MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
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OVERVIEW
The financial improvement that began in 1998 continued throughout 1999 at
Northeast Utilities (NU or the company), despite rate reductions in Connecticut
and Massachusetts, and larger operating losses at NU's unregulated subsidiaries.
NU's results benefited from the successful restart of the Millstone 2 nuclear
unit, the strong operating performance delivered by the Millstone 3 and
Seabrook Station (Seabrook) nuclear units, retail sales growth, and continued
control over operation and maintenance (O&M) expenses. The financial
improvement allowed NU to resume the payment of a quarterly dividend for the
first time since early 1997. NU shareholders received a common dividend of 10
cents per share in the fourth quarter of 1999.
During 1999, NU resolved key industry restructuring issues by establishing
initial stranded cost recovery levels and standard offer service tariffs and
agreements in Connecticut and by receiving final approval of a restructuring
plan in Massachusetts. The auction of substantially all of the fossil and
hydroelectric generation assets owned by The Connecticut Light and Power
Company (CL&P) and Western Massachusetts Electric Company (WMECO) and the
auction of their respective interests in the output of the Millstone units,
moved both companies along in their transition into purely electric
transmission and distribution companies, as contemplated by restructuring
legislation in both Connecticut and Massachusetts. Also in 1999, the company
made significant progress toward resolving restructuring issues in the state
of New Hampshire by negotiating a global restructuring settlement that is still
subject to regulatory approval.
NU earned $34.2 million, or $0.26 per share in 1999, compared with a loss of
$146.8 million, or $1.12 per share in 1998 and a loss of $130 million, or $1.01
per share in 1997. Absent significant one-time items, the NU system earned
$0.89 per share in 1999, compared with a loss of $0.30 per share in 1998 and a
loss of $0.76 per share in 1997. NU's improved 1999 operating results are
attributed to better operating performance of its nuclear units, a strong
economy and continued strong expense control throughout the year. The 1999
results included $83 million, or $0.63 per share, in after-tax write-offs.
These write-offs were associated with the settlement of nuclear related issues
($0.39 per share), industry restructuring ($0.15 per share) and fees related to
the pending merger with Consolidated Edison, Inc. (Con Edison) ($0.09 per
share). During 1998, NU recorded $133 million, or $0.82 per share, in after-tax
write-offs associated with a rate decision in Connecticut, the retirement of
Millstone 1 and nonrecurring charges at Charter Oak Energy, an unregulated
generation subsidiary of NU. The "Agreement to Settle PSNH Restructuring"
(Settlement Agreement), involving the Public Service Company of New Hampshire
(PSNH) calls for an after-tax write-off of $225 million. However, that write-
off was not recorded in 1999, as key aspects of the Settlement Agreement still
required regulatory and legislative approval and it was not possible to
determine the ultimate resolution of this matter at year end.
In 1999, NU's revenues exceeded $4 billion for the first time, totaling
$4.47 billion, up 18.7 percent from revenues of $3.77 billion in 1998. The
growth was primarily due to increased electric sales by Select Energy, Inc.
(Select Energy), NU's unregulated power marketing subsidiary, and higher retail
sales from NU's regulated subsidiaries. Select Energy's revenues totaled $554.9
million in 1999, compared with $29.3 million in 1998. Revenues from the
company's regulated subsidiaries also benefited from a 3.8 percent increase in
retail sales, the largest increase in retail sales in recent history.
Approximately 40 percent of that growth was due to weather related factors that
included a hotter than normal summer. The balance of that increase was due to
economic expansion in NU's service territories.
Aside from increased revenues, the primary reason for better operating
performance in 1999 was the return to service from extended outages of
Millstone 3 in July 1998 and Millstone 2 in May 1999. The return to service of
those units reduced replacement power costs by $215 million in 1999, compared
to 1998.
Retail rate reductions involving CL&P and WMECO offset some of the growth in
revenues. CL&P's rates were reduced 5 percent in early 1999. CL&P's rates were
further reduced in January 2000 by 5 percent. The additional 5 percent rate
reduction will offset some of the growth in future revenues. WMECO's rates were
reduced a total of 15 percent from its August 1997 rates, 11.8 percent adjusted
for inflation, between March 1998 and September 1999.
Sharply higher purchased-power costs at Select Energy also offset many of
the benefits from higher sales. Select Energy recorded a net loss of $38.8
million in 1999, compared with a net loss of $13.4 million in 1998. Also in
1999, Select Energy's earnings were reduced by $4.1 million related to retail
contracts which extend through 2003.
NU's ability to continue improving financial performance in 2000 will depend
largely on continued regulated sales growth and on successful control of O&M
expenses. Additionally, NU plans to meet the challenges of assimilating Yankee
Energy System, Inc. (Yankee) into its business and achieving, by July 2000, the
shareholder and regulatory approvals needed to complete the merger with Con
Edison. NU also hopes to complete in 2000 the majority of restructuring work
remaining, primarily the implementation of the Settlement Agreement in New
Hampshire, the issuance of rate reduction bonds (securitization) to lower
stranded costs at CL&P, WMECO and PSNH, and the auction of NU's ownership
interests in the Millstone units. Additionally, during 2000, NU intends to
continue focusing on the growth of its competitive businesses. NU's ability to
reverse losses in its unregulated businesses will depend largely on the energy
marketing subsidiary's ability to better balance its supply options, including
soon to be acquired hydroelectric generation assets, with sales commitments.
MERGERS
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In 1998 and 1999, NU management concluded that the pace of deregulation was
accelerating throughout the northeastern United States and that shareholders
would benefit from NU, not only remaining a major provider of electric
transmission and distribution service, but also becoming an unregulated
marketer of both electricity and natural gas. NU management also concluded that
as a result of the changes occurring in the highly competitive electric utility
industry, increased size would be crucial to achieve its objective of being a
leading provider of energy products and services in the Northeast.
NU management discussed potential business combinations with several
electric utilities in the northeastern United States. On October 13, 1999, NU
announced an agreement to merge with Con Edison, a financially stronger utility
based in New York. Con Edison will pay approximately $3.8 billion for all of
the outstanding common stock of NU and will assume NU's debt, capitalized
leases and preferred securities which totaled $3.7 billion at December 31,
1999. Under the merger agreement, NU shareholders will receive $25 per share,
in a combination of cash and Con Edison common stock. NU shareholders will have
the right to elect cash or stock subject to proration if the total elections
exceed 50 percent in either cash or stock. NU shareholders who elect to receive
stock will receive the number of shares of Con Edison stock based on the
average trading prices, determined pursuant to a formula, during a fixed period
prior to the closing. So long as such average trading prices are between $36
and $46 per share, the total value of the Con Edison common stock received by
NU shareholders will be $25 per share. NU shareholders also have the right to
receive an additional $1 per share in value as long as definitive agreements to
sell its interests (other than that now held by PSNH) in Millstone 2 and 3 are
entered into and recommended by the Utility Operations and Management Unit of
the Connecticut Department of Public Utility Control (DPUC) on or prior to the
later of December 31, 2000, or the closing of the merger. In addition, another
$0.0034 per share per day for every day beyond August 5, 2000, that the merger
is not consummated is added to the purchase price. If Con Edison's stock price
is below $36 per share, then the value received for the stock portion will be
less than $25 per share. The merger will create the nation's largest electric
distribution system with more than 5 million customers and one of the 15
largest natural gas distribution systems with 1.4 million customers.
NU and Con Edison filed with various state and federal regulatory bodies in
January 2000 to secure approval of the merger. The two companies expect these
regulatory proceedings can be completed by the end of July 2000.
Also in 1999, NU management concluded that the Northeast Utilities system
(NU system) would be stronger and customers could be better served if NU
reentered the natural gas distribution business that it had exited in 1989 and
examined several potential businesses in New England. By adding gas to NU's
energy mix, NU will be able to broaden its services to its existing customers
and will have additional opportunities for long-term growth. In June 1999, NU
announced an agreement to merge with Yankee. Yankee is the natural gas division
that CL&P divested in 1989. Yankee shareholders will receive $45 per share, or
$479.6 million in cash and NU common stock. In addition, NU will assume
Yankee's outstanding debt of approximately $240.8 million. Yankee shareholders
will receive 45 percent of the $479.6 million in NU common stock and 55 percent
in cash. NU will finance the cash portion of the transaction and will meet the
stock component of the transaction by issuing new shares. NU expects to redeem
a similar amount of shares later this year by closing out forward share
purchase transactions with proceeds from restructuring. The forward share
purchase transactions were arranged in late 1999 with two financial
institutions. NU is prohibited from purchasing additional shares under its
merger agreement with Con Edison. The merger will return to NU Connecticut's
largest natural gas distribution system, as well as several unregulated
businesses involved in energy services, collections and other areas. The Yankee
merger received final DPUC approval in December 1999 and Securities and
Exchange Commission (SEC) approval in January 2000. The merger is expected to
close in early March 2000.
LIQUIDITY
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During 1999, strong sales growth, improved nuclear performance and continued
control of O&M expenses resulted in net cash flows provided by operations of
$614.2 million in 1999, compared to $663.3 million in 1998 and $340.6 million
in 1997.
On December 15, 1999, CL&P closed on the sale of 2,235 megawatts (MW) of
fossil generation assets with an unaffiliated company. Proceeds from the sale
totaled $516.9 million, including payments for fuel and inventory. CL&P used
the proceeds primarily to par call $406 million of first mortgage bonds in
December 1999. CL&P also used $57.5 million to buy out its lease of four 40 MW
turbines.
On July 26, 1999, WMECO closed on the sale of 290 MW of fossil and
hydroelectric generation assets with an affiliate of Con Edison. Proceeds from
the sale were $48.5 million.
Proceeds from these generation asset sales are included in net cash flows
provided by investing activities. Including construction expenditures and
investments in nuclear decommissioning trusts, net cash flows provided by
investing activities were $151.2 million in 1999, compared with net cash flows
used in investing activities of $295.2 million in 1998 and $293 million in
1997.
The strong operating cash flows provided by NU's regulated businesses and
the proceeds from generation asset sales enabled the NU system to substantially
reduce its outstanding debt. As of December 31, 1999, the NU system's total
debt level, including capital lease obligations, was $3.3 billion, compared
with $3.9 billion as of December 31, 1998, and $4.1 billion as of December 31,
1997.
The net cash flows used in financing activities were $646.4 million in 1999,
compared to $375.3 million in 1998 and $98.5 million in 1997. This included
$864 million paid in 1999 to retire long-term debt and preferred stock,
compared to $331.8 million in 1998 and $313.8 million in 1997. Cash dividends
on common shares paid in 1999 were $13.2 million, compared to no cash dividends
in 1998 and $32.1 million in 1997. Payments made for preferred stock dividends
were $22.8 million, $26.4 million and $30.3 million for 1999, 1998 and 1997,
respectively.
The NU system's access to capital also benefited from the strong operating
performance at Millstone 2 and 3, continued progress toward the resolution of
all restructuring issues in New Hampshire and the announced merger with Con
Edison. During 1999, NU system securities received several upgrades from three
credit rating agencies. CL&P's and WMECO's senior secured bonds achieved
investment grade ratings for the first time since early 1997 and PSNH's bonds
were upgraded to investment grade by Standard & Poor's (S&P) for the first time
since early 1994. At year end, all securities were under review for possible
upgrades, or on "credit watch" with positive implications by S&P, Moody's
Investors Service and Fitch IBCA.
The rating agency upgrades benefited NU's efforts to broaden its credit
lines. On November 19, 1999, NU parent entered into a $350 million, 364-day
unsecured revolving credit facility which allows NU parent access to $350
million in a combination of cash and letters of credit. NU parent provides
credit assurance in the form of guarantees of letters of credit, performance
guarantees and other assurances for the financial performance obligations of
certain of its unregulated subsidiaries, particularly Select Energy. Over the
course of 1999, NU parent sought and received approval from the SEC to increase
the limit of such credit assurance arrangements from $75 million to $500
million. However, NU is limited under certain loan agreements to $350 million
of such arrangements without creditor approval. As of December 31, 1999, NU
had provided approximately $190 million of such credit assurances.
Also on November 19, 1999, CL&P and WMECO entered into a new 364-day
revolving credit facility for $500 million, replacing the previous $313.75
million facility which was to expire on November 21, 1999. The revolving credit
facility, which is secured by second mortgages on Millstone 2 and 3, will be
used to bridge gaps in working capital and provide short-term liquidity. CL&P
may draw up to $300 million and WMECO may draw up to $200 million under the
facility. Once CL&P and WMECO receive the proceeds from securitization, the
$500 million facility will be reduced to $300 million, with a $200 million
limit for CL&P and a $100 million limit for WMECO. As of December 31, 1999,
CL&P had $90 million and WMECO had $123 million outstanding under this
facility.
For further information regarding the NU parent revolving credit facility
and the CL&P and WMECO revolving credit facility, see Note 3, "Short-Term
Debt," to the consolidated financial statements.
PSNH's $75 million revolving credit agreement was terminated on April 14,
1999. PSNH currently funds its operations through cash on hand and operating
cash flows. As of December 31, 1999, PSNH had $182.6 million of cash and cash
equivalents. On April 14, 1999, PSNH renewed bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control bonds.
CL&P also has arranged financing through the sale of its accounts
receivable. CL&P can finance up to $200 million through this facility. As of
December 31, 1999, CL&P had $170 million outstanding under this facility.
WMECO terminated its $40 million accounts receivable credit facility on
June 30, 1999.
In late 1999, NU arranged forward purchase transactions for approximately
10 million NU common shares with two financial institutions (counterparties).
To effect these transactions, the counterparties purchased on the open market
between November 1999 and January 2000, NU common shares, at an average price
per share of $21.26, in a total aggregate amount of $215 million. The
counterparties maintain ownership of the shares until the transactions are
settled. Additionally, NU will continue to accrue fees on the total aggregate
amount at LIBOR plus 2.5 percent per annum, until the transactions are settled.
