale of investments by Charter Oak Energy (COE),
equity losses on COE investments, costs associated with the accounts receivable
facility, nonutility marketing and advertising costs and lower miscellaneous
income.
1998 USE OF REVENUE AND RETAINED EARNINGS
- --------------------------------------------------------------------------------
[GRAPHIC OMITTED]
TAXES 7%
DEPRECIATION, AMORITIZATION AND OTHER EXPENSES 17%
WAGES AND BENEFITS 12%
INTEREST CHARGES AND PREFERRED DIVIDENDS 8%
NONFUEL OPERATION AND MAINTENANCE EXPENSES 23%
ENERGY COSTS 33%
19
COMPANY REPORT
The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that
encourages the maintenance of high standards of conduct in all of its business
activities. The company maintains a system of internal controls over financial
reporting which is designed to provide reasonable assurance to the company's
management and Board of Trustees regarding the preparation of reliable,
published financial statements. The system is supported by an organization of
trained management personnel, policies and procedures, and a comprehensive
program of internal audits. Through established programs, the company regularly
communicates to its management employees their internal control responsibilities
and policies prohibiting conflict of interest.
The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. This committee meets periodically with management, the internal
auditors and the independent auditors to review the activities of each and to
discuss audit matters, financial reporting and the adequacy of internal
controls.
Because of inherent limitations in any system of internal controls, errors
or irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation of
all financial statements, are reliable.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees and
Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 1998 and 1997, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows
and income taxes for each of the three years in the period ended December 31,
1998. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
/s/ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
20
CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES...................................................... $ 3,767,714 $ 3,834,806 $ 3,792,148
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
- --------------------------------------------------------------------------------------------------------------------------------
Operation --
Fuel, purchased and net interchange power........................... 1,296,480 1,293,518 1,139,848
Other............................................................... 977,139 1,104,479 1,094,078
Maintenance............................................................. 399,165 501,693 415,532
Depreciation............................................................ 332,807 354,329 359,507
Amortization of regulatory assets, net.................................. 203,132 123,718 122,573
Federal and state income taxes (See Consolidated........................
Statements of Income Taxes)......................................... 82,332 12,650 94,363
Taxes other than income taxes........................................... 251,932 253,637 257,577
- --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses............................................ 3,542,987 3,644,024 3,483,478
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME........................................................ 224,727 190,782 308,670
- --------------------------------------------------------------------------------------------------------------------------------
OTHER (LOSS)/INCOME:
Deferred nuclear plants return -- other funds........................... 6,896 7,288 8,988
Equity in earnings of regional nuclear generating
and transmission companies.......................................... 12,420 11,306 13,155
Millstone 1 -- unrecoverable costs (Note 1M)............................ (143,239) -- --
Other, net.............................................................. (19,121) (38,473) 30,932
Minority interest in income of subsidiary............................... (9,300) (9,300) (9,300)
Income taxes............................................................ 76,393 10,702 (1,747)
- --------------------------------------------------------------------------------------------------------------------------------
Other (loss)/ income, net........................................... (75,951) (18,477) 42,028
- --------------------------------------------------------------------------------------------------------------------------------
Income before interest charges...................................... 148,776 172,305 350,698
- --------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt.............................................. 273,824 282,095 285,463
Other interest.......................................................... 7,808 3,561 7,649
Deferred nuclear plants return -- borrowed funds........................ (12,543) (13,675) (15,119)
- --------------------------------------------------------------------------------------------------------------------------------
Interest charges, net............................................... 269,089 271,981 277,993
- --------------------------------------------------------------------------------------------------------------------------------
(Loss)/income after interest charges................................ (120,313) (99,676) 72,705
PREFERRED DIVIDENDS OF SUBSIDIARIES..................................... 26,440 30,286 33,776
- --------------------------------------------------------------------------------------------------------------------------------
NET (LOSS)/INCOME....................................................... $ (146,753) $ (129,962) $ 38,929
================================================================================================================================
(LOSS)/EARNINGS PER COMMON SHARE -- BASIC AND DILUTED................... $ (1.12) $ (1.01) $ 0.30
================================================================================================================================
COMMON SHARES OUTSTANDING (AVERAGE)..................................... 130,549,760 129,567,708 127,960,382
================================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
NET (LOSS)/INCOME....................................................... $ (146,753) $ (129,962) $ 38,929
- --------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Foreign currency translation adjustments................................ -- (499) 433
Unrealized gains on securities.......................................... 2,019 -- --
Minimum pension liability adjustments................................... (613) -- --
Other comprehensive income, net of tax (Note 12)................... 1,406 (499) 433
- --------------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE (LOSS)/INCOME............................................. $ (145,347) $ (130,461) $ 39,362
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
21
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
ASSETS
UTILITY PLANT, AT COST:
Electric........................................................................... $9,570,547 $ 9,869,561
Other.............................................................................. 195,325 186,130
- --------------------------------------------------------------------------------------------------------------------------------
9,765,872 10,055,691
Less: Accumulated provision for depreciation....................................... 4,224,416 4,330,599
- --------------------------------------------------------------------------------------------------------------------------------
5,541,456 5,725,092
PSNH acquisition costs................................................................. 352,855 402,285
Construction work in progress.......................................................... 143,159 141,077
Nuclear fuel, net...................................................................... 133,411 194,704
- --------------------------------------------------------------------------------------------------------------------------------
Total net utility plant............................................................ 6,170,881 6,463,158
- --------------------------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS:
Nuclear decommissioning trusts, at market.............................................. 619,143 502,749
Investments in regional nuclear generating companies, at equity........................ 85,791 86,955
Investments in transmission companies, at equity....................................... 17,692 19,635
Other, at cost......................................................................... 136,812 95,352
- --------------------------------------------------------------------------------------------------------------------------------
859,438 704,691
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents.............................................................. 136,155 143,403
Investments in securitizable assets.................................................... 182,118 230,905
Receivables, less accumulated provision for uncollectible
accounts of $2,416 in 1998 and $2,052 in 1997...................................... 237,207 214,914
Accrued utility revenues............................................................... 42,145 36,885
Fuel, materials and supplies, at average cost.......................................... 202,661 212,721
Recoverable energy costs, net -- current portion....................................... 67,181 59,959
Prepayments and other.................................................................. 65,440 71,896
- --------------------------------------------------------------------------------------------------------------------------------
932,907 970,683
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Regulatory assets (Note 1H)............................................................ 2,328,949 2,173,278
Unamortized debt expense............................................................... 40,416 38,758
Other.................................................................................. 54,790 63,844
- --------------------------------------------------------------------------------------------------------------------------------
2,424,155 2,275,880
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS........................................................................... $10,387,381 $10,414,412
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
22
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION: (See Consolidated Statements of Capitalization)
Common shareholders' equity (See Note (a) -- Consolidated Statements of
Shareholders' Equity):
Common shares, $5 par value -- authorized 225,000,000 shares; 137,031,264
shares issued and 130,954,740 shares outstanding in 1998 and 136,842,170
shares issued and 130,182,736 shares outstanding in 1997........................ $ 685,156 $ 684,211
Capital surplus, paid in............................................................ 940,661 932,494
Deferred contribution plan -- employee stock ownership plan (ESOP).................. (140,619) (154,141)
Retained earnings................................................................... 560,769 707,522
Accumulated other comprehensive income (Note 12).................................... 1,405 (1)
- --------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity................................................... 2,047,372 2,170,085
Preferred stock not subject to mandatory redemption..................................... 136,200 136,200
Preferred stock subject to mandatory redemption......................................... 167,539 245,750
Long-term debt.......................................................................... 3,282,138 3,645,659
- --------------------------------------------------------------------------------------------------------------------------------
Total capitalization................................................................ 5,633,249 6,197,694
- --------------------------------------------------------------------------------------------------------------------------------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES.......................................... 100,000 100,000
- --------------------------------------------------------------------------------------------------------------------------------
OBLIGATIONS UNDER CAPITAL LEASES (Note 4)............................................... 88,423 30,427
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Notes payable to banks.................................................................. 30,000 50,000
Long-term debt and preferred stock -- current portion................................... 397,153 274,810
Obligations under capital leases -- current portion..................................... 120,856 177,304
Accounts payable........................................................................ 338,612 402,870
Accrued taxes........................................................................... 50,755 46,016
Accrued interest........................................................................ 51,044 30,786
Accrued pension benefits................................................................ 33,034 77,186
Other................................................................................... 106,333 88,396
- --------------------------------------------------------------------------------------------------------------------------------
1,127,787 1,147,368
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS:
Accumulated deferred income taxes....................................................... 1,848,694 1,984,513
Accumulated deferred investment tax credits............................................. 143,369 158,837
Decommissioning obligation -- Millstone 1 (Note 2)...................................... 692,000 --
Deferred contractual obligations (Note 2)............................................... 418,760 525,076
Other................................................................................... 335,099 270,497
- --------------------------------------------------------------------------------------------------------------------------------
3,437,922 2,938,923
- --------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES.................................................... $10,387,381 $10,414,412
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
23
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES:
(Loss)/income before preferred dividends of subsidiaries.................. $(120,313) $(99,676) $ 72,705
Adjustments to reconcile to net cash from operating activities:
Depreciation.......................................................... 332,807 354,329 359,507
Deferred income taxes and investment tax credits, net................. 23,502 26,435 71,832
Deferred nuclear plants return........................................ (19,439) (20,963) (24,107)
Amortization of nuclear plants return................................. 50,386 -- --
Amortization of demand-side management costs, net..................... 42,085 38,029 26,941
Amortization/(deferral) of recoverable energy costs................... 38,356 (54,102) (14,289)
Amortization of PSNH acquisition costs................................ 49,431 89,424 89,744
Amortization of regulatory asset -- income taxes...................... 68,684 19,379 22,266
Amortization of cogeneration deferral................................. 29,559 37,338 28,162
Amortization of regulatory liability -- PSNH.......................... (32,860) (32,860) (32,860)
Amortization of other regulatory assets............................... 37,932 10,437 15,261
Millstone 1 -- unrecoverable costs (Note 1M).......................... 143,239 -- --
Other sources of cash................................................. 181,591 77,248 186,173
Other uses of cash.................................................... (81,271) (86,202) (41,589)
Changes in working capital:
Receivables and accrued utility revenues, net......................... (62,553) 262,384 (31,992)
Fuel, materials and supplies.......................................... 10,060 (1,307) (10,834)
Accounts payable...................................................... (64,258) (104,269) 188,101
Accrued taxes......................................................... 4,739 38,966 (68,168)
Sale of receivables and accrued utility revenues...................... 35,000 90,000 --
Investments in securitizable assets................................... 48,787 (230,905) --
Other working capital (excludes cash)................................. (26,714) (36,464) (21,383)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows from operating activities.................................. 688,750 377,221 815,470
- --------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES:
Issuance of common shares................................................. 2,659 6,502 10,622
Issuance of long-term debt................................................ 275 260,000 222,150
Net (decrease)/increase in short-term debt................................ (20,000) 11,250 (60,250)
Reacquisitions and retirements of long-term debt.......................... (269,555) (288,793) (248,142)
Reacquisitions and retirements of preferred stock......................... (62,211) (25,000) (36,500)
Cash dividends on preferred stock......................................... (26,440) (30,286) (33,776)
Cash dividends on common shares........................................... -- (32,134) (176,277)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for financing activities.............................. (375,272) (98,461) (322,173)
- --------------------------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES:
Investment in plant:
Electric and other utility plant...................................... (217,009) (233,399) (222,829)
Nuclear fuel.......................................................... (17,026) (6,852) (14,529)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments in plant.............................. (234,035) (240,251) (237,358)
Investment in nuclear decommissioning trusts.............................. (75,551) (61,046) (65,716)
Other investment activities, net.......................................... (11,140) (28,257) (25,064)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments....................................... (320,726) (329,554) (328,138)
- --------------------------------------------------------------------------------------------------------------------------------
NET (DECREASE)/INCREASE IN CASH FOR THE PERIOD............................ (7,248) (50,794) 165,159
Cash and cash equivalents -- beginning of period.......................... 143,403 194,197 29,038
- --------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS -- END OF PERIOD................................ $136,155 $143,403 $ 194,197
================================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized...................................... $238,990 $291,335 $ 268,129
================================================================================================================================
Income taxes.............................................................. $ 19,454 $(26,387) $ 64,189
================================================================================================================================
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases....................... $ 5,064 $ 3,475 $ 3,524
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
24
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- --------------------------------------------------------------------------------------------------------------------------------
Accumulated
Other
Deferred Comprehensive
Common Capital Surplus Contribution Retained Income
(Thousands of Dollars) Shares (a) Paid In Plan -- ESOP Earnings (b) (Note 12) Total
- --------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1996............. $678,056 $936,197 $(198,152) $1,007,340 $ 65 $2,423,506
- --------------------------------------------------------------------------------------------------------------------------------
Net income for 1996................... 38,929 38,929
Cash dividends on common shares --
$1.38 per share................... (176,277) (176,277)
Loss on retirement of preferred stock. (374) (374)
Issuance of 440,772 common shares,
$5 par value...................... 2,204 8,418 10,622
Allocation of benefits -- ESOP........ (8,103) 22,061 13,958
Capital stock expenses, net........... 3,077 3,077
Other comprehensive income............ 433 433
- --------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1996........... 680,260 939,589 (176,091) 869,618 498 2,313,874
- --------------------------------------------------------------------------------------------------------------------------------
Net loss for 1997 .................... (129,962) (129,962)
Cash dividends on common shares --
$0.25 per share................... (32,134) (32,134)
Issuance of 790,232 common shares,
$5 par value...................... 3,951 2,551 6,502
Allocation of benefits -- ESOP........ (12,238) 21,950 9,712
Capital stock expenses, net........... 2,592 2,592
Other comprehensive income............ (499) (499)
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 1997........... 684,211 932,494 (154,141) 707,522 (1) 2,170,085
- --------------------------------------------------------------------------------------------------------------------------------
Net loss for 1998 .................... (146,753) (146,753)
Issuance of 189,094 common shares,
$5 par value...................... 945 1,714 2,659
Allocation of benefits -- ESOP........ (4,769) 13,522 8,753
Unearned stock compensation........... (537) (537)
Capital stock expenses, net........... 3,560 3,560
Gain on equity investment............. 8,140 8,140
Gain on repurchase of preferred stock. 59 59
Other comprehensive income............ 1,406 1,406
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 1998........... $685,156 $940,661 $(140,619) $ 560,769 $1,405 $2,047,372
================================================================================================================================
(a) NU issued 8,430,910 warrants as part of its acquisition of PSNH. These
warrants, which expired on June 5, 1997, entitled the holder to purchase one
share of NU common stock at an exercise price of $24 per share. As of June
5, 1997, 464,678 shares had been purchased through the exercise of warrants.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount of
retained earnings available for NU common dividends. At December 31, 1998,
these restrictions totaled approximately $832.2 million.
