EXHIBIT 13.1
ANNUAL REPORT OF NORTHEAST UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
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OVERVIEW
Northeast Utilities and subsidiaries (NU or the company) reported 2001 earnings
of $243.5 million, or $1.79 per share on a fully diluted basis, compared with a
loss of $28.6 million, or $0.20 per share on a fully diluted basis in 2000 and
earnings of $34.2 million, or $0.26 per share on a fully diluted basis in 1999.
In 2001 and 2000, NU's results were affected significantly by nonrecurring
items.
In 2001, NU recorded an after-tax gain of $115.6 million, or $0.85 per
share, in connection with the sale of the Millstone nuclear units to a
subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc.
(DNCI). In 2001, NU also recorded an after-tax nonrecurring loss of $22.4
million, or $0.17 per share, as a result of the adoption of Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, and an after-tax mark-to-
market loss of $35.4 million, or $0.26 per share, associated with the
repurchase of NU shares in the first half of 2001. In 2000, NU recorded an
extraordinary after-tax loss of $233.9 million, or $1.65 per share, primarily
associated with electric utility industry restructuring in New Hampshire.
Excluding the effect of these nonrecurring items, NU earned $185.7 million,
or $1.37 per share on a fully diluted basis, in 2001, compared with $205.3
million, or $1.45 per share on a fully diluted basis, in 2000.
The decline in operating results at NU's regulated companies was due to a
number of factors. Earnings at both The Connecticut Light and Power Company
(CL&P) and Western Massachusetts Electric Company (WMECO) decreased primarily
because the sale of Millstone three months into 2001 removed a significant
source of earnings as compared with 2000. Earnings before preferred dividends
at CL&P totaled $109.8 million in 2001, compared with $148.1 million in 2000
and a loss of $13.6 million in 1999. Earnings before preferred dividends at
WMECO totaled $15 million in 2001, compared with $35.3 million in 2000 and $2.9
million in 1999. In addition to the sale of Millstone, CL&P's lower earnings
also reflect a $21.1 million reduction in distribution and transmission rates
the Connecticut Department of Public Utility Control (DPUC) imposed, which was
effective on June 20, 2001.
Operating results at Public Service Company of New Hampshire (PSNH) and
North Atlantic Energy Corporation (NAEC) declined as a result of the
implementation of industry restructuring and an 11 percent reduction in retail
rates on May 1, 2001. Earnings before preferred dividends at PSNH totaled
$81.8 million in 2001, compared with a loss of $146.7 million in 2000 and
earnings of $84.2 million in 1999. The PSNH results included an after-tax
gain of $15.5 million associated with the Millstone sale in 2001 and an
after-tax $214.2 million extraordinary charge associated with electric industry
restructuring in 2000. Earnings at NAEC totaled $4.2 million in 2001, compared
with $32.5 million in 2000 and $29.6 million in 1999. The lower results at
NAEC reflect a reduction in payments made by PSNH to NAEC due to a buydown of
the Seabrook Power Contracts with the proceeds from the sale of rate reduction
bonds. Management expects combined operating results at PSNH and NAEC to
continue to decline in 2002, reflecting the effects of a full year of electric
utility industry restructuring.
Results at NU's competitive energy subsidiaries also declined in 2001. The
competitive energy subsidiaries earned $5 million on revenues of $3 billion in
2001, compared with a contribution towards NU's consolidated earnings of $13.6
million on revenues of $1.9 billion in 2000 and a loss of $37 million on
revenues of $0.6 billion in 1999, excluding nonrecurring items. The decline was
primarily due to higher purchased power costs in the winter of 2001 and lower
than expected summer and fall customer loads due to mild weather conditions.
Partially offsetting those declines in operating results was a significant
increase in earnings at Yankee Energy System, Inc. (Yankee), which NU acquired
on March 1, 2000. Yankee earned $25.8 million in 2001, compared with a loss of
$0.7 million during the 10 months of 2000 it was part of the Northeast
Utilities system (NU system). The improved results were primarily due to the
inclusion of January 2001 and February 2001 results in 2001 earnings and the
settlement of property tax litigation with the City of Meriden, Connecticut.
NU's earnings per share (EPS) benefited from the repurchase of approximately
14.3 million NU common shares in 2001. NU's outstanding share count totaled
130.1 million shares on December 31, 2001, compared with 143.8 million shares
outstanding on December 31, 2000.
FUTURE OUTLOOK
NU estimates that its EPS will range between $1.40 per share and $1.65 per
share in 2002, excluding significant nonrecurring items. NU expects that no
retail rate cases will be filed in 2002. The company therefore expects the
financial performance of its regulated businesses to be relatively stable and
predictable in 2002, absent significant adverse events, such as a catastrophic
storm.
Also affecting the 2002 earnings range is the income associated with NU's
qualified pension plan. In 2001, NU's operating results included pretax pension
income of approximately $101 million associated with this plan, excluding the
effects of the Voluntary Separation Program. NU currently expects pretax
pension income in 2002 to be reduced to approximately $73 million. Pension
income is annually adjusted during the second quarter based upon updated
actuarial evaluations, and the 2002 estimate may be modified at that time.
Additionally, a prime determinant of where NU performs within the
aforementioned 2002 earnings range is the performance of the company's
competitive energy subsidiaries. NU expects revenues from its competitive
energy subsidiaries to exceed $3.8 billion in 2002. Much of that increase
over 2001 is the result of Select Energy, Inc.'s (Select Energy) acquisition
of Niagara Mohawk Energy Marketing, Inc. (NMEM) in late November 2001 for
approximately $31.7 million. That business was subsequently renamed Select
Energy New York, Inc. (SENY).
In 2001, Select Energy's profits from its wholesale electric sales were
reduced by its obligation to serve 50 percent of CL&P's standard offer service
load at below market rates. Select Energy's obligation to serve that load,
continues through 2003. Select Energy's results would benefit from an increase
in the pricing for CL&P's standard offer service load. A proceeding to begin
this process was filed with the DPUC in 2001, and management is pursuing
raising those prices in 2002 and 2003. Select Energy's profits also will
depend on its ability to renew and expand its wholesale business in its
12-state Northeastern market area, as well as to continue to grow its retail
natural gas and electric businesses.
CONSOLIDATED EDISON, INC. MERGER LITIGATION
On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it was
unwilling to close its merger with NU on the terms set forth in the parties'
October 13, 1999, Agreement and Plan of Merger, as amended and restated as of
January 11, 2000, (Merger Agreement). That same day, NU notified Con Edison
that it would treat Con Edison's refusal to proceed with the merger as a
repudiation and breach of the Merger Agreement, and would file suit to obtain
the benefits of the transaction for NU shareholders. On March 6, 2001, Con
Edison filed suit in the United States District Court for the Southern District
of New York (District Court) seeking a declaratory judgment that it had been
relieved of its obligation to proceed with the merger due to, among other
things, NU's alleged breach of the Merger Agreement and the alleged occurrence
of a "Material Adverse Change" with respect to NU as that term is defined in
the Merger Agreement. Con Edison also contends that it is entitled to recover
damages from NU equal to the benefits it would have received if the merger had
been consummated together with the costs incurred in preparing for and seeking
approval of the merger. NU believes that Con Edison's claim for damages is
without merit and, in any event, that Con Edison's proposed measure of damages
is inappropriate. On March 12, 2001, NU filed suit against Con Edison in the
District Court seeking damages in excess of $1 billion arising from Con
Edison's breach of the Merger Agreement.
On May 11, 2001, in accordance with a stipulation of the parties and order
of the District Court, Con Edison filed an amended complaint in which it added
claims seeking damages for breach of contract, fraudulent inducement and
negligent misrepresentation. On June 1, 2001, NU answered Con Edison's amended
complaint, denying all of its material allegations and asserting affirmative
defenses, and asserted a counterclaim seeking damages in excess of $1 billion
against Con Edison for breach of the Merger Agreement. NU subsequently
dismissed its March 12, 2001, complaint as duplicative of the June 1, 2001,
counterclaim. On June 8, 2001, Con Edison answered NU's counterclaim, denying
its material allegations and asserting affirmative defenses.
The parties substantially completed fact discovery in the litigation on
December 21, 2001, and are currently conducting expert discovery. The case
schedule currently calls for the parties to be prepared for trial on or after
June 21, 2002; however no trial date has yet been set by the court.
In addition, separate petitions were filed with the DPUC asking that its
merger approval be rescinded or reversed. The DPUC reopened its docket
approving the merger and asked parties to comment on the question of whether
a date certain should be imposed for consummation of the merger and whether
that date should be January 31, 2002. On January 30, 2002, the DPUC issued a
decision establishing January 31, 2002, as the deadline for merger
consummation. As a result, the DPUC's prior approval of the merger is no
longer effective.
At this early stage of the litigation, management can predict neither the
outcome of this matter nor its ultimate effect on NU.
LIQUIDITY
The year 2001 was marked by tremendous inflows of cash into the NU system as a
result of the securitization of stranded costs and the sale of the Millstone
units. During a seven-week period between March 30, 2001, and May 17, 2001,
NU's subsidiaries' liquidity benefited from the issuance of $2.1 billion in
rate reduction bonds and certificates and the receipt of the $1.2 billion from
the sale of the Millstone units. The largest share of those proceeds was used
for the repayment of debt and preferred securities. As a result, NU's combined
short-term and long-term debt other than rate reduction bonds decreased to
approximately $2.6 billion at the end of 2001 from approximately $3.7 billion
at the end of 2000. Capital lease obligations declined to $17.5 million at the
end of 2001 from $159.9 million at the end of 2000. In 2001, CL&P also repaid
$100 million of Monthly Income Preferred Securities and reduced the amount
outstanding under its accounts receivable facility by $170 million. WMECO and
PSNH repaid all of their preferred stock, leaving CL&P's $116.2 million of
preferred stock not subject to mandatory redemption as the only preferred
securities in the NU system.
Of the $2.1 billion of rate reduction bonds and certificates issued by CL&P,
PSNH and WMECO, approximately $1.2 billion was used to buyout or buydown
high-cost, long-term purchased-power contracts. PSNH paid approximately another
$50 million in December 2001 to buyout other purchased-power contracts and
issued an equivalent amount of rate reduction bonds in January 2002, to pay for
those costs. PSNH continues to negotiate buyout or buydown arrangements with
other plant operators and may require additional funds if successfully
renegotiated agreements are approved by the New Hampshire Public Utilities
Commission (NHPUC) and result in upfront payments.
The remaining proceeds from the Millstone sale were used primarily to pay
state and federal income taxes on the Millstone sale and return equity capital
to NU parent from the regulated electric companies. Including both return of
capital and common dividends, CL&P, PSNH, WMECO, and NAEC paid $60.1 million,
$287 million, $37 million, and $136 million, respectively, to NU parent in
2001. Yankee paid no dividends to NU parent in 2001, as NU parent used Yankee
earnings and the receipt of approximately $20 million from the sale of
interests in certain electric generating facilities owned by Yankee
subsidiaries to repay debt and fund Yankee's expanded capital expenditure
program.
NU parent used the dividends and return of capital primarily to repurchase
approximately 14.3 million NU common shares in 2001 of which approximately 10.3
million shares were repurchased in the second quarter of 2001. In July 2001,
the NU Board of Trustees authorized the repurchase of 15 million additional NU
common shares by July 2003. Under this authorization, NU repurchased
approximately 4 million shares by the end of the year and has authorization to
repurchase approximately another 11 million shares.
In addition to repurchasing shares, NU spent another $31.7 million through
Select Energy to acquire NMEM and through its subsidiary Mode 1 Communications,
Inc. (Mode 1) lent $15 million to NEON Communications, Inc. (NEON) in the form
of subordinated convertible notes. On December 6, 2001, NEON announced that it
had retained an unaffiliated financial institution to explore, among other
options, debt restructuring. On January 22, 2002, NEON announced it was seeking
a waiver from one of its significant unaffiliated suppliers on a $7.3 million
payment that had been due on December 31, 2001. If that supplier accelerates
payment on its $42 million note from NEON, the action would trigger a
cross-default on $180 million of senior notes previously issued by NEON.
If NEON were to restructure its debt obligations or declare bankruptcy, NU
management believes that some or all of its debt and equity investment in NEON
would be impaired. In addition to the $15 million of subordinated convertible
notes, Mode 1 owns approximately 4 million shares of NEON common stock. This
equity investment had a book value of $4.6 million, and a fair value of $11.2
million at December 31, 2001. Subsequent to December 31, 2001, the market
value of NEON stock has decreased significantly.
NU continues to pursue additional investments in both the regulated and
unregulated energy businesses in the Northeast United States or other strategic
initiatives from time to time and will weigh making those investments against
continued share repurchases.