These transactions can be settled in cash or NU common shares at the company's
discretion. As required under the terms of the contracts, NU must settle the
transactions no later than December 31, 2000, for an aggregate purchase price
equal to $215 million. However, NU expects to settle these purchase trans-
actions with the proceeds from restructuring in the second half of 2000. If
prior to the settlement date, NU's share price falls below $15.80 per share, NU
may be required to provide the counterparties with additional collateral.
During 2000, the NU system companies hope to receive regulatory approval to
begin the process of securitizing approximately $2.5 billion of approved
stranded costs. Securitization involves issuing rate reduction bonds with
interest rates lower than the company's weighted average cost of capital.
Proceeds from securitization will be used to significantly reduce the
capitalization of NU's regulated subsidiaries and buyout or buydown certain
purchased-power contracts with a number of nonutility generators.
RESTRUCTURING
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During 1999, Connecticut and Massachusetts made significant progress in
resolving industry restructuring issues. Restructuring orders issued in
Connecticut and Massachusetts allowed NU to determine the impacts of
discontinuing Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," for the generation
portion of CL&P's and WMECO's businesses. In both states, the transmission and
distribution portion of those businesses will continue to be cost-of-service
regulated. In addition, the restructuring orders provided for a transition
charge which allows for the recovery of CL&P's and WMECO's generation-related
regulatory assets and prudently incurred stranded costs.
The process of restructuring the electric utility industry in New Hampshire
has not yet been concluded, however, significant progress has been made over
the past year. In August 1999, PSNH and state officials reached a Settlement
Agreement, addressing all rate and restructuring issues involving PSNH, which
is awaiting New Hampshire Public Utilities Commission (NHPUC) approval.
CONNECTICUT
During April 1999, CL&P filed its standard offer service plan with the DPUC and
received a decision on October 1, 1999, as amended on December 15, 1999. In
that decision, the DPUC approved the recovery of CL&P's regulatory assets and
certain stranded costs associated with CL&P's nuclear generation assets and
established the methodology for setting CL&P's standard offer rates, including
the transition charge and transmission and distribution rates. The DPUC ruled
on CL&P's stranded cost filing in July 1999 approving $3.5 billion of stranded
cost recovery, which is utilized, in part, in the determination of the
transition charge.
As provided for in the electric utility restructuring legislation enacted in
April 1998, 35 percent of CL&P's customers were able to choose their electric
generation supplier on January 1, 2000, with the remaining 65 percent having
choice on July 1, 2000. The major components of rates are a transmission and
distribution charge, a generation charge and a transition charge. For those
customers who do not or are unable to choose another competitive electric
generation supplier, CL&P will supply standard offer or generation service at
an average rate of $0.04813 per kilowatt-hour (kWh) through December 31, 2003.
The revenues attributable to standard offer (generation) service are expected
to exceed the actual cost of providing generation and the difference will be
applied against stranded costs. In accordance with a plan approved by the DPUC,
one-half of the CL&P standard offer load was procured through a competitive
bidding process, with the remaining one-half of the power being supplied by an
affiliated company. The contracts are in place through the end of 2003. For
further information regarding commitments and contingencies related to the
Connecticut restructuring order, see Note 7A, "Commitments and Contingencies --
Restructuring -- Connecticut," to the consolidated financial statements.
MASSACHUSETTS
Massachusetts enacted electric utility restructuring legislation in November
1997. Based on an interim order approving WMECO's restructuring plan filed in
December 1997, WMECO's customers were able to choose an alternative retail
electricity supplier beginning on March 1, 1998. In 1999, the Massachusetts
Department of Telecommunications and Energy (DTE) issued its final decision on
WMECO's restructuring plan. In that decision, the DTE permitted WMECO to
recover its generation-related regulatory asset balances and its nuclear
decommissioning costs. However, the DTE disallowed any return on Millstone 2
and 3 starting March 1, 1998, until they returned to service and on Millstone
1 for its remaining life. The pretax impact of these disallowances was $41
million. The DTE also approved one-year contracts with the winning bidders of
the standard offer and default service supply auction. For further information
regarding commitments and contingencies related to the Massachusetts
restructuring order, see Note 7A, "Commitments and Contingencies --
Restructuring -- Massachusetts," to the consolidated financial statements.
GENERATION ASSET DIVESTITURES--
CONNECTICUT AND MASSACHUSETTS
The Connecticut and Massachusetts restructuring laws required CL&P and WMECO to
divest of their nonnuclear generation assets and utilize substantially all of
the net gains from any sales to offset stranded costs. During 1999, WMECO and
CL&P sold their nonnuclear generation assets resulting in net gains of $22.4
million and $286.5 million, respectively. A corresponding amount of regulatory
assets was amortized. In September 1999, NU announced that the Millstone
nuclear generation assets of its subsidiaries, CL&P and WMECO, will be put up
for auction as soon as practical. For further information regarding commitments
and contingencies related to the Connecticut and Massachusetts generation asset
divestitures, see Note 7A, "Commitments and Contingencies -- Restructuring --
Nuclear Generation Assets Auction," to the consolidated financial statements.
NEW HAMPSHIRE
In August 1999, NU, PSNH and the state of New Hampshire signed the Settlement
Agreement which will resolve a number of pending regulatory and court
proceedings related to PSNH. The Settlement Agreement is awaiting approval of
the NHPUC and is subject to legislative approval of securitization. The key
components of the agreement include an after-tax write-off of $225 million of
stranded costs; the recovery of the remaining stranded costs; the
securitization of $725 million of approved stranded costs; the sale of
generation assets and wholesale power entitlements, with transition service
being available to customers for three years; a reduction in rates of an
average of 18.3 percent, and the opening of the New Hampshire electricity
market to competition. For further information regarding commitments and
contingencies related to the New Hampshire Settlement Agreement, see Note 7A,
"Commitments and Contingencies -- Restructuring -- New Hampshire," to the
consolidated financial statements.
UNREGULATED ENERGY SERVICES
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The energy marketing and brokering business is intensely competitive, with many
companies with larger financial resources than NU's bidding for business in the
deregulating New England market. The sharply fluctuating cost of power supply
caused by, among other things, weather extremes, plant outages and fuel costs,
and a lack of load-following generating facilities, have made it difficult for
Select Energy to economically match its wholesale power purchases with its
power supply obligations. In 1999, Select Energy recorded a net loss of $38.8
million on revenues of $554.9 million, compared to a net loss of $13.4 million
on revenues of $29.3 million in 1998. Select Energy's ability to economically
compete has also been affected by NU's weakened financial position caused by
the extended Millstone outages which ended in mid 1999. In 2000, Select
Energy's expected contract with an affiliated company, Northeast Generation
Company, to purchase 1,329 MW of capacity and energy should significantly
reduce the load-following risk and allow Select Energy to better manage its
portfolio profitability.
Select Energy's goal is to be the regional and national leader in providing
standard offer service to those Northeast markets opened to retail competition.
Currently, Select Energy provides more than 5,000 MW of standard offer load,
making it the largest provider of standard offer service in the Northeast. On
December 22, 1999, Select Energy and an unaffiliated company signed a 6-month
power supply agreement, effective January 1, 2000, to meet the utility's
standard offer service requirements, which are expected to exceed 3,000 MW.
This contract does not include renewal or termination provisions, and payment
is due within ten days of the receipt of the bill. Select Energy has been
serving this standard offer load since December 1998. During 1999, revenues
billed to this customer totaled $276.1 million or approximately 46 percent of
Select Energy's revenues. On January 1, 2000, Select Energy began serving CL&P
with one-half of its approximately 2,000 MW standard offer requirement for a
4-year period. The CL&P standard offer contract does not include renewal
provisions. Select Energy can terminate the contract if the Federal Energy
Regulatory Commission (FERC) or DPUC require changes to the contract which
create material adverse economic impact to Select Energy which cannot be cured.
These power supply contracts are expected to provide Select Energy with over
50 percent of its revenues in the year 2000. In addition, beginning in January
2000, Select Energy assumed responsibility for serving approximately 30 market-
based wholesale contracts, totaling approximately 500 MW, throughout New
England with electric energy supply that was previously provided by CL&P and
WMECO. For the most part, the prices are fixed by contract and applicable to
actual volumes.
NUCLEAR GENERATION
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MILLSTONE NUCLEAR UNITS
Millstone 3 received the appropriate Nuclear Regulatory Commission (NRC)
approvals and resumed operation in July 1998. Millstone 2 received similar NRC
approvals, resumed operation and was returned to CL&P's rate base in May 1999.
Millstone 3 and 2 achieved annual capacity factors of 81.7 percent and 57.9
percent in 1999, respectively. After a 60-day refueling and maintenance outage,
Millstone 3 returned to service on June 29, 1999, and has achieved a 98.1
percent capacity factor through December 31, 1999. Since returning to service
in May 1999, Millstone 2 has achieved a 90.3 percent capacity factor through
December 31, 1999. NU's total share of O&M expenses associated with Millstone 3
and 2 totaled $261.8 million in 1999, as compared to $323.2 million in 1998
and $406 million in 1997. Millstone 1 is currently in decommissioning status.
An auction of the NU system's ownership interests in the Millstone units is
expected in 2000 with a closing in 2001. Based on regulatory decisions received
in 1999, management expects to recover all of its remaining nuclear stranded
costs from retail customers.
SEABROOK
Seabrook achieved an annual capacity factor of 86.4 percent in 1999. However,
since returning to service on May 13, 1999, after a 48-day refueling and
maintenance outage, Seabrook has achieved a 99 percent capacity factor through
December 31, 1999.
CL&P anticipates auctioning its 4.06 percent share of Seabrook, with the
35.98 percent share owned by its affiliate North Atlantic Energy Corporation
(NAEC) after approval of the Settlement Agreement. The Settlement Agreement
with the state of New Hampshire requires divestiture prior to December 31,
2003.
YANKEE COMPANIES
On June 1, 1999, the FERC accepted the offer of settlement which was filed on
January 15, 1999, by the Maine Yankee Atomic Power Company (MYAPC). The
significant aspects of the settlement allowed MYAPC to collect $33.1 million
annually to pay for decommissioning and spent fuel, approved its return on
equity of 6.5 percent, permitted full recovery of MYAPC's unamortized
investment, including fuel, and set an incentive budget for decommissioning at
$436.3 million.
On October 15, 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC)
agreed to sell its unit for $22 million to an unaffiliated company. Among other
commitments, the acquiring company agreed to assume the decommissioning cost of
the unit after it is taken out of service, and the VYNPC owners have agreed to
fund the uncollected decommissioning cost to a negotiated amount at the time of
the closing of the sale. VYNPC's owners have also agreed either to enter into a
new purchased-power agreement with the acquiring company or to buy out such
future power payment obligations by making a fixed payment to them. CL&P, WMECO
and PSNH have elected the buyout option. The VYNPC owners' obligations to close
and pay such amounts are conditioned upon their receipt of satisfactory
regulatory approval of the transaction, including provision for adequate
recovery of these payments.
NUCLEAR DECOMMISSIONING
The staff of the SEC has questioned certain of the current accounting practices
of the electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear units in their financial
statements.
Currently, the Financial Accounting Standards Board plans to review the
accounting for obligations associated with the retirement of long-lived assets,
including the decommissioning of nuclear units. If current accounting practices
for nuclear decommissioning change, the annual provision for decommissioning
could increase relative to 1999, and the estimated cost for decommissioning
could be recorded as a liability with recognition of an increase in the cost of
the related nuclear unit. However, management does not believe that such a
change will have a material impact on the NU system's financial statements due
to its current and future ability to recover decommissioning costs through
rates.
SPENT NUCLEAR FUEL DISPOSAL COSTS
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent fuel in 1998. However, delays in confirming the
suitability of 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. NU has the primary
responsibility for the interim storage of its spent nuclear fuel. Adequate
storage capacity exists to accommodate all spent nuclear fuel at Millstone 1.
The facilities for Millstone 2 are expected to provide adequate storage to
accommodate a full-core discharge from the reactor until 2005 with the
implementation of currently planned modifications. Fuel consolidation, which
has been licensed for Millstone 2, could provide adequate storage capacity for
its projected life. The facilities for Millstone 3 are expected to provide
adequate storage for its projected life with the addition of new storage racks.
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. For further information regarding spent
nuclear fuel disposal cost, see Note 7D, "Commitments and Contingencies - Spent
Nuclear Fuel Disposal Costs," to the consolidated financial statements.
MARKET RISK AND RISK MANAGEMENT INSTRUMENTS
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The NU system uses swaps and collars to manage the market risk exposures
associated with changes in variable interest rates and energy prices. The NU
system uses these instruments to reduce risk by essentially creating offsetting
market exposures. Based on the derivative instruments which are currently being
utilized by the NU system companies to hedge some of their interest rate and
energy price risks, there may be an impact on earnings upon adoption of SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," which
management has not estimated at this time.
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. A 10 percent increase in market interest rates above the
1999 weighted average variable rate during 2000 would result in an immaterial
impact on interest expense.
ENERGY 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
were protected by a regulatory fuel price adjustment clause. However, for a
specific, well-defined volume of fuel that was excluded from the energy price
adjustment clause, CL&P employed energy 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 were created by the sale
of long-term fixed-price electricity sales contracts to wholesale customers.
In 1999, CL&P divested substantially all of its fossil and hydroelectric
generation assets and also transferred the rights and obligations of its
long-term fixed-price contracts to an unregulated affiliate. As a result, the
fuel swap positions were marked-to-market and CL&P recognized a loss of $5.2
million. In January 2000, the fuel swap positions were liquidated.