The accompanying notes are an integral part of these financial statements.
25
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets) ............................. $2,047,372 $2,170,085
- --------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value - authorized 36,600,000 shares at December 31, 1998 and 1997;
3,780,000 shares outstanding in 1998 and 4,840,000 shares outstanding in
1997
$50 par value - authorized 9,000,000 shares at December 31, 1998 and 1997;
4,709,774 shares outstanding in 1998 and 5,424,000 shares outstanding in
1997
$100 par value - authorized 1,000,000 shares at December 31, 1998 and 1997;
200,000 shares outstanding in 1998 and 1997
- --------------------------------------------------------------------------------------------------------------------------------
Dividend Rates Current Redemption Prices (a) Current Shares Outstanding
- --------------------------------------------------------------------------------------------------------------------------------
NOT SUBJECT TO MANDATORY REDEMPTION:
$50 par value -- $1.90 to $3.28 $50.50 to $54.00 2,324,000..... 116,200 116,200
$100 par value -- $7.72 $103.51 200,000..... 20,000 20,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory Redemption.................................. 136,200 136,200
- --------------------------------------------------------------------------------------------------------------------------------
SUBJECT TO MANDATORY REDEMPTION: (b)
$25 par value -- $1.90 to $2.65 $25.00 to $25.51 3,780,000..... 94,500 121,000
$50 par value -- $2.65 to $3.615 $50.67 to $52.17 2,385,774..... 119,289 155,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption...................................... 213,789 276,000
Less: Preferred Stock to be redeemed within one year...................................... 46,250 30,250
- --------------------------------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption, net....................................... 167,539 245,750
- --------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (c)
First Mortgage Bonds --
Maturity Interest Rates
- --------------------------------------------------------------------------------------------------------------------------------
1998 6.50% to 9.17%............................................................ -- 199,800
1999 5.50% to 7.25%............................................................ 254,000 279,000
2000 5.75% to 6.875%........................................................... 260,000 260,000
2001 7.375% to 7.875%.......................................................... 220,000 220,000
2002 7.75% to 9.05%............................................................ 560,000 580,000
2004 6.125%.................................................................... 140,000 140,000
2019-2023 7.375% to 7.50%........................................................... 120,000 120,000
2024-2025 7.375% to 8.50%........................................................... 430,000 430,000
- --------------------------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds............................................................. 1,984,000 2,228,800
- --------------------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt -- (d)
Pollution Control Notes and Other Notes --
2000 Adjustable Rate (e) and 7.67%............................................. 212,022 218,033
2005-2006 8.38% to 8.58%............................................................ 177,000 194,000
2013-2018 Adjustable Rate and 5.90% (d)............................................. 33,400 33,400
2020 Adjustable Rate........................................................... 15,300 15,300
2021-2022 5.85% to 7.65% and Adjustable Rate (d).................................... 552,485 552,485
2028 5.85% to 5.95% (d)........................................................ 369,300 369,300
2031 Adjustable Rate........................................................... 62,000 62,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other Notes.......................................... 1,421,507 1,444,518
Fees and interest due for spent nuclear fuel disposal costs (Note 7E)...................... 216,377 205,502
Other...................................................................................... 17,043 18,513
- --------------------------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt................................................................. 1,654,927 1,668,533
- --------------------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net...................................................... (5,886) (7,113)
- --------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt....................................................................... 3,633,041 3,890,220
Less: Amounts due within one year......................................................... 350,903 244,561
- --------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, net........................................................................ 3,282,138 3,645,659
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION....................................................................... $5,633,249 $6,197,694
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
26
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
- --------------------------------------------------------------------------------
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Balance at December 31, 1995................ $304,000
Reacquisitions and Retirements............ (3,000)
- --------------------------------------------------------------------------------
Balance at December 31, 1996................ 301,000
Reacquisitions and Retirements............ (25,000)
- --------------------------------------------------------------------------------
Balance at December 31, 1997................ 276,000
Reacquisitions and Retirements............ (62,211)
- --------------------------------------------------------------------------------
Balance at December 31, 1998................ $213,789
================================================================================
The minimum sinking-fund requirements of the series subject each year to
mandatory redemption aggregate approximately $46.3 million each year in 1999,
2000 and 2001; $21.3 million in 2002 and $7.7 million in 2003. In case of
default on sinking-fund payments, no payments may be made on any junior stock by
way of dividends or otherwise (other than in shares of junior stock) so long as
the default continues. If a subsidiary is in arrears in the payment of
dividends on any outstanding shares of preferred stock, the subsidiary is
prohibited from redeeming or purchasing less than all of the outstanding
preferred stock.
(c) Long-term debt maturities and cash sinking-fund requirements, excluding fees
and interest due for spent nuclear fuel disposal costs, on debt outstanding at
December 31, 1998, for the years 1999 through 2003 are approximately $350.9
million, $557.8 million, $313.2 million, $375.4 million and $25.6 million,
respectively.
In addition, there are annual one percent sinking- and improvement-fund
requirements of approximately $1.5 million for 1999 and 2000, $900,000 for 2001
and 2002, and no requirements for 2003 for certain series of Western
Massachusetts Electric Company (WMECO) first mortgage bonds which expire in
2003. The WMECO 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), WMECO and North Atlantic Energy
Corporation (NAEC) is subject to the liens of each company's respective first
mortgage bond indenture. NAEC's first mortgage bonds also are secured by
payments made to NAEC by PSNH under the terms of the Seabrook Power Contracts.
CL&P and WMECO have secured $369.3 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.
CL&P and WMECO have issued $225 million and $80 million, respectively, of
first mortgage bonds as collateral to enable them to borrow under a three-year
revolving credit agreement. At December 31, 1998, CL&P and WMECO had $10 million
and $20 million, respectively, in borrowings under this agreement. PSNH's
Revolving Credit Facility is secured by $75 million of first mortgage bonds and
substantially all of PSNH's accounts receivable. At December 31, 1998, PSNH had
no borrowings under the Revolving Credit Facility. See Note 3, "Short-Term
Debt," for further information.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by first mortgage bonds and a liquidity facility.
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA
issued seven series of PCRBs and loaned the proceeds to PSNH. At December 31,
1998, $516.5 million of the PCRBs were outstanding. PSNH's obligation to repay
each series of PCRBs is secured by first mortgage bonds. Each such series of
first mortgage bonds contains similar terms and provisions as the applicable
series of PCRBs. For financial reporting purposes, these bonds would not be
considered outstanding unless PSNH failed to meet its obligations under the
PCRBs.
(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.1 percent to 5.6 percent for 1998 and 3.4 percent to 5.6
percent for 1997.
During 1998, approximately $535 million of adjustable-rate debt was
converted to fixed-rate debt at rates ranging from 5.85 percent to 6.0 percent.
At December 31, 1998 and 1997, adjustable-rate debt totaled $410 million and
$945 million, respectively.
(e) Interest-rate swaps effectively fix the interest rate of NAEC's $200
million variable-rate bank note at 7.823 percent. For further information, see
Note 8, "Interest-Rate and Fuel-Price Risk-Management."
27
CONSOLIDATED STATEMENTS OF INCOME TAXES
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
The components of the federal and state income tax provisions charged to
operations are:
Current income taxes:
Federal................................................................ $(13,660) $(22,760) $ 13,500
State.................................................................. (3,903) (1,727) 10,778
- --------------------------------------------------------------------------------------------------------------------------------
Total current.............................................................. (17,563) (24,487) 24,278
- --------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal................................................................ 51,913 46,871 90,093
State.................................................................. (12,948) (10,841) (8,667)
- --------------------------------------------------------------------------------------------------------------------------------
Total deferred............................................................. 38,965 36,030 81,426
- --------------------------------------------------------------------------------------------------------------------------------
Investment tax credits, net................................................ (15,463) (9,595) (9,594)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE................................................... $ 5,939 $ 1,948 $ 96,110
- --------------------------------------------------------------------------------------------------------------------------------
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses ............................ $82,332 $12,650 $ 94,363
Other income taxes .................................................... (76,393) (10,702) 1,747
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE .................................................. $ 5,939 $ 1,948 $ 96,110
================================================================================================================================
Deferred income taxes are comprised of the tax effects of temporary differences
as follows:
Deferred tax asset associated with net operating losses................ $69,212 $ -- $ 96,756
Depreciation, leased nuclear fuel, settlement credits
and disposal costs................................................... 16,217 32,932 18,401
Energy adjustment clauses.............................................. (22,308) 5,916 (8,268)
Nuclear plant deferrals................................................ (2,291) 13,989 (15,549)
Bond redemptions....................................................... (2,809) (4,260) (4,685)
Amortization of New Hampshire regulatory settlement.................... 11,501 11,501 11,501
Demand-side management................................................. (13,688) (12,169) (14,954)
State net operating loss carryforward.................................. 1,150 (7,670) --
Millstone revenue out of rate base..................................... (18,080) -- --
Other ................................................................. 61 (4,209) (1,776)
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES, NET................................................. $38,965 $36,030 $ 81,426
================================================================================================================================
A reconciliation between income tax expense and the expected tax expense at 35
percent of pretax income:
Expected federal income tax................................................ $(40,031) $(34,205) $ 59,085
Tax effect of differences:
Depreciation........................................................... 27,630 20,566 22,537
Deferred nuclear plants return......................................... (2,414) (2,551) (3,146)
Amortization of regulatory assets...................................... 30,740 5,498 7,910
Amortization of PSNH acquisition costs................................. 17,301 31,298 31,410
Seabrook intercompany gains and losses................................. 630 (3,898) (7,503)
Investment tax credit amortization and write-off....................... (15,463) (9,595) (9,594)
State income taxes, net of federal benefit............................. (4,759) (7,839) 1,372
Nondeductible penalties................................................ 3,589 648 846
Adjustment for prior years' taxes...................................... (15,369) (1,712) (962)
Employee stock ownership plan.......................................... (1,670) (4,648) (4,007)
Dividends received deduction........................................... (3,218) (1,563) (3,027)
Loss reserve on sale of investment..................................... 7,000 8,750 --
Other, net............................................................. 1,973 1,199 1,189
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE................................................... $ 5,939 $ 1,948 $ 96,110
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT NORTHEAST UTILITIES
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (the NU system). The NU system furnishes franchised retail
electric service in Connecticut, New Hampshire and western Massachusetts through
three wholly owned subsidiaries: CL&P, PSNH and WMECO. Another wholly owned
subsidiary, NAEC, sells all of its entitlement to the capacity and output of the
Seabrook nuclear power plant (Seabrook 1 or Seabrook) to PSNH under two
life-of-unit, full cost recovery contracts. A fifth wholly owned subsidiary,
Holyoke Water Power Company (HWP), also is engaged in the production and
distribution of electric power. The NU system also furnishes firm and other
wholesale electric services to various municipalities and other utilities, and
participates in limited retail access programs, providing off-system retail
electric service. The NU system serves in excess of 30 percent of New England's
electric needs and is one of the 24 largest electric utility systems in the
country as measured by revenues.
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).
NU and its subsidiaries are subject to the provisions of the 1935 Act.
Arrangements among the NU system companies, outside agencies and other utilities
covering interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory Commission
(FERC) and/or the SEC. The operating subsidiaries are subject to further
regulation for rates, accounting and other matters by the FERC and/or applicable
state regulatory commissions.
Several wholly owned subsidiaries of NU provide support services for the NU
system companies and, in some cases, for other New England utilities. Northeast
Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing and other services to the NU system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
generating facilities. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibility for Seabrook. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by the NU system
companies. In addition, CL&P and WMECO each have established a special purpose
subsidiary whose business consists of the purchase and resale of receivables.