Aside from the issuance of rate reduction bonds and certificates, the NU
system undertook a number of refinancings in 2001. On February 28, 2001, NU
issued $263 million of variable-rate unsecured notes to repay an equal amount
of bank debt incurred a year earlier when NU acquired Yankee. On October 18,
2001, Northeast Generation Company (NGC) issued $440 million of amortizing
senior secured debt. The $440 million includes $120 million of bonds that
mature on October 15, 2005, at an interest rate of 4.998 percent, and $320
million of bonds that mature on October 15, 2026, at an interest rate of
8.812 percent. Proceeds from the issuance plus cash on hand were used to
return $75 million to NU parent through a combination of capital and common
dividends and to repay bank borrowings NGC had incurred to acquire 1,289
megawatts (MW) of predominantly hydroelectric generation assets in early 2000.
On December 19, 2001, PSNH refinanced $287.5 million of tax-exempt pollution
control revenue bonds (PCRBs) by issuing $109 million of insured lower
fixed-rate bonds and $178.5 million of insured variable-rate bonds. At current
rates, that refinancing is expected to save PSNH in excess of $10 million
annually. Also, in late 2001, Holyoke Water Power Company (HWP) repaid all
of its public debt in connection with the sale of its hydroelectric generation
assets and electric distribution system to the City of Holyoke for $17.5
million.
Primarily as a result of the Millstone sale and the issuance of rate
reduction bonds and certificates, NU's consolidated capitalization ratio was
significantly stronger at the end of 2001 than it was a year earlier. Including
capital lease obligations, but excluding rate reduction bonds as these bonds
are nonrecourse to the NU system, NU's capitalization ratio was 54.3 percent
debt, 2.4 percent preferred securities and 43.3 percent common equity at the
end of 2001, compared with 60.4 percent debt, 4.4 percent preferred securities
and 35.2 percent common equity at the end of 2000. The improved capitalization
ratio and lowered overall risk profile resulted in a series of upgrades of the
NU system securities through 2001. At the end of 2001, senior debt ratings on
NU parent securities were Baa1 and BBB, A2 and A- for CL&P, A3 and BBB+ for
WMECO, and A3, BBB+, and BBB for PSNH. Overall, those ratings were the highest
for NU securities in decades and are expected to continue to enhance the NU
system's access to low-cost capital.
NU's net cash flows provided by operating activities declined to $376.7
million in 2001, compared with $578.4 million in 2000 and $614.2 million in
1999. In 2001, cash flows provided by operating activities, decreased primarily
due to an increase in receivables and unbilled revenues, net, associated with
the sales growth at NU's competitive energy subsidiaries. The level of common
dividends totaled $60.9 million in 2001, as compared to $57.4 million in 2000
and $13.2 million in 1999. This increase was a result of NU paying a $0.10 per
share quarterly common dividend in the first two quarters of 2001 and a $0.125
per share quarterly common dividend in the last two quarters of 2001, as
compared to paying a $0.10 per share quarterly common dividend for all of 2000.
The level of preferred dividends decreased to $7.3 million in 2001, compared
with $14.2 million in 2000 and $22.8 million in 1999, reflecting NU's ongoing
effort to reduce preferred stock outstanding. The NU system companies currently
forecast construction expenditures of up to $593 million for the year 2002.
On September 28, 2001, NU paid a quarterly dividend of $0.125 per share, an
increase of 25 percent from a quarterly dividend of $0.10 per share declared
since the fourth quarter of 1999. Similar dividends were declared for payment
on December 31, 2001, and were declared in January 2002 for payment on
March 29, 2002. NU anticipates increasing its dividend by approximately 10
percent annually and eventually paying out approximately 50 percent of the
aggregate earnings of its regulated companies in the form of common dividends.
Such a program will be dependent upon numerous factors, including NU's ability
to meet earnings targets and the judgment of its Board of Trustees at the time.
Over the coming years, management expects WMECO and NAEC to pay out
substantially all of their earnings as dividends to the parent company. PSNH is
expected to pay out most of its earnings in the form of dividends to the parent
company. There may also be an additional dividend to NU near the end of 2002,
depending on the amount of cash received as a result of the sale of
Seabrook. NGC also is expected to pay annual dividends to NU as allowed by the
bond covenants contained in NGC's 2001 bond indenture.
Yankee Gas Services Company (Yankee Gas) is expected to reinvest its
earnings in its distribution expansion program. NU is expected to make an
additional equity contribution to Yankee Gas in 2002 to help fund its expansion
program. CL&P's dividend policy will depend largely on its earnings and the
timing and scope of its expected increasing investment in its distribution and
transmission system. In 2002, both CL&P and WMECO may make additional dividend
payments to NU to help achieve their target leverage ratios of approximately
55 percent, excluding rate reduction bonds. As of December 31, 2001, CL&P's
capitalization included total debt of approximately 48 percent and WMECO's
capitalization included total debt of approximately 52 percent, in each case
excluding rate reduction bonds.
The NU system has $50.5 million of sinking fund obligations due in 2002,
primarily at NU parent and NGC. Management expects to meet those obligations
through operating cash flows. Additionally, NU plans to refinance a $263
million variable-rate note with a fixed-rate note in April 2002, to take
advantage of current interest rates. NU also expects to meet its capital
expenditure and common dividend obligations in 2002 primarily through operating
cash flows, while maintaining excess funds for further common share
repurchases.
Beyond 2001, management expects that Yankee Gas will likely need to issue
additional long-term debt to fund its capital investment program, even without
paying any common dividends to NU. CL&P also may need to issue long-term debt
if its currently planned transmission construction program is approved by
regulators. Current debt levels at WMECO are expected to remain stable in
future years and the level at PSNH may decline, contingent upon the results of
the sale of NAEC's share of Seabrook. The NU system could need additional
sources of capital to fund expansion of its competitive energy subsidiaries in
future years, but management cannot currently estimate that amount.
COMPETITIVE ENERGY SUBSIDIARIES
NU's competitive energy subsidiaries grew significantly in 2001 with revenues
of $3 billion, compared with revenues of $1.9 billion in 2000. Earnings,
however, declined to $5 million before the cumulative effect of an accounting
change in 2001, as compared to a contribution toward NU's consolidated earnings
of $13.6 million before an extraordinary charge in 2000. NU's competitive
energy subsidiaries own and manage 1,436 MW of generation capacity, including
1,289 MW at NGC and 147 MW at HWP. These businesses also include wholesale and
retail energy marketing organizations and an expanding trading business. The
energy marketing organizations also buy and sell natural gas and other fuels.
The competitive energy subsidiaries also include Select Energy Services, Inc.
(SES) (formerly HEC Inc.), which performs energy management services for large
industrial, commercial and institutional facilities, including the United
States Department of Defense, and Northeast Generation Services Company (NGS),
which operates and maintains NGC's and HWP's generation assets and provides
third-party contracting services for power plants and large industrial
facilities.
NU operates its competitive energy subsidiaries as a combined entity.
However, in connection with the initial financing of NGC and its issuance of
nonrecourse debt, Select Energy has an above-market contract to purchase energy
and related products from NGC. Select Energy's performance under that contract
is guaranteed by NU. Select Energy has another contract to acquire power from
HWP's 147 megawatt coal-fired Mount Tom generating unit in Holyoke,
Massachusetts. Primarily as a result of the favorable terms to NGC and HWP in
those contracts, NGC earned $42.3 million on revenues of $129.7 million in 2001
and HWP earned $4.4 million on revenues of $55.2 million in 2001. Both of NU's
primary energy services businesses also were profitable in 2001 with NGS
earning $4.6 million on revenues of $112 million and SES earning $2.4 million
on revenues of $102 million. Select Energy's marketing and trading business
combines the output and capacity from NGC and HWP with other generation and
provides wholesale and retail electric service throughout the Northeast United
States. In addition to electricity, Select Energy sells natural gas and other
fuels on a wholesale and retail basis.
NU's investment in Select Energy grew in 2001 due in large part to the
acquisition of NMEM, and the need to post additional working capital as a
result of a significantly increased level of business. NU invested $109.4
million of equity in Select Energy in 2001 and Select Energy had borrowings
from the parent company of $162 million and $114.1 million at December 31,
2001 and 2000, respectively. This investment was partially offset by the
return of $75 million to NU parent through a combination of capital and common
dividends by NGC in October 2001.
One of management's primary goals in 2002 is to improve the results of
Select Energy's energy marketing and trading businesses. To reduce risk, Select
Energy has already procured almost 100 percent of the projected on-peak and the
vast majority of the off-peak electricity requirements needed to serve the CL&P
standard offer service load. In addition, management continues to work with
state regulators to increase CL&P's standard offer service price to make it
more competitive with alternative energy suppliers. Select Energy management
also continues to work with third parties to arrange new profitable energy
contracts to replace a number of wholesale contracts that are in the process of
expiring. Management also expects the operations of SENY to significantly
increase its business in New York and to generate positive net income in 2002.
NU provides credit assurance in the form of guarantees and letters of credit
for the financial performance obligations of certain of its competitive energy
subsidiaries. NU currently has authorization from the Securities and Exchange
Commission (SEC) to provide up to $500 million of guarantees, and has applied
for authority to increase this amount to $750 million. As of December 31, 2001,
NU had provided approximately $268.2 million and $45 million of such guarantees
and letters of credit, respectively. In addition, NU's "aggregate investment"
in Select Energy and its other energy service companies (but not including NGC,
HWP or certain subsidiaries of SES) (which is inclusive of most of such credit
assurances) is limited by SEC rule to 15 percent of NU's most recent quarterly
consolidated capitalization. In light of the increasing size of the energy
marketing and trading businesses, NU has applied to the SEC for authority to
exempt Select Energy and SENY from this limitation.
COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS
NU's competitive energy subsidiaries, as major providers of electricity and
natural gas, are exposed to certain market risks inherent in their business
activities. The competitive energy subsidiaries enter into contracts of varying
lengths of time to buy and sell energy commodities, primarily electricity,
natural gas and oil. Market risk represents the risk of loss that may impact
the companies' financial statements due to adverse changes in commodity market
prices.
The competitive energy subsidiaries manage their portfolio of contracts and
assets to maximize value and minimize associated risks. The lengths of
contracts to buy and sell energy vary in duration from daily/hourly to several
years. At any point in time, the portfolio may be long (purchases exceed sales)
or short (sales exceed purchases). Portfolio and risk management disciplines
are used to manage exposures to market risks. Policies and procedures have been
established to manage these risks. At market spot prices in effect at
December 31, 2001, the portfolio had a positive mark-to-market position. There
is significant volatility in the energy commodities market, and for certain of
the energy products and contracts there has been limited liquidity. The
position increased in value due to the decline in energy prices in the region
and new transactions entered into during 2001.
Select Energy also engages in the trading of commodity derivatives, which
are accounted for using the mark-to-market method under Emerging Issues Task
Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities." All other nontrading transactions are recognized when settled.
All trading positions are marked-to-market daily at the end of each trading
day. All NYMEX futures and options are marked to closing exchange prices.
Over-the-counter forwards and options are marked to the mid-point of bid and
ask quotes. In most cases there are multiple sources of over-the-counter and
broker quotes. Options, for which specific quotes are not available, are
marked-to-market using a forward volatility curve derived from other options
for which quotes are available.
As of and for the year ended December 31, 2001, the sources of the fair
value of these trading activities and the change in fair value of these trading
activities are as follows:
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(Millions of Dollars) Fair Value of Contracts at December 31, 2001
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Maturity Maturity Maturity in
Less than of One to Excess of Total
Sources of Fair Value One Year Four Years Four Years Fair Value
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Prices actively quoted $ 1.0 $ 0.2 $ -- $ 1.2
Prices provided by
external sources 6.5 15.9 20.8 43.2
Prices based on model or
other valuation method -- -- -- --
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Totals $ 7.5 $16.1 $20.8 $44.4
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(Millions of Dollars) Total Fair Value
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Fair value at beginning of period
(January 1, 2001) $13.8
Contracts realized or otherwise
settled during the period (7.9)
Fair value of new contracts entered
into during the period 17.7
Changes in fair value of contracts
that existed at the beginning of
the period 20.8
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Fair value at end of period
(December 31, 2001) $44.4
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For further information see Note 1J, "Summary of Significant Accounting
Policies - Accounting for Competitive Energy Contracts," Note 9, "Market Risk
and Risk Management Instruments," and Note 12, "Other Comprehensive Income," to
the consolidated financial statements.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
In 2001, NU system companies announced a number of initiatives to significantly
increase their investment in regulated electric transmission and natural gas
distribution facilities, particularly in Connecticut. CL&P announced that it
planned to construct two new 345,000 volt transmission line facilities totaling
approximately 85 miles into Norwalk, Connecticut at a combined cost of
approximately $520 million. An application to construct one of the facilities,
an approximately 20 mile facility from Bethel, Connecticut to Norwalk,
Connecticut, was filed in October 2001 with the Connecticut Siting Council. A
decision is expected by the fall of 2002. The application related to a second
facility from Middletown, Connecticut to Norwalk, Connecticut will be filed
with the Connecticut Siting Council later in 2002. CL&P also has proposed
replacing the existing 138,000 volt transmission line beneath Long Island Sound
between Norwalk, Connecticut and Northport - Long Island, New York. CL&P, which
owns an equal share of the existing line with the Long Island Power Authority,
would bear approximately half of the cost of the $80 million project. That
project would require Connecticut, New York and federal regulatory approvals.