UNREGULATED ENERGY SERVICES MARKET RISK
NU's unregulated companies, as major providers of electricity and natural gas,
have certain market risks inherent in their business activities. Market risk
represents the risk of loss that may impact the companies' financial position,
results of operations or cash flows due to adverse changes in commodity market
prices. In 1999, the companies increased their volume of electricity and gas
marketing activities, increasing their risks. Policies and procedures have
been established to manage these exposures including the use of risk management
instruments.
OTHER MATTERS
- --------------------------------------------------------------------------------
ENVIRONMENTAL MATTERS
NU is subject to environmental laws and regulations structured to mitigate or
remove the effect of past operations and to improve or maintain the quality of
the environment. For further information regarding environmental matters, see
Note 7C, "Commitments and Contingencies -- Environmental Matters," to the
consolidated financial statements.
OTHER COMMITMENTS AND CONTINGENCIES
NU is subject to other other commitments and contingencies primarily relating
to nuclear litigation, nuclear insurance contingencies, its construction
program, long-term contractual arrangements, and the New England Power Pool
generation pricing. For further information regarding these other commitments
and contingencies, see Note 7, "Commitments and Contingencies," to the
consolidated financial statements.
YEAR 2000 ISSUES
The transition into the year 2000 was a success for the NU system. Its mission
to provide safe, reliable energy to its customers and to ensure continued
operability of critical business functions was not affected by any year 2000
related issues.
The projected total cost of the year 2000 program is estimated at $21
million. The total cost to date was funded through operating cash flows. The
NU system has incurred and expensed $20 million related to year 2000 readiness
efforts.
FORWARD LOOKING STATEMENTS
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts. Words such as estimates,
expects, anticipates, intends, plans, and similar expressions identify forward
looking statements. Actual results or outcomes could differ materially as a
result of further actions by state and federal regulatory bodies, competition
and industry restructuring, changes in economic conditions, changes in
historical weather patterns, changes in laws, developments in legal or public
policy doctrines, technological developments, and other presently unknown or
unforeseen factors.
RESULTS OF OPERATIONS
- ---------------------------------------------------------------------------------------------------------------
The components of significant income statement variances for the past two years are provided in the
table below.
- ---------------------------------------------------------------------------------------------------------------
INCOME STATEMENT VARIANCES 1999 OVER/(UNDER) 1998 1998 OVER/(UNDER) 1997
----------------------------- --------------------------
(Millions of Dollars) AMOUNT PERCENT AMOUNT PERCENT
- ---------------------------------------------------------------------------------------------------------------
Operating Revenues $ 704 19% $ (67) (2)%
Operating Expenses:
Fuel, purchased and net interchange power 428 29 (8) (1)
Other operation 52 7 (116) (13)
Maintenance (58) (15) (103) (20)
Depreciation (31) (9) (22) (6)
Amortization of regulatory assets, net 393 (a) 79 64
Federal and state income taxes 93 (a) 4 (a)
Taxes other than income taxes 9 4 (2) (1)
Gain on sale of utility plant (309) -- -- --
Total operating expenses 584 16 (101) (3)
Operating income 120 53 34 18
Equity in earnings of regional nuclear
generating and transmission companies (7) (59) (1) (9)
Nuclear unrecoverable costs 72 50 (143) --
Other income/(loss), net (19) (a) 19 61
Interest charges, net (5) (2) (3) (1)
Preferred dividends of subsidiaries (4) (14) (4) (13)
Net income/(loss) 181 (a) (17) (13)
- ---------------------------------------------------------------------------------------------------------------
(a) Percentage greater than 100.
OPERATING REVENUES
Total revenues increased by $704 million or 19 percent in 1999 due to higher
revenues from the competitive companies ($552 million), higher regulated
wholesale revenue ($107 million) and higher regulated retail revenue ($45
million). The competitive companies' increase is due to higher revenues from
Select Energy ($526 million) and HEC Inc. (HEC) ($26 million). Select Energy's
revenues were higher in 1999 as a result of new contracts for energy sales. The
regulated wholesale revenue increase is primarily due to higher energy sales
and related capacity and transmission revenues. The regulated retail increase
is primarily due to higher retail sales ($99 million) and the impact of
Millstone 2 and 3 being returned to CL&P's rate base ($13 million). These
retail increases were partially offset by retail rate reductions for CL&P and
WMECO ($55 and $12 million, respectively). Regulated retail kilowatt-hour sales
increased by 3.8 percent.
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 3 being removed from CL&P's rate base. Wholesale revenues decreased by $32
million primarily as a result of the terminated contract with the Connecticut
Municipal Electric Energy Cooperative (CMEEC). Other revenues decreased $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 from PSNH as a
result of a higher fuel and purchased-power adjustment clause 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.
FUEL, PURCHASED AND NET
INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 1999, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($521 million), regulated wholesale ($86 million) and
regulated retail ($36 million), partially offset by lower replacement power
costs due to the return to service of Millstone 2 and 3 ($215 million).
The change in fuel, purchased and net interchange power expense in 1998 was
not significant.
OTHER OPERATION AND MAINTENANCE
Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($125 million), partially offset by the recognition of
environmental insurance proceeds in 1998 and additional environmental reserves
in 1999 ($30 million), higher transmission and power exchange expenses ($35
million), higher spending at Seabrook ($10 million) as a result of the
refueling outage, higher expenditures for HEC and the competitive businesses
($32 million), and expenses associated with the Con Edison merger ($12 million)
in 1999.
Other O&M expenses decreased in 1998, primarily due to lower costs at the
Millstone units ($159 million), lower costs at the Seabrook and Yankee
companies' 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).
DEPRECIATION
Depreciation decreased in 1999 and 1998, primarily due to the retirement of
Millstone 1.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 1999, primarily due to the
increased amortization associated with the gain on the sale of CL&P's and
WMECO's fossil and hydroelectric generation assets ($309 million), the
amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56
million) and the reclassification of the depreciation on the nuclear plants to
regulatory assets ($23 million).
Amortization of regulatory assets, net increased in 1998, primarily due to
accelerated amortizations in accordance with regulatory decisions for CL&P ($49
million), the amortization of NAEC's Seabrook deferred return ($79 million) and
the beginning of the amortization of CL&P's Millstone 1 investment ($23
million). These increases were partially offset by the lower amortization of
the PSNH acquisition premium ($40 million).
FEDERAL AND STATE INCOME TAXES
The consolidated statement of income taxes provides a reconciliation of actual
and expected tax expense. The tax effect of temporary differences is accounted
for in accordance with the rate-making treatment of the applicable regulatory
commissions. In past years, this rate-making treatment has required the company
to provide the customers with a portion of the tax benefits associated with
accelerated tax depreciation in the year it is generated (flow-through
depreciation). As these flow-through differences turn around, higher tax
expense is recorded.
Federal and state income taxes increased approximately $93 million in 1999,
primarily due to the significant increase in pretax earnings. Significant
variances of other items include a $10 million increase in flow-through
depreciation turnaround and $4.6 million of nontax deductible merger related
expenditures offset by the elimination of a $23 million deferred tax asset
valuation reserve.
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.
GAIN ON SALE OF UTILITY PLANT
CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric
generation assets in 1999. A corresponding amount of amortization expense was
recorded.
EQUITY IN EARNINGS OF REGIONAL NUCLEAR
GENERATING AND TRANSMISSION COMPANIES
Equity in earnings of regional nuclear generating and transmission companies
decreased in 1999 and 1998, primarily due to lower earnings from the
Connecticut Yankee Atomic Power Company.
NUCLEAR UNRECOVERABLE COSTS
Nuclear unrecoverable costs in 1999 are comprised of one-time charges related
to the CL&P write-off of CMEEC nuclear costs ($19.9 million), the CL&P write-
off of capital projects as a result of the Connecticut standard offer decision
($11 million), the CL&P/WMECO settlement of Millstone 3 joint owner litigation,
net of insurance proceeds ($27 million), the WMECO return disallowed on
Millstone 1 unrecovered plant from March 1998 forward ($10.8 million), and the
WMECO disallowed Millstone 1 plant per the Massachusetts restructuring order
($2.1 million). In comparison, 1998 is comprised of the write-off of the
Millstone 1 entitlement formerly held by CMEEC ($27.8 million) and the write-
off of unrecoverable costs as a result of the February 1999 CL&P rate decision
($115.3 million).
OTHER INCOME/(LOSS), NET
Other income/(loss), net decreased in 1999, primarily due to the PSNH
settlement with the New Hampshire Electric Cooperative ($6.2 million) and the
loss on the CL&P assignment of market-based contracts to Select Energy ($15
million).
The 1998 increase over 1997 is primarily due to the proceeds resulting from
the shareholder derivative suit.
COMPANY REPORT
The accompanying consolidated financial statements of Northeast Utilities and
subsidiaries and other sections of this annual report were prepared by the
company. These financial statements, which were audited by Arthur Andersen
LLP, were prepared in accordance with generally accepted accounting principles
using estimates and judgment, where required, and giving consideration to
materiality.
The company has endeavored to establish a control environment that
encourages the maintenance of high standards of conduct in all of its business
activities. The company maintains a system of internal controls over financial
reporting which is designed to provide reasonable assurance to the company's
management and Board of Trustees regarding the preparation of reliable,
published financial statements. The system is supported by an organization of
trained management personnel, policies and procedures, and a comprehensive
program of internal audits. Through established programs, the company regularly
communicates to its management employees their internal control
responsibilities and policies prohibiting conflicts of interest.
The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. The Audit 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, 1999 and 1998, 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,
1999. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 25, 2000
CONSOLIDATED STATEMENTS OF INCOME
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Operating Revenues $ 4,471,251 $ 3,767,714 $ 3,834,806
- ---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power 1,898,314 1,470,200 1,478,566
Other 855,917 803,419 919,431
Maintenance 340,419 399,165 501,693
Depreciation 302,305 332,807 354,329
Amortization of regulatory assets, net 596,437 203,132 123,718
Federal and state income taxes 180,883 82,332 12,650
Taxes other than income taxes 261,353 251,932 253,637
Gain on sale of utility plant (308,914) -- --
- ---------------------------------------------------------------------------------------------------------------
Total operating expenses 4,126,714 3,542,987 3,644,024
- ---------------------------------------------------------------------------------------------------------------
Operating Income 344,537 224,727 190,782
- ---------------------------------------------------------------------------------------------------------------
Other Income/(Loss):
Equity in earnings of regional nuclear generating
and transmission companies 5,034 12,420 11,306
Nuclear unrecoverable costs (71,066) (143,239) --
Other, net (30,855) (12,225) (31,185)
Minority interest in loss of subsidiary (9,300) (9,300) (9,300)
Income taxes 82,272 76,393 10,702
- ---------------------------------------------------------------------------------------------------------------
Other loss, net (23,915) (75,951) (18,477)
- ---------------------------------------------------------------------------------------------------------------
Income before interest charges 320,622 148,776 172,305
- ---------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 258,093 273,824 282,095
Other interest 13,959 7,808 3,561
Deferred interest - nuclear plants (8,401) (12,543) (13,675)
- ---------------------------------------------------------------------------------------------------------------
Interest charges, net 263,651 269,089 271,981
- ---------------------------------------------------------------------------------------------------------------
Income/(loss) after interest charges 56,971 (120,313) (99,676)
Preferred Dividends of Subsidiaries 22,755 26,440 30,286
- ---------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 34,216 $ (146,753) $ (129,962)
- ---------------------------------------------------------------------------------------------------------------
Earnings/(Loss) Per Common Share - Basic and Diluted $ 0.26 $ (1.12) $ (1.01)
- ---------------------------------------------------------------------------------------------------------------
Common Shares Outstanding (Average) 131,415,126 130,549,760 129,567,708
- ---------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 34,216 $ (146,753) $ (129,962)
- ---------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax:
Foreign currency translation adjustments 1 -- (499)
Unrealized gains on securities 118 2,019 --
Minimum pension liability adjustments -- (613) --
- ---------------------------------------------------------------------------------------------------------------
Other comprehensive income/(loss), net of tax 119 1,406 (499)
- ---------------------------------------------------------------------------------------------------------------
Comprehensive Income/(Loss) $ 34,335 $ (145,347) $ (130,461)
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998
- ---------------------------------------------------------------------------------------------------------------
Assets
Utility Plant, at cost:
Electric $ 9,185,272 $ 9,570,547
Other 226,002 195,325
- ---------------------------------------------------------------------------------------------------------------
9,411,274 9,765,872
Less: Accumulated provision for depreciation 6,088,310 4,224,416
- ---------------------------------------------------------------------------------------------------------------
3,322,964 5,541,456
Unamortized PSNH acquisition costs 324,437 352,855
Construction work in progress 177,504 143,159
Nuclear fuel, net 122,529 133,411
- ---------------------------------------------------------------------------------------------------------------
Total net utility plant 3,947,434 6,170,881
- ---------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at market 711,910 619,143
Investments in regional nuclear generating companies, at equity 81,503 85,791
Other, at cost 94,768 151,857
- ---------------------------------------------------------------------------------------------------------------
888,181 856,791
- ---------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 255,154 136,155
Investments in securitizable assets 107,620 182,118
Receivables, less accumulated provision for uncollectible accounts
of $4,895 in 1999 and $2,416 in 1998 310,190 237,207
Unbilled revenues 75,728 42,145
Fuel, materials and supplies, at average cost 172,973 202,661
Recoverable energy costs, net - current portion 73,721 67,181
Prepayments and other 75,894 68,087
- ---------------------------------------------------------------------------------------------------------------
1,071,280 935,554
- ---------------------------------------------------------------------------------------------------------------
Deferred Charges:
Regulatory assets 3,642,439 2,328,949
Unamortized debt expense 39,192 40,416
Other 99,526 54,790
- ---------------------------------------------------------------------------------------------------------------
3,781,157 2,424,155
- ---------------------------------------------------------------------------------------------------------------
Total Assets $ 9,688,052 $10,387,381
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998
- ---------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities:
Capitalization:
Common shares, $5 par value - authorized 225,000,000 shares; 137,393,829 shares
issued and 131,870,284 shares outstanding in 1999 and 137,031,264 shares
issued and 130,954,740 shares outstanding in 1998 $ 686,969 $ 685,156
Capital surplus, paid in 940,726 940,661
Deferred contribution plan - employee stock ownership plan (127,725) (140,619)
Retained earnings 581,817 560,769
Accumulated other comprehensive income 1,524 1,405
- ---------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 2,083,311 2,047,372
Preferred stock not subject to mandatory redemption 136,200 136,200
Preferred stock subject to mandatory redemption 121,289 167,539
Long-term debt 2,372,341 3,282,138
- ---------------------------------------------------------------------------------------------------------------
Total capitalization 4,713,141 5,633,249
- ---------------------------------------------------------------------------------------------------------------
Minority Interest in Consolidated Subsidiaries 100,000 100,000
- ---------------------------------------------------------------------------------------------------------------
Obligations Under Capital Leases 62,824 88,423
- ---------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 278,000 30,000
Long-term debt and preferred stock - current portion 503,315 397,153
Obligations under capital leases - current portion 118,469 120,856
Accounts payable 347,321 338,612
Accrued taxes 158,684 50,755
Accrued interest 37,904 51,044
Other 126,768 139,367
- ---------------------------------------------------------------------------------------------------------------
1,570,461 1,127,787
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Long-Term Liabilities:
Accumulated deferred income taxes 1,688,114 1,848,694
Accumulated deferred investment tax credits 140,407 143,369
Decommissioning obligation - Millstone 1 702,351 692,000
Deferred contractual obligations 358,387 418,760
Other 352,367 335,099
- ---------------------------------------------------------------------------------------------------------------
3,241,626 3,437,922
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,688,052 $10,387,381
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------------------------------------
Accumulated
Capital Deferred Retained Other
Common Surplus, Contribution Earnings Comprehensive
(Thousands of Dollars) Shares Paid In Plan -- ESOP (a) Income Total
- ---------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1997 $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 loss (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
- ---------------------------------------------------------------------------------------------------------------
Net income for 1999 34,216 34,216
Cash dividends on common shares -
$0.10 per share (13,168) (13,168)
Issuance of 362,565 common shares,
$5 par value 1,813 3,505 5,318
Allocation of benefits - ESOP (3,053) 12,894 9,841
Unearned stock compensation (1,194) (1,194)
Capital stock expenses, net 807 807
Other comprehensive income 119 119
- ---------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1999 $686,969 $940,726 $(127,725) $ 581,817 $1,524 $ 2,083,311
- ---------------------------------------------------------------------------------------------------------------
(a) 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,
1999, retained earnings available for the payment of dividends totaled
$158.5 million.