Select Energy, Inc. (Select), HEC Inc. (HEC), Mode 1 Communications, Inc.
(Mode 1), and Charter Oak Energy, Inc. (COE) are other NU system companies which
engage in a variety of activities. During 1998, revenues from these four
subsidiaries accounted for approximately one percent of consolidated revenues.
Currently, Select serves as a vehicle for participation in other retail
pilot competition programs and open-access retail and wholesale electric markets
in the Northeast and other areas of the country as appropriate. In addition,
Select develops and markets energy-related products and services in order to
enhance its core electric service and customer relationships. Select has taken
steps to establish strategic alliances with other companies in various
energy-related fields including fuel supply and management, power quality,
energy efficiency and load management services.
HEC provides energy management services for the NU system's and other
utilities' commercial, industrial and institutional electric customers. Mode 1
is a wholly owned subsidiary of NU which develops and invests in
telecommunications and related activities.
COE has an investment in a foreign utility company as permitted under the
Energy Policy Act of 1992 (Energy Act). This investment is accounted for on the
equity basis based upon COE's level of participation. NU has put COE up for
sale.
During the first quarter of 1999, NU established three new subsidiaries: NU
Enterprises, Inc., Northeast Generation Company and Northeast Generation
Services Company. Directly or through multiple subsidiaries, these entities will
engage in a variety of energy-related activities, including the acquisition and
management of non-nuclear generating plants.
B. PRESENTATION
The consolidated financial statements of the NU system include the accounts of
all wholly owned subsidiaries. Significant intercompany transactions have been
eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent liabilities at the date of the financial statements
and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
C. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued two new accounting
standards during 1998: Statement of Financial Accounting Standards (SFAS) 132,
"Employers' Disclosures About Pensions and Other Postretirement Benefits," and
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."
SFAS 132 revises employers' disclosures about pension and other
postretirement benefit plans, but it does not change the measurement or
recognition of those plans. See
29
Note 5A, "Pension Benefits and Postretirement Benefits Other Than Pensions," for
further information on the NU system's pension and postretirement benefits
disclosures.
SFAS 133 establishes accounting and reporting standards for derivative
instruments and hedging activities. This statement becomes effective for the NU
system companies on January 1, 2000, and will require derivative instruments
used by the NU system companies to be recognized on the balance sheets as assets
or liabilities at fair value. The NU system uses derivative instruments for
hedging purposes. The accounting for these hedging instruments will depend on
which hedging classification each derivative instrument falls under, as
defined by SFAS 133, offset by any changes in the market value of the hedged
item.
Based on the derivative instruments which currently are being utilized by NU
system companies to hedge some of their fuel price and interest rate risks,
there will be an impact on earnings upon adoption of SFAS 133 which management
cannot estimate at this time. For further information regarding derivative
instruments, see Note 1N, "Interest-Rate and Fuel-Price Risk-Management."
In November 1998, the Emerging Issues Task Force (EITF) reached a final
consensus on EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." The Task Force determined in its
consensus that when an operation's activities are considered to be trading
activities, its energy trading and risk-management contracts should be marked to
market with the gains and losses included in earnings. The consensus on this
Issue is effective for financial statements issued for years beginning after
December 15, 1998. Management has determined that EITF 98-10 currently has no
effect on its financial statements.
During June 1997, the FASB issued SFAS 131, "Disclosures about Segments of
an Enterprise and Related Information." SFAS 131 determines the standards for
reporting and disclosing qualitative and quantitative information about a
company's operating segments. More specifically, it requires financial
information to be disclosed for segments whose operating results are received by
the chief operating officer for decisions on resource allocation. It also
requires related disclosures about products and services, geographic areas and
major customers. The NU system currently evaluates management performance using
a cost-based budget, and the information required by SFAS 131 is not available.
As a result of the changes the NU system and the industry are undergoing,
the company will implement business segment reporting in 1999. This reporting
will provide management with revenue and expense information at the business
segment level. Management has identified significant segments to include
transmission, distribution, generation-related and energy marketing.
The NU system's revenues primarily are derived from residential, commercial
and industrial customers. A breakdown of revenues by class of customers is shown
on the Consolidated Sales Statistics table.
D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock of
four regional nuclear generating companies (Yankee companies) which are
accounted for on the equity basis due to the NU system companies' ability to
exercise significant influence over their operating and financial policies.
The NU system's equity investments and ownership interests in the Yankee
companies at December 31, 1998, are:
- --------------------------------------------------------------------------------
(Thousands of Dollars, except for percentages)
- --------------------------------------------------------------------------------
Connecticut Yankee Atomic
Power Company (CYAPC)............. $51,685 49.0%
Yankee Atomic Electric
Company (YAEC).................... 7,632 38.5
Maine Yankee Atomic
Power Company (MYAPC)............. 17,342 20.0
Vermont Yankee Nuclear
Power Corporation (VYNPC)......... 9,132 16.0
- --------------------------------------------------------------------------------
Total Equity Investment............. $85,791
================================================================================
Each Yankee company owns a single nuclear generating unit. YAEC's, CYAPC's and
MYAPC's nuclear power plants were shut down permanently on February 26, 1992,
December 4, 1996, and August 6, 1997, respectively. For further information on
the Yankee companies, see Note 2, "Nuclear Decommissioning and Plant Closure
Costs."
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear generating unit and Millstone 2, a 870 MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. During
the third quarter of 1998, CL&P and WMECO decided to retire Millstone 1 and
prepare for final decommissioning. For further information on the Millstone 1
closure, see Note 2, "Nuclear Decommissioning and Plant Closure Costs," and
Management's Discussion and Analysis (MD&A). For further information on
Millstone 2 and 3, see Note 2, "Nuclear Decommissioning and Plant Closure
Costs," Note 7C, "Commitments and Contingencies -- Nuclear Performance," and the
MD&A.
Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook 1, a 1,148 MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook 1 to PSNH under two long-term
contracts (the Seabrook Power Contracts).
30
Plant-in-service and the accumulated provision for depreciation for the NU
system's share of the three Millstone units and Seabrook 1 are as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Millions of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Plant-in-service
Millstone 1........................ $ -- $ 478.7
Millstone 2........................ 936.8 857.1
Millstone 3........................ 2,407.4 2,404.3
Seabrook 1......................... 895.5 897.5
Accumulated provision
for depreciation
Millstone 1........................ $ -- $ 212.1
Millstone 2........................ 379.6 306.7
Millstone 3........................ 765.9 695.1
Seabrook 1......................... 170.0 150.0
================================================================================
The NU system's share of Millstone and Seabrook 1 expenses are included in
operating expenses on the accompanying Consolidated Statements of Income.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
approximately $17.7 million, in two companies that transmit electricity imported
from the Hydro-Quebec system in Canada.
E. DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency. Except for major facilities, depreciation rates are applied
to the average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is retired from
service, the original cost of plant, including cost of removal, less salvage, is
charged to the accumulated provision for depreciation. The costs of closure and
removal of non-nuclear facilities are accrued over the life of the plant as a
component of depreciation. The depreciation rates for the several classes of
electric plant-in-service are equivalent to a composite rate of 3.3 percent in
1998 and 3.8 percent for 1997 and 1996, respectively. See Note 2, "Nuclear
Decommissioning and Plant Closure Costs," for information on nuclear plant
decommissioning.
At December 31, 1998 and 1997, the accumulated provision for depreciation
included approximately $88.4 million and $83.2 million, respectively, accrued
for the cost of removal, net of salvage, for non-nuclear generation property.
F. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, commercial and industrial customers and limited retail access
programs, utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through a
formal proceeding before the appropriate regulatory commission. Regulatory
commissions also have authority over the terms and conditions of nontraditional
ratemaking arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue an estimate for the amount of energy delivered but unbilled.
For information on rate proceedings and their potential impact on CL&P and
PSNH, see Note 7B, "Commitments and Contingencies -- Rate Matters."
G. PSNH ACQUISITION COSTS
The PSNH acquisition costs represent the aggregate value placed by the 1989 rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in
excess of the net book value of PSNH's non-Seabrook assets, plus the $700
million value assigned to Seabrook by the Rate Agreement, as part of the
bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate Agreement
provides for the recovery through rates, with a return, of the PSNH acquisition
costs. The unrecovered balance was approximately $352.9 million at December 31,
1998, and is being recovered ratably over a 20-year period through May 1, 2011,
in accordance with the Rate Agreement. Through December 31, 1998, $640.0 million
has been collected.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of the utility operating companies and the accompanying
consolidated financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." Assuming a cost-of-service based regulatory
structure, regulators may permit incurred costs, normally treated as expenses,
to be deferred and recovered through future revenues. Through their actions,
regulators also may reduce or eliminate the value of an asset, or create a
liability. If any of the operating companies were no longer subject to the
provisions of SFAS 71, the company would be required to write off all of its
related regulatory assets and liabilities unless there is a formal transition
plan which provides for the recovery, through established rates, for the
collection of these costs through a portion of the business which would remain
regulated on a cost-of-service basis. At the time of transition, the operating
companies also would be required to determine any impairment to the carrying
costs of deregulated plant and inventory assets.
Restructuring programs are being implemented within each of the NU system
operating companies' respective jurisdictions, however, management continues to
believe the application of SFAS 71 remains appropriate at this time. Once the NU
system operating companies' respective restructuring plans have been formally
approved by the appropriate regulatory agency and management can determine the
impacts of restructuring, the NU system operating companies' generation
businesses no longer will be rate regulated on a cost-of-service basis. The
majority of the NU system operating companies' regulatory assets are related to
their respective generation business. Management expects that the transmission
and distribution business
31
within each of the NU system operating companies' respective jurisdictions will
continue to be rate regulated on a cost-of-service basis and restructuring plans
will allow for the recovery of regulatory assets through this portion of the
business.
For further information on the NU system companies' respective regulatory
environments and the potential impacts of restructuring, see Note 7A,
"Commitments and Contingencies -- Restructuring" and the MD&A.
Based on a current evaluation of the various factors and conditions that are
expected to impact future cost recovery, management continues to believe it is
probable that the NU system operating companies will recover their investments
in long-lived assets, including regulatory assets. The components of the NU
system companies' regulatory assets are as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Income taxes, net
(Note 1I)...................... $ 762,495 $ 938,564
Recoverable energy costs,
net (Note 1J).................. 279,232 324,809
Deferred costs -- nuclear
plants (Note 1K)............... 187,132 208,129
Unrecovered contractual
obligations (Note 1L).......... 407,926 515,076
Millstone 1 (Note 1M)............ 576,323 --
Other............................ 115,841 186,700
- --------------------------------------------------------------------------------
$2,328,949 $2,173,278
================================================================================
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods in
which they affect the determination of taxable income) is accounted for in
accordance with the ratemaking treatment of the applicable regulatory
commissions. See the Consolidated Statements of Income Taxes for the components
of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Accelerated depreciation and other
plant-related differences....... $1,537,903 $1,567,597
Net operating loss
carryforwards................... (33,387) (102,492)
Regulatory assets -- income
tax gross up.................... 370,029 395,619
Other............................. (25,851) 123,789
- --------------------------------------------------------------------------------
$1,848,694 $1,984,513
================================================================================
At December 31, 1998, PSNH had a federal net operating loss (NOL)
carryforward of approximately $94 million that can be used against PSNH's
federal taxable income and which if unused expires between the years 2005 and
2006. CL&P had a state of Connecticut NOL carryforward of approximately $149
million that can be used against CL&P and affiliates' combined Connecticut
taxable income and which if unused expires in the year 2002. PSNH also had
Investment Tax Credit (ITC) carryforwards of $37 million which if unused expire
between the years 1999 and 2004. The reorganization of PSNH under Chapter 11 of
the United States Bankruptcy Code limits the annual amount of PSNH ITC
carryforward that may be used. Approximately $6 million of the ITC carryforward
is subject to this limitation.
J. RECOVERABLE ENERGY COSTS
Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed for
their proportionate shares of the costs of decontaminating and decommissioning
uranium enrichment plants owned by the United States Department of Energy (D&D
assessment). The Energy Act requires that regulators treat D&D assessments as a
reasonable and necessary current cost of fuel, to be fully recovered in rates
like any other fuel cost. CL&P, PSNH, WMECO and NAEC currently are recovering
these costs through rates. As of December 31, 1998, the NU system's total D&D
deferrals were approximately $57.5 million.
CL&P: CL&P has in place an energy adjustment clause under which fuel prices
above or below base-rate levels are charged or credited to customers. At
December 31, 1998, recoverable energy costs included $78.1 million of costs
previously deferred.
PSNH: The Rate Agreement includes a comprehensive fuel and purchased-power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period that began in May 1991, the retail portion of differences
between the fuel and purchased-power costs assumed in the Rate Agreement and
PSNH's actual costs, which include the costs related to the Seabrook Power
Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are
subject to a prudence review by the New Hampshire Public Utilities Commission
(NHPUC). At December 31, 1998, PSNH had $156.3 million of noncurrent recoverable
energy costs deferred under the FPPAC.
WMECO: Prior to March 1, 1998, WMECO had in place a comprehensive fuel
adjustment clause which allowed for the collection or refund of fuel price
differences between the cost of fuel and the amounts collected. Management
expects the deferred fuel balance will be collected as part of the restructuring
proceeding.