This application was filed with the Connecticut Siting Council in February
2002. If approved, these three projects would increase CL&P's capital
expenditures. CL&P's capital investments in electric utility plant totaled
$237.4 million in 2001 and $208.2 million in 2000, well above the $132.2
million level of 1998, primarily as a result of increased spending on CL&P's
distribution system. CL&P's capital expenditures are expected to total $244
million in 2002 and higher in 2003 through 2005, if the transmission projects
are approved.
In addition to the three CL&P transmission projects noted above, the NU
system announced plans for a fourth project involving construction of a new
undersea direct-current line between Norwalk, Connecticut and western Long
Island that is projected to be in service by no later than 2005. The cost of
that line, which will require several regulatory approvals, depends on a number
of factors, including its size and route. Management expects the line to be
built and owned by a new NU transmission subsidiary that will secure its own
external financing and receive an equity contribution from NU.
Yankee Gas received approval for a significant expansion of its distribution
system as it has a relatively low penetration rate for gas service in its
service territory. To begin increasing that penetration rate, Yankee Gas
commenced work in 2001 on 12 projects expected to cost $23 million in total. As
a result, Yankee Gas' capital expenditures were $47.8 million in 2001, compared
with $21.6 million in 2000. Yankee Gas has proposed system expansion projects
totaling $190 million through 2005, including the 12 projects announced in
2001. Yankee Gas also is considering construction of a liquefied natural gas
storage terminal in Waterbury, Connecticut that could cost in excess of $50
million. Yankee Gas may issue up to $100 million of long-term debt in 2002 to
finance its capital needs and may require additional debt issuances in later
years, depending on the extent of its capital program.
Capital investments in electric utility plant at PSNH and WMECO totaled
$92.6 million and $30.9 million, respectively, in 2001, as compared to $69.5
million and $27.3 million, respectively, in 2000. The company anticipates no
material increase in capital expenditures at those subsidiaries in the next
several years.
Capital expenditures at NU's competitive energy subsidiaries are expected to
be modest over the next several years. The most significant ongoing project is
a repowering of six hydroelectric generation units at the Cabot Facility in
Turners Falls, Massachusetts. That project began in 2001 and is expected to
cost approximately $7 million per year and continue through 2003.
NU continues to search for investment opportunities in competitive energy
businesses in the Northeast United States. Over the past three years, NU
acquired Denron, a heating, ventilating and air conditioning contractor based
in New Hampshire; E.S. Boulos Company (Boulos), a high-voltage electrical
contractor based in Maine, and; NMEM, an energy marketing company based in New
York. NU also invested $10 million in Acumentrics, a Massachusetts firm that
manufactures power quality and uninterruptible power quality components. The
NMEM acquisition at approximately $31.7 million, was the largest investment of
the four aforementioned investments. With approximately $570 million in
revenues in 2001, this acquisition is expected to increase Select Energy's
consolidated revenues by approximately 25 percent in 2002 and significantly
increase Select Energy's activities in the New York market.
RESTRUCTURING AND RATE MATTERS
Connecticut - CL&P: Industry restructuring for CL&P was essentially completed
in 2000. In June 2001, the DPUC concluded an investigation of potential
overearnings by CL&P and ordered a $21.1 million reduction in CL&P's electric
transmission and distribution rates and an equal increase in CL&P's Generation
Services Charge. The DPUC also implemented an earnings sharing mechanism under
which earnings in excess of a 10.3 percent return on equity will be shared
equally by shareholders and ratepayers. On September 28, 2001, the DPUC ordered
a $21.3 million annual reduction in CL&P's System Benefits Charge as a result
of a sharp reduction in decommissioning collections and an equal increase in
the Competitive Transition Assessment, effective January 1, 2002. Also, on
July 26, 2001, the DPUC authorized CL&P to assess a charge of approximately
$0.002 per kilowatt-hour (kWh) from August 2001 through December 2003 to
collect approximately $98.5 million of deferred fuel costs. The net result of
these decisions was a reduction in CL&P's pretax earnings of $21.1 million
beginning June 20, 2001, an acceleration of CL&P's recovery of stranded costs
in 2002 and 2003, and further enhancement of CL&P's cash flows.
On September 27, 2001, CL&P filed its application with the DPUC for approval
of the disposition of the proceeds from the sale of the Millstone units to
DNCI. This application described and requested DPUC approval for CL&P's
treatment of its share of the proceeds from the sale. A decision from the DPUC
is expected in the first half of 2002.
Since retail competition began in Connecticut in 2000, an extremely small
number of CL&P customers have opted to choose their retail supplier. As of
December 31, 2001, virtually all of CL&P's customers were procuring their
electricity through CL&P's standard offer service. Through December 2003, 50
percent of CL&P's standard offer service requirements will be purchased from
Select Energy with the remaining 50 percent being purchased from two
unaffiliated companies. On November 18, 2001, at the request of one of the
unaffiliated companies, CL&P filed a request with the DPUC to raise the
standard offer service rate from an average of $0.0495 per kWh to $0.0595 per
kWh to help promote competition in advance of the January 1, 2004, termination
of the standard offer service period and to provide financial relief to the
standard offer suppliers. In December 2001, the DPUC rejected CL&P's request,
but opened two new dockets to examine the absence of effective retail electric
competition in Connecticut and the financial condition of the suppliers. The
dockets will include the gathering of information regarding the viability of
the standard offer service contracts, their reliability and whether the
standard offer service contracts should be linked to market conditions. The
DPUC held hearings in February 2002. A decision in this docket which could lead
to the re-opening of CL&P's standard offer docket to consider these issues is
expected to be issued in the first half of 2002.
Connecticut - Yankee Gas: On July 24, 2001, Yankee Gas filed a rate
application with the DPUC requesting a 7.64 percent or $29.2 million increase
in rates to fund system reliability projects and a proposed expansion of its
distribution system. On January 30, 2002, the DPUC issued a final decision
which ordered a $4 million rate decrease effective March 1, 2002. This rate
decrease was, in part, based upon adjustments that Yankee Gas had agreed to
during the proceedings. The final decision however, approved partially or fully
many of the proposals made by Yankee Gas in its filing. The decision endorses
Yankee Gas' distribution system expansion plan, subject to annual reviews and
approves, with some conditions, its ratemaking recovery mechanism
(Infrastructure Expansion Rate Mechanism). The final decision also authorizes
an 11 percent return on equity for Yankee Gas and a sharing formula for
earnings above that level from 2002 through 2005. Subsequent to the final
decision, the effective date of the rate decrease was delayed until
April 1, 2002.
New Hampshire: On May 1, 2001, PSNH implemented industry restructuring
allowing its customers to begin choosing their electric suppliers (competition
day). They also received an overall reduction of 10 percent, in addition to the
5 percent reduction they received on October 1, 2000.
On May 22, 2001, the Governor of New Hampshire signed a bill modifying the
state's 1996 and 2000 electric utility industry restructuring laws. The
revisions delay the sale of PSNH's fossil and hydroelectric generation assets
to no sooner than 33 months after restructuring takes effect, or February 1,
2004. The revisions also fixed the charges retail customers will pay PSNH for
electric supply, or transition service.
PSNH and NAEC have entered into two contracts where PSNH is obligated to
purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook.
The 2001 amended restructuring bill requires the NHPUC to complete the sale of
NAEC's share of Seabrook in an expeditious manner. In late 2001, the NHPUC and
the DPUC named J. P. Morgan as the selling agent for all owners seeking to sell
their Seabrook shares. Those owners, which include CL&P with its 4.06 percent
share, collectively own approximately 88 percent of Seabrook. J. P. Morgan
expects to consummate the sale in late 2002. NAEC's proceeds will be used to
repay all $90 million of NAEC's outstanding debt and return all NAEC's equity,
which totaled $35 million as of December 31, 2001, to NU. Following the sale of
NAEC's share of Seabrook, the Seabrook Power Contracts will be terminated. PSNH
will use these proceeds to more quickly amortize stranded costs.
On October 10, 2000, NU reached an agreement with an unaffiliated joint
owner of Seabrook under which that joint owner would include its aggregate 15
percent ownership share of Seabrook in the upcoming sale. Under the terms of
the agreement, in the event that the sale yields proceeds for that joint owner
of more than $87.2 million, NU and that joint owner would share the excess
proceeds. Should those sales proceeds be less than $87.2 million, NU would make
up the difference below that amount up to a maximum of $17.4 million. The
agreement also limits any top-off amount required to be funded by that joint
owner for decommissioning as part of the sale process at the amount required by
the Nuclear Regulatory Commission (NRC) regulations.
Massachusetts: Unlike Connecticut, Massachusetts has experienced a continued
expansion in the number of customers securing their electric supply through
competitive suppliers. In January 2001, WMECO instituted approximately a 17
percent overall rate increase for its customers taking standard offer service.
The increase reflected a sharp increase, from approximately $0.045 per kWh to
approximately $0.073 per kWh, in prices paid to third-party suppliers during
2001. In December 2001, however, the Massachusetts Department of
Telecommunications and Energy approved approximately a 14 percent reduction in
WMECO's overall rates for standard offer service customers, primarily
reflecting a reduction in WMECO's standard offer service supply costs in 2002
to approximately $0.048 per kWh. The significant reduction in supply costs in
2002 will result in a material reduction in WMECO's operating revenues and
purchased power costs in 2002, but should not have a significant impact on
financial performance since electric supply costs are passed through to
customers.
For further information regarding commitments and contingencies related to
restructuring, see Note 7A, "Commitments and Contingencies - Restructuring,"
to the consolidated financial statements.
REGIONAL TRANSMISSION ORGANIZATION
The Federal Energy Regulatory Commission (FERC) has required all transmission
owning utilities to voluntarily start forming regional transmission
organizations (RTO) or to state why this process has not begun. In July 2001,
the FERC stated that the three existing Northeastern Independent System
Operators (ISO) (PJM, New York and New England) should work together to form
one RTO. The FERC initiated a mediation effort between all interested parties
to begin the process of forming such an entity.
NU has been discussing with the other transmission owners in the three pool
area the potential to form an Independent Transmission Company (ITC). The ITC
would be a for-profit entity and would perform certain transmission functions
required by the FERC including tariff control, system planning and system
operations. The remaining functions required by the FERC would be performed by
the ISO and deal with the energy market and short-term reliability. Together,
the ITC and ISO form the FERC desired RTO.
In January 2002, the New York and New England ISOs announced their intention
to form an RTO. NU is working with the other transmission owners in these two
power pools to create an ITC. The agreements needed to create the ITC and to
define the working relationships among the ISO, the ITC and the transmission
owners should be created in 2002 and will allow the ITC to begin operation
shortly thereafter. The ITC and/or ISO will have the responsibility to collect
the revenue requirements of each transmission owning entity from the market
place through FERC approved tariffs. The creation of the ITC and/or RTO will
require a FERC rate case and the impact on NU's return on equity as a result of
this rate case cannot be estimated at this time.
NUCLEAR PLANT PERFORMANCE AND OTHER MATTERS
Seabrook: Seabrook operated at a capacity factor of 85.9 percent in 2001. After
returning from a scheduled refueling outage in January 2001, Seabrook operated
at a capacity factor of 93.4 percent. Seabrook is scheduled to undergo a
refueling outage in the spring of 2002. The NU system companies own 40.04
percent of Seabrook.
Yankee Companies: In August 2001, Vermont Yankee Nuclear Power Corporation
announced it would sell the unit to an unaffiliated company for $180 million,
including $145 million for the plant and materials and supplies and $35 million
for the nuclear fuel. NU subsidiaries own 16 percent of the unit, and under the
terms of the sale, will continue to buy 16 percent of the plant's output
through March 2012 at a range of fixed prices. The sale requires several
regulatory approvals and is scheduled to close during the first half of 2002.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of
Millstone 1 and 2 to DNCI. Additionally, CL&P, PSNH and WMECO sold their
ownership interests in Millstone 3 to DNCI. On October 5, 2001, NU issued a
report, following an extensive search, concerning two missing fuel pins at the
retired Millstone 1 nuclear unit, which was sold to DNCI on March 31, 2001.
As of December 31, 2001, costs related to this search totaled $7.1 million.
The report concluded that the pins are currently located in one of four
facilities licensed to store low or high-level nuclear waste and that they are
not a threat to public health and safety. A follow-up review by the NRC
commenced shortly after the report was filed and resulted in a NRC sponsored
public meeting on January 15, 2002. In February 2002, the NRC issued a written
inspection report which concluded that NU's investigation was thorough and
complete, and that its conclusions were reasonable and supportable.
NUCLEAR DECOMMISSIONING
In connection with the aforementioned sale of the Millstone units, DNCI has
agreed to assume responsibility for decommissioning those units.
For further information regarding nuclear decommissioning, see Note 8,
"Nuclear Decommissioning and Plant Closure Costs," to the consolidated
financial statements.
SPENT NUCLEAR FUEL DISPOSAL COSTS
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel on January 31, 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 prior to divestiture of its remaining operating nuclear
units, Seabrook and Vermont Yankee, as well as the three nuclear units
currently undergoing decommissioning, Connecticut Yankee, Maine Yankee and
Yankee Rowe.