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Operating Activities:
Income/(loss) after interest charges $ 56,971 $ (120,313) $ (99,676)
Adjustments to reconcile to net cash
provided by operating activities:
Depreciation 302,305 332,807 354,329
Deferred income taxes and investment tax credits, net (183,356) 23,502 26,435
Amortization of regulatory assets, net 596,437 203,132 123,718
Amortization of demand-side-management costs, net 10,014 42,085 38,029
Amortization/(deferral) of recoverable energy costs 44,526 38,356 (54,102)
Nuclear unrecoverable costs 71,066 143,239 --
Gain on sale of utility plant (308,914) -- --
Net other (uses)/sources of cash (55,543) 55,399 (66,518)
Changes in working capital:
Receivables and unbilled revenues, net (106,566) (27,553) 352,384
Fuel, materials and supplies 29,688 10,060 (1,307)
Accounts payable 8,709 (64,258) (104,269)
Accrued taxes 107,929 4,739 38,966
Investments in securitizable assets 74,498 48,787 (230,905)
Other working capital (excludes cash) (33,546) (26,714) (36,464)
- ---------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 614,218 663,268 340,620
- ---------------------------------------------------------------------------------------------------------------
Financing Activities:
Issuance of common shares 5,318 2,659 6,502
Issuance of long-term debt 200 275 260,000
Net increase/(decrease) in short-term debt 248,000 (20,000) 11,250
Reacquisitions and retirements of long-term debt (817,759) (269,555) (288,793)
Reacquisitions and retirements of preferred stock (46,250) (62,211) (25,000)
Cash dividends on preferred stock (22,755) (26,440) (30,286)
Cash dividends on common shares (13,168) -- (32,134)
- ---------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (646,414) (375,272) (98,461)
- ---------------------------------------------------------------------------------------------------------------
Investing Activities:
Investment in plant:
Electric and other utility plant (287,081) (217,009) (233,399)
Nuclear fuel (42,471) (17,026) (6,852)
- ---------------------------------------------------------------------------------------------------------------
Net cash flows used for investments in plant (329,552) (234,035) (240,251)
Investment in nuclear decommissioning trusts (74,231) (75,551) (61,046)
Investment in nonregulated assets (23,542) -- --
Net proceeds from the sale of utility plant 565,436 -- --
Other investment activities, net 13,084 14,342 8,344
- ---------------------------------------------------------------------------------------------------------------
Net cash flows provided by/(used in) investing activities 151,195 (295,244) (292,953)
- ---------------------------------------------------------------------------------------------------------------
Net increase/(decrease) in cash for the period 118,999 (7,248) (50,794)
Cash and cash equivalents - beginning of period 136,155 143,403 194,197
- ---------------------------------------------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 255,154 $ 136,155 $ 143,403
- ---------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized $ 266,823 $ 238,990 $ 291,335
- ---------------------------------------------------------------------------------------------------------------
Income taxes $ 86,183 $ 19,454 $ (26,387)
- ---------------------------------------------------------------------------------------------------------------
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases $ 5,865 $ 12,583 $ 3,475
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ---------------------------------------------------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998
- ---------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity $2,083,311 $2,047,372
- ---------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$25 par value -- authorized 36,600,000 shares at December 31, 1999 and 1998;
2,720,000 shares outstanding in 1999 and 3,780,000 shares outstanding in 1998
$50 par value -- authorized 9,000,000 shares at December 31, 1999 and 1998;
4,314,774 shares outstanding in 1999 and 4,709,774 shares outstanding in 1998
$100 par value -- authorized 1,000,000 shares at December 31, 1999 and 1998;
200,000 shares outstanding in 1999 and 1998
- ---------------------------------------------------------------------------------------------------------------
Dividend Rates Current Redemption Current Shares
Prices (a) 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 $25.38 2,720,000 68,000 94,500
$50 par value -- $2.65 to $3.615 $50.67 to $51.93 1,990,774 99,539 119,289
- ---------------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption 167,539 213,789
Less: Preferred Stock to be redeemed within one year 46,250 46,250
- ---------------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption, net 121,289 167,539
- ---------------------------------------------------------------------------------------------------------------
Long-Term Debt:(c)
First Mortgage Bonds --
Maturity Interest Rates
- ---------------------------------------------------------------------------------------------------------------
1999 5.50% to 7.25% -- 254,000
2000 5.75% to 6.875% 159,000 260,000
2001 7.375% to 7.875% 220,000 220,000
2002 7.75% to 9.05% 489,150 560,000
2004 6.125% -- 140,000
2019-2023 7.375% to 7.50% 20,000 120,000
2024-2025 7.375% to 8.50% 305,000 430,000
- ---------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 1,193,150 1,984,000
- ---------------------------------------------------------------------------------------------------------------
Other Long-Term Debt --
Pollution Control Notes and Other Notes -- (d)
2000 Adjustable Rate(e) and 7.67% 206,011 212,022
2005-2006 8.38% to 8.58% 158,000 177,000
2013-2018 Adjustable Rate and 5.90% 33,400 33,400
2020 Adjustable Rate 15,300 15,300
2021-2022 5.85% to 7.65% and Adjustable Rate 552,485 552,485
2028 5.85% to 5.95% 369,300 369,300
2031 Adjustable Rate 62,000 62,000
- ---------------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other Notes 1,396,496 1,421,507
Fees and interest due for spent nuclear fuel disposal costs 226,463 216,377
Other 15,346 17,043
- ---------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt 1,638,305 1,654,927
- ---------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (2,049) (5,886)
- ---------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 2,829,406 3,633,041
Less: Amounts due within one year 457,065 350,903
- ---------------------------------------------------------------------------------------------------------------
Long-Term Debt, net 2,372,341 3,282,138
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization $4,713,141 $5,633,249
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
(Millions of Dollars)
- -----------------------------------------------------------------------------
Balance at December 31, 1997 $ 276.0
Reacquisitions and Retirements (62.2)
- -----------------------------------------------------------------------------
Balance at December 31, 1998 213.8
Reacquisitions and Retirements (46.3)
- -----------------------------------------------------------------------------
Balance at December 31, 1999 $ 167.5
- -----------------------------------------------------------------------------
The minimum sinking fund requirements of the series subject each year to
mandatory redemption aggregate $46.3 million each year in 2000 and 2001, $21.3
million in 2002, $7.7 million in 2003 and $5.3 million in 2004. 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, 1999, for the years 2000 through 2004 are $457.1
million, $314 million, $374.6 million, $25.6 million, and $25.5 million,
respectively.
Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject to
the liens of each company's respective first mortgage bond indenture. NAEC's
first mortgage bonds are also secured by payments made to NAEC by PSNH under
the terms of two life-of-unit, full cost recovery 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 has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by the 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,
1999 and 1998, $516.5 million of the PCRBs were outstanding. PSNH's obligation
to repay each series of PCRBs is secured by the 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 2.2 percent to 6.1 percent for 1999 and 3.1 percent to 5.6
percent for 1998.
During 1998, $535 million of adjustable-rate debt was converted to fixed-
rate debt at rates ranging from 5.85 percent to 6.0 percent.
(e) Interest rate swaps effectively fix the interest rate of NAEC's $200
million variable-rate bank note at interest rates ranging from 5.81 percent to
6.07 percent.
CONSOLIDATED STATEMENTS OF INCOME TAXES
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
The components of the federal and state income
tax provisions charged to operations are:
Current income taxes:
Federal $ 248,012 $(13,660) $(22,760)
State 33,955 (3,903) (1,727)
- ---------------------------------------------------------------------------------------------------------------
Total current 281,967 (17,563) (24,487)
- ---------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (134,773) 51,913 46,871
State (28,789) (12,948) (10,841)
- ---------------------------------------------------------------------------------------------------------------
Total deferred (163,562) 38,965 36,030
- ---------------------------------------------------------------------------------------------------------------
Investment tax credits, net (19,794) (15,463) (9,595)
- ---------------------------------------------------------------------------------------------------------------
Total income tax expense $ 98,611 $ 5,939 $ 1,948
- ---------------------------------------------------------------------------------------------------------------
The components of total income tax expense are
classified as follows:
Income taxes charged to operating expenses $ 180,883 $ 82,332 $ 12,650
Other income taxes (82,272) (76,393) (10,702)
- ---------------------------------------------------------------------------------------------------------------
Total income tax expense $ 98,611 $ 5,939 $ 1,948
- ---------------------------------------------------------------------------------------------------------------
Deferred income taxes are comprised of the tax effects
of temporary differences as follows:
Deferred tax asset associated with net operating losses $ 14,801 $ 69,212 $ --
Depreciation, leased nuclear fuel, settlement credits
and disposal costs (4,580) 16,217 32,932
Regulatory deferral (23,463) (26,786) 19,237
State net operating loss carryforward 7,777 1,150 (7,670)
Regulatory disallowance (30,719) (18,080) --
Sale of fossil and hydroelectric generation assets (125,807) -- --
Other (1,571) (2,748) (8,469)
- ---------------------------------------------------------------------------------------------------------------
Deferred income taxes, net $(163,562) $ 38,965 $ 36,030
- ---------------------------------------------------------------------------------------------------------------
A reconciliation between income tax expense and the
expected tax expense at 35 percent of pretax income:
Expected federal income tax $ 54,454 $(40,031) $(34,205)
Tax effect of differences:
Depreciation 35,672 25,793 21,776
Amortization of regulatory assets 34,736 30,740 5,498
Amortization of PSNH acquisition costs 9,946 17,301 31,298
Investment tax credit amortization (19,794) (15,463) (9,595)
State income taxes, net of federal benefit 3,358 (10,953) (8,169)
Nondeductible penalties 17 3,589 648
Adjustment for prior years' taxes (2,796) (7,338) (2,592)
Employee stock ownership plan 1,166 (1,670) (4,648)
Dividends received deduction (1,314) (3,218) (1,563)
Adjustment to tax asset valuation allowance (23,129) 7,000 8,750
Merger related expenditures 4,597 -- --
Other, net 1,698 189 (5,250)
- ---------------------------------------------------------------------------------------------------------------
Total income tax expense $ 98,611 $ 5,939 $ 1,948
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are in integral part of these financial statements.
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 (NU system). Through its regulated utilities and unregulated
energy service companies, the NU system serves in excess of 30 percent of New
England's electric needs and is one of the 20 largest electric utility systems
in the country as measured by revenues. The NU system's regulated utilities
furnish franchised retail electric service in Connecticut, New Hampshire and
western Massachusetts through three wholly owned subsidiaries: The Connecticut
Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH)
and Western Massachusetts Electric Company (WMECO). Another wholly owned
subsidiary, North Atlantic Energy Corporation (NAEC), sells all of its
entitlement to the capacity and output of the Seabrook Station (Seabrook)
nuclear unit to PSNH under the terms of two life-of-unit, full cost recovery
contracts (Seabrook Power Contracts). A fifth wholly owned subsidiary, Holyoke
Water Power Company (HWP), also is engaged in the production and distribution
of electric power.
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935 (1935
Act), and the NU system is 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.
NU Enterprises, Inc. (NUEI) is a wholly owned subsidiary of NU and acts as
the holding company for NU's unregulated energy service companies. Northeast
Generation Company (NGC) was formed to acquire generating facilities. Northeast
Generation Services Company (NGS) was formed to provide services to the
electric generation market as well as to large commercial and industrial
customers in the Northeast. Select Energy, Inc. (Select Energy), HEC Inc.