For further information on rate matters, see Note 7B, "Commitments and
Contingencies -- Rate Matters" and the MD&A.
32
K. DEFERRED COSTS -- NUCLEAR PLANTS
Under the Rate Agreement, the plant costs of Seabrook were phased into rates
over a seven-year period beginning May 15, 1991. Total costs deferred under the
phase-in plan were approximately $288 million. This plan is in compliance with
SFAS 92, "Regulated Enterprises - Accounting for Phase-In Plans." These deferred
costs are being billed to PSNH by NAEC through the Seabrook Power Contracts
beginning December 1, 1997, and will be recovered fully from PSNH's customers by
May 2001.
L. UNRECOVERED CONTRACTUAL OBLIGATIONS
Under the terms of contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor
companies, including CL&P, PSNH and WMECO, are responsible for their
proportionate share of the remaining costs of the units, including
decommissioning. As management expects that the NU system companies will be
allowed to recover these costs from their customers, the NU system companies
have recorded regulatory assets, with corresponding obligations, on their
respective balance sheets. For further information, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs."
M. MILLSTONE 1
The Millstone 1 regulatory asset includes the recoverable portion of the
undepreciated plant and related balances of approximately $190.3 million, and
the regulatory asset associated with the decommissioning and closure obligation
of $386.0 million. See Note 2, "Nuclear Decommissioning and Plant Closure
Costs," for further information.
N. INTEREST-RATE AND FUEL-PRICE RISK-MANAGEMENT
The NU system utilizes market risk-management instruments to hedge well-defined
risks associated with variable interest rates and changes in fuel prices. To
qualify for hedge treatment, the underlying hedged item must expose the company
to risks associated with market fluctuations and the market risk-management
instrument used must be designated as a hedge and must reduce the NU system's
exposure to market fluctuations throughout the period.
Amounts receivable or payable under fuel-price management instruments are
recognized in operating expenses when realized. Amounts receivable or payable
under interest-rate management instruments are accrued and offset against
interest expense. For further information, see Note 8, "Interest-Rate and
Fuel-Price Risk-Management."
O. CASH AND CASH EQUIVALENTS
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
2. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone 2 and 3 and Seabrook 1: The NU system operating nuclear power plants
have service lives that are expected to end during the years 2015 through 2026.
Upon retirement, these units must be decommissioned. Current decommissioning
studies conclude that complete and immediate dismantlement at retirement
continues to be the most viable and economic method of decommissioning the
units. Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning Millstone 2, in year-end 1998 dollars,
is $397.5 million. The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 in year-end 1998 dollars is $380.6
million and $195.8 million, respectively. Millstone 2 and 3 and Seabrook 1
decommissioning costs will be increased annually by their respective escalation
rates. Nuclear decommissioning costs are accrued over the expected service lives
of the units and are included in depreciation expense on the Consolidated
Statements of Income. Nuclear decommissioning costs for these units amounted to
$27.9 million in 1998, $28.6 million in 1997 and $27.6 million in 1996. Nuclear
decommissioning, as a cost of removal, is included in the accumulated provision
for depreciation on the Consolidated Balance Sheets. At December 31, 1998 and
1997, the decommissioning balance in the accumulated provision for depreciation
amounted to $229.7 million and $202.1 million, respectively.
External decommissioning trusts have been established for the costs of
decommissioning Millstone 2 and 3. Payments for the company's portions of the
cost of decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the estimated
decommissioning costs assumes levelized collections for the Millstone units and
escalated collections for Seabrook 1 and after-tax earnings on the Millstone and
Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent,
respectively.
As of December 31, 1998, CL&P, PSNH and WMECO collected a total of $229.7
million through rates toward the future decommissioning costs of their share of
Millstone 2 and 3 and Seabrook, of which $209.9 million has been transferred to
external decommissioning trusts. Earnings on the decommissioning trusts increase
the decommissioning trust balance and the accumulated reserve for depreciation.
Unrealized gains and losses associated with the decommissioning trusts and
financing fund also impact the balance of the trusts and the accumulated
reserve for depreciation. The fair value of the amounts in the external
decommissioning trusts was $349.9 million at December 31, 1998.
Changes in requirements or technology, the timing of funding or dismantling
or adoption of a decommissioning method other than immediate dismantlement would
change decommissioning cost estimates and the amounts required to be recovered.
CL&P, PSNH and WMECO attempt to
33
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 NU system companies. Based on present estimates and assuming its
nuclear units operate to the end of their respective license periods, the NU
system expects that the decommissioning trusts and financing fund will be
substantially funded when the units are retired from service.
Millstone 1: The total estimated decommissioning costs for Millstone 1,
which have been updated to reflect the early shutdown of the unit, are
approximately $692.0 million as of December 31, 1998. The company has recorded
the decommissioning and closure obligation as a liability. Nuclear
decommissioning costs for Millstone 1 were $19.8 million in 1998 and $20.2
million in 1997 and 1996, respectively.
In February 1999, the DPUC issued a decision on CL&P's rate case filing.
The decision allowed for recovery over a three-year period, without a return, of
$126.0 million of CL&P's remaining investment in Millstone 1. As a result, CL&P
recorded an after-tax loss of approximately $80 million, related to the
write-down of its investment in Millstone 1. The decision allowed for the
recovery of CL&P's decommissioning and closure obligations. Accordingly, CL&P
recorded a regulatory asset for its portion of the decommissioning and closure
obligation. For further information on the DPUC decision, see Note 7B,
"Commitments and Contingencies - Rate Matters" and the MD&A.
During 1998, CL&P recorded a loss of approximately $27.9 million related to
the termination of an approximate 4.3 percent entitlement contract of CL&P's
share of Millstone 1, formerly held by the Connecticut Municipal Electric Energy
Cooperative.
WMECO will seek recovery of unrecovered Millstone 1 balances of
approximately $60.8 million and decommissioning related costs of approximately
$63.3 million as part of its restructuring regulatory proceedings. Based upon
the restructuring law in Massachusetts, management believes it is probable that
WMECO will be allowed the recovery of these costs and has recorded a regulatory
asset.
CL&P and WMECO use external trusts to fund the estimated decommissioning
costs of Millstone 1. As of December 31, 1998, CL&P and WMECO had collected a
total of $182.0 million through rates toward the future decommissioning costs of
their share of Millstone 1, of which $160.1 million has been transferred to
external decommissioning trusts. At December 31, 1998, the fair market value of
the balance in the external trusts was approximately $269.2 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share of
estimated costs, in year-end 1998 dollars, of decommissioning this unit is
approximately $84.8 million.
At December 31, 1998, the remaining estimated obligation, including
decommissioning, for the Yankee companies' nuclear generating facilities which
have been shut down were:
- --------------------------------------------------------------------------------
Total NU's
(Thousands of Dollars) Obligation Share
- --------------------------------------------------------------------------------
Maine Yankee..................... $715,065 $143,013
Connecticut Yankee............... $498,557 $244,293
Yankee Atomic.................... $ 81,699 $ 31,454
================================================================================
For further information on the Yankee companies, see Note 7B, "Commitments
and Contingencies -- Rate Matters."
For information on proposed changes to the accounting for decommissioning,
see the MD&A.
3. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by NU and the
NU system operating companies is subject to periodic approval by either the SEC
under the 1935 Act or by the respective state regulators. SEC authorization
allowed CL&P, WMECO and NAEC, as of January 1, 1999, to incur total short-term
borrowings up to a maximum of $375 million, $150 million and $60 million,
respectively. In addition, the charters of CL&P and WMECO contain preferred
stock provisions restricting the amount of unsecured debt those companies may
incur. As of December 31, 1998, CL&P's and WMECO's charters permit CL&P and
WMECO to incur an additional $466 million and $96 million, respectively, of
unsecured debt. Effective April 1998, PSNH is authorized under a NHPUC order to
incur short-term borrowings up to a maximum of $75 million.
Credit Agreements: NU, CL&P and WMECO are parties to a $313.75 million
revolving credit agreement (Credit Agreement). Under the Credit Agreement
amended on September 11, 1998, CL&P and WMECO are able to borrow, subject to the
availability of first mortgage bond collateral, up to $313.75 million and $150
million, respectively. At December 31, 1998, CL&P and WMECO have issued first
mortgage bonds to enable borrowings under this facility up to a maximum of $225
million and $80 million, respectively. NU, which cannot issue first mortgage
bonds, would be able to borrow up to $50 million if NU consolidated, CL&P and
WMECO each meet certain interest coverage tests for two consecutive quarters.
This requirement for NU has not been met. In addition, CL&P and WMECO each must
meet certain minimum quarterly financial ratios to access the Credit Agreement.
CL&P currently is in the process of obtaining a waiver of the equity financial
ratio requirement for the quarter ended December 31, 1998. WMECO satisfied
these requirements for the quarter ending December 31, 1998. In connection with
obtaining the waiver for the equity test, NU's participation in the Credit
Agreement will be terminated. The overall limit for all of the NU system
companies under the entire Credit Agreement is $313.75 million. The NU system
companies
34
are obligated to pay a facility fee of .50 percent per annum of each
bank's total commitment under this Credit Agreement, which will expire in
November 1999. At December 31, 1998 and 1997, there were $30 million and $50
million, respectively, in borrowings under this Credit Agreement.
In February 1998, NU entered into a separate $25 million 364-day revolving
credit facility (Credit Facility) with one bank. NU is obligated to pay a
facility fee of .625 percent per annum on the unused commitment. At December 31,
1998, there were no borrowings under the Credit Facility. NU currently is
seeking an extension for this Credit Facility.
PSNH has access to a $75 million revolving credit agreement entered into in
April 1998 with a group of 16 banks. The borrowing level under this agreement
was reduced from a previous level of $125 million. The agreement will expire in
April 1999. Under the terms of this agreement, PSNH is obligated to pay a
facility fee of .50 percent per annum on the commitment. PSNH's borrowings under
the $75 million agreement are secured, per dollar of borrowing, by $75 million
of first mortgage bonds and substantially all of PSNH's accounts receivable.
There were no borrowings under this facility at December 31, 1998 and 1997.
On March 20, 1998, in connection with the $75 million PSNH credit agreement,
the NHPUC issued an order requiring PSNH to obtain NHPUC approval before paying
any dividends on its common stock and before investing any PSNH funds in the NU
system Money Pool during the expected 364-day term of the facilities. PSNH has
not sought such authorization.
Under the credit facilities discussed above, with the exception of the $25
million NU Credit Facility, the NU system companies may borrow funds on a
short-term revolving basis under their respective agreements, using either
fixed-rate loans or standby loans. Fixed rates are set using competitive
bidding. Standby loans are based upon several alternative variable rates. Loans
advanced under the $25 million NU Credit Facility are on a standby basis only.
The weighted average annual interest rate on the NU system companies' notes
payable to banks outstanding on December 31, 1998 and 1997, was 6.53 percent and
6.95 percent, respectively.
Maturities of short-term debt obligations were for periods of three months or
less.
For further information on NU system companies' short-term debt, see the
MD&A.
4. LEASES
CL&P and WMECO finance their nuclear fuel for Millstone 2 and their
respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel
Trust (NBFT) capital lease agreement. This lease agreement has an expiration
date of June 1, 2040. On June 5, 1998, the NBFT issued $180 million Series G
intermediate term notes (ITNs) through a private placement offering. The
five-year notes mature June 5, 2003, and will bear interest at a rate of 8.59
percent per annum, payable semiannually. At December 31, 1998, the capital lease
obligation to the NBFT was approximately $178.7 million.
The permanent shutdown of Millstone 1 in July 1998 afforded the NBFT ITN
holders the right to seek repurchase of a pro rata share of their notes based
upon the stipulated loss value of Millstone 1 fuel compared to the stipulated
loss value of all fuel then under the NBFT. This amount was approximately $80
million. The shutdown also obligates CL&P and WMECO to pay such amount to the
NBFT under the NBFT lease whether or not any ITN holders request repurchase. The
NU system companies are seeking consents from the ITN holders to amend this
lease provision so that they will not be obligated to make this payment, but
instead will issue an additional $80 million of collateral first mortgage bonds
in mid-1999.
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 NU
system companies also have entered into lease agreements, some of which are
capital leases, for the use of data processing and office equipment, vehicles,
gas turbines, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $31.0 million
in 1998, $19.0 million in 1997 and $28.2 million in 1996. Interest included in
capital lease rental payments was $18.3 million in 1998, $13.6 million in 1997
and $14.1 million in 1996. Operating lease rental payments charged to expense
were $15.7 million in 1998, $17.3 million in 1997 and $18.3 million in 1996.
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, 1998, are:
- -------------------------------------------------------------------------------
(Thousands of Dollars)
- -------------------------------------------------------------------------------
Capital Operating
Year Leases Leases
- -------------------------------------------------------------------------------
1999 ........................................... $ 8,500 $ 28,400
2000 ........................................... 8,000 26,200
2001 ........................................... 5,800 21,600
2002 ........................................... 3,400 11,600
2003 ........................................... 3,500 7,000
After 2003 ..................................... 47,700 24,200
===============================================================================
Future minimum
lease payments ............................... 76,900 $119,000
Less amount
representing interest ........................ 46,300
- -------------------------------------------------------------------------------
Present value of future
minimum lease payments
for other than nuclear fuel .................. 30,600
Present value of future
nuclear fuel lease payments .................. 178,700
- -------------------------------------------------------------------------------
Present value of future
minimum lease payments ....................... $209,300
===============================================================================
35
5. EMPLOYEE BENEfiTS
A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system subsidiaries participate in a uniform noncontributory defined
benefit retirement plan covering all regular NU system employees. Benefits are
based on years of service and the employees' highest eligible compensation
during 60 consecutive months of employment. Total pension (credit)/cost, part of
which was (credited)/charged to utility plant, approximated $(44.1) million in
1998, $(22.5) million in 1997 and $9.1 million in 1996.
