Exhibit 99.3 to Form 8-K Report
Financial Condition
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
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 approximately $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
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 mortgaes 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 settled the
transactions no later than December 31, 2000 for an aggregate purchase price
equal to $215 million. However, NU expects to settle these purchase
transactions 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
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
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
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 $33.6 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 costs, see Note 7D, "Commitments and
Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated
financial statements.
Market Risk and Risk Management Instruments
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 commitments and contingencies primarily relating to
nuclear litigation, nuclear insurance contingencies, its constuction 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
(Millions of Dollars)
1999 over/(under) 1998 1998 over/(under) 1997
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) (100)
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 revenues ($107 million) and higher regulated retail revenues ($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 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 tax expense 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.