(HEC) and Mode 1 Communications, Inc. (Mode 1) engage in a variety of energy-
related and telecommunications activities, as applicable, primarily in the
unregulated energy retail and wholesale commodity, marketing and services
fields. During 1999 and 1998, NUEI accounted for 13.6 percent and 1.4 percent
of consolidated revenues, respectively.
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 provides centralized accounting, administrative,
information resources, engineering, financial, legal, operational, planning,
purchasing, and other services to the NU system companies. Northeast Nuclear
Energy Company acts as agent for the NU system companies and other New England
utilities in operating the Millstone nuclear units. North Atlantic Energy
Service Corporation has operational responsibility for Seabrook. Three other
subsidiaries construct, acquire or lease some of the property and facilities
used by the NU system companies.
On October 13, 1999, NU and Consolidated Edison, Inc. (Con Edison) announced
that they have agreed to a merger to combine the two companies. For further
information, see Note 15, " Merger Agreement with Con Edison."
On October 12, 1999, Yankee Energy System, Inc. shareholders approved the
proposed merger with NU. On December 20, 1999, the Connecticut Department of
Public Utility Control (DPUC) issued its final decision approving the merger.
In January 2000, the SEC granted final approval of the merger. The transaction
is expected to close in early March 2000.
B. PRESENTATION
The consolidated financial statements of the NU system include the accounts of
all subsidiaries. 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) has issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 establishes accounting and
reporting standards for derivative instruments and hedging activities. This
statement will require derivative instruments utilized by the NU system
companies to be recognized on the balance sheets as assets or liabilities at
fair value.
In June 1999, the FASB delayed the adoption date of SFAS No. 133 until
January 1, 2001.
Based on the derivative instruments which currently are being utilized by
the NU system companies to hedge some of their interest rate risk and certain
power contracts, there may be an impact on earnings upon adoption of SFAS No.
133 which management has not estimated at this time.
D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock in
four regional nuclear companies (Yankee Companies). The NU system's ownership
interests in the Yankee Companies at December 31, 1999 and 1998, 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 are
49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent
of the Yankee Atomic Electric Company (YAEC), 20 percent of the Maine Yankee
Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee Nuclear
Power Corporation (VYNPC). The NU system's total equity investment in the
Yankee Companies at December 31, 1999 and 1998, is $81.5 million and $85.8
million, respectively. Each Yankee Company owns a single nuclear generating
unit. However, VYNPC is the only unit still in operation at December 31, 1999.
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear unit and Millstone 2, an 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. The company
expects to auction all three units as a single package in 2000, with a closing
in 2001. Appropriate regulatory approvals will be required to complete the
auction.
Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook, a 1,148 MW nuclear generating unit. NAEC sells all of its
share of the power generated by Seabrook to PSNH under the Seabrook Power
Contracts. CL&P and NAEC expect to auction their investment in Seabrook upon
the resolution of the restructuring issues in the state of New Hampshire.
Plant-in-service and the accumulated provision for depreciation for the NU
system's share of Millstone 2 and 3 and Seabrook are as follows:
- ------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------
(Millions of Dollars) 1999 1998
- ------------------------------------------------------------------
Plant-in-service
Millstone 2 $ 952.1 $ 936.8
Millstone 3 2,414.9 2,407.4
Seabrook 901.9 895.5
Accumulated provision for depreciation
Millstone 2 $ 910.0 $ 379.6
Millstone 3 2,220.5 765.9
Seabrook 318.8 170.0
- ------------------------------------------------------------------
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
$16.5 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 the estimated remaining useful lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as approved by
the appropriate regulatory agency where applicable. 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
the plant, including costs of removal less salvage, is charged to the
accumulated provision for depreciation. The costs of closure and removal of
nonnuclear 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 1999
and 1998 and 3.8 percent in 1997.
At December 31, 1999 and 1998, the accumulated provision for depreciation
included $91.5 million and $88.4 million, respectively, accrued for the cost of
removal, net of salvage, for nonnuclear generation property.
As a result of discontinuing the application of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation
businesses, including CL&P's ownership interest in Seabrook, the company
recorded a charge to accumulated depreciation for the nuclear plant in excess
of fair market value in the amount of $2 billion and a corresponding regulatory
asset was created.
F. REVENUES
Regulated 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
rate-making arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue a revenue estimate for the amount of energy delivered but
unbilled.
Revenues for NU's unregulated subsidiaries, primarily Select Energy, are
recognized when the energy is delivered.
G. PSNH ACQUISITION COSTS
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. The Rate Agreement provides for the
recovery through rates, with a return, of the PSNH acquisition costs. The
unrecovered balance was $324.4 million and $352.9 million at December 31, 1999
and 1998, respectively, and is being recovered ratably over a 20-year period
ending May 1, 2011, in accordance with the Rate Agreement. Through December 31,
1999 and 1998, $668 million and $640 million, respectively, has been collected.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of the NU system operating companies and the
accompanying consolidated financial statements conform to generally accepted
accounting principles applicable to rate-regulated enterprises and historically
reflect the effects of the rate-making process in accordance with SFAS No. 71.
As a result of final restructuring orders issued in 1999, CL&P and WMECO
discontinued the application of SFAS No. 71 for the generation portion of their
businesses.
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. In addition, all material
regulatory assets are earning a return. The components of the NU system
companies' regulatory assets are as follows:
- ------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------
(Millions of Dollars) 1999 1998
- ------------------------------------------------------------------
Recoverable nuclear costs $2,210.8 $ 576.3
Income taxes, net 636.6 762.5
Unrecovered contractual obligations 349.2 408.0
Recoverable energy costs, net 228.2 279.2
Deferred costs - nuclear plants 111.6 187.1
Other 106.0 115.8
- ------------------------------------------------------------------
$3,642.4 $2,328.9
- ------------------------------------------------------------------
The restructuring orders in Connecticut and Massachusetts provide for the
transmission and distribution business to continue to be cost-of-service based
and also provide for a transition charge which recovers stranded costs,
including the nuclear regulatory assets established below.
As a result of discontinuing the application of SFAS No. 71 for CL&P's and
WMECO's generation businesses, the company reclassified nuclear plant in excess
of its estimated fair market value from plant to regulatory assets. As of
December 31, 1999, both the CL&P unamortized balance ($1.38 billion) and the
WMECO unamortized balance ($316.1 million) are classified as recoverable
nuclear costs. Also included in that regulatory asset component for 1999 is
$514.7 million, which includes Millstone 1 recoverable nuclear costs relating
to the recoverable portion of the undepreciated plant and related assets
($145.7 million) and the decommissioning and closure obligation ($369 million).
At this time, management continues to believe that the application of SFAS
No. 71 for PSNH and NAEC remains appropriate. If the "Agreement to Settle PSNH
Restructuring" (Settlement Agreement), as filed, is approved by the New
Hampshire Public Utilities Commission (NHPUC) and implemented, then PSNH will
discontinue the application of SFAS No. 71 for the generation portion of its
business and record an after-tax write-off of $225 million. PSNH's transmission
and distribution business will continue to be rate-regulated on a
cost-of-service basis as the Settlement Agreement allows for the recovery of
the remaining regulatory assets through that portion of the business.
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 rate-making treatment of the applicable regulatory
commissions.
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,
- ---------------------------------------------------------------
(Millions of Dollars) 1999 1998
- ---------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $1,388.0 $1,537.9
Net operating loss carryforwards -- (33.4)
Regulatory assets--
income tax gross-up 241.2 370.0
Other 58.9 (25.8)
- --------------------------------------------------------------
$1,688.1 $1,848.7
- --------------------------------------------------------------
As of December 31, 1999, PSNH had an Investment Tax Credit carryforward of
$23 million, which if unused, expires in 2004.
J. RECOVERABLE ENERGY COSTS
Energy Policy Act of 1992: Under the Energy Policy Act of 1992 (Energy Act),
CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of the
costs of decontaminating and decommissioning uranium enrichment plants owned by
the United States Department of Energy (DOE) (D&D Assessment). The Energy Act
requires that regulators treat D&D Assessments as a reasonable and necessary
current cost of fuel, to be fully recovered in rates like any other fuel cost.
CL&P, PSNH, WMECO, and NAEC are currently recovering these costs through rates.
As of December 31, 1999 and 1998, the NU system's total D&D Assessment
deferrals were $38.4 million and $57.5 million, respectively.
CL&P: Through December 31, 1999, CL&P had an energy adjustment clause under
which fuel prices above or below base-rate levels were charged to or credited
to customers. At December 31, 1999 and 1998, recoverable energy costs included
$62.6 million and $78.1 million, respectively, of costs previously deferred.
Coincident with the start of restructuring, the fuel clause was terminated. The
balance at December 31, 1999, has been recorded as a generation-related
stranded cost and will be recovered through a transition charge mechanism.
PSNH: The Rate Agreement includes a fuel and purchased-power adjustment
clause (FPPAC) permitting PSNH to pass through to retail customers, for a
10-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 NHPUC. At December 31, 1999 and 1998, PSNH
had $120.7 million and $156.3 million, respectively, of noncurrent recoverable
energy costs deferred under the FPPAC. If the Settlement Agreement is approved,
the FPPAC will be recovered through a transition charge.
K. DEFERRED COSTS -- NUCLEAR PLANTS
Under the Rate Agreement, the plant costs of Seabrook were phased into rates
over a 7-year period beginning May 15, 1991. Total costs deferred under the
phase-in plan were $288 million. This plan is accounted for in compliance with
SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-In Plans." The
costs will be fully recovered from PSNH's customers by May 2001.
L. UNRECOVERED CONTRACTUAL OBLIGATIONS
Under the terms of contracts with the Yankee Companies, the shareholder-
sponsored companies 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.
M. INTEREST RATE RISK MANAGEMENT INSTRUMENTS
The NU system utilizes market risk management instruments to hedge well-defined
risks associated with variable interest rates. 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
interest rate risk management instruments are accrued and offset against
interest expense.
N. 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 and Seabrook: The NU system operating nuclear power plants, Millstone
2 and 3 and Seabrook, have service lives that are expected to end during the
years 2015 through 2026, and upon retirement, must be decommissioned. Millstone
1's expected service life was to end in 2010, however, in July 1998, restart
activities were discontinued and preparations for decommissioning the unit
began. Current decommissioning studies conclude that complete and immediate
dismantlement as soon as practical after retirement continues to be the most
viable and economic method of decommissioning a unit. These studies are
reviewed and updated periodically to reflect changes in decommissioning
requirements, costs, technology, and inflation. Changes in requirements or
technology, the timing of funding or dismantling or adoption of a
decommissioning method other than immediate dismantlement would change
decommissioning cost estimates and the amounts required to be recovered.
CL&P, PSNH and WMECO attempt to recover sufficient amounts through their
allowed rates to cover their expected decommissioning costs.
The estimated cost of decommissioning Millstone 2, in year end 1999 dollars
is $413.4 million. The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook in year end 1999 dollars, is $421.3
million and $226.2 million, respectively. Nuclear decommissioning costs are
accrued over the expected service lives of the units and are included in
depreciation expense. Nuclear decommissioning expenses for these units
amounted to $30.6 million in 1999, $27.9 million in 1998 and $28.6 million in
1997. Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation. Through December 31, 1999 and 1998,
total decommissioning expenses of $260.6 million and $229.7 million,
respectively, have been collected from customers and are reflected in the
accumulated provision for depreciation.
A Post-Shutdown Decommissioning Activities Report for Millstone 1 was filed
with the Nuclear Regulatory Commission (NRC) in June 1999 which outlines
decommissioning activities, and costs, and supports the obligation recorded by
the company. Nuclear decommissioning expenses for Millstone 1 were $25.7
million in 1999, $19.8 million in 1998 and $20.2 million in 1997.
External decommissioning trusts have been established for the costs of
decommissioning the Millstone units. Payments for the NU system's ownership
share of the cost of decommissioning Seabrook 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 and after-tax earnings
on the Millstone and Seabrook decommissioning funds of 5.5 percent and 6.5
percent, respectively.
As of December 31, 1999 and 1998, CL&P, PSNH and WMECO collected a total of
$260.6 million and $229.7 million, respectively, through rates toward the
future decommissioning costs of their shares of Millstone 2 and 3 and Seabrook,
of which $239.7 million in 1999 and $209.9 million in 1998 have been
transferred to external decommissioning trusts. Earnings on the decommissioning
trusts increase the decommissioning trust balances and the accumulated reserves
for depreciation. Unrealized gains and losses associated with the
decommissioning trusts and financing funds also impact the balance of the
trusts and the accumulated reserve for depreciation. The fair values of the
amounts in the external decommissioning trusts were $410.2 million and $349.9
million at December 31, 1999 and 1998, respectively.
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 1999 dollars, of decommissioning this unit is
$68.6 million. On October 15, 1999, VYNPC agreed to sell the unit for $22
million to an unaffiliated company. Among other commitments, the acquiring
company agreed to assume the decommissioning cost of the unit after it is taken
out of service, and the VYNPC owners have agreed to fund the uncollected
decommissioning cost to a negotiated amount at the time of the closing of the
sale.
As of December 31, 1999 and 1998, NU's remaining estimated obligation,
including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which
have been shut down was $358.4 million and $418.8 million, respectively.
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 NU, CL&P, WMECO, and NAEC, as of January 1, 1999, to incur total
short-term borrowings up to a maximum of $400 million, $375 million, $250
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, 1999, CL&P's and WMECO's
charters permit CL&P and WMECO to incur $322 million and $132 million,
respectively, of unsecured debt. PSNH is authorized under a NHPUC order to
incur short-term borrowings up to a maximum of $68.3 million.