Currently, the NU system subsidiaries annually fund 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.
The NU system subsidiaries also 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 retiring
from the NU system who have met specified service requirements. For current
employees and certain retirees, the total benefit is limited to two times the
1993 per-retiree health care cost. These costs are charged to expense over the
future estimated work life of the employee. The NU system subsidiaries are
funding postretirement costs through external trusts. The NU system subsidiaries
are funding, on an annual basis, amounts that have been rate-recovered and which
also are tax deductible under the Internal Revenue Code.
Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning fair
value of plan assets balance reconciled to the ending fair value of plan assets
balance and the respective funds' funded status reconciled to the Consolidated
Balance Sheets:
The components of net cost are:
- -------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------- -----------------------
(Thousands of Dollars) 1998 1997 1998 1997
- -------------------------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year ............................. $(1,392,833) $(1,321,146) $(285,959) $(306,082)
Service cost ........................................................ (37,420) (34,903) (6,625) (5,746)
Interest cost ....................................................... (96,785) (98,621) (20,920) (20,556)
Transfers ........................................................... 8,510 -- -- --
Actuarial (loss)/gain ............................................... (37,656) (18,956) (16,077) 20,926
Benefits paid ....................................................... 76,951 78,188 24,393 25,499
Curtailments and settlements ........................................ -- 2,605 -- --
- --------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year ................................... $(1,479,233) $(1,392,833) $(305,188) $(285,959)
- --------------------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year ...................... $ 1,919,414 $ 1,660,404 $ 129,434 $ 105,086
Actual return on plan assets ........................................ 264,717 337,198 17,353 21,132
Employer contribution ............................................... -- -- 28,831 28,715
Benefits paid ....................................................... (76,951) (78,188) (24,393) (25,499)
Transfers ........................................................... (9,160) -- -- --
- --------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year ............................ $ 2,098,020 $ 1,919,414 $ 151,225 $ 129,434
- --------------------------------------------------------------------------------------------------------------------------------
Funded status at December 31 ........................................ $ 618,787 $ 526,581 $(153,963) $(156,525)
Unrecognized transition amount ...................................... (9,019) (10,562) 211,881 227,015
Unrecognized prior service cost ..................................... 27,620 29,711 -- --
Unrecognized net gain ............................................... (670,422) (622,916) (57,918) (70,391)
- --------------------------------------------------------------------------------------------------------------------------------
(Accrued)/prepaid benefit cost ...................................... $ (33,034) $ (77,186) $ -- $ 99
================================================================================================================================
36
The following actuarial assumptions were used in calculating the plans' year-end
funded status:
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------- -----------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
Discount rate ..................................................... 7.00% 7.25% 7.00% 7.25%
Compensation/progression rate ..................................... 4.25 4.25 4.25 4.25
Health care cost trend rate (a) ................................... N/A N/A 5.22 5.76
================================================================================================================================
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 4.40 percent by 2001.
The components of net periodic benefit cost are:
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------------------- -------------------------------
(Thousands of Dollars) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
Service cost ................................... $ 37,420 $ 34,903 $ 35,435 $ 6,625 $ 5,746 $ 7,457
Interest cost .................................. 96,785 98,621 94,723 20,920 20,556 22,698
Expected return on
plan assets ................................ (153,152) (135,093) (117,882) (9,871) (8,065) (3,969)
Amortization of unrecognized
transition (asset)/obligation .............. (1,543) (1,543) (1,543) 15,134 15,134 15,134
Amortization of prior
service costs .............................. 2,091 2,091 2,091 -- -- --
Amortization of
actuarial gain ............................. (25,739) (18,901) (11,526) -- -- --
Other amortization, net ........................ -- -- -- (3,879) (5,060) (2,167)
Curtailment .................................... -- (2,605) 7,771 -- -- --
- --------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit (credit)/cost ............. $(44,138) $ (22,527) $ 9,069 $28,929 $28,311 $39,153
================================================================================================================================
For calculating pension and postretirement benefit costs, the following
assumptions were used:
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------------------- -------------------------------
1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
Discount rate .................................. 7.25% 7.75% 7.50% 7.25% 7.75% 7.50%
Expected long-term
rate of return ............................. 9.50 9.25 8.75 N/A N/A N/A
Compensation/
progression rate ........................... 4.25 4.75 4.75 4.25 4.75 4.75
Long-term rate of return --
Health assets, net of tax .................. N/A N/A N/A 7.75 7.50 5.25
Life assets ................................ N/A N/A N/A 9.50 9.25 8.75
================================================================================================================================
37
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. The effect of changing the assumed health
care cost trend rate by one percentage point in each year would have the
following effects:
- -------------------------------------------------------------------
One Percentage One Percentage
(Thousands of Dollars) Point Increase Point Decrease
- -------------------------------------------------------------------
Effect on total service and
interest cost components ........... $ 1,294 $(1,325)
Effect on postretirement
benefit obligation ................. 16,214 (16,141)
===================================================================
The trust holding the health plan assets is subject to federal income taxes at a
39.6 percent tax rate.
B. 401(K) SAVINGS PLAN
NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
The company matches, with cash and company stock, employee contributions up to a
maximum of 3 percent of eligible compensation. The matching contributions made
by the company were $13.2 million for 1998, $12.0 million for 1997 and $11.8
million for 1996.
C. ESOP
NU maintains an ESOP for purposes of allocating shares to employees
participating in the NU system's 401(k) Savings Plan. Under this arrangement, NU
issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds
of which were lent to the ESOP trust for purchase of approximately 10.8 million
newly issued NU common shares (ESOP shares). The ESOP trust is obligated to make
principal and interest payments on the ESOP notes at the same rate that ESOP
shares are allocated to employees. NU makes annual contributions to the ESOP
equal to the ESOP's debt service, less dividends received by the ESOP. All
dividends received by the ESOP on unallocated shares are used to pay debt
service and are not considered dividends for financial reporting purposes.
During 1998, there were no dividends on NU stock.
In 1998 and 1997, the ESOP trust issued approximately 584,000 and 948,000 of
NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to
employees. As of December 31, 1998 and 1997, the total allocated ESOP shares
were 4,724,858 and 4,140,751, respectively, and total unallocated ESOP shares
were 6,075,327 and 6,659,434, respectively. The fair market value of unallocated
ESOP shares as of December 31, 1998 and 1997, was approximately $97.2 million
and $78.7 million, respectively.
D. STOCK BASED COMPENSATION
Employee Stock Purchase Plan: Beginning in July 1998, the NU system has an
employee stock purchase plan (ESPP) for all eligible employees. Under the ESPP,
shares of NU common stock may be purchased at six-month intervals at 85 percent
of the lower of the price on the first or last day of each six-month period.
Employees may purchase shares having a value not exceeding 25 percent of their
compensation at the beginning of the purchase period. During 1998, employees
purchased 129,471 shares at a discounted price of $13.60 per share. At December
31, 1998, 1,870,529 shares remained reserved for future issuance under the ESPP.
Incentive Plans: The NU system has long-term incentive plans authorizing
various types of stock based awards, including stock options, to be made to
eligible employees and board members. The exercise price of stock options, as
set at the time of grant, is equal to the fair market value per share at the
date of grant. Under the Northeast Utilities Incentive Plan (Incentive Plan)
approved by shareholders in May 1998, the number of shares which may be utilized
for awards granted during a given calendar year may not exceed 1 percent of the
total number of shares of NU common stock outstanding as of the first day of
that calendar year.
No stock options were granted in 1996. Stock option transactions for 1997 and
1998 are as follows:
- --------------------------------------------------------------------------------------------------------------------------------
Price Per Share
- --------------------------------------------------------------------------------------------------------------------------------
Weighted
Options Range Average
- --------------------------------------------------------------------------------------------------------------------------------
Outstanding December 31, 1996 ............................................. -- -- --
Granted ................................................................... 500,000 $9.625 $ 9.625
- --------------------------------------------------------------------------------------------------------------------------------
Outstanding December 31, 1997 ............................................. 500,000 $ 9.625 $ 9.625
Granted ................................................................... 741,273 $14.875 - $16.8125 $ 16.178
Forfeited ................................................................. (7,595) $16.3125 $16.3125
- --------------------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1998 ............................................. 1,233,678 $ 9.625 - $16.8125 $13.5213
- --------------------------------------------------------------------------------------------------------------------------------
EXERCISABLE DECEMBER 31, 1998 ............................................. 232,936 $14.875 - $16.8125 $16.2972
================================================================================================================================
38
The vesting schedule for the options granted in 1997 is 50 percent after two
years, 75 percent after three years and 100 percent after four years. The
vesting schedule for the options granted in 1998 is one-third upon grant,
two-thirds after one year and the total award after two years.
Under the Incentive Plan, the NU system awarded 49,973 shares of restricted
stock in 1998. These shares have the same vesting schedule as the options
granted under the Incentive Plan. During 1997, certain key officers were
awarded restricted stock totaling 25,700 shares and which vest pro rata over
three years from the date of grant. During 1996, the same key officers were
awarded 43,000 shares of restricted stock which vest upon meeting specific
performance goals. The NU system also has made several small grants of
restricted stock and other incentive-based stock compensation.
During 1998, 1997 and 1996, approximately $795,000, $246,000 and $411,000,
respectively, was expensed for stock based compensation.
Had compensation cost been determined for the stock options and the ESPP
under the fair value method as opposed to the intrinsic value method followed by
the NU system, the effect on net loss and loss per share would have been as
follows:
- ---------------------------------------------------------
(Thousands of Dollars,
except per share amounts) 1998 1997
- ---------------------------------------------------------
Net loss ........................... $149,054 $130,035
Basic and diluted loss
per share ........................ $ 1.14 $ 1.01
=========================================================
The fair value of each stock option grant has been estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:
- ---------------------------------------------------------
1998 1997
- ---------------------------------------------------------
Risk-free interest rate ............ 5.82% 6.41%
Expected life ...................... 10 years 10 years
Expected volatility ................ 35.05% 31.89%
Expected dividend yield ............ 5.46% 7.42%
=========================================================
The weighted average grant date fair values of options granted during 1998 and
1997 were $3.98 and $1.68, respectively.
6. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
CL&P and WMECO have entered into agreements to sell up to $200 million and $40
million, respectively, of undivided ownership interests in eligible customer
receivables and accrued utility revenues (receivables).
CL&P and WMECO each have established a special purpose, wholly owned
subsidiary whose business consists of the purchase and resale of receivables:
CL&P Receivables Corporation (CRC), and WMECO Receivables Corporation (WRC),
respectively. For receivables sold, both CL&P and WMECO have retained collection
responsibilities as agent for the purchaser under each company's respective
agreements. As collections reduce previously sold receivables, new receivables
may be sold. At December 31, 1998, approximately $105 million and $20 million
of receivables had been sold to third-party purchasers by CL&P and WMECO,
respectively. All receivables sold to CRC and WRC are not available to pay
CL&P's or WMECO's creditors.
The receivables are sold to third-party purchasers with limited recourse.
The sales agreements provide for a formula-based loss reserve in which
additional receivables may be assigned to the third-party purchasers for costs
such as bad debt. The third-party purchasers absorb the excess amount in the
event that actual loss experience exceeds the loss reserve. At December 31,
1998, approximately $11.6 million and $2.9 million were the formula-based
amounts of credit exposure and have been reserved as collateral by CRC and WRC,
respectively. Historical losses for bad debt for both CL&P and WMECO have been
substantially less.
As a result of prior period downgrades on WMECO's first mortgage bonds, the
current bond rating is at a level where the sponsor of WMECO's accounts
receivable program could take various actions at its discretion, which would
have the practical effect of limiting WMECO's ability to utilize the facility.
To date, the sponsor has not notified WMECO that it will elect to exercise
those rights and the program is functioning in its normal mode.
Concentrations of credit risk to the respective purchasers under each
company's agreements with respect to the receivables are limited due to CL&P's
and WMECO's diverse customer base within their respective service territories.
39
7. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING
Connecticut: During April 1998, the utility restructuring bill was signed into
law by the governor of the state of Connecticut. The legislation provides for
electric utilities, including CL&P, to recover stranded costs. The legislation
also allows for securitization of generation-related regulatory assets and the
costs associated with renegotiated above-market purchased-power contracts and
requires divestiture of generation-related assets through public auction.