For further information regarding spent nuclear fuel disposal costs, see
Note 7C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the consolidated financial statements.
OTHER MATTERS
Critical Accounting Policies: The preparation of financial statements in
conformity with accounting principles generally accepted in the United States
requires management to make estimates, assumptions and at times difficult,
subjective or complex judgments. Accounting policies related to the
recoverability of certain regulatory assets, the performance of impairment
assessments of recorded goodwill and other long-lived assets, mark-to-market
accounting and the related treatment of derivative instruments and certain
trading and hedging activities, and the assumptions used in developing the
pension and postretirement benefit obligations are the accounting principles
that management believes are critical and could have a significant impact on
NU's consolidated financial statements.
Regulatory Assets: The accounting policies of the NU system's regulated
operating companies historically reflect the effects of the rate-making process
in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." Through their cost-of-service rate regulated transmission and
distribution businesses, CL&P, PSNH and WMECO are currently recovering their
investments in long-lived assets, including regulatory assets, and management
believes that the application of SFAS No. 71 to that portion of their
businesses continues to be appropriate. Management must reaffirm this
conclusion at each balance sheet date. If, as a result of a change in
circumstances, it is determined that any portion of these investments is no
longer recoverable under SFAS No. 71, that portion would be written off.
Such a write-off could have a material impact on NU's consolidated financial
statements. Management currently believes that all long-lived assets, including
regulatory assets, are recoverable.
Goodwill and Other Intangible Assets: Effective January 1, 2002, under SFAS
No. 142, "Goodwill and Other Intangible Assets," NU is required to perform at
least an annual assessment for impairment of goodwill by applying a fair
value-based test. Management is in the process of the first assessment of
impairment of goodwill and expects to complete this assessment by the June 30,
2002, deadline imposed by SFAS No. 142. Upon adoption of the impairment testing
rules under SFAS No. 142, there may be a cumulative effect of an accounting
change which management has not evaluated at this time.
Mark-To-Market Accounting: At each balance sheet date, NU's energy trading
positions are marked-to-market using closing exchange prices or quotes from
external sources. Market risk represents the risk of loss that may impact NU's
financial statements due to adverse changes in commodity market prices which
could affect the realizability of the positive mark-to-market position of $44.4
million at December 31, 2001.
Additionally, the mark-to-market position for certain effective hedging
activities is currently included in other comprehensive income. If it is
determined that these hedging activities are no longer effective, as defined in
SFAS No. 133, this mark-to-market position would be included currently in
earnings. This mark-to-market position was a negative $36.9 million at
December 31, 2001, net of tax (decrease to equity).
Pension and Postretirement Benefit Obligations: The NU system companies
participate in a uniform noncontributory defined benefit retirement plan
covering substantially all regular NU system employees and also provide certain
health care benefits, primarily medical and dental, and life insurance benefits
through a benefit plan to retired employees. For each of these plans, the
development of the benefit obligation, fair value of plan assets, funded status
and net periodic benefit credit or cost is based on several significant
assumptions. These assumptions primarily relate to the application of a
discount rate, expected long-term rate of return and other trend rates. If
these assumptions were changed, the resultant change in benefit obligations,
fair values of plan assets, funded status and net periodic benefit credits or
costs could have a material impact on NU's consolidated financial statements.
For further information regarding these types of activities, see Note 1G,
"Regulatory Accounting and Assets," Note 1C, "New Accounting Standards,"
Note 9, "Market Risk and Risk Management Instruments," and Note 4, "Employee
Benefits," to the consolidated financial statements.
Environmental Matters: The NU system 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 7B, "Commitments and Contingencies -
Environmental Matters," to the consolidated financial statements.
Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 7, "Commitments and Contingencies," to
the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Aggregated information
regarding the NU system's contractual obligations and commercial commitments as
of December 31, 2001, is summarized as follows:
- ---------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2003 2004 2005 2006 Totals
- ---------------------------------------------------------------------------------------------------------------------
Notes payable to banks $ 290.5 $ -- $ -- $ -- $ -- $ 290.5
Long-term debt 50.5 318.6 58.5 86.6 24.3 538.5
Capital leases 3.1 3.1 3.0 2.8 2.7 14.7
Operating leases 23.7 18.4 15.5 13.3 11.1 82.0
Long-term contractual obligations 442.1 450.8 459.3 462.2 411.9 2,226.3
Select Energy purchase agreements 2,416.2 836.2 145.9 95.7 34.8 3,528.8
- ---------------------------------------------------------------------------------------------------------------------
Totals $3,226.1 $1,627.1 $ 682.2 $ 660.6 $ 484.8 $6,680.8
=====================================================================================================================
For further information regarding NU's contractual obligations and
commercial commitments, see the Consolidated Statements of Capitalization
and related footnotes, and Note 2, "Short-Term Debt," Note 3, "Leases," and
Note 7E, "Long-Term Contractual Arrangements," to the consolidated financial
statements.
Forward Looking Statements: This discussion and analysis includes forward
looking statements, which are statements of future expectations and not facts
including, but not limited to, statements regarding future earnings,
refinancings, the use of proceeds from restructuring, and the recovery of
operating costs. 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 2001 over/(under) 2000 2000 over/(under) 1999
------------------------- --------------------------
(Millions of Dollars) Amount Percent Amount Percent
- -----------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 997 17% $1,405 31%
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel, purchased and net interchange power 1,237 37 1,406 74
Other operation (93) (11) 11 1
Maintenance 3 1 (85) (25)
Depreciation (39) (16) (62) (21)
Amortization of regulatory assets, net 706 (a) (320) (54)
Taxes other than income taxes (19) (8) (23) (9)
Gain on sale of utility plant (642) (100) 309 100
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,153 22 1,236 31
- -----------------------------------------------------------------------------------------------------------------------
Operating Income (156) (22) 169 32
Other income (loss), net 202 (a) 92 87
Interest expense, net (19) (7) 36 14
- -----------------------------------------------------------------------------------------------------------------------
Income before income tax expense 65 17 225 (a)
Income tax expense 12 7 63 64
Preferred dividends of subsidiaries (7) (47) (9) (38)
- -----------------------------------------------------------------------------------------------------------------------
Income before extraordinary loss and cumulative effect of
accounting change 60 30 171 (a)
Extraordinary loss, net of tax benefit 234 100 (234) 100
Cumulative effect of accounting change, net of tax benefit (22) 100 -- --
- -----------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 272 (a) $ (63) (a)
=======================================================================================================================
(a) Percent greater than 100.
OPERATING REVENUES
Total revenues increased by $997 million or 17 percent in the year 2001,
compared with the year 2000, primarily due to higher revenues from the
competitive energy subsidiaries ($1,069 million which reflects eliminations of
sales to other NU affiliates), higher revenues from Yankee Gas ($127 million)
and higher regulated retail electric revenues ($33 million), partially offset
by lower wholesale regulated revenues ($190 million) and lower transmission
revenues ($26 million). The competitive energy subsidiaries' increase is
primarily due to higher revenues from Select Energy as a result of new
contracts for energy services. The Yankee Gas increase is primarily due to a
full year of revenue in 2001 versus ten months post merger in 2000. The
regulated retail increase is primarily due to a 1.7 percent increase in sales
($41 million), the increase in WMECO's standard offer service rate ($59
million) and the recovery of previously deferred fuel costs for CL&P ($19
million), partially offset by the 5 and 11 percent rate decreases for PSNH that
were effective October 1, 2000 and May 1, 2001, respectively ($89 million).
Wholesale revenues were lower primarily due to the sale of Millstone at the end
of the first quarter of 2001.
Total revenues increased by $1,405 million or 31 percent in 2000, primarily
due to higher revenues from the competitive energy subsidiaries ($1,246 million
of which $669 million represents sales to other NU affiliates which are
eliminated in consolidation), the acquisition of Yankee ($262 million) and
higher regulated wholesale revenues ($727 million of which $281 million
represents sales to other NU affiliates which are eliminated in consolidation),
partially offset by lower regulated retail revenues ($26 million). The
competitive energy subsidiaries' increase is primarily due to higher revenues
from Select Energy as a result of new contracts for energy sales and services.
The regulated wholesale revenue increase is primarily due to higher PSNH energy
sales and higher CL&P and WMECO revenue from the sale of the output from
Millstone 2 and 3. The regulated retail decrease is primarily due to retail
rate reductions for CL&P and PSNH ($108 and $8 million, respectively),
partially offset by the impact of Millstone 2 being returned to CL&P's rate
base ($33 million), higher retail sales ($18 million), higher fuel revenues
for PSNH ($15 million), and higher retail revenue attributed to lower price
discounts in 2000 and changing customer mix ($24 million). Regulated retail kWh
sales increased by 0.8 percent in 2000.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 2001, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($1,252 million which reflects eliminations of purchases from
other NU affiliates), higher expense for Yankee primarily due to a full year in
2001 and higher gas prices ($83 million), and higher expense for WMECO
primarily due to the increased cost of the standard offer supply ($70 million),
partially offset by lower wholesale cost for CL&P and PSNH ($173 million, net
of eliminations).
Fuel, purchased and net interchange power expense increased in 2000,
primarily due to higher purchased energy and capacity costs as a result of
higher sales for Select Energy ($1,036 million of which $660 million represents
purchases from other NU affiliates which are eliminated in consolidation),
Yankee expenses ($135 million) and higher purchased power for regulated
subsidiaries ($235 million).
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance (O&M) expenses decreased $90 million in 2001,
primarily due to lower nuclear expenses ($133 million) as a result of the sale
of the Millstone units at the end of the first quarter of 2001, partially
offset by higher O&M expenses for the competitive energy subsidiaries,
primarily due to the acquisition of Boulos ($49 million).
Other O&M expenses decreased $74 million in 2000, primarily due to lower
spending at the nuclear units due to better performance ($75 million), lower
expenses due to the sale of certain CL&P and WMECO fossil and hydroelectric
generation assets ($74 million), lower corporate support ($38 million), the
decommissioning status of Millstone 1 ($17 million), lower environmental-
related costs ($12 million) and 1999 expenses associated with the Con Edison
merger ($12 million), partially offset by the addition of Yankee ($60 million),
higher O&M expenses for the unregulated businesses ($84 million), primarily
due to the business expansion, and higher distribution expenses ($29 million),
including increased conservation program expenses.
DEPRECIATION
Depreciation expense decreased $39 million in 2001, primarily due to the
elimination of decommissioning expenses as a result of the sale of the
Millstone units at the end of the first quarter of 2001 ($25 million) and
the buydown of the Seabrook Power Contracts ($14 million).
Depreciation decreased $62 million in 2000, primarily due to the effect of
discontinuing SFAS No. 71 for the portion of the generation business for CL&P
and WMECO and the resulting reclassification of depreciable nuclear plant
balances to regulatory assets ($84 million) and the sale of certain CL&P and
WMECO fossil and hydroelectric generation assets, partially offset by the
addition of Yankee ($23 million).
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 2001, primarily due to the
amortization in 2001 related to the gain on sale of the Millstone units by CL&P
and WMECO ($641 million) and higher amortization related to restructuring.
Amortization of regulatory assets, net decreased in 2000, primarily due to
the amortization in 1999 of the gain on sale of fossil and hydroelectric
generation assets for WMECO and CL&P ($309 million), and changes in
amortization levels as a result of industry restructuring ($95 million). These
decreases were partially offset by higher amortization associated with the
reclassified nuclear plant balances ($84 million).
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes decreased in 2001, primarily due to settlement of
a property tax appeal with the City of Meriden for CL&P and Yankee in 2001 ($15
million), the reduction in property tax for CL&P and WMECO due to the sale of
the Millstone units ($16 million) and lower New Hampshire franchise tax ($5
million), partially offset by higher Connecticut gross earnings taxes ($14
million) on higher CL&P revenues.
Taxes other than income taxes decreased in 2000, primarily due to lower
Connecticut gross earnings taxes ($12 million) and lower payroll taxes ($7
million).
GAIN ON SALE OF UTILITY PLANT
NU recorded gains on the sale of CL&P's and WMECO's ownership interests in
Millstone. A corresponding amount of amortization expense was recorded in 2001.
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.
OTHER INCOME/(LOSS), NET
Other income/(loss), net increased primarily due to NU's recognition in 2001 of
a gain in connection with the sale of the Millstone nuclear units to DNCI (the
pretax amount of $189 million is included in other income with an offsetting
income tax expense impact of $73 million), lower nuclear related costs in 2001
($18 million), lower environmental reserve expense in 2001 ($10 million), and
higher interest and dividend income ($20 million), partially offset by the
charge related to the forward purchase of 10.1 million NU common shares ($35
million).
Other income/(loss), net increased in 2000, primarily due to lower nuclear
related costs in 2000 ($53 million), a one-time gain related to the company's
investment in NEON of Mode 1 ($17 million), and the loss in 1999 on the CL&P
assignment of market-based contracts to Select Energy ($15 million).