Credit Agreements: On November 19, 1999, CL&P and WMECO entered into a new
364-day revolving credit facility for $500 million, replacing the previous
$313.75 million facility which was to expire on November 21, 1999. The
revolving credit facility will be used to bridge gaps in working capital and
provide short-term liquidity. CL&P and WMECO may draw up to $300 million and
$200 million, respectively, under the facility which is secured by second
mortgages on Millstone 2 and 3. Unless extended, the new credit facility will
expire on November 17, 2000. At December 31, 1999 and 1998, there were $213
million and $30 million, respectively, in borrowings under these facilities.
To support the working capital needs of NU and its unregulated subsidiaries,
NU replaced its $25 million 364-day revolving credit facility which was to
expire on November 21, 1999, with a new 364-day unsecured revolving credit
facility (NU Credit Agreement) on November 19, 1999. This new facility provides
a total commitment of $350 million which is available subject to two
overlapping sub-limits. First, subject to the notional amount of any letters of
credit outstanding, amounts up to $200 million are available for advances.
Second, subject to the advances outstanding, letters of credit may be issued in
notional amounts up to $250 million. Unless extended, this credit facility will
expire on November 17, 2000. As of December 31, 1999 and 1998, there were $65
million and no borrowings under the NU Credit Agreement and the previous credit
facility, respectively. In regard to credit support, NU had $29 million in
letters of credit issued under this agreement as of December 31, 1999.
In addition, NU provides credit assurance in the form of guarantees, letters
of credit, performance guarantees and other assurances for the financial
performance obligations of certain of its unregulated subsidiaries. NU
currently has authorization from the SEC to provide up to $500 million of
guarantees, but is limited under certain loan agreements to $350 million of
such arrangements without creditor approval. As of December 31, 1999, NU had
provided approximately $190 million of such credit assurances.
Under the credit agreements discussed above, the respective borrowers may
borrow at fixed or variable rates plus an applicable margin based upon the
companies' most senior secured debt as rated by the lower of Standard and
Poor's or Moody's Investor Service (Moody's). The weighted average interest
rate on the NU system companies' notes payable to banks outstanding on
December 31, 1999 and 1998, was 7.928 percent and 6.53 percent, respectively.
Maturities of short-term debt obligations were for periods of three months or
less.
These credit agreements provide that the parties to these agreements must
comply with certain financial and nonfinancial covenants as are customarily
included in such agreements, including, but not limited to, common equity
ratios, interest coverage ratios and dividend payment restrictions.
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 capital lease agreement has an expiration
date of June 1, 2040. At December 31, 1999 and 1998, the present value of the
capital lease obligation to the NBFT was $157 million and $178.7 million,
respectively. In connection with the planned nuclear divestiture, CL&P and
WMECO anticipate that the NBFT capital lease agreement will be terminated and
the NBFT's obligation under the $180 million Series G Intermediate Term Note
agreement will be assigned to CL&P and WMECO.
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, 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 $20.8
million in 1999, $31 million in 1998 and $19 million in 1997. Interest included
in capital lease rental payments was $13.7 million in 1999, $18.3 million in
1998 and $13.6 million in 1997. Operating lease rental payments charged to
expense were $7.5 million in 1999, $15.7 million in 1998 and $17.3 million in
1997.
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, 1999 are:
- ------------------------------------------------------------------
(Millions of Dollars)
- ------------------------------------------------------------------
Capital Operating
Year Leases Leases
- ------------------------------------------------------------------
2000 $ 7.4 $ 24.4
2001 4.9 22.6
2002 3.1 19.0
2003 3.1 15.5
2004 3.0 13.6
After 2004 30.6 26.9
- ------------------------------------------------------------------
Future minimum lease payments 52.1 $ 122.0
Less amount representing interest 27.8
- ------------------------------------------------------------------
Present value of future
minimum lease payments
for other than nuclear fuel 24.3
Present value of future
nuclear fuel lease payments 157.0
- ------------------------------------------------------------------
Present value of future
minimum lease payments $ 181.3
- ------------------------------------------------------------------
5. EMPLOYEE BENEFITS
A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system companies participate in a uniform noncontributory defined
benefit retirement plan covering substantially all regular NU system employees.
Benefits are based on years of service and the employees' highest eligible
compensation during 60 consecutive months of employment. The total pension
credit, part of which was credited to utility plant, was $54.4 million in
1999, $44.1 million in 1998 and $22.5 million in 1997.
Currently, the NU system companies annually fund an amount at least equal to
that which will satisfy the requirements of the Employee Retirement Income
Security Act and Internal Revenue Code (the Code).
The NU system companies 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 companies annually fund
postretirement costs through external trusts with amounts that have been
rate-recovered and which also are tax deductible under the Code.
Pension and trust assets are invested primarily in domestic and
international equity securities and bonds.
The following table represents information on the plans' benefit obligation,
fair value of plan assets, and the respective plans' funded status:
- ---------------------------------------------------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ (1,479.2) $(1,392.8) $(305.2) $(286.0)
Service cost (43.7) (37.4) (7.6) (6.6)
Interest cost (106.3) (96.8) (21.8) (20.9)
Plan amendment (79.6) -- -- --
Transfers -- 8.5 -- --
Actuarial gain/(loss) 133.8 (37.7) (1.3) (16.1)
Benefits paid 78.3 77.0 28.9 24.4
Settlements (19.9) -- 0.2 --
- ---------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $ (1,516.6) $(1,479.2) $(306.8) $(305.2)
- ---------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 2,098.0 $ 1,919.4 $ 151.2 $ 129.4
Actual return on plan assets 310.5 264.7 18.7 17.4
Employer contribution -- -- 29.7 28.8
Benefits paid (78.3) (77.0) (28.9) (24.4)
Transfers -- (9.1) -- --
- ---------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 2,330.2 $ 2,098.0 $ 170.7 $ 151.2
- ---------------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 813.6 $ 618.8 $(136.1) $(154.0)
Unrecognized transition (asset)/obligation (7.4) (9.0) 196.6 211.9
Unrecognized prior service cost 99.2 27.6 -- --
Unrecognized net gain (904.7) (670.4) (60.4) (57.9)
- ---------------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 0.7 $ (33.0) $ 0.1 $ --
- ---------------------------------------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plans' year end
funded status:
- ---------------------------------------------------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------------
Discount rate 7.75% 7.00% 7.75% 7.00%
Compensation/progression rate 4.75 4.25 4.75 4.25
Health care cost trend rate(a) N/A N/A 5.57 5.22
- ---------------------------------------------------------------------------------------------------------------
(a) The annual per capita cost of covered health care benefits was assumed to
decrease to 4.90 percent by 2001.
The components of net periodic benefit cost are:
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Service cost $ 43.7 $ 37.4 $ 34.9 $ 7.6 $ 6.6 $ 5.7
Interest cost 106.3 96.8 98.6 21.8 20.9 20.6
Expected return on plan assets (175.5) (153.2) (135.1) (11.7) (9.9) (8.1)
Amortization of unrecognized net
transition (asset)/obligation (1.5) (1.5) (1.5) 15.1 15.1 15.1
Amortization of prior service cost 7.9 2.1 2.1 -- -- --
Amortization of actuarial gain (33.5) (25.7) (18.9) -- -- --
Other amortization, net -- -- -- (3.1) (3.8) (5.0)
Settlements (1.8) -- (2.6) -- -- --
- ---------------------------------------------------------------------------------------------------------------
Net periodic benefit (credit)/cost $ (54.4) $ (44.1) $ (22.5) $ 29.7 $ 28.9 $ 28.3
- ---------------------------------------------------------------------------------------------------------------
For calculating pension and postretirement benefit costs, the following
assumptions were used:
- ---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Discount rate 7.00% 7.25% 7.75% 7.00% 7.25% 7.75%
Expected long-term rate of return 9.50 9.50 9.25 N/A N/A N/A
Compensation/progression rate 4.25 4.25 4.75 4.25 4.25 4.75
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.50 7.75 7.50
Life assets N/A N/A N/A 9.50 9.50 9.25
- ---------------------------------------------------------------------------------------------------------------
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
(Millions of Dollars) Point Increase Point Decrease
- ----------------------------------------------------------------------------
Effect on total service and
interest cost components $ 1.4 $ (1.4)
Effect on postretirement
benefit obligation $16.4 $(16.1)
- ----------------------------------------------------------------------------
The trust holding the health plan assets is subject to federal income taxes.
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.
NU matches employee contributions up to a maximum of 3 percent of eligible
compensation with cash and NU stock. The matching contributions made by NU were
$13.8 million for 1999, $13.2 million for 1998 and $12 million for 1997.
C. ESOP
NU maintains an Employee Stock Ownership Plan (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 the purchase of
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 the fourth quarter of 1999, NU paid a 10 cent per share dividend. During
1998, there were no dividends paid on NU stock.
In 1999 and 1998, the ESOP trust issued 556,978 and 584,107 of NU common
shares, respectively, to satisfy 401(k) Savings Plan obligations to employees.
As of December 31, 1999 and 1998, the total allocated ESOP shares were
5,281,836 and 4,724,858, respectively, and total unallocated ESOP shares were
5,518,349 and 6,075,327, respectively. The fair market value of unallocated
ESOP shares as of December 31, 1999 and 1998, was $113.5 million and $97.2
million, respectively.
D. STOCK-BASED COMPENSATION
Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system has
maintained an ESPP for all eligible employees. Under the ESPP, shares of NU
common stock may be purchased at 6-month intervals at 85 percent of the lower
of the price on the first or last day of each 6-month period. Employees may
purchase shares having a value not exceeding 25 percent of their compensation
at the beginning of the purchase period. During 1999 and 1998, employees
purchased 253,853 and 129,471 shares, respectively, at discounted prices
ranging from $13.76 to $14.93 per share in 1999 and $13.60 per share in 1998.
At December 31, 1999 and 1998, 1,616,676 and 1,870,529 shares remained reserved
for future issuance under the ESPP, respectively.
Incentive Plans: The NU system has long-term incentive plans authorizing
various types of share-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 generally equal to the fair market value per share
at the date of grant. Under the Northeast Utilities Incentive Plan (Incentive
Plan), the number of shares which may be utilized for awards granted during a
given calendar year may not exceed one percent of the total number of shares of
NU common stock outstanding as of the first day of that calendar year.
Stock option transactions for 1997, 1998 and 1999 are as follows:
- ---------------------------------------------------------------------------------------------------------------
Exercise 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
Granted 644,123 $ 14.9375 -- $ 21.125 $ 15.2514
Exercised (19,368) $ 16.3125 -- $ 16.8125 $ 16.3986
Forfeited (32,177) $ 14.9375 -- $ 16.3125 $ 15.8714
- ---------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1999 1,826,256 $ 9.625 -- $ 21.125 $ 14.0585
- ---------------------------------------------------------------------------------------------------------------
Exercisable December 31, 1997 -- $ -- $ --
Exercisable December 31, 1998 232,936 $ 14.875 -- $ 16.8125 $ 16.2972
EXERCISABLE DECEMBER 31, 1999 711,787 $ 9.625 -- $ 21.125 $ 14.0102
- ---------------------------------------------------------------------------------------------------------------
The vesting schedule for the options granted in 1997 is 50 percent after two
years, 75 percent after three years and the total award 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. The options that
were granted in 1999 vest ratably over three years from the date of grant.
Also under the Incentive Plan, the NU system awarded 91,120 and 49,973 of
restricted shares in 1999 and 1998, respectively. 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 which
vest ratably over three years from the date of grant. The NU system has also
made several small grants of restricted stock and other incentive-based stock
compensation. During 1999, 1998 and 1997, $2.2 million, $0.8 million and $0.3
million, respectively, was expensed for stock-based compensation.
Had compensation cost been determined for the ESPP and the incentive plan
stock options under the fair value method as opposed to the intrinsic value
method followed by the NU system, net income/(loss) and net income/(loss) per
share would have been as follows:
- ----------------------------------------------------------------
(Millions of Dollars,
except per share amounts) 1999 1998 1997
- ----------------------------------------------------------------
Net income/(loss) $ 29.6 $(149.1) $(130.0)
Basic income/(loss)
per share $ 0.23 $ (1.14) $ (1.01)
Diluted income/(loss)
per share $ 0.22 $ (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:
- ---------------------------------------------------------------
1999 1998 1997
- ---------------------------------------------------------------
Risk-free interest rate 5.69% 5.82% 6.41%
Expected life 10 years 10 years 10 years
Expected volatility 36.21% 35.05% 31.89%
Expected dividend yield 1.89% 5.46% 7.42%
- ---------------------------------------------------------------
The weighted average grant date fair values of options granted during 1999,
1998 and 1997 were $6.79, $3.98 and $1.68, respectively. As of December 31,
1999, the weighted average remaining contractual life for those options out
standing is 8.47 years.
6. SALE OF CUSTOMER RECEIVABLES
As of December 31, 1999 and 1998, CL&P had sold accounts receivable of $170
million and $105 million, respectively, to a third-party purchaser with limited
recourse through the CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. In addition, at December 31, 1999 and 1998, $22.5 million
and $11.6 million, respectively, of assets was designated as collateral under
the agreement with CRC.
On June 30, 1999, WMECO terminated its $40 million accounts receivable
program with its respective sponsor. At December 31, 1998, WMECO had sold
accounts receivable of $20 million to a third-party purchaser.
Concentrations of credit risk to the purchaser under the company's agreement
with respect to the receivables are limited due to CL&P's diverse customer base
within its service territory.
7. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING
Connecticut: During 1999, restructuring orders were issued by the DPUC which
required CL&P to discontinue the application of SFAS No. 71 to the generation
portion of its business and allowed for the recovery of the majority of its
stranded costs. Stranded costs including regulatory assets will be collected
through a transition charge through 2026. The restructuring orders also allowed
for securitization of CL&P's nonnuclear regulatory assets and the costs to
buyout or buydown the various purchased-power contracts. Securitization is the
process of monetizing stranded costs through the sale of nonrecourse debt
securities by a special purpose entity, collateralized by CL&P's interests in
its stranded cost recoveries.