As a result of the restructuring legislation, CL&P will sell non-nuclear
generating assets and purchased-power contracts with nonutility generators
through public auction. CL&P also will transfer its ownership interests in
Millstone 2 and 3 and Seabrook to a corporate affiliate or division, subject to
prior federal regulatory approvals, which would assume CL&P's responsibilities
related to the plants for the period prior to offering them for sale. In
February 1999, the DPUC announced the offering for sale of CL&P's fossil fuel
and hydroelectric generating facilities. Interested parties will be required to
submit nonbinding bids by April 8, 1999. A smaller field of qualified bidders
will be selected to participate in the second round of the auction and will be
invited to submit binding bids. A winning bidder will be chosen by mid-1999 and
the sale will be completed by the end of 1999. At December 31, 1998, the book
value of assets to be auctioned during 1999 was approximately $170 million.
After restructuring is complete, CL&P will be an electric transmission and
distribution company which will continue to provide transmission and
distribution services on a cost-of-service basis.
Management continues to believe that it is probable that CL&P will recover
fully its prudently incurred costs, including regulatory assets and stranded
investments.
New Hampshire: In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1998. In February 1997, the NHPUC
issued its restructuring order, which would have forced PSNH and NAEC to write
off all of their regulatory assets, and possibly to seek protection under
Chapter 11 of the bankruptcy laws. The amount of potential write-off which would
have been triggered by the order currently is estimated to be in excess of $400
million, after taxes.
Following the issuance of these orders, PSNH immediately sought declaratory
and injunctive relief on various grounds in federal district court and has
received a preliminary injunction that freezes implementation of the NHPUC's
restructuring orders. Restructuring in New Hampshire has resulted in numerous
subsequent proceedings within the federal and state legal systems.
As the court proceedings are ongoing, PSNH continues to be involved in
settlement discussions with representatives from the state of New Hampshire.
PSNH hopes to reach a settlement which would include, among other things,
recovery of regulatory assets and stranded costs, rate reductions, an auction of
PSNH's generating units and securitization of PSNH's stranded costs. If a
settlement is not reached, a trial is expected to begin in mid to late 1999.
As a result of the NHPUC decision and the potential consequences discussed
above, the reports of our auditors on the individual financial statements of
PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs
indicate that a substantial doubt exists currently about the ability of PSNH and
NAEC to continue as going concerns. The accounts of PSNH and NAEC are included
in the accompanying consolidated financial statements on the basis of a going
concern. While the effect of the implementation of that decision would have a
material adverse impact on NU's financial position, results of operations and
cash flows, it would not in and of itself result in defaults under borrowing or
other financial agreements of NU or its other subsidiaries.
Management believes that PSNH is entitled to full recovery of its prudently
incurred costs, including regulatory assets and other stranded costs. It bases
this belief both on the general nature of public utility industry
cost-of-service based regulation and the specific circumstances of the
resolution of PSNH's previous bankruptcy proceedings and its acquisition by NU,
including the recoveries provided by the Rate Agreement and related agreements.
Massachusetts: Electric utility industry restructuring within the state of
Massachusetts became effective March 1, 1998. As required by the legislation
enacted in November 1997, WMECO will continue to operate and maintain its
transmission and local distribution network and deliver electricity to all
customers. The restructuring legislation specifically provides for the cost
recovery of generation-related assets. The legislation gives the DTE the
authority to determine the amount of stranded costs that will be eligible for
recovery by utilities. Costs which will qualify as stranded costs and be
eligible for recovery include, but are not limited to, certain above-market
costs associated with generating facilities, costs associated with long-term
commitments to purchase power at above-market prices from small-power producers
and nonutility generators (NUGs), and regulatory assets and associated
liabilities related to the generation portion of WMECO's business.
Effective March 1, 1998, WMECO's restructuring plan has been filed with the
DTE and includes a 10 percent rate reduction, divestiture of generation assets,
securitization of approximately $500 million of stranded costs and customer
choice of supplier. The DTE has not approved WMECO's plan yet and rates are
being charged under an interim order. A final decision is expected in mid-1999.
On January 22, 1999, WMECO signed an agreement to sell 290 MW of fossil and
hydroelectric generation assets to Consolidated Edison Energy, Inc. of New York
for $47 million. The sale price is approximately 3.8 times greater
40
than the assets' 1997 book value of $12.5 million. WMECO did not offer its 19
percent share of the Northfield Mountain pumped storage generating facility and
associated hydroelectric facilities. WMECO's book value in Northfield Mountain
was $13.0 million at December 31, 1998. This asset will be auctioned in
conjunction with CL&P's fossil/hydroelectric auction discussed above. The net
proceeds in excess of book value received from the actual divestiture of these
units will be used to mitigate stranded costs.
Based upon the legislation and regulatory proceedings to date, management
continues to believe that the NU system companies will recover their prudently
incurred costs, including regulatory assets and generation-related investments.
However, a change in one or more of these factors could affect the recovery of
stranded costs and may result in a loss to the company.
B. RATE MATTERS
Connecticut: On February 25, 1998, the DPUC issued its decision in CL&P's
Interim Rate case. During the period from March 1, 1998, through September 28,
1998, rates were charged under an interim rate which required a $30.5 million
annual credit to customer bills to reflect the removal of Millstone 1 from
rates.
During April 1998, the DPUC issued a decision finding Millstone 2 unlikely
to restart in 1998 and ordered its removal from rate base effective May 1, 1998.
The DPUC allowed the revenue requirement reductions related to this decision to
be potentially applied against regulatory asset balances. As a result, there was
no change in rates or CL&P's cash flow from rates. CL&P has accounted for these
reductions as a reserve against revenues until such time when the regulatory
asset balances are reduced. At December 31, 1998, the amount of revenue
reductions related to this decision totaled approximately $36.4 million. The
unit will remain out of rate base until the plant is restarted.
On June 1, 1998, CL&P filed its rate application for a comprehensive rate
proceeding. On February 5, 1999, the DPUC issued its final decision in CL&P's
rate case. The DPUC concluded that CL&P's annual revenue requirements should be
reduced by approximately $232 million, or 9.68 percent, through a combination of
a 4 percent reduction to CL&P's rates and accelerated amortization of approxi-
mately $136 million of its deferred tax regulatory asset. The decision is
retroactive to September 28, 1998. The retroactive portion of the decision did
not require a base-rate decrease. It resulted in accelerated amortization of the
deferred tax regulatory asset in the amount of $27.6 million. The decision also
resulted in an after-tax write-off of approximately $80 million related to
CL&P's investment in Millstone 1. For further information, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs," and the MD&A.
New Hampshire: PSNH's Rate Agreement between NU, PSNH and the state of New
Hampshire provided for seven base-rate increases of 5.5 percent per year
beginning in 1990 and provided for the FPPAC. The final base-rate increase went
into effect on June 1, 1996. The Rate Agreement contemplates that PSNH's rates
are subject to traditional rate regulation after the fixed-rate period, which
expired on May 31, 1997. The FPPAC, however, would continue through May 31,
2001, and other Rate Agreement requirements would continue in accordance with
the terms of the agreement.
A PSNH base-rate case was filed in May 1997, but was delayed in connection
with the restructuring proceedings discussed above. In November 1997, the NHPUC
ordered a temporary base-rate reduction for PSNH of 6.87 percent effective
December 1, 1997. The NHPUC also set an interim return on equity of 11 percent.
In December 1998, the base-rate case was reopened and an updated rate case was
filed. A final decision, which will be retroactive to July 1, 1997, currently
is scheduled to be issued by June 1, 1999.
Concurrently with the 6.87 percent rate reduction beginning in December
1997, the NHPUC allowed an FPPAC increase of approximately 6 percent. This rate
increase was effective for the period from December 1, 1997, through May 31,
1998. On May 29, 1998, the NHPUC approved slightly more than a 1 percent
increase in PSNH's FPPAC rate for the period June through November 1998. On
December 1, 1998, the NHPUC allowed the current FPPAC rate to remain in place
through May 31, 1999. As a result of this decision, the current portion of un-
recovered energy costs are projected to increase by approximately $17.4 million
from January 1, 1999, through May 31, 1999, to an estimated balance of
approximately $79.7 million. PSNH's ongoing restructuring settlement
negotiations with the state of New Hampshire could resolve both the base-rate
case and the FPPAC proceedings discussed above.
FERC: During November 1997, MYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. During January 1998, the FERC accepted the amendments
and proposed rates, subject to a refund. On January 18, 1999, MYAPC filed with
the FERC Administrative Law Judge (ALJ) an Offer of Settlement which if accepted
by the FERC, will resolve all the issues in the FERC decommissioning rate case
proceeding. The settlement provides, among other things, the following: (1)
MYAPC will collect $33.6 million annually to pay for decommissioning and spent
fuel; (2) its return on equity will be set at 6.5 percent; (3) MYAPC is
permitted full recovery of all unamortized investment in MY, including fuel, and
(4) an incentive budget for decommissioning is set at $436.3 million.
During late December 1996, CYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. On February 27, 1997, the FERC accepted
41
CYAPC's contract amendment. The new rates became effective March 1, 1997,
subject to a refund.
On August 31, 1998, the FERC ALJ released an initial decision regarding the
December 1996 filing. The decision contained provisions which would allow for
the recovery, through rates, of the balance of the NU system companies' net
unamortized investment in CYAPC, which was approximately $51.7 million as of
December 31, 1998. The decision also called for the disallowance of the recovery
of a portion of the return on the CY investment. The ALJ's decision also stated
that decommissioning collections should continue to be based on the previously
approved estimate of $309.1 million (in 1992 dollars), with an inflation
adjustment of 3.8 percent per year, until a new, more reliable estimate has been
prepared and tested.
During October 1998, CYAPC, CL&P, PSNH and WMECO filed briefs on exceptions
to the ALJ decision. If the initial ALJ decision is upheld, CYAPC could be
required to write off a portion of the regulatory asset associated with the
plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ decision
on CYAPC's earnings would be approximately $37.5 million, of which the NU
system's share would be approximately $18.4 million. NU management cannot
predict the ultimate outcome of the hearing at this time, however, management
believes that the associated regulatory assets are probable of recovery.
C. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. All three units were
placed on the NRC watch list on January 29, 1996. The units cannot be restarted
without appropriate NRC approvals. Millstone 3 has received these approvals and
resumed operation in July 1998. Restart efforts continue for Millstone 2 and it
is expected to be ready to restart in the spring of 1999. The estimated
replacement power costs are approximately $8 million per month while Millstone 2
remains out of service. In July 1998, CL&P and WMECO decided to retire Millstone
1 and prepare for final decommissioning.
Litigation: Several shareholder class-action lawsuits have been filed
against the company and certain present and former officers and employees of NU
in connection with the company's nuclear operations. Management cannot estimate
the potential outcome of these suits, but believes these suits are without merit
and intends to defend itself vigorously in all these actions.
In addition, certain of the non-NU joint owners of Millstone 3 filed
demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts
Superior Court against NU and its current and former trustees related to the
company's operation of Millstone 3. The arbitrations and lawsuits seek to
recover compensatory damages in excess of $200 million, together with punitive
damages, treble damages and attorney's fees. Management cannot estimate the
potential outcome of these suits but believes there is no legal basis for the
claims and intends to defend against them vigorously.
D. ENVIRONMENTAL MATTERS
The NU system is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of toxic
substances and hazardous and solid wastes, and the handling and use of chemical
products. The NU system has an active environmental auditing and training
program and believes that it is in substantial compliance with current
environmental laws and regulations. However, the NU system is subject to certain
pending enforcement actions and governmental investigations in the environmental
area. Management cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new generating
units, transmission and distribution lines, substations and other facilities.
Changing environmental requirements could also require extensive and costly
modifications to the NU system's existing generating units and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the NU 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 byproducts and wastes. The NU system also may
encounter significantly increased costs to remedy the environmental effects of
prior waste handling activities. The cumulative long-term cost impact of
increasingly stringent environmental requirements cannot be estimated
accurately.
The NU system has recorded a liability based upon currently available
information for the estimated environmental remediation costs that the NU system
subsidiaries expect to incur. In most cases, additional future environmental
cleanup costs are not reasonably estimable due to a number of factors, including
the unknown magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and the
possible effects of technological changes. At December 31, 1998, the liability
recorded by the NU system for its estimated environmental remediation costs, not
considering any possible recoveries from third parties, amounted to
approximately $21.5 million, within a range of $21.5 million to $36.4 million.
The NU system companies have received proceeds from several insurance
carriers for the settlement with certain insurance companies of all past,
present and future environmental matters. As a result of these settlements, the
NU system companies will retain the risk loss, in part, for some environmental
remediation costs.
The NU system cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against it.
However, considering known facts, existing laws and regulatory practices,
management does not believe the matters disclosed above will have a material
effect on the NU system's financial position or future results of operations.
42
E. 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. The DOE is responsible for the selection
and development of repositories for, and the disposal of, spent nuclear fuel and
high-level radioactive waste. Fees for nuclear fuel burned on or after April 7,
1983, are billed currently to customers and paid to the DOE on a quarterly
basis. For nuclear fuel used to generate electricity prior to April 7, 1983
(prior period fuel), payment must be made prior to the first delivery of spent
fuel to the DOE. Until such payment is made, the outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield Rate. At
December 31, 1998, fees due to the DOE for the disposal of prior period fuel
were approximately $216.1 million, including interest costs of $134.0 million.