INTEREST EXPENSE, NET
Interest expense, net decreased in 2001, primarily due to reacquisitions and
retirements of long-term debt ($54 million) and higher short-term borrowings in
2000 associated with asset transfers and the Yankee merger ($54 million),
partially offset by the interest expense associated with the issuance of rate
reduction bonds and certificates in 2001 ($88 million).
Interest expense, net increased in 2000, primarily due to higher short-term
borrowings associated with the NGC asset transfer and the Yankee merger,
partially offset by lower long-term debt as a result of reacquisitions and
retirements.
INCOME TAX EXPENSE
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 combined increased in 2001, primarily due to
higher taxable income. The increase in income taxes as a result of higher
taxable income was partially offset by a reduction in income taxes as a result
of the favorable resolution of certain tax contingencies. For further
information regarding income taxes, see the Consolidated Statements of Income
Taxes.
Federal and state income tax expense increased approximately $63 million in
2000. Significant variances responsible for this increase include higher pretax
earnings ($90 million) and lower adjustments to the tax valuation allowance
($21 million). Reduction in flow-through depreciation and amortization ($51
million) partially offset the overall change.
PREFERRED DIVIDENDS OF SUBSIDIARIES
Preferred dividends decreased in 1999, 2000, and 2001 primarily due to lower
preferred stock outstanding.
EXTRAORDINARY LOSS, NET OF TAX BENEFIT
The extraordinary loss, net of tax benefit, is primarily due to an after-tax
write-off by PSNH of approximately $225 million of stranded costs under an
industry restructuring settlement with the state of New Hampshire, combined
with other positive effects on PSNH from the discontinuance of SFAS No. 71 ($11
million) and a loss associated with the then pending sale of certain HWP assets
($20 million).
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX BENEFIT
The cumulative effect of accounting change, net of tax benefit, recorded in
2001, represents the effect of the adoption of SFAS No. 133 ($22 million).
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 accounting principles generally accepted in
the United States using estimates and judgments, 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
independent 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, 2001 and 2000, 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,
2001. 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 auditing standards generally
accepted in the United States. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 1C to the consolidated financial statements, effective
January 1, 2001, the company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended.
/s/ ARTHUR ANDERSEN LLP
-------------------
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 22, 2002
CONSOLIDATED STATEMENTS OF INCOME
- ------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $6,873,826 $5,876,620 $4,471,251
- -------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Operation --
Fuel, purchased and net interchange power 4,541,342 3,303,995 1,898,314
Other 773,058 866,742 855,917
Maintenance 258,961 255,884 340,419
Depreciation 201,013 239,798 302,305
Amortization of regulatory assets, net 983,037 276,821 596,437
Taxes other than income taxes 219,197 238,587 261,353
Gain on sale of utility plant (641,956) -- (308,914)
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 6,334,652 5,181,827 3,945,831
- -------------------------------------------------------------------------------------------------------------------
Operating Income 539,174 694,793 525,420
Other Income/(Loss), Net 187,627 (14,309) (106,187)
- -------------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Tax Expense 726,801 680,484 419,233
- -------------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE:
Interest on long-term debt 147,049 200,697 258,093
Interest on rate reduction bonds 87,616 -- --
Other interest 44,993 98,605 5,558
- -------------------------------------------------------------------------------------------------------------------
Interest expense, net 279,658 299,302 263,651
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Tax Expense 447,143 381,182 155,582
Income Tax Expense 173,952 161,725 98,611
- -------------------------------------------------------------------------------------------------------------------
Income Before Preferred Dividends of Subsidiaries 273,191 219,457 56,971
Preferred Dividends of Subsidiaries 7,249 14,162 22,755
- -------------------------------------------------------------------------------------------------------------------
Income before extraordinary loss and cumulative effect of accounting
change, net of tax benefits 265,942 205,295 34,216
Extraordinary loss, net of tax benefit of $169,562 -- (233,881) --
Cumulative effect of accounting change, net of tax benefit of $14,908 (22,432) -- --
- -------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $243,510 $(28,586) $34,216
===================================================================================================================
BASIC EARNINGS/(LOSS) PER COMMON SHARE:
Income before extraordinary loss and cumulative effect of accounting
change, net of tax benefits $1.97 $1.45 $0.26
Extraordinary loss, net of tax benefit -- (1.65) --
Cumulative effect of accounting change, net of tax benefit (0.17) -- --
- -------------------------------------------------------------------------------------------------------------------
Basic Earnings/(Loss) Per Common Share $1.80 $(0.20) $0.26
===================================================================================================================
FULLY DILUTED EARNINGS/(LOSS) PER COMMON SHARE:
Income before extraordinary loss and cumulative effect of accounting
change, net of tax benefits $1.96 $1.45 $0.26
Extraordinary loss, net of tax benefit -- (1.65) --
Cumulative effect of accounting change, net of tax benefit (0.17) -- --
- -------------------------------------------------------------------------------------------------------------------
Fully Diluted Earnings/(Loss) Per Common Share $1.79 $(0.20) $0.26
===================================================================================================================
Basic Common Shares Outstanding (average) 135,632,126 141,549,860 131,415,126
===================================================================================================================
Fully Diluted Common Shares Outstanding (average) 135,917,423 141,967,216 132,031,573
===================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- -------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2001 2000 1999
- -------------------------------------------------------------------------------------------------------
NET INCOME/(LOSS) $243,510 $(28,586) $34,216
- -------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE (LOSS)/INCOME, NET OF TAX:
Qualified cash flow hedging instruments (36,859) -- --
Unrealized gains on securities 2,620 245 118
Foreign currency translation adjustments -- -- 1
- -------------------------------------------------------------------------------------------------------
Other comprehensive (loss)/income, net of tax (34,239) 245 119
- -------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME/(LOSS) $209,271 $(28,341) $34,335
=======================================================================================================
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 96,658 $ 200,017
Investments in securitizable assets 36,367 98,146
Receivables, less accumulated provision for uncollectible accounts
of $16,353 in 2001 and $12,500 in 2000 831,221 472,863
Unbilled revenues 126,398 121,090
Fuel, materials and supplies, at average cost 108,516 163,711
Special deposits 60,261 2,624
Prepayments and other 126,233 91,904
- ------------------------------------------------------------------------------------------------------------------------
1,385,654 1,150,355
- ------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT:
Electric utility 5,743,575 9,003,298
Gas utility 634,884 608,153
Competitive energy 344,063 409,035
Other 195,741 211,417
- ------------------------------------------------------------------------------------------------------------------------
6,918,263 10,231,903
Less: Accumulated provision for depreciation 3,418,577 7,041,279
- ------------------------------------------------------------------------------------------------------------------------
3,499,686 3,190,624
Construction work in progress 289,889 228,330
Nuclear fuel, net 32,564 128,261
- ------------------------------------------------------------------------------------------------------------------------
3,822,139 3,547,215
- ------------------------------------------------------------------------------------------------------------------------
DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets 3,950,445 3,910,801
Goodwill and other purchased intangible assets, net 322,600 324,389
Prepaid pension 232,398 139,546
Nuclear decommissioning trusts, at market 61,713 740,058
Other 466,460 404,785
- ------------------------------------------------------------------------------------------------------------------------
5,033,616 5,519,579
- ------------------------------------------------------------------------------------------------------------------------
Total Assets $10,241,409 $ 10,217,149
========================================================================================================================
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Notes payable to banks $ 290,500 $ 1,309,977
Long-term debt and preferred stock - current portion 50,462 340,041
Accounts payable 669,545 538,983
Accrued taxes 26,203 54,088
Accrued interest 35,659 41,131
Other 178,071 304,810
- -----------------------------------------------------------------------------------------------------------------------------------
1,250,440 2,589,030
- -----------------------------------------------------------------------------------------------------------------------------------
Rate Reduction Bonds 2,018,351 --
- -----------------------------------------------------------------------------------------------------------------------------------
Minority Interest in Consolidated Subsidiary -- 100,000
- -----------------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes 1,491,394 1,585,494
Accumulated deferred investment tax credits 120,071 153,155
Decommissioning obligation - Millstone 1 -- 692,560
Deferred contractual obligations 216,566 244,608
Other 618,191 452,926
- -----------------------------------------------------------------------------------------------------------------------------------
2,446,222 3,128,743
- -----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Long-Term Debt 2,292,556 2,029,593
- -----------------------------------------------------------------------------------------------------------------------------------
Preferred Stock 116,200 151,200
- -----------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREHOLDERS' EQUITY:
Common shares, $5 par value - authorized 225,000,000 shares; 148,890,640
shares issued and 130,132,136 shares outstanding in 2001 and 148,781,861
shares issued and 143,820,405 shares
outstanding in 2000 744,453 693,345
Capital surplus, paid in 1,107,609 942,144
Temporary equity from stock forward -- 215,000
Deferred contribution plan - employee stock ownership plan (101,809) (114,463)
Retained earnings 678,460 495,873
Accumulated other comprehensive (loss)/income (32,470) 1,769
Treasury stock (278,603) (15,085)
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity 2,117,640 2,218,583
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization 4,526,396 4,399,376
- -----------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTE 7)
Total Liabilities and Capitalization $10,241,409 $10,217,149
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- -----------------------------------------------------------------------------------------------------------------------------------
Capital Accumulated
Common Surplus, Deferred Retained Other
Shares Paid In Contribution Earnings Comprehensive Treasury
(Thousands of Dollars) (a) (a) Plan -- ESOP (b) Income/(Loss) Stock Total
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1999 $685,156 $ 941,960 $(140,619) $560,769 $ 1,405 $ (1,299) $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 686,969 942,025 (127,725) 581,817 1,524 (1,299) 2,083,311
- -----------------------------------------------------------------------------------------------------------------------------------
Net loss for 2000 (28,586) (28,586)
Cash dividends on common
shares-$0.40 per share (57,358) (57,358)
Issuance of 11,388,032 common
shares, $5 par value 56,940 164,443 221,383
Transaction fee on forward
share purchase arrangement (13,786) (13,786)
Allocation of benefits-ESOP (1,617) 13,262 11,645
Redemption of
preferred stock (749) (749)
Capital stock expenses, net 2,478 2,478
Other comprehensive income 245 245
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2000 743,909 1,106,580 (114,463) 495,873 1,769 (15,085) 2,218,583
- -----------------------------------------------------------------------------------------------------------------------------------
Net income for 2001 243,510 243,510
Cash dividends on common
shares-$0.45 per share (60,923) (60,923)
Issuance of 108,779 common
shares, $5 par value 544 1,207 1,751
Transaction fee on forward
share purchase arrangement (1,663) (1,663)
Allocation of benefits-ESOP (2,296) 12,654 10,358
Repurchase of common shares (291,789) (291,789)
Mark-to-market on forward
share purchase arrangement 29,934 29,934
Capital stock expenses, net 2,118 2,118
Other comprehensive loss (34,239) (34,239)
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 2001 $744,453 $1,107,609 $(101,809) $678,460 $(32,470) $(278,603) $2,117,640
- -----------------------------------------------------------------------------------------------------------------------------------
(a) In conjunction with NU's forward share purchase arrangement, 10,112,879
shares or $50.6 million and $164.4 million, respectively, were reclassified
from Common Shares and Capital Surplus, Paid In, at December 31, 2000 and 1999,
to Temporary Equity from Stock Forward.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount of
retained earnings available for NU common dividends. At December 31, 2001,
retained earnings available for payment of dividends totaled $267.5 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) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES:
Income before preferred dividends of subsidiaries $ 273,191 $ 219,457 $ 56,971
Adjustments to reconcile to net cash flows provided by operating activities:
Depreciation 201,013 239,798 302,305
Deferred income taxes and investment tax credits, net (116,704) (16,117) (183,356)
Amortization of regulatory assets, net 983,037 276,821 596,437
Gain on sale of utility plant (641,956) -- (308,914)
Cumulative effect of accounting change (22,432) -- --
Net other (uses)/sources of cash (80,362) (101,927) 36,360
Changes in working capital:
Receivables and unbilled revenues, net (356,863) (104,868) (106,566)
Fuel, materials and supplies 55,195 12,450 29,688
Accounts payable 130,562 171,148 8,709
Accrued taxes (27,885) (128,107) 107,929
Investments in securitizable assets 61,779 9,474 74,498
Other working capital (excludes cash) (81,837) 254 157
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 376,738 578,383 614,218
- -----------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES:
Investments in regulated plant:
Electric, gas and other utility plant (428,312) (345,596) (278,726)
Nuclear fuel (14,275) (61,286) (42,471)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments in regulated plant (442,587) (406,882) (321,197)
Investments in nuclear decommissioning trusts (105,076) (39,550) (74,231)
Investments in competitive energy assets (15,368) (7,140) (31,897)
Other investment activities, net (51,677) (28,478) 13,084
Net proceeds from the sale of utility plant 1,048,636 -- 565,436
Buyout/buydown of IPP contracts (1,176,872) -- --
Payment for the purchase of SENY, net of cash acquired (25,823) -- --
Payment for the purchase of Yankee, net of cash acquired -- (260,347) --