On December 15, 1999, the DPUC issued a supplemental decision approving the
components of CL&P's rates for standard offer service commencing on January 1,
2000. The DPUC also approved an interim nuclear capital recovery mechanism for
the period from January 1, 2000, until the nuclear units are sold at auction.
In approving the rates, the DPUC denied recovery of most of the capital
additions made to Millstone 2 and 3 subsequent to June 30, 1997, which the
company has or will expend to maintain those plants in a safe and efficient
condition or to maintain their auction value. If implemented as approved, the
company would not recover a significant portion of the capital additions which
have been or are expected to be incurred subsequent to July 1, 1997, until the
plants are sold in 2001. On December 29, 1999, CL&P filed with the DPUC a
petition for reconsideration of this portion of the order. The DPUC has agreed
to reopen the docket to consider CL&P's petition. Management believes the
restructuring legislation provides for the recovery of these prudently incurred
expenditures. If CL&P is unsuccessful in favorably resolving this contingency,
an impairment loss of $50 million would be recorded.
Massachusetts: In 1999, restructuring orders required WMECO to discontinue
the application of SFAS No. 71 for the generation portion of its business. In
these restructuring orders, WMECO was allowed to recover the majority of its
stranded costs through a transition charge over the 12-year transition period
beginning March 1, 1998. The decision instructed WMECO to work with the
Massachusetts attorney general regarding the recovery of nuclear capital
additions made after July 1, 1991. The decision also concluded that the
company's deferred fuel balance should be included as part of the company's
outstanding generating unit performance proceedings and not as part of the
transition charge. Management believes that these costs are recoverable and
that there will not be an impact on the results of operations.
Nuclear Generation Assets Auction: In September 1999, NU announced that the
Millstone nuclear generation assets of CL&P and WMECO will be put up for
auction as soon as practical. On November 8, 1999, CL&P filed its divestiture
plan for the Millstone units with the DPUC. The auction is expected to begin in
early 2000, provided all regulatory approvals have been met, with a successful
bidder chosen by mid 2000 and a closing in 2001. No NU system company will
participate as a bidder in the auction process. Management expects to recover
all of its nuclear stranded costs through the net proceeds of generation asset
sales and through billing a transition charge to retail customers.
New Hampshire: In August 1999, NU, PSNH and the state of New Hampshire
signed a Settlement Agreement intended to settle a number of pending regulatory
and court proceedings related to PSNH. Parties to the agreement included the
governor of New Hampshire, the Governor's Office of Energy and Community
Service, the New Hampshire attorney general, certain members of the staff of
the NHPUC, PSNH and NU. The Settlement Agreement was submitted to the NHPUC on
August 2, 1999, and is awaiting approval. If approved by the NHPUC, the
Settlement Agreement would resolve 11 NHPUC dockets and PSNH's federal lawsuit
which had enjoined the state of New Hampshire from implementing its
restructuring legislation, would require PSNH to write off $225 million after-
tax of its stranded costs and would allow for the recovery of the remaining
amount. Also, implementation of the Settlement Agreement is contingent upon the
issuance of $725 million in rate reduction bonds (securitization). Issuance of
the rate reduction bonds requires the initial approval of the NHPUC and final
approval from the New Hampshire Legislature via enactment of appropriate
legislation. Other approvals are also required from various federal and state
regulatory agencies and financial lenders. Under the terms of the Settlement
Agreement, on the effective date, PSNH's rates will be reduced from current
levels by an average of 18.3 percent. Due to the number of approvals required
and still pending to implement the Settlement Agreement, management continues
to believe the application of SFAS No. 71 is appropriate for PSNH at this time.
The Settlement Agreement also requires PSNH to sell its generation assets
and certain power contracts, including PSNH's current purchased-power contract
with NAEC for the output from Seabrook. The net proceeds from all sales will be
used to recover a portion of PSNH's stranded costs. The sales would be
accomplished through an auction process subject to approval by the NHPUC.
Following the divestiture, the transmission and distribution portion of the
business will continue to be cost-of-service based.
Phase I of the proceeding regarding the Settlement Agreement allowed
proponents to provide sufficient record for the NHPUC to compare the Settlement
Agreement to a range of reasonable outcomes in the other associated dockets.
The NHPUC also determined within the testimony of Phase I that the Con Edison
merger is relevant to the Settlement Agreement and intervening parties should
have discovery in Phase II to evaluate the impact of the merger on the
Settlement Agreement. Phase II allowed opponents to file testimony concerning
the Settlement Agreement and then allowed proponents to conduct discovery and
file rebuttal testimony. A decision on the Settlement Agreement is expected in
the first quarter of 2000.
B. NUCLEAR LITIGATION
The non-NU joint owners of Millstone 3 have 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 companies' operation of
Millstone 3. During 1999, NU and these subsidiaries agreed in principle to
settle with certain of the joint owners, who own 58 percent of the non-NU
ownership of Millstone 3. The settlements provide for the payment to the
claimants of $36.4 million and certain contingent payments.
Arbitration and litigation claims remain outstanding for the remaining joint
owners who have not agreed to settle. Management cannot estimate the potential
outcome of the arbitration and litigation for the nonsettled joint owners,
therefore, no liability has been established as of December 31, 1999.
C. ENVIRONMENTAL MATTERS
The NU system is subject to environmental laws and regulations intended to
mitigate or remove the effect of past operations and improve or maintain the
quality of our environment. As such, the NU system has an active environmental
auditing and training program and believes it is in compliance with the current
laws and regulations.
However, the normal course of operations may necessarily involve activities
and substances that expose the NU system to potential liabilities of which
management cannot determine the outcome. Additionally, management cannot
determine the outcome for liabilities that may be imposed for past acts, even
though such past acts may have been lawful at the time they occurred.
Management does not believe, however, that this will have a material impact on
the NU system's financial statements.
Based upon currently available information for the estimated remediation
costs as of December 31, 1999 and 1998, the liability recorded by the NU system
for its estimated environmental remediation costs amounted to $24.8 million and
$21.5 million, respectively.
D. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must
pay the 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), an accrual has
been recorded for the full liability and 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 3-month treasury
bill yield rate. As of December 31, 1999 and 1998, fees due to the DOE for the
disposal of Prior Period Fuel were $226.5 million and $216.4 million,
respectively, including interest costs of $144.3 million and $134 million,
respectively.
E. NUCLEAR INSURANCE CONTINGENCIES
Insurance policies covering the NU system's nuclear facilities have been
purchased for the primary cost of repair, replacement or decontamination of
utility property, certain extra costs incurred in obtaining replacement power
during prolonged accidental outages and the excess cost of repair, replacement
or decontamination or premature decommissioning of utility property.
The NU system is subject to retroactive assessments if losses under those
policies exceed the accumulated funds available to the insurer. The maximum
potential assessments with respect to losses arising during the current policy
year for the primary property insurance program, the replacement power policies
and the excess property damage policies are $11 million, $6.2 million and $15
million, respectively. In addition, insurance has been purchased in the
aggregate amount of $200 million on an industry basis for coverage of worker
claims.
Under certain circumstances, in the event of a nuclear incident at one of
the nuclear facilities covered by the federal government's third-party
liability indemnification program, the NU system could be assessed liabilities
in proportion to its ownership interest in each of its nuclear units up to
$83.9 million. The NU system's payment 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 liability, in proportion to its ownership interests in each of its
nuclear units. Based upon its ownership interests in the Millstone units and
in Seabrook, the NU system's maximum liability, including any additional
assessments, would be $271 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 assessment of $14.1 million per incident, of which payments would
be limited to $1.6 million per year.
F. CONSTRUCTION PROGRAM
The NU system companies currently forecast construction expenditures of $1.8
billion for the years 2000-2004, including $309.7 million for 2000. The NU
system companies estimate that nuclear fuel requirements, including nuclear
fuel financed through the NBFT, will be $217.8 million for the years 2000-2003,
including $74.2 million for 2000.
G. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: The NU system companies relied on VYNPC for 1.5 percent of
their capacity under long-term contracts. Under the terms of their agreements,
the NU system companies paid their ownership (or entitlement) shares of costs,
which included depreciation, operation and maintenance (O&M) expenses, taxes,
the estimated cost of decommissioning, and a return on invested capital. These
costs were recorded as purchased-power expenses and recovered through the
companies' rates. The total cost of purchases under contracts with VYNPC
amounted to $29.2 million in 1999, $27.3 million in 1998 and $24.2 million in
1997. VYNPC has agreed to sell its nuclear unit. Upon completion of the sale,
this long-term contract will be terminated.
Nonutility Generators (NUGs): CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from NUGs. For the years
ended December 31, 1999 and 1998, 13 percent and for the year ended December
31, 1997, 14 percent, of NU system electricity requirements were met by NUGs.
The total cost of purchases under these arrangements amounted to $461.8 million
in 1999, $459.7 million in 1998 and $447.6 million in 1997. The company is in
the process of renegotiating the terms of these contracts through either a
contract buydown or buyout. The company expects any payments to the NUGs as
result of these renegotiations to be recovered from the company's customers.
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 expenses and capital costs
of those facilities.
New Hampshire Electric Cooperative (NHEC): Previously, PSNH entered into a
buy-back agreement to purchase the capacity and energy of the NHEC's share of
Seabrook and to pay all of NHEC's Seabrook costs for a 10-year period, which
began on July 1, 1990. The total cost of purchases under this agreement was $33
million in 1999, $29.7 million in 1998 and $23.4 million in 1997. These costs
are recoverable through the FPPAC. The estimated annual cost of this agreement
for year 2000 is $14.6 million.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements, absent the effects of any
contract terminations or buydowns are as follows:
- -------------------------------------------------------------------
(Millions of Dollars) 2000 2001 2002 2003 2004
- -------------------------------------------------------------------
VYNPC $ 24.1 $ 21.8 $ 21.9 $ 21.5 $ 21.0
NUGs 472.6 480.2 489.2 500.1 487.3
Hydro-Quebec 31.3 30.3 29.6 28.7 27.8
- -------------------------------------------------------------------
Select Energy: Select Energy maintains long-term agreements to purchase both
wholesale and retail energy in the normal course of business. The notional
amount of these purchase contracts is $3.1 billion at December 31, 1999. These
contracts extend through 2004 as follows:
- -------------------------------------------------------------------
(Millions of Dollars)
- -------------------------------------------------------------------
Year
- -------------------------------------------------------------------
2000 $1,271
2001 638
2002 573
2003 499
2004 101
- -------------------------------------------------------------------
Total $3,082
- -------------------------------------------------------------------
H. NEW ENGLAND POWER POOL (NEPOOL)
GENERATION PRICING
Disputes with respect to interpretation and implementation of the NEPOOL market
rules have arisen with respect to various competitive product markets. In
certain cases, Select Energy and the NU operating companies stand to gain as a
result of resolution of such disputes. In other cases, Select Energy and the NU
operating companies could incur additional costs as the result of resolution of
the disputes. The various disputes are in various stages of resolution through
alternative dispute resolution and regulatory review. It is too early to tell
the level of potential gain or loss that may result upon resolution of these
issues.
8. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS
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. Under the agreements, NAEC exchanges quarterly
payments based on a differential between a fixed contractual interest rate and
the 3-month LIBOR rate at a given time. As of December 31, 1999 and 1998, NAEC
had outstanding agreements with a total notional value of $200 million and
mark-to-market positions of positive $0.5 million and negative $2.3 million,
respectively.
Energy Price Risk Management: Beginning in 1997 through 1999, CL&P used swap
instruments with financial institutions to hedge the energy price risk created
by long-term negotiated energy contracts. These agreements were intended to
minimize exposure associated with rising fuel prices by managing a portion of
CL&P's cost of producing power for these negotiated energy contracts.
In 1999, CL&P divested substantially all of its fossil and hydroelectric
generation assets and agreed to transfer the rights and obligations related to
the long-term negotiated energy contracts to an unregulated affiliate.
Accordingly, the fuel swap positions were marked-to-market and CL&P recognized
a loss of $5.2 million. In January 2000, the fuel swap positions were
liquidated.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
NAEC is exposed to credit risk on its 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.
Unregulated Energy Services Market Risk: NU's unregulated companies, as
major providers of electricity and natural gas, have certain market risks
inherent in their business activities. Market risk represents the risk of loss
that may impact the companies' financial position, results of operations or
cash flows due to adverse changes in commodity market prices. In 1999, the
companies increased their volume of the electricity and gas marketing
activities, increasing their risks. Policies and procedures have been
established to manage these exposures including the use of risk management
instruments.
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 a minority interest.
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 (SERP) Investments: Investments held
for the benefit of the SERP are recorded at fair market value. The investments
having a cost basis of $5.8 million and $5.4 million held for benefit of the
SERP were recorded at their fair market values at December 31, 1999 and 1998
of $9.2 million and $8.7 million, respectively.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were marked-to-market by $129 million
as of December 31, 1999 and $110.4 million as of December 31, 1998, with
corresponding offsets to the accumulated provision for depreciation. The
amounts adjusted in 1999 and in 1998 represent cumulative net unrealized gains.
The cumulative gross unrealized holding losses were immaterial for both 1999
and 1998.