The DOE originally was scheduled to begin accepting delivery of spent fuel
in 1998. However, delays in identifying a permanent storage site continually
have postponed plans for the DOE's long-term storage and disposal site. Extended
delays or a default by the DOE could lead to consideration of costly
alternatives. The company has primary responsibility for the interim storage of
its spent nuclear fuel. Adequate storage capacity exists to accommodate all
spent nuclear fuel at Millstone 1. With the addition of new storage racks,
storage facilities for Millstone 3 are expected to be adequate for the projected
life of the unit. With the implementation of currently planned modifications,
the storage facilities for Millstone 2 are expected to be adequate to
accommodate a full-core discharge from the reactor until 2005. Fuel
consolidation, which has been licensed for Millstone 2, could provide adequate
storage capability for its projected life. Seabrook is expected to have spent
fuel storage capacity until at least 2010. Meeting spent fuel storage
requirements beyond these periods could require new and separate storage
facilities, the costs for which have not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit ruled that
the lack of an interim storage facility does not excuse the DOE from meeting its
contractual obligation to begin accepting spent nuclear fuel no later than
January 31, 1998. The 1997 ruling by the appeals court said, however, that the
1982 federal law could not require the DOE to accept waste when it did not have
a suitable storage facility. The court directed the plaintiffs to pursue relief
under the terms of their contracts with the DOE. Based on this ruling, since the
DOE did not take the spent nuclear fuel as scheduled, it may have to pay
contract damages.
In May 1998, the same court denied petitions from 60 states and state
agencies, collectively, and 41 utilities, including the company, asking the
court to compel the DOE to submit a program, beginning immediately, for
disposing of spent nuclear fuel. The petitions were filed after the DOE
defaulted on its January 31, 1998 obligation to begin accepting the fuel. The
court directed the company and other plaintiffs to pursue relief under the terms
of their contracts with the DOE.
In a petition filed in August 1998, the court's May 1998 decision was
appealed to the U.S. Supreme Court. In November 1998, the Supreme Court declined
to review the lower court ruling that said utilities should go to court and seek
monetary damages from the DOE. The ultimate outcome of this legal proceeding is
uncertain at this time.
F. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities in the country covered by the federal government's
third-party liability indemnification program, the NU system could be assessed
in proportion to its ownership interest in each of its nuclear units up to $83.9
million. The NU system's payments of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear units, $10 million
in any one year per nuclear unit. In addition, if the sum of all claims and
costs from any one nuclear incident exceeds the maximum amount of financial
protection, the NU system would be subject to an additional 5 percent or $4.2
million, in proportion to its ownership interests in each of its nuclear units.
Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1,
the NU system's maximum liability, including any additional assessments, would
be $271.0 million per incident, of which payments would be limited to $30.8
million per year. In addition, through purchased-power contracts with VYNPC, the
NU system would be responsible for up to an additional $14.1 million per
incident, of which payments would be limited to $1.6 million per year.
The NRC approved CYAPC's and MYAPC's requests for withdrawal from
participation in the secondary financial protection program effective November
19, 1998, and January 17, 1999, respectively, due to their permanently shutdown
and defueled status. Therefore, neither CYAPC, MYAPC nor their sponsor companies
have any future obligations for potential assessment.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from insured
occurrences. The NU system is subject to retroactive assessments if losses
exceed the accumulated funds available to the insurer. The maximum potential
assessment against the NU system with respect to losses arising during the
current policy year is approximately $14.2 million under the primary property
insurance program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and the excess
cost of repair, replacement or decontamination or premature decommis-
43
sioning of utility property resulting from insured occurrences. The NU system is
subject to retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessments against the NU
system with respect to losses arising during current policy years are
approximately $6.9 million under the replacement power policies and $16.4
million under the excess property damage, decontamination and decommissioning
policies. The cost of a nuclear incident could exceed available insurance
proceeds.
Insurance has been purchased aggregating $200 million on an industry basis
for coverage of worker claims.
G. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision by
management. The NU system companies currently forecast construction expenditures
of approximately $2.1 billion for the years 1999-2003, including $364 million
for 1999. In addition, the NU system companies estimate that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $252.2 million for the years 1999-2003, including $34.0 million
for 1999. See Note 4, "Leases," for additional information about the financing
of nuclear fuel.
H. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: The NU system companies rely on VY for approximately 1.4
percent of their capacity under long-term contracts. Under the terms of their
agreements, the NU system companies pay their ownership (or entitlement) shares
of costs, which include depreciation, O&M expenses, taxes, the estimated cost of
decommissioning and a return on invested capital. These costs are recorded as
purchased-power expense and recovered through the companies' rates. The total
cost of purchases under contracts with VYNPC amounted to $27.3 million in 1998,
$24.2 million in 1997 and $25.5 million in 1996. CL&P, PSNH and WMECO also may
be asked to provide direct or indirect financial support for one or more of the
Yankee companies, including VYNPC.
NUGs: CL&P, PSNH and WMECO have entered into various arrangements for the
purchase of capacity and energy from NUGs. These arrangements have terms from 10
to 30 years, currently expiring in the years 1999 through 2029, and require the
companies to purchase energy at specified prices or formula rates. For the
12-month period ending December 31, 1998, approximately 13 percent of NU system
electricity requirements was met by NUGs. The total cost of purchases under
these arrangements amounted to $459.7 million in 1998, $447.6 million in 1997
and $441.6 million in 1996.
New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement
to purchase the capacity and energy of the New Hampshire Electric Cooperative,
Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for
a 10-year period, which began on July 1, 1990. The total cost of purchases under
this agreement was $29.7 million in 1998, $23.4 million in 1997 and $14.6
million in 1996. The total cost of these purchases has been collected through
the FPPAC in accordance with the Rate Agreement.
Although under the agreement NHEC agreed to continue as a firm-requirements
customer of PSNH for 15 years, it has recently received a FERC ruling allowing
it to purchase power from qualifying facilities. The ruling allows that the
price for such purchases may be determined through negotiation between NHEC and
the qualifying facility. The financial impact of this decision in the future
will vary depending upon the level of purchases made by NHEC from the qualifying
purchasers.
NHEC also is seeking to be able to purchase energy under the agreement from
competitive sources once competition has begun in its service territory. A
final FERC decision is expected by March 1999. The financial impact of this
decision in the future will depend upon the implementation of restructuring in
NHEC's service territory.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and
HWP have entered into agreements to support transmission and terminal facilities
to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO
and HWP are obligated to pay, over a 30-year period ending in 2020, their
proportionate shares of the annual O&M and capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements are as follows:
- --------------------------------------------------------------
(Millions of Dollars) 1999 2000 2001 2002 2003
- --------------------------------------------------------------
VYNPC ................. $ 29.2 $ 27.0 $ 29.4 $ 30.0 $ 27.9
NUGs .................. 473.3 476.8 484.9 493.5 505.1
NHEC .................. 30.0 14.6 -- -- --
Hydro-Quebec .......... 32.2 30.9 30.0 29.3 28.5
==============================================================
8. INTEREST-RATE AND FUEL-PRICE RISK-MANAGEMENT
Interest-Rate Risk-Management: NAEC uses swap instruments with financial
institutions to hedge against interest rate risk associated with its $200
million variable-rate bank note. The interest-rate management instruments
employed eliminate the exposure associated with rising interest rates, and
effectively fix the interest rate for this borrowing arrangement. Under the
agreements, NAEC exchanges quarterly payments based on a differential between a
fixed
44
contractual interest rate and the three-month LIBOR rate at a given time.
As of December 31, 1998, NAEC had outstanding agreements with a total notional
value of approximately $200 million and a negative mark-to-market position of
approximately $2.3 million.
Fuel-Price Risk-Management: CL&P uses swap instruments with financial
institutions to hedge against some of the fuel price risk created by long-term
negotiated energy contracts. These agreements minimize exposure associated with
rising fuel prices by managing a portion of CL&P's cost of producing power for
these negotiated energy contracts. As of December 31, 1998, CL&P had outstanding
agreements with a total notional value of approximately $422.2 million, and a
negative mark-to-market position of approximately $44.9 million.
The terms of the agreements require CL&P to post cash collateral with its
counterparties in the event of negative mark-to-market positions and lowered
credit ratings. The amount of the collateral is to be returned to CL&P when the
mark-to-market position becomes positive, when CL&P meets specified credit
ratings or when an agreement ends and all open positions are properly settled.
At December 31, 1998, cash collateral in the amount of $45.7 million was posted
under these terms. This amount has been recorded in Other Investments on the
accompanying Consolidated Balance Sheets.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
Each respective system company will be exposed to credit risk on their
respective market risk-management instruments if the counterparties fail to
perform their obligations. Management anticipates that the counterparties will
fully satisfy their obligations under the agreements.
9. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
CL&P Capital LP (CL&P LP, a subsidiary of CL&P) previously had issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million
capital contribution, back to CL&P in the form of an unsecured debenture. CL&P
consolidates CL&P LP for financial reporting purposes. Upon consolidation, the
unsecured debenture is eliminated, and the MIPS securities are accounted for as
minority interests.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value due
to the short-term nature of cash and cash equivalents.
Supplemental Executive Retirement Plan investments: SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities," requires investments in
debt and equity securities to be presented at fair value. As a result of this
requirement, the investments having a cost basis of $5.4 million held for
benefit of the Supplemental Executive Retirement Plan were recorded on the
Consolidated Balance Sheet at their fair market value at December 31, 1998, of
$8.7 million.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were adjusted to market by
approximately $110.4 million as of December 31, 1998, and $69.6 million as of
December 31, 1997, with corresponding offsets to the accumulated provision for
depreciation. The amounts adjusted in 1998 and in 1997 represent cumulative net
unrealized gains. The cumulative gross unrealized holding losses were immaterial
for both 1998 and 1997.
Preferred stock and long-term debt: The fair value of the NU system's
fixed-rate securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair value
equal to their carrying value. The carrying amounts of the NU system's financial
instruments and the estimated fair values are as follows:
- ---------------------------------------------------------
At December 31, 1998
- ---------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- ---------------------------------------------------------
Preferred stock not subject
to mandatory redemption ....... $ 136,200 $ 97,017
Preferred stock subject to
mandatory redemption .......... 213,789 205,905
Long-term debt --
First mortgage bonds .......... 1,984,000 2,003,630
Other long-term debt .......... 1,654,927 1,682,722
MIPS ............................ 100,000 102,000
=========================================================
- ---------------------------------------------------------
At December 31, 1997
- ---------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- ---------------------------------------------------------
Preferred stock not subject
to mandatory redemption ....... $ 136,200 $ 79,141
Preferred stock subject to
mandatory redemption .......... 276,000 255,180
Long-term debt --
First mortgage bonds .......... 2,228,800 2,210,423
Other long-term debt .......... 1,668,533 1,691,362
MIPS ............................ 100,000 100,760
=========================================================
45
11. EARNINGS PER SHARE
Earnings per share is computed based upon the weighted average number of common
shares outstanding during each year. Diluted earnings per share is computed on
the basis of the weighted average number of common shares outstanding plus the
potential dilution effect if certain securities are converted into common stock.
The following table sets forth the components of basic and diluted earnings
per share:
- ---------------------------------------------------------------
(Thousands of Dollars,
except per share data) 1998 1997 1996
- ---------------------------------------------------------------
(Loss)/ income after
interest charges ..... $(120,313) $ (99,676) $72,705
Preferred dividends
of subsidiaries ...... 26,440 30,286 33,776
- ---------------------------------------------------------------
Net (loss)/income ...... $(146,753) $(129,962) $38,929
===============================================================
Basic EPS common
shares outstanding
(average) ............ 130,549,760 129,567,708 127,960,382
Dilutive effect of
employee stock
options .............. --(a) --(a) 112,879
- ---------------------------------------------------------------
Diluted EPS common
shares outstanding
(average) ............ 130,549,760 129,567,708 128,073,261
===============================================================
Basic earnings
per share ............ $ (1.12) $ (1.01) $ 0.30
Diluted earnings
per share ............ $ (1.12) $ (1.01) $ 0.30
===============================================================
(a) The addition of dilutive potential common shares would be anti-dilutive for
1998 and 1997 and, therefore, are not included.
12. OTHER COMPREHENSIVE INCOME
During 1998, the NU system adopted SFAS 130, "Reporting Comprehensive Income,"
which established standards for reporting and displaying comprehensive income
and its components in a financial statement that is displayed with the same
prominence as other financial statements.
The accumulated balance for each other comprehensive income item is as
follows:
- ---------------------------------------------------------------
Current
December 31, Period DECEMBER 31,
(Thousands of Dollars) 1997 Change 1998
- ---------------------------------------------------------------
Foreign currency
translation adjustments ........ $(1) $ -- $ (1)
Unrealized gains on
securities ..................... -- 2,019 2,019
Minimum pension liability
adjustment ..................... -- (613) (613)
- ---------------------------------------------------------------
Accumulated other
comprehensive income ........... $(1) $1,406 $1,405
===============================================================
The changes in the components of other comprehensive income are reported on the
Consolidated Statements of Comprehensive Income net of the following income tax
effects:
- ---------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- ---------------------------------------------------------------
Foreign currency
translation
adjustments ................ $ -- $359 $(313)
Unrealized gains
on securities .............. (1,222) -- --
Minimum pension
liability
adjustment ................. 398 -- --
- ---------------------------------------------------------------
Other comprehensive
income ..................... $ (824) $359 $(313)
===============================================================
13. MODE 1
In July 1998, Mode 1's equity investments, FiveCom LLC and NECOM LLC,
reorganized along with other related companies to form a new company, NorthEast
Optic Network, Inc. ("NEON"). Mode 1's ownership interest of 40.78 percent in
the new company was equal to its combined ownership interest in FiveCom LLC and
NECOM LLC.