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows (used in)/provided by investing activities (768,767) (742,397) 151,195
- -----------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES:
Issuance of common shares 1,751 4,269 5,318
Repurchase of common shares (291,789) -- --
Issuance of long-term debt 703,000 26,477 200
Issuance of rate reduction bonds 2,118,400 -- --
Retirement of rate reduction bonds (100,049) -- --
Net (decrease)/increase in short-term debt (1,019,477) 961,977 248,000
Reacquisitions and retirements of long-term debt (714,226) (685,555) (817,759)
Reacquisitions and retirements of preferred stock (60,768) (126,771) (46,250)
Retirement of monthly income preferred securities (100,000) -- --
Retirement of capital lease obligation (180,000) -- --
Cash dividends on preferred stock (7,249) (14,162) (22,755)
Cash dividends on common shares (60,923) (57,358) (13,168)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by/(used in) financing activities 288,670 108,877 (646,414)
- -----------------------------------------------------------------------------------------------------------------------------------
Net (decrease)/increase in cash and cash equivalents (103,359) (55,137) 118,999
Cash and cash equivalents - beginning of year 200,017 255,154 136,155
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 96,658 $200,017 $255,154
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREHOLDERS' EQUITY (a) $ 2,117,640 $ 2,218,583
- -----------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value - authorized 36,600,000 shares at December 31, 2001 and 2000; no
shares outstanding in 2001 and 1,630,722 shares outstanding in 2000
$50 par value - authorized 9,000,000 shares at December 31, 2001 and 2000;
2,324,000 shares outstanding in 2001 and 2000
$100 par value - authorized 1,000,000 shares at December 31, 2001 and 2000;
no shares outstanding in 2001 and 200,000 shares outstanding in 2000
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------------------
Current Redemption Current Shares
Dividend Rates Prices Outstanding 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
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 -- -- -- 20,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory
Redemption 116,200 136,200
- -----------------------------------------------------------------------------------------------------------------------------------
SUBJECT TO MANDATORY REDEMPTION:
$25 par value - $1.90 to $2.65 -- -- -- 40,768
- -----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption -- -- 40,768
Less: Preferred Stock to Be Redeemed Within One Year -- -- 25,768
- -----------------------------------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption, Net -- -- 15,000
- -----------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT: (b)
First Mortgage Bonds -
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------------------------
Maturity Interest Rates 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
2001 7.375% to 7.875% -- 220,000
2002 9.05% -- 375,000
2005 4.998% to 6.75% 140,000 20,000
2009-2012 6.20% to 7.19% 80,000 80,000
2019-2024 7.875% to 10.07% 255,945 313,050
2026 8.81% 320,000 --
- -----------------------------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 795,945 1,008,050
- -----------------------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt -
Pollution Control Notes and
Other Notes - (c)
2003-2006 Adjustable Rate and 6.24% to 8.58% 381,500 139,600
2013-2018 Adjustable Rate and 5.90% 25,400 33,400
2020 Adjustable Rate -- 15,300
2021-2022 Adjustable Rate and 5.45% to 7.65% 428,285 443,285
2028 5.85% to 5.95% 369,300 369,300
2031 Adjustable Rate 62,000 62,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total Pollution Control Notes
and Other Notes 1,266,485 1,062,885
Fees and interest due for spent
nuclear fuel disposal costs 249,314 240,303
Other 36,257 38,978
- -----------------------------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt 1,552,056 1,342,166
- -----------------------------------------------------------------------------------------------------------------------------------
Unamortized Premium and Discount, Net (4,983) (6,350)
- -----------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 2,343,018 2,343,866
Less: Amounts due within one year 50,462 314,273
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, Net 2,292,556 2,029,593
- -----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION $4,526,396 $4,399,376
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) On January 2, 2001, NU modified its forward share purchase arrangements for
NU common shares. To initially effect these arrangements, the financial
institutions (counterparties) purchased approximately 10.1 million NU common
shares on the open market in December 1999 and January 2000, in a total
aggregate amount of $215 million, at an average price of $21.26. The
counterparties maintained ownership of the shares until the transactions were
settled. NU accrued charges on the total aggregate amount at LIBOR plus an
agreed upon percentage per annum, until the transactions were settled. These
transactions could have been settled in cash or NU common shares at the
company's discretion. NU repurchased the shares from the counterparties in
April 2001 with the proceeds from restructuring. This amount has been
classified as temporary equity from stock forward on NU's consolidated balance
sheets at December 31, 2000.
(b) 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, 2001, for the years 2002 through 2006 are $50.5
million, $318.6 million, $58.5 million, $86.6 million, and $24.3 million,
respectively.
Essentially all utility plant of CL&P, PSNH, NGC, and Yankee is subject to
the liens of each company's respective first mortgage bond indenture.
CL&P has $315.5 million of pollution control notes secured by second
mortgage liens on transmission assets, junior to the liens of their first
mortgage bond indentures.
CL&P has $62 million of tax-exempt PCRBs with bond insurance secured by the
first mortgage bonds and a liquidity facility. For financial reporting
purposes, these first mortgage bonds would not be considered outstanding
unless CL&P failed to meet its obligations under the PCRBs.
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire. Pursuant to which the BFA issued five
series of PCRBs and loaned the proceeds to PSNH. At December 31, 2001 and 2000,
$407.3 million of the PCRBs were outstanding. PSNH's obligation to repay each
series of PCRBs is secured by bond insurance and 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 first
mortgage bonds would not be considered outstanding unless PSNH failed to meet
its obligations under the PCRBs.
(c) The average effective interest rate on the variable-rate pollution
control notes ranged from 1.2 percent to 3.8 percent for 2001 and 3.2 percent
to 6.8 percent for 2000.
Consolidated Statements of Income Taxes
- ---------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------------
The components of the federal and state income tax provisions
charged to the operations are:
Current income taxes:
Federal $ 244,501 $ 154,790 $ 248,012
State 46,155 23,052 33,955
- ---------------------------------------------------------------------------------------------------------------------------------
Total current 290,656 177,842 281,967
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (80,968) 7,297 (134,773)
State (15,644) (5,529) (28,789)
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred (96,612) 1,768 (163,562)
- ---------------------------------------------------------------------------------------------------------------------------------
Investment tax credits, net (20,092) (17,885) (19,794)
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $ 173,952 $ 161,725 $ 98,611
=================================================================================================================================
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
Deferred tax asset associated with net operating losses $ 2,206 $ 1,563 $ 14,801
Depreciation, leased nuclear fuel, settlement credits and disposal costs (185,850) 9,514 (4,580)
Regulatory deferral (33,187) (34,486) (27,297)
Regulatory disallowance 2,323 -- (30,719)
Sale of generation assets (225,019) -- (125,807)
Pension 24,183 25,751 8,936
Loss on bond redemptions 12,396 655 314
Securitized contract termination costs and other 279,673 -- --
Contract settlements 16,640 (4,442) (7,622)
Other 10,023 3,213 8,412
- ---------------------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES, NET $ (96,612) $ 1,768 $(163,562)
=================================================================================================================================
A reconciliation between income tax expense and the expected tax expense at
the statutory rate is as follows:
Expected federal income tax $ 156,500 $ 133,413 $ 54,454
Tax effect of differences:
Depreciation 5,313 2,882 24,583
Amortization of regulatory assets 5,748 16,835 45,825
Amortization of PSNH acquisition costs 4,512 9,946 9,946
Investment tax credit amortization (20,092) (17,885) (19,794)
State income taxes, net of federal benefit 19,832 11,390 3,358
Nondeductible stock expenses 12,388 -- --
Dividends received deduction (3,382) (8,618) (1,314)
Tax asset valuation allowance/reserve adjustments (7,000) (2,136) (23,129)
Merger-related expenditures (4,589) 5,829 4,597
Other, net 4,722 10,069 85
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $ 173,952 $ 161,725 $ 98,611
=================================================================================================================================
The accompanying notes are an 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 competitive
energy subsidiaries, NU strives to become the leading regional provider of
energy products and services, and one of the major energy traders in the
Northeast. 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 nuclear unit (Seabrook) 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 of electric power. A sixth wholly
owned subsidiary, Yankee Energy System, Inc. (Yankee), the parent company of
Yankee Gas Services Company (Yankee Gas), is Connecticut's largest natural gas
distribution system.
On November 30, 2001, Select Energy, Inc. (Select Energy) acquired
Niagara Mohawk Energy Marketing, Inc. (NMEM) for $31.7 million. Assuming Select
Energy and NMEM had been combined as of January 1, 2001, NU's operating
revenues, income before extraordinary loss and cumulative effect of accounting
change, net income, and total fully diluted earnings per share (EPS) would have
been $7.4 billion, $255.5 million, $245.8 million, and $1.81, respectively, for
the year ended December 31, 2001.
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. is a wholly owned subsidiary of NU and acts as
the holding company for certain of NU's competitive energy subsidiaries. These
subsidiaries include Select Energy Services, Inc. (SES), a provider of energy
management, demand-side management and related consulting services for
commercial, industrial and institutional electric companies and electric
utility companies; Northeast Generation Company (NGC), a corporation that
acquires and manages generation facilities; Northeast Generation Services
Company (NGS), a corporation that maintains and services any fossil or
hydroelectric facility that is acquired or contracted with for fossil or
hydroelectric generation services, and; Select Energy, a corporation engaged
in the marketing, transportation, storage, and sale of energy commodities, at
wholesale, in designated geographical areas and in the marketing of electricity
to retail customers.
Another subsidiary is Mode 1 Communications, Inc. (Mode 1), an
investor in a fiber-optic communications network.
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, engineering, financial, information resources, legal,
operational, planning, purchasing, and other services to the NU system
companies. 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.
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 accounting
principles generally accepted in the United States 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
Derivative Instruments: Effective January 1, 2001, NU adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. All derivative instruments
have been identified and recorded at fair value effective January 1, 2001. In
addition, for those derivative instruments which are hedging an identified
risk, NU has designated and documented all hedging relationships.
For those contracts that do not meet the hedging requirements, the
changes in fair value of those contracts were recognized currently in earnings.
As explained in Note 9, commodity derivatives that are utilized for trading
purposes are accounted for using the mark-to-market method, under Emerging
Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and
Risk Management Activities."
On June 27, 2001, the Financial Accounting Standards Board (FASB)
cleared SFAS No. 133 Implementation Issue No. C15, "Scope Exceptions: Normal
Purchases and Normal Sales Exception for Option-Type Contracts and Forward
Contracts in Electricity." Under Issue No. C15, power purchase or sales
agreements, including capacity contracts, for the purchase or sale of
electricity would qualify for the normal purchases and normal sales exception
provided that certain criteria are met. The company has reviewed its capacity
contracts and other applicable energy contracts and has determined that they
should not be marked-to-market under the criteria in the guidance cleared by
the FASB on June 27, 2001.
On December 19, 2001, the FASB issued revised guidance regarding power
purchase and sales agreements. The revised guidance is effective on July 1,
2002. Management is currently evaluating the impacts of the guidance issued by
the FASB on December 19, 2001, on its accounting for capacity contracts,
however, management does not expect it to have a material effect on its
consolidated financial statements.
Goodwill and Other Intangible Assets: In June 2001, the FASB issued
SFAS No. 142, "Goodwill and Other Intangible Assets." This statement requires
that goodwill and indefinite-lived intangible assets not be amortized effective
January 1, 2002. This statement also requires that goodwill will be subject to
at least an annual assessment for impairment by applying a fair value-based
test also effective January 1, 2002. Based on the goodwill and intangible
assets maintained by the NU system companies, management believes that upon
adoption of SFAS No. 142, annual goodwill amortization expense will be reduced
by $9 million. Management is in the process of the first assessment of
impairment of goodwill and expects to complete this assessment by the June 30,
2002, deadline. Upon adoption of the impairment testing rules under SFAS No.
142, there may be a cumulative effect of an accounting change which management
has not evaluated at this time.
Asset Retirement Obligations: Also in June 2001, the FASB issued SFAS
No. 143, "Accounting for Asset Retirement Obligations." This statement
addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset
retirement costs and applies to (a) all entities and (b) legal obligations
associated with the retirement of long-lived assets that result from the
acquisition, construction, development, and/or the normal operation of a
long-lived asset, except for certain obligations of lessees. SFAS No. 143 is
effective for NU's 2003 calendar year. Upon adoption of SFAS No. 143, there may
be an impact on NU's consolidated financial statements which management has not
estimated at this time.
Long-Lived Assets: In August 2001, the FASB issued SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." This
statement modifies financial accounting and reporting for the impairment or
disposal of long-lived assets. SFAS No. 144 is effective for NU's 2002
calendar year. Currently, management does not expect the adoption of SFAS
No. 144 to have a material impact on NU's consolidated financial statements.
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, 2001 and 2000, which are
accounted for on the equity method 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, 2001 and 2000, is $52.5 million and $62.5
million, respectively. Each Yankee Company owns a single nuclear generating
unit. However, VYNPC was the only unit still in operation at December 31, 2001.
Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook, a 1,148 megawatt 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 sell their joint ownership interests
in Seabrook around the end of 2002 through a public auction.
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 Dollar) 2001 2000
- ---------------------------------------------------------------------
Plant-in-service:
Millstone 2 $ -- $ 962.0
Millstone 3 -- 2,427.2
Seabrook 912.5 909.3
Accumulated provision for depreciation:
Millstone 2 $ -- $ 953.6
Millstone 3 -- 2,214.3
Seabrook 840.6 821.3
=====================================================================
Hydro-Quebec: NU has a 22.66 percent equity ownership interest,
totaling $13.6 million and $15 million at December 31, 2001 and 2000,
respectively, 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. Depreciation rates are
applied to plant-in-service 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 depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.1 percent in 2001
and 2000 and 3.3 percent in 1999.
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 in 1999, including CL&P's ownership interest in
Seabrook, NU recorded a charge to accumulated depreciation for the nuclear
plant in excess of the estimated fair market value at the time in the amount of
approximately $2 billion and a corresponding regulatory asset was created. In
2000, HWP discontinued SFAS No. 71 and recorded a charge to accumulated
depreciation for the plant in excess of fair value for certain hydroelectric
generation assets, which was recorded as an extraordinary loss. These assets
were sold in the fourth quarter of 2001.
F. Revenues
Regulated utility revenues are based on authorized rates applied to each
customer's use of energy. 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.
Revenues for NU's competitive energy subsidiaries, including Select
Energy and NGC, are recognized when the energy is delivered or service is
provided.
At the end of each accounting period, CL&P, PSNH, WMECO, Select
Energy, and Yankee Gas accrue a revenue estimate for the amount of energy
delivered but unbilled.
G. Regulatory Accounting and Assets
The accounting policies of the NU system regulated operating companies conform
to accounting principles generally accepted in the United States applicable to
rate-regulated enterprises and historically reflect the effects of the
rate-making process in accordance with SFAS No. 71.
CL&P's, PSNH's and WMECO's transmission and distribution businesses
continue to be cost-of-service rate regulated, and management believes the
application of SFAS No. 71 to that portion of those businesses continues to be
appropriate. Management also believes it is probable that the NU system
operating companies will recover their investments in long-lived assets,
including regulatory assets. These costs will be recovered over a period of
time ranging from 7 to 26 years, subject to certain adjustments. Stranded costs
for CL&P and WMECO will be recovered through a transition charge over a 12-year
period. PSNH has three categories of stranded costs. Part 1 costs are
securitized regulatory assets that are recovered over the life of the rate
reduction bonds. Part 2 costs are ongoing costs consisting of nuclear
decommissioning and independent power producer costs that are recovered as
incurred, over the time period PSNH is responsible for those costs. Part 3
costs are nonsecuritized regulatory assets which must be recovered by a
recovery end date to be determined in accordance with the "Agreement to
Settle PSNH Restructuring" (Settlement Agreement) or which will be written off
as stipulated by that Settlement Agreement. Based on current projections, PSNH
expects to fully recover all of its Part 3 costs by the recovery end date.
In March 2000, CL&P and WMECO completed the auction of certain
hydroelectric generation assets with a book value of $129 million. NGC was the
winning bidder in the auction and paid approximately $865.5 million for these
assets. Restructuring legislation in both Connecticut and Massachusetts
requires gains from the sale of generation to be used to reduce regulatory
assets and other stranded costs. Since the entities to the transaction are all
wholly owned by NU, a gain was not recognized. In connection with this
transaction, the remaining unamortized balance of the regulatory asset created
of $654.5 million will be recovered over the next 24 years. This regulatory
asset is not specifically earning a return in rates. Management continues to
evaluate the recovery of this regulatory asset for impairment and has concluded
the asset is not impaired at this time.
In addition, all other remaining 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) 2001 2000
- -------------------------------------------------------------------
Recoverable nuclear costs $ 894.5 $2,565.8
Securitized regulatory assets 2,004.1 --
Income taxes, net 312.8 504.7
Unrecovered contractual obligations 78.3 255.8
Recoverable energy costs, net 334.5 332.5
Other 326.2 252.0
- -------------------------------------------------------------------
Totals $3,950.4 $3,910.8
===================================================================
As a result of discontinuing the application of SFAS No. 71 for CL&P's
and WMECO's generation businesses, CL&P and WMECO had unamortized balances of
$1.35 billion and $286.9 million, respectively, included in recoverable nuclear
costs at December 31, 2000. These amounts were the result of reclassified
nuclear plant in excess of its estimated fair market value from plant to
regulatory assets, which took place in 1999. In March 2001, CL&P and WMECO sold
their ownership interests in the Millstone units. The gain on these sales in
the amount of approximately $521.6 million and $119.8 million, respectively,
for CL&P and WMECO were used to offset recoverable nuclear costs, resulting in
unamortized balances of $690.3 million and $130.7 million, respectively, after
the current year's amortization expense. Also included in that regulatory asset
component for 2001 and 2000 are $44.5 million and $449.2 million, respectively,
which includes Millstone 1 recoverable nuclear costs relating to the
recoverable portion of the undepreciated plant and related assets ($44.5
million and $90.8 million, respectively) and the decommissioning and closure
obligation ($358.4 million in 2000). Additionally, in March 2001, PSNH recorded
a regulatory asset in conjunction with the sale of the Millstone units. The
unamortized balance of $29 million as of December 31, 2001, is included in
recoverable nuclear costs.
In 2000, PSNH discontinued the application of SFAS No. 71 for its
generation business, and created a regulatory asset for Seabrook over market
generation, which was classified as recoverable nuclear costs. The unamortized
balance of the regulatory asset created was $484.7 million as of December 31,
2000. In April 2001, PSNH issued rate reduction bonds in the amount of $525
million. PSNH used the majority of this amount to buydown its power contracts
with NAEC. The Seabrook over market generation was securitized at that time and
was reclassified as a securitized regulatory asset as of December 31, 2001.
CL&P issued $1.4 billion in rate reduction certificates and used $1.1
billion of those proceeds to buyout or buydown certain contracts with
independent power producers. WMECO, issued rate reduction certificates in the
amount of $155 million in May of 2001 and used $99.7 million of those proceeds
to buyout two contracts with independent power producers. The majority of the
payments to buyout or buydown these contracts were recorded as securitized
regulatory assets. CL&P also securitized a portion of its SFAS No. 109
regulatory asset.
CL&P, WMECO and PSNH, under the terms of contracts with the Yankee
Companies, are responsible for their proportionate share of the remaining costs
of the units, including decommissioning. These amounts are recorded as
unrecovered contractual obligations. A portion of these obligations was
securitized in 2001 and is included in securitized regulatory assets.
CL&P, PSNH, WMECO, and NAEC, under the Energy Policy Act of 1992
(Energy Act), 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, 2001 and 2000, the NU system's total D&D Assessment
deferrals were $35.4 million and $34.5 million, respectively, and have been
recorded as recoverable energy costs, net.
In addition, 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. Coincident with the start of restructuring, the
energy adjustment clause was terminated. Energy costs deferred and not yet
collected under the energy adjustment clause amounted to $59 million and $61.1
million at December 31, 2001 and 2000, respectively, which have been recorded
as recoverable energy costs, net.
In conjunction with the implementation of restructuring under the
Settlement Agreement on May 1, 2001, the fuel and purchased-power adjustment
clause (FPPAC) was discontinued. At December 31, 2001 and 2000, PSNH had $251.4
million and $230.1 million, respectively, of recoverable energy costs deferred
under the FPPAC, including previous deferrals of purchases from independent
power producers. Under the Settlement Agreement, the FPPAC deferrals are
recovered as a Part 3 regulatory asset through a transition charge, subject to
a prudence determination by the New Hampshire Public Utilities Commission
(NHPUC).
H. 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) 2001 2000
- -------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $ 574.1 $ 756.0
Regulatory assets:
Nuclear stranded investment 328.4 608.9
Securitized contract termination
costs and other 279.7 --
Income tax gross-up 190.0 189.1
Other 119.2 31.5
- -------------------------------------------------------------------
Totals $1,491.4 $1,585.5
===================================================================
I. 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.
J. Accounting for Competitive Energy Contracts
The accounting treatment for energy contracts entered into by Select Energy
varies between contracts and depends primarily on the intended use of the
particular contract. Contracts that are entered into to provide the normal
purchase or sale of energy to customers are recorded at the point of delivery
in accordance with accrual accounting. Contracts that are entered into to
speculate in the commodity market are marked-to-market in accordance with EITF
Issue No. 98-10 and recognized currently in earnings. Contracts that hedge the
purchase or delivery of commodities are marked-to-market in accordance with
SFAS No. 133 and earnings are deferred in other comprehensive income until the
contracts are utilized.
K. Other Income/(Loss), Net
The components of the NU system companies' other income/(loss), net items are
as follows:
- ------------------------------------------------------------------------
For the Years Ended December 31,
- ------------------------------------------------------------------------
(Millions of Dollars) 2001 2000 1999
- ------------------------------------------------------------------------
Gain related to
Millstone sale $ 189.3 $ -- $ --
Loss on share repurchase
contracts (35.4) -- --
Other nuclear-related
costs -- (17.9) (71.1)
Other, net 33.7 3.6 (35.1)
- ------------------------------------------------------------------------
Totals $ 187.6 $ (14.3) $(106.2)
========================================================================
L. Supplemental Cash Flow Information
In conjunction with the Yankee acquisition on March 1, 2000, common stock was
issued and debt was assumed as follows (millions of dollars):
- ------------------------------------------------
Fair value of assets acquired,
net of liabilities assumed $712.5
Cash paid (261.4)
NU common stock issued (217.1)
- ------------------------------------------------
$234.0
================================================
- --------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------
(Millions of Dollars) 2001 2000 1999
- --------------------------------------------------------------------
Cash paid during the year for:
Interest, net of amounts
capitalized $ 275.3 $ 269.7 $ 266.8
Income taxes $ 321.0 $ 253.4 $ 86.2
====================================================================
Increase in obligations:
Niantic Bay Fuel Trust
and other capital
leases $ 2.2 $ 8.1 $ 5.9
====================================================================
2. 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. Currently, SEC
authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term
borrowings up to a maximum of $400 million, $375 million, $250 million, and
$100 million, respectively. In addition, the charter of CL&P contains preferred
stock provisions restricting the amount of unsecured debt that CL&P may incur.
As of December 31, 2001, CL&P's charter permits CL&P to incur $535 million of
additional unsecured debt. PSNH and NAEC are authorized by the NHPUC to incur
short-term borrowings up to a maximum of $100 million and $260 million,
respectively.
Credit Agreements:
Regulated Companies: On November 16, 2001, CL&P, PSNH, WMECO, and Yankee Gas
entered into a 364-day unsecured revolving credit facility for $350 million.
This facility replaced a $250 million facility for CL&P and WMECO and a $60
million facility for Yankee Gas, both of which expired on November 16, 2001.
CL&P may draw up to $150 million under the facility. PSNH, WMECO and Yankee Gas
each may draw up to $100 million, subject to the $350 million maximum borrowing
limit under the facility. Unless extended, the credit facility will expire on
November 15, 2002. At December 31, 2001 and 2000, there were $160.5 million and
$225 million, respectively, in borrowings under these facilities.
NU Parent: To support the working capital needs of NU and its
competitive energy subsidiaries, NU replaced its $400 million 364-day unsecured
revolving credit facility which was to expire on November 16, 2001, with a
364-day unsecured revolving credit facility on November 16, 2001. This facility
provides a total commitment of $300 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 $300 million are available for advances.
Second, subject to the advances outstanding, letters of credit may be issued in
notional amounts up to $200 million. Unless extended, this credit facility will
expire on November 15, 2002. At December 31, 2001 and 2000, there were $40
million and $173 million, respectively, in borrowings under these facilities.
With regard to credit support, NU had $45 million and $40 million,
respectively, in letters of credit issued under these facilities at
December 31, 2001 and 2000.
NAEC: On November 9, 2001, NAEC entered into an unsecured 364-day term
credit agreement for $90 million. This term credit agreement replaced a $200
million term credit agreement which expired on November 9, 2001. The term
credit agreement contains a mandatory prepayment provision requiring 100
percent prepayment of the aggregate amount outstanding within two days of the
sale of Seabrook. Unless extended, the term credit agreement will expire on
November 8, 2002. At December 31, 2001 and 2000, there were $90 million and
$200 million, respectively, in borrowings under these term credit agreements.
Under the aforementioned credit agreements, the respective borrowers
may borrow at fixed or variable rates plus an applicable margin based upon
certain debt ratings, as rated by the lower of Standard and Poor's or Moody's
Investors Service. The weighted average interest rate on the NU system
companies' notes payable to banks outstanding on December 31, 2001 and 2000,
was 3.38 percent and 8.85 percent, respectively.
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, consolidated debt ratios and interest coverage ratios. The
parties to the credit agreements currently are and expect to remain in
compliance with these covenants.