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, 1999
- --------------------------------------------------------------------------
Carrying Fair
(Millions of Dollars) Amount Value
- --------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 136.2 $ 164.0
Preferred stock subject to
mandatory redemption 167.5 166.8
Long-term debt -
First mortgage bonds 1,193.2 1,209.5
Other long-term debt 1,638.3 1,430.1
MIPS 100.0 97.3
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
At December 31, 1998
- --------------------------------------------------------------------------
Carrying Fair
(Millions of Dollars) Amount Value
- --------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 136.2 $ 97.0
Preferred stock subject to
mandatory redemption 213.8 205.9
Long-term debt -
First mortgage bonds 1,984.0 2,003.6
Other long-term debt 1,654.9 1,682.7
MIPS 100.0 102.0
- --------------------------------------------------------------------------
11. OTHER COMPREHENSIVE INCOME
The accumulated balance for each other comprehensive income item is as follows:
- --------------------------------------------------------------------------
Current
December 31, Period December 31,
(Thousands of Dollars) 1998 Change 1999
- --------------------------------------------------------------------------
Foreign currency
translation adjustments $ (1) $ 1 $ --
Unrealized gains
on securities 2,019 118 2,137
Minimum pension
liability adjustments (613) -- (613)
- --------------------------------------------------------------------------
Accumulated other
comprehensive income $ 1,405 $ 119 $ 1,524
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
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 adjustments -- (613) (613)
- --------------------------------------------------------------------------
Accumulated other
comprehensive income $(1) $1,406 $ 1,405
- --------------------------------------------------------------------------
The changes in the components of other comprehensive income are reported net of
the following income tax effects:
- -------------------------------------------------------------------------
(Thousands of Dollars) 1999 1998 1997
- -------------------------------------------------------------------------
Foreign currency
translation
adjustments $ -- $ -- $359
Unrealized gains
on securities (71) (1,222) --
Minimum pension
liability adjustments -- 398 --
- -------------------------------------------------------------------------
Other comprehensive
income $(71) $ (824) $359
- -------------------------------------------------------------------------
12. EARNINGS PER SHARE
Earnings per share (EPS) 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 dilutive effect if certain securities are
converted into common stock.
The following table sets forth the components of basic and diluted EPS:
- ---------------------------------------------------------------------------
(Millions of Dollars,
except share information) 1999 1998 1997
- ---------------------------------------------------------------------------
Income/(loss) after
interest charges $57.0 $(120.4) $ (99.7)
Preferred dividends
of subsidiaries 22.8 26.4 30.3
- ---------------------------------------------------------------------------
Net income/(loss) $34.2 $(146.8) $(130.0)
- ---------------------------------------------------------------------------
Basic EPS
common shares
outstanding
(average) 131,415,126 130,549,760 129,567,708
Dilutive effect
of employee
stock options 616,447 --(a) --(a)
- ---------------------------------------------------------------------------
Diluted EPS
common shares
outstanding
(average) 132,031,573 130,549,760 129,567,708
- ---------------------------------------------------------------------------
Basic earnings/
(loss) per share $0.26 $(1.12) $(1.01)
Diluted earnings/
(loss) per share $0.26 $(1.12) $(1.01)
- ---------------------------------------------------------------------------
(a) The addition of dilutive potential common shares would be anti-dilutive for
1998 and 1997 and was not included.
13. MODE 1
In August 1998, NorthEast Optic Network, Inc. (NEON) issued 4,000,000 new
common shares on the open market in an initial public offering (IPO). The IPO
had the effect of decreasing Mode 1's ownership interest in NEON 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. However, as a result of the
startup nature of NEON's operations, this change in ownership interest was
recognized in additional paid in capital.
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.
On November 23, 1999, NEON entered into two agreements with unaffiliated
companies. Under the agreements, NEON will provide network transport and
carrier services among the service areas of NEON and the two unaffiliated
companies and each company will provide connectivity from the backbone system
to their respective local loops. Additionally, each company will manage their
local distribution into their respective end-users' locations. NEON will also
develop, operate and market the combined telecommunications infrastructure
created under the two agreements.
As the agreements are implemented, the two unaffiliated companies will
ultimately obtain 10.75 percent and 9.25 percent ownership interests,
respectively, in NEON and will each nominate one member to the NEON Board of
Directors. The agreements are subject to regulatory approvals, which are
expected by the spring of 2000.
14. SEGMENT INFORMATION
Effective January 1, 1999, the NU system companies adopted SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information." The NU
system is organized between regulated utilities and unregulated energy
services.
The regulated utilities segment represents 87 percent of the NU system's
total revenue and is comprised of several business units including generation,
transmission and distribution.
The unregulated energy services segment in the following table includes NGC,
NGS, Select Energy and HEC.
Other in the following table includes the results for Mode 1. Mode 1 had a
net loss of $4.3 million for the year ended December 31, 1999. Interest expense
included in Other primarily relates to the debt of NU parent. Inter-segment
eliminations of revenues and expenses are also included in Other.
Regulated utilities revenues primarily are derived from residential,
commercial and industrial customers and are not dependent on any single
customer. The unregulated energy services segment has a major customer whose
purchases represented 46 percent of its total revenues for the year ended
December 31, 1999.
- ---------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 1999
- ---------------------------------------------------------------------------------------------------------------
Unregulated
Regulated Energy
(Millions of Dollars) Utilities Services Other Total
- ---------------------------------------------------------------------------------------------------------------
Operating revenues $ 3,888.7 $ 606.3 $(23.7) $ 4,471.3
Operating expenses (3,495.9) (646.7) 15.9 (4,126.7)
- ---------------------------------------------------------------------------------------------------------------
Operating income/(loss) 392.8 (40.4) (7.8) 344.6
Other (loss)/income (36.4) (1.2) 13.7 (23.9)
Interest expense (247.8) (1.0) (14.9) (263.7)
Preferred dividends (22.8) -- -- (22.8)
- ---------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 85.8 $ (42.6) $ (9.0) $ 34.2
- ---------------------------------------------------------------------------------------------------------------
Total assets $ 9,388.3 $ 222.5 $ 77.3 $ 9,688.1
- ---------------------------------------------------------------------------------------------------------------
Prior to 1999, the NU system evaluated management performance using a
cost-based budget, therefore business segment reporting on a comparative basis
will not be available until the year 2000.
15. MERGER AGREEMENT WITH CON EDISON
On October 13, 1999, NU and Con Edison announced that they have agreed to a
merger to combine the two companies. The shareholders of NU will receive $25
per share in a combination of cash and Con Edison common stock.
NU shareholders also have the right to receive an additional $1 per share if
a definitive agreement to sell its interests (other than that now held by PSNH)
in Millstone 2 and 3 is entered into and recommended by the Utility Operations
and Management Unit of the DPUC on or prior to the later of December 31, 2000,
or the closing of the merger. Further, the value of the amount of cash or
common stock to be received by NU shareholders is subject to increase by an
amount of $0.0034 per share per day for each day that the transaction does not
close after August 5, 2000.
Upon completion of the merger, NU will become a wholly owned subsidiary of
Con Edison. The purchase is subject to the approval of the shareholders of both
companies and several regulatory agencies. The companies anticipate that these
regulatory procedures will be completed by July 2000.
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
Quarter Ended (a)
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per
share information) March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------------
1999
Operating Revenues $ 1,043,407 $ 1,038,569 $ 1,240,539 $ 1,148,736
Operating Income $ 89,638 $ 56,492 $ 110,544 $ 87,863
Net Income/(Loss) $ 18,444 $ 228 $ 31,218 $ (15,674)
Basic and Diluted Earnings/(Loss)
Per Common Share $ 0.14 $ -- $ 0.24 $ (0.12)
- ---------------------------------------------------------------------------------------------------------------
1998
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) $ (132,002)
Basic and Diluted (Loss)/Earnings
Per Common Share $ (0.14) $ 0.05 $ (0.02) $ (1.01)
- ---------------------------------------------------------------------------------------------------------------
CONSOLIDATED GENERATION STATISTICS (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
Source of Electric Energy: (kWh-millions)
Nuclear -- Steam(b) 13,558 5,679 3,778 9,405 18,235
Fossil -- Steam 10,959 12,505 13,155 9,188 9,162
Hydro -- Conventional 1,206 1,510 1,260 1,544 1,099
Hydro -- Pumped Storage 944 819 959 1,217 1,209
Internal Combustion 262 80 184 206 37
Energy Used for Pumping (1,318) (1,130) (1,327) (1,668) (1,674)
- ---------------------------------------------------------------------------------------------------------------
Net Generation 25,611 19,463 18,009 19,892 28,068
- ---------------------------------------------------------------------------------------------------------------
Purchased and Net Interchange 43,849 24,945 24,377 22,111 14,256
Company Use and Unaccounted for (2,612) (2,566) (2,802) (2,473) (2,706)
- ---------------------------------------------------------------------------------------------------------------
Net Energy Sold 66,848 41,842 39,584 39,530 39,618
- ---------------------------------------------------------------------------------------------------------------
System Capability -- MW(b) (c) 8,194.2 8,169.6 8,312.0(d) 8,894.0 8,394.8
System Peak Demand -- MW 7,188.2 6,454.7 6,455.5 5,946.9 6,358.2
Nuclear Capacity -- MW(b) (c) 2,218.5 2,217.8 2,785.0(d) 3,117.8 3,239.6
Nuclear Contribution to Total
Energy Requirements (%)(b) 38.0 19.0 13.0 28.0 52.0
Nuclear Capacity Factor (%)(d) 86.4 32.8 19.6 38.0 69.9
- ---------------------------------------------------------------------------------------------------------------
(a) Reclassifications of prior years' data have been made to conform with the
current presentation.
(b) Includes the NU system's entitlements in regional nuclear generating
companies, net of capacity sales and purchases.
(c) Millstone 2 returned to service during the second quarter of 1999, following
NRC approval. 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.
(d) Represents the average capacity factor for the nuclear units operated by the
NU system.
SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars,
except percentages and
share information) 1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Net Utility Plant $ 3,947,434 $ 6,170,881 $ 6,463,158 $ 6,732,165 $ 7,000,837
Total Assets 9,688,052 10,387,381 10,414,412 10,741,748 10,559,574
Total Capitalization (a) 5,216,456 6,030,402 6,472,504 6,659,617 6,820,624
Obligations Under Capital
Leases (a) 181,293 209,279 207,731 206,165 230,482
- ---------------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues $ 4,471,251 $ 3,767,714 $ 3,834,806 $ 3,792,148 $ 3,750,560
Net Income/(Loss) 34,216 (146,753) (129,962) 38,929 282,434
- ---------------------------------------------------------------------------------------------------------------
Common Share Data:
Basic and Diluted Earnings/
(Loss) Per Common Share $0.26 $(1.12) $(1.01) $0.30 $2.24
Common Shares
Outstanding (Average) 131,415,126 130,549,760 129,567,708 127,960,382 126,083,645
Dividends Per Share $0.10 $-- $0.25 $1.38 $1.76
Market Price -- High $22 $17 1/4 $14 1/4 $25 1/4 $25 3/8
Market Price -- Low $13 9/16 $11 11/16 $7 5/8 $9 1/2 $21
Market Price -- Closing
(end of year) $20 9/16 $16 $11 13/16 $13 1/8 $24 1/4
Book Value Per Share
(end of year) $15.80 $15.63 $16.67 $18.02 $19.08
Rate of Return Earned
on Average
Common Equity (%) 1.6 (7.0) (5.8) 1.6 12.0
Market-to-Book Ratio
(end of year) 1.3 1.0 0.7 0.7 1.3
- ---------------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity 40% 34% 34% 35% 36%
Preferred Stock (a)(b) 5 5 6 6 7
Long-Term Debt (a) 55 61 60 59 57
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization 100% 100% 100% 100% 100%
- ---------------------------------------------------------------------------------------------------------------
(a) Includes portions due within one year.
(b) Excludes $100 million of MIPS.
CONSOLIDATED SALES STATISTICS (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
Revenues: (thousands)
Residential $1,517,913 $1,475,363 $1,499,394 $1,501,465 $1,469,988
Commercial 1,272,969 1,273,146 1,266,449 1,246,822 1,230,608
Industrial 560,801 568,913 560,782 565,900 583,204
Other Utilities 926,056 336,623 329,764 315,577 303,004
Streetlighting and Railroads 45,564 47,682 48,867 48,053 47,510
Non-Franchised Sales 24,659 22,479 21,476 8,360 --
Miscellaneous 52,357 16,429 47,446 23,513 50,353
- ---------------------------------------------------------------------------------------------------------------
Total Electric 4,400,319 3,740,635 3,774,178 3,709,690 3,684,667
Other 70,932 27,079 60,628 82,458 65,893
- ---------------------------------------------------------------------------------------------------------------
Total $4,471,251 $3,767,714 $3,834,806 $3,792,148 $3,750,560
- ---------------------------------------------------------------------------------------------------------------
Sales: (kWh - millions)
Residential 12,912 12,162 12,099 12,241 12,005
Commercial 12,850 12,477 12,091 12,012 11,737
Industrial 7,050 6,948 6,801 6,820 6,842
Other Utilities 33,575 9,742 8,034 8,032 8,718
Streetlighting and Railroads 314 320 318 319 316
Non-Franchised Sales 147 193 241 50 --
- ---------------------------------------------------------------------------------------------------------------
Total 66,848 41,842 39,584 39,474 39,618
- ---------------------------------------------------------------------------------------------------------------
Customers: (average)
Residential 1,569,932 1,555,013 1,535,134 1,532,015 1,526,127
Commercial 164,932 162,500 159,350 157,347 156,652
Industrial 7,721 7,847 7,804 7,792 7,861
Other 3,908 3,890 3,929 3,916 3,878
- ---------------------------------------------------------------------------------------------------------------
Total 1,746,493 1,729,250 1,706,217 1,701,070 1,694,518
- ---------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 8,243 7,799 7,898 8,005 7,880(a)
- ---------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $ 969.38 $ 946.80 $ 978.72 $ 980.19 $ 964.88(a)
- ---------------------------------------------------------------------------------------------------------------
Average Revenue per kWh:
Residential 11.76 cents 12.14 cents 12.39 cents 12.27 cents 12.24 cents
Commercial 9.91 10.20 10.47 10.38 10.49
Industrial 7.95 8.19 8.25 8.30 8.52
- ---------------------------------------------------------------------------------------------------------------
(a) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.