In August 1998, NEON issued 4,000,000 new common shares on the open market
in an initial public offering (IPO). NEON's IPO had the effect of decreasing
Mode 1's ownership interest from 40.78 percent to 30.74 percent. The shares were
issued at an amount greater than Mode 1's investment, resulting in a $13.7
million pretax increase to Mode 1's equity. NU's accounting policy is to
recognize the gain or loss from this type of change in ownership interest in net
income. Based upon new information received regarding the startup nature of
NEON's operations, this change in ownership interest was recognized in
additional paid in capital instead of net income.
In conjunction with the IPO, Mode 1 sold 217,997 NEON shares, resulting in a
pretax gain of $1.7 million and further reducing its ownership interest to 29.4
percent of the outstanding common shares of NEON.
46
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA
(UNAUDITED)
- ----------------------------------------------------------------------------------------------------------------------
1998 Quarter Ended (a)
- ----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share data) March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues ........................................... $958,905 $874,809 $974,382 $ 959,618
======================================================================================================================
Operating Income ............................................. $ 40,488 $ 76,296 $ 82,675 $ 25,268
======================================================================================================================
Net (Loss)/Income ............................................ $(17,949) $ 6,273 $ (3,075)(b) $(132,002)
======================================================================================================================
Basic and Diluted (Loss)/Earnings Per Common Share ........... $ (0.14) $ 0.05 $ (0.02)(b) $ (1.01)
======================================================================================================================
- ----------------------------------------------------------------------------------------------------------------------
1997
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues ........................................... $975,368 $903,323 $977,127 $ 978,988
======================================================================================================================
Operating Income ............................................. $ 69,377 $ 23,542 $ 46,361 $ 51,502
======================================================================================================================
Net Income/(Loss) ............................................ $ 876 $(47,017) $(30,832) $ (52,989)
======================================================================================================================
Basic and Diluted Earnings/(Loss) Per Common Share ........... $ 0.01 $ (0.37) $ (0.24) $ (0.41)
======================================================================================================================
CONSOLIDATED GENERATION STATISTICS
(UNAUDITED)
- ----------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
SOURCE OF ELECTRIC ENERGY: (kWh-millions)
Nuclear -- Steam (c) .......................... 5,679 3,778 9,405 18,235 19,443
Fossil -- Steam ............................... 12,505 13,155 9,188 9,162 8,292
Hydro -- Conventional ......................... 1,510 1,260 1,544 1,099 1,239
Hydro -- Pumped Storage ....................... 819 959 1,217 1,209 1,195
Internal Combustion ........................... 80 184 206 37 13
Energy Used for Pumping ....................... (1,130) (1,327) (1,668) (1,674) (1,629)
- ----------------------------------------------------------------------------------------------------------------------
Net Generation ................................ 19,463 18,009 19,892 28,068 28,553
- ----------------------------------------------------------------------------------------------------------------------
Purchased and Net Interchange ................. 24,945 24,377 22,111 14,256 14,028
Company Use and Unaccounted for ............... (2,566) (2,802) (2,473) (2,706) (2,535)
- ----------------------------------------------------------------------------------------------------------------------
Net Energy Sold ............................... 41,842 39,584 39,530 39,618 40,046
======================================================================================================================
System Capability -- MW (c)(d) ................ 8,169.6 8,312.0(e) 8,894.0 8,394.8 8,494.8
System Peak Demand -- MW ...................... 6,454.7 6,455.5 5,946.9 6,358.2 6,338.5
Nuclear Capacity -- MW (c)(d) ................. 2,217.8 2,785.0(e) 3,117.8 3,239.6 3,272.6
Nuclear Contribution to
Total Energy Requirements (%)(c) .......... 19.0 13.0 28.0 52.0 54.0
Nuclear Capacity Factor (%)(e) ................ 32.8 19.6 38.0 69.9 67.5
======================================================================================================================
(a) Reclassifications of prior years' data have been made to conform with the
current presentation.
(b) During the third quarter of 1998, Mode 1 classified the change in ownership
interest in NEON as a gain in net income. In the fourth quarter, the gain
was reclassified to additional paid in capital. See Note 13, "Mode 1" for
further information. Amounts previously reported for the third quarter were
net income of $4,976 and earnings per common share of $0.04.
(c) Includes the NU system's entitlements in regional nuclear generating
companies, net of capacity sales and purchases.
(d) Millstone 2 has been out of service since February 21, 1996. The NU system
hopes to return Millstone 2 to service in the spring of 1999. Millstone 3
returned to service during the third quarter of 1998 following NRC approval.
During the third quarter of 1998, CL&P and WMECO decided to retire Millstone
1 and prepare for final decommissioning.
(e) Represents the average capacity factor for the nuclear units operated by the
NU system.
47
SELECTED CONSOLIDATED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except percentages and per share data) 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA:
Net Utility Plant (a) ................................. $ 6,170,881 $ 6,463,158 $ 6,732,165 $ 7,000,837 $ 7,282,421
Total Assets .......................................... 10,387,381 10,414,412 10,741,748 10,559,574 10,584,880
Total Capitalization (b) .............................. 6,030,402 6,472,504 6,659,617 6,820,624 7,035,989
Obligations Under Capital Leases (b) .................. 209,279 207,731 206,165 230,482 239,121
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME DATA:
Operating Revenues .................................... $ 3,767,714 $ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742
Net (Loss)/Income ..................................... (146,753) (129,962) 38,929 282,434 286,874
- ----------------------------------------------------------------------------------------------------------------------------------
COMMON SHARE DATA:
Basic and Diluted (Loss)/Earnings
Per Share ......................................... $(1.12) $(1.01) $0.30 $2.24 $2.30
Dividends Per Share (c) ............................... $-- $0.25 $1.38 $1.76 $1.76
Number of Shares Outstanding -- Average ............... 130,549,760 129,567,708 127,960,382 126,083,645 124,678,192
Market Price -- High .................................. $17 1/4 $14 1/4 $25 1/4 $25 3/8 $25 3/4
Market Price -- Low ................................... $11 11/16 $7 5/8 $9 1/2 $21 $20 3/8
Market Price -- Closing (end of year) ................. $16 $11 13/16 $13 1/8 $24 1/4 $21 5/8
Book Value Per Share (end of year) .................... $15.63 $16.67 $18.02 $19.08 $18.47
Rate of Return Earned on Average
Common Equity (%) ................................. (7.0) (5.8) 1.6 12.0 12.7
Market-to-Book Ratio (end of year) .................... 1.0 0.7 0.7 1.3 1.2
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Common Shareholders' Equity ........................... 34% 34% 35% 36% 33%
Preferred Stock (b)(d) ................................ 5 6 6 7 9
Long-Term Debt (b) .................................... 61 60 59 57 58
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization .................................. 100% 100% 100% 100% 100%
==================================================================================================================================
(a) Restated to include the reclassification of the PSNH acquisition costs to
net utility plant.
(b) Includes portions due within one year.
(c) On March 25, 1997, the NU Board of Trustees adopted a resolution suspending
the quarterly dividends on NU's common shares.
(d) Excludes $100 million of Monthly Income Preferred Securities.
48
CONSOLIDATED SALES STATISTICS
- -------------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------------
REVENUES: (thousands)
Residential .................................. $1,475,363 $1,499,394 $1,501,465 $1,469,988 $1,430,239
Commercial ................................... 1,273,146 1,266,449 1,246,822 1,230,608 1,173,808
Industrial ................................... 568,913 560,782 565,900 583,204 559,801
Other Utilities .............................. 336,623 329,764 315,577 303,004 330,801
Streetlighting and Railroads ................. 47,682 48,867 48,053 47,510 45,943
Nonfranchised Sales .......................... 22,479 21,476 8,360 -- --
Miscellaneous ................................ 16,429 47,446 23,513 50,353 44,140
- -------------------------------------------------------------------------------------------------------------------------
Total Electric ........................... 3,740,635 3,774,178 3,709,690 3,684,667 3,584,732
Other ........................................ 27,079 60,628 82,458 65,893 58,010
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... $3,767,714 $3,834,806 $3,792,148 $3,750,560 $3,642,742
=========================================================================================================================
SALES: (kWh - millions)
Residential .................................. 12,162 12,099 12,241 12,005 12,231
Commercial ................................... 12,477 12,091 12,012 11,737 11,649
Industrial ................................... 6,948 6,801 6,820 6,842 6,729
Other Utilities .............................. 9,742 8,034 8,032 8,718 9,123
Streetlighting and Railroads ................. 320 318 319 316 314
Nonfranchised Sales .......................... 193 241 50 -- --
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... 41,842 39,584 39,474 39,618 40,046
=========================================================================================================================
CUSTOMERS: (average)
Residential .................................. 1,555,013 1,535,134 1,532,015 1,526,127 1,513,987
Commercial ................................... 162,500 159,350 157,347 156,652 154,703
Industrial ................................... 7,847 7,804 7,792 7,861 7,813
Other ........................................ 3,890 3,929 3,916 3,878 3,818
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... 1,729,250 1,706,217 1,701,070 1,694,518 1,680,321
=========================================================================================================================
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh) ........................... 7,799 7,898 8,005 7,880(a) 8,152
=========================================================================================================================
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER ................................. $ 946.80 $ 978.72 $ 980.19 $ 964.88(a) $ 953.23
=========================================================================================================================
AVERAGE REVENUE PER KWH:
Residential .................................. 12.14(cent) 12.39(cent) 12.27(cent) 12.24(cent) 11.69(cent)
Commercial ................................... 10.20 10.47 10.38 10.49 10.08
Industrial ................................... 8.19 8.25 8.30 8.52 8.32
=========================================================================================================================
(a) Effective January 1, 1996, the amounts shown reflect billed and unbilled
sales. 1995 has been restated to reflect this change.
49
NORTHEAST UTILITIES SYSTEM OFFICERS* As of March 1, 1999
CHAIRMAN, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
Michael G. Morris
GROUP PRESIDENTS
Bruce D. Kenyon
Generation Group
Hugh C. MacKenzie
Retail Business Group
EXECUTIVE VICE PRESIDENTS
Ted C. Feigenbaum
Nuclear Group
John H. Forsgren
Chief Financial Officer
SENIOR VICE PRESIDENTS
Cheryl W. Grise
Secretary and General Counsel
Leon J. Olivier
Chief Nuclear Officer
Gary D. Simon
Strategy and Development
VICE PRESIDENTS
David B. Amerine
Nuclear Technical Services
David H. Boguslawski
Energy Delivery
Michael H. Brothers
Nuclear Operations
Gregory B. Butler
Governmental Affairs
John T. Carlin
Human Services, Nuclear
Stephen J. Fabiani
Retail Sales and Marketing
Barry Ilberman
Human Resources and General Services
John B. Keane
Administration
Mary Jo Keating
Corporate Communications
Keith R. Marvin
Chief Information Officer
David R. McHale
Treasurer
William J. Nadeau
Fossil/Hydro Engineering and Operations
Raymond P. Necci
Nuclear Oversight and Regulatory Affairs
Thomas W. Philbin
Energy Services
John J. Roman
Controller
Frank C. Rothen
Nuclear Work Services
Frank P. Sabatino
Wholesale Marketing
Lisa J. Thibdaue
Rates, Regulatory Affairs
and Compliance
Dennis E. Welch
Environmental, Safety and Ethics
Roger C. Zaklukiewicz
Transmission and Distribution
ELECTRIC OPERATING COMPANY OFFICERS
William T. Frain, Jr.
President and Chief Operating Officer - PSNH
Robert G. Abair**
Vice President and Chief Administrative Officer - WMECO
Robert J. Kost
Vice President - Western Region - CL&P
Kerry J. Kuhlman
Vice President - Customer Operations - WMECO
Gary A. Long
Vice President - Customer Service and Economic Development - PSNH
Rodney O. Powell
Vice President - Central Region - CL&P
Paul E. Ramsey
Vice President - Customer Operations - PSNH
Richard L. Tower
Vice President - Eastern Region - CL&P
OTHER OFFICER
John P. Stack
Executive Director - Corporate Accounting and Taxes
ASSISTANT CONTROLLERS
Deborah L. Canyock
Management Information and Budgeting Services
Lori A. Mahler
Accounting Services
William J. Starr
Taxes
ASSISTANT TREASURERS
Robert C. Aronson
Treasury Operations
Randy A. Shoop
Finance
ASSISTANT SECRETARIES AND CLERKS
Theresa Hopkins Allsop
Robert A. Bersak - PSNH
O. Kay Comendul
Thomas V. Foley, Clerk - HWP
Patricia A. Wood, Clerk - WMECO
Margaret L. Morton
HEC INC., OFFICERS
Thomas W. Philbin
President
H. Donald Burbank
Vice President - Customer Service
David S. Dayton
Vice President
Linda A. Jensen
Vice President - Finance, Treasurer and Clerk
James B. Redden
Vice President - Operations
* All officers shown are for
Northeast Utilities Service Company,
unless otherwise indicated.
** Mr. Abair will retire effective April 1, 1999.
50