Guarantees: NU provides credit assurance in the form of guarantees and
letters of credit for the financial performance obligations of certain of its
competitive energy subsidiaries. NU currently has authorization from the SEC to
provide up to $500 million of guarantees, and has applied for authority to
increase this amount to $750 million. As of December 31, 2001, NU had provided
approximately $268.2 million and $45 million of such guarantees and letters of
credit, respectively.
3. Leases
The NU system companies 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 $13.1
million in 2001, $50.1 million in 2000, and $20.8 million in 1999. Interest
included in capital lease rental payments was $4.7 million in 2001, $11.6
million in 2000, and $13.7 million in 1999. Operating lease rental payments
charged to expense were $7 million in 2001, $10.1 million in 2000 and $7.5
million in 1999.
Future minimum rental payments excluding executory costs, such as
property taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, as of December 31, 2001 are as follows:
- ------------------------------------------------------------
(Millions of Dollars) Capital Operating
Year Leases Leases
- ------------------------------------------------------------
2002 $ 3.1 $ 23.7
2003 3.1 18.4
2004 3.0 15.5
2005 2.8 13.3
2006 2.7 11.1
After 2006 25.1 23.6
- ------------------------------------------------------------
Future minimum lease payments 39.8 $105.6
Less amount representing interest 22.3
- ------------------------------------------------------------
Present value of future
minimum lease payments $ 17.5
============================================================
4. 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 $191.7 million in
2001, $97.9 million in 2000, and $33.7 million in 1999.
In conjunction with the Voluntary Separation Program (VSP) that was
announced in December 2000, NU recorded $90.7 million in settlement and
curtailment gains in 2001. This amount is included in the $191.7 million in
pension credit recorded in 2001. The VSP was intended to reduce the
generation-related support staff between March 1, 2001, and February 28, 2002,
and was available to nonbargaining unit employees who, by February 1, 2002,
would be at least age 50, with a minimum of five years of credited service, and
as of December 15, 2000, were assigned to certain groups and in eligible job
classifications.
One component of the VSP included special termination benefits equal
to the greater of 5 years added to both age and credited service of eligible
participants or two weeks pay for each year of service subject to a minimum
level of 12 weeks and a maximum level of 52 weeks for eligible participants.
The special termination benefits associated with the VSP approximated $93.3
million. The net of the settlement and curtailment gains and the special
termination benefits was approximately $2.6 million, of which $7.5 million was
included in earnings, $5.1 million was deferred as a regulatory liability and
is expected to be returned to customers and $0.2 million was billed to the
joint owners of Millstone and Seabrook.
Currently, the NU system companies' policy is to 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 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
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.
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) 2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $(1,670.9) $(1,516.6) $ (335.3) $ (306.8)
Yankee merger -- (66.7) -- (9.9)
Service cost (35.7) (41.2) (6.2) (7.6)
Interest cost (119.7) (118.5) (27.2) (25.5)
Employee contribution -- -- -- (0.1)
Actuarial loss (72.2) (39.4) (76.2) (13.6)
Benefits paid 228.3 109.5 38.0 27.5
Settlements and other (17.4) 2.0 6.9 0.7
- -----------------------------------------------------------------------------------------------------------------
BENEFIT OBLIGATION AT END OF YEAR $(1,687.6) $(1,670.9) $ (400.0) $ (335.3)
- -----------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 2,319.4 $ 2,330.2 $ 197.6 $ 170.7
Yankee merger -- 107.5 -- 16.1
Actual return on plan assets (100.7) (8.8) (17.1) 8.6
Employer contribution -- -- 28.6 29.6
Employee contribution -- -- -- 0.1
Benefits paid (228.3) (109.5) (38.0) (27.5)
- -----------------------------------------------------------------------------------------------------------------
FAIR VALUE OF PLAN ASSETS AT END OF YEAR $ 1,990.4 $ 2,319.4 $ 171.1 $ 197.6
- -----------------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 302.8 $ 648.5 $ (228.9) $ (137.7)
Unrecognized transition (asset)/obligation (3.6) (5.8) 159.1 180.9
Unrecognized prior service cost 72.8 90.9 -- --
Unrecognized net (gain)/loss (139.6) (594.1) 55.4 (35.5)
- -----------------------------------------------------------------------------------------------------------------
PREPAID/(ACCRUED) BENEFIT COST $ 232.4 $ 139.5 $ (14.4) $ 7.7
=================================================================================================================
The following actuarial assumptions were used in calculating the plans' year end
funded status:
- -----------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.25% 7.50%
Compensation/progression rate 4.25 4.50 4.25 4.50
Health care cost trend rate (a) N/A N/A 11.00 5.26
===============================================================================================
(a) The annual per capita cost of covered health care benefits was assumed
to decrease to 5.00 percent by 2007.
The components of net periodic benefit (credit)/cost are:
- ----------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2001 2000 1999 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Service cost $ 35.7 $ 41.2 $ 43.7 $ 6.2 $ 7.6 $ 7.6
Interest cost 119.7 118.5 106.3 27.2 25.5 21.8
Expected return on plan assets (214.1) (205.1) (175.5) (17.0) (15.3) (11.7)
Amortization of unrecognized net
transition (asset)/obligation (1.5) (1.4) (1.5) 14.5 15.1 15.1
Amortization of prior service cost 6.9 7.9 7.9 -- -- --
Amortization of actuarial gain (47.7) (52.4) (33.5) -- -- --
Other amortization, net -- -- -- (2.6) (4.3) (3.1)
Settlements and other (90.7) (6.6) 18.9 11.9 -- --
- ----------------------------------------------------------------------------------------------------------------------------------
NET PERIODIC BENEFIT (CREDIT)/COST $(191.7) $ (97.9) $ (33.7) $ 40.2 $ 28.6 $ 29.7
==================================================================================================================================
For calculating pension and postretirement benefit costs, the following
assumptions were used:
- ---------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------------
Discount rate 7.50% 7.75% 7.00% 7.50% 7.75% 7.00%
Expected long-term rate of return 9.50 9.50 9.50 N/A N/A N/A
Compensation/progression rate 4.50 4.75 4.25 4.50 4.75 4.25
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.50 7.50 7.50
Life assets N/A N/A N/A 9.50 9.50 9.50
=================================================================================================================================
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 One
Percentage Percentage
Point Point
(Millions of Dollars) Increase Decrease
- --------------------------------------------------------
Effect on total service and
interest cost components $ 1.1 $ (1.0)
Effect on postretirement
benefit obligation $13.4 $(12.4)
========================================================
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
$11.7 million in 2001, $13.6 million in 2000, and $13.8 million in 1999.
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 through the second quarter of 2001, NU
declared a $0.10 per share quarterly dividend. During the third quarter of 2001
through the fourth quarter of 2001, NU declared a $0.125 per share quarterly
dividend.
In 2001 and 2000, the ESOP trust issued 546,610 and 572,863 of NU
common shares, respectively, to satisfy 401(k) Savings Plan obligations to
employees. As of December 31, 2001 and 2000, the total allocated ESOP shares
were 6,401,309 and 5,854,699, respectively, and total unallocated ESOP shares
were 4,398,876 and 4,945,486, respectively. The fair market value of
unallocated ESOP shares as of December 31, 2001 and 2000, was $77.6 million
and $119.9 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 were 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 2000, employees purchased
199,520 shares at discounted prices ranging from $17.48 to $18.49. At
December 31, 2000, 1,417,156 shares remained reserved for future issuance
under the ESPP. Effective January 1, 2001, the ESPP was terminated because of
the then pending merger.
In the second quarter of 2001, a new ESPP was adopted by NU's Board of
Trustees and approved by NU's shareholders. Shares under the new ESPP were
issued in the first quarter of 2002.
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 1999, 2000 and 2001, including those
options acquired in connection with the Yankee merger, are as follows:
- -----------------------------------------------------------------------------------------------------------------------------
Exercise Price Per Share
---------------------------------------
Weighted
Options Range Average
- -----------------------------------------------------------------------------------------------------------------------------
Outstanding December 31, 1998 1,233,678 $ 9.6250 -- $ 16.8125 $ 13.5213
Granted 644,123 $ 14.9375 -- $ 21.1250 $ 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 $ 9.6250 -- $ 21.1250 $ 14.0585
Granted 669,470 $ 18.4375 -- $ 22.2500 $ 18.7029
Yankee merger 10,167 $ 9.3640 -- $ 12.6888 $ 10.7653
Exercised (43,750) $ 14.9375 -- $ 19.5000 $ 16.0658
Forfeited (28,281) $ 14.9375 -- $ 19.5000 $ 16.6515
- -----------------------------------------------------------------------------------------------------------------------------
Outstanding December 31, 2000 2,433,862 $ 9.3640 -- $ 22.2500 $ 15.2569
Granted 817,300 $ 17.4000 -- $ 21.0300 $ 20.2065
Exercised (108,779) $ 9.3640 -- $ 19.5000 $ 16.0970
Forfeited (132,467) $ 14.8750 -- $ 21.0300 $ 18.2217
- -----------------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 2001 3,009,916 $ 9.6250 -- $ 22.2500 $ 16.4467
=============================================================================================================================
Exercisable December 31, 1999 711,787 $ 9.6250 -- $ 21.1250 $ 14.0102
Exercisable December 31, 2000 1,298,339 $ 9.3640 -- $ 22.2500 $ 14.2021
- -----------------------------------------------------------------------------------------------------------------------------
EXERCISABLE DECEMBER 31, 2001 1,712,260 $ 9.6250 -- $ 22.2500 $ 14.4650
=============================================================================================================================
For certain options that were granted in 2001 and 2000, and for the
options that were granted in 1999, the vesting schedule for these options is
ratably over three years from the date of grant. Other options granted in 2001
and 2000 vest 50 percent at the date of grant and 50 percent one year from the
date of grant.
Also under the Incentive Plan, the NU system awarded 91,120 of
restricted shares in 1999. These shares have the same vesting schedule as the
options granted under the Incentive Plan. The NU system has also made several
small grants of restricted stock and other incentive-based stock compensation.
During 2001, 2000 and 1999, $1.2 million, $1.9 million and $2.2 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) 2001 2000 1999
- ----------------------------------------------------------------------------
Net income/(loss) $ 239.1 $ (33.9) $ 29.6
Basic income/(loss) per
common share $ 1.76 $ (0.24) $ 0.23
Diluted income/(loss)
per common share $ 1.76 $ (0.24) $ 0.22
============================================================================
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:
- -------------------------------------------------------------
2001 2000 1999
- -------------------------------------------------------------
Risk-free interest rate 5.34% 6.56% 5.69%
Expected life 10 years 10 years 10 years
Expected volatility 25.47% 26.15% 36.21%
Expected dividend yield 2.11% 1.82% 1.89%
=============================================================
The weighted average grant date fair values of options granted during
2001, 2000 and 1999 were $6.94, $7.50, and $6.79, respectively. As of December
31, 2001 and 2000, the weighted average remaining contractual lives for those
options outstanding are 7.50 years and 7.92 years, respectively.
5. SALE OF CUSTOMER RECEIVABLES
On July 11, 2001, CL&P renewed its accounts receivable securitization credit
line for one year. At that time, the credit line capacity was reduced from $200
million to $100 million.
As of December 31, 2001, CL&P had no amounts outstanding through the
CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. As of
December 31, 2000, CL&P had sold accounts receivable of $170 million to a
third-party purchaser with limited recourse through the CRC. In addition, at
December 31, 2000, $18.9 million of accounts receivable were designated as
collateral under the agreement with the CRC.
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.
6. NUCLEAR GENERATION ASSETS DIVESTITURE
On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to a
subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc.
(DNCI). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to
DNCI. This sale included all of the respective joint ownership interests of
CL&P, PSNH and WMECO in Millstone 3. The NU system received approximately $1.2
billion of cash proceeds from the sale and applied the proceeds to taxes and
reductions of debt and equity at CL&P, PSNH and WMECO. As part of the sale,
DNCI assumed responsibility for decommissioning the three Millstone units.
In connection with the sale, CL&P and WMECO recorded a gain in the
amount of $642 million which was used to offset stranded costs. Additionally,
NU recorded an after-tax gain of $115.6 million related to the prior settlement
of Millstone 3 joint owner claims.
7. COMMITMENTS AND CONTINGENCIES
A. Restructuring and Rate Matters
Connecticut: On September 27, 2001, CL&P filed its application with the
Connecticut Department of Public Utility Control (DPUC) for approval of the
disposition of the proceeds from the sale of the Millstone units to DNCI. This
application described and requested DPUC approval for CL&P's treatment of its
share of the proceeds from the sale. In accordance with Connecticut's electric
utility industry restructuring legislation, CL&P was required to utilize any
gains from the Millstone sale to offset stranded costs. There are certain
contingencies related to this filing regarding the potential disallowance of
what management believes were prudently incurred costs. Management believes the
recoverability of these costs is probable. A decision from the DPUC is expected
in the first half of 2002.
New Hampshire: In July 2001, the NHPUC opened a docket to review the
FPPAC cost accruals between August 2, 1999, and April 30, 2001. Hearings at the
NHPUC are expected to be held during the spring of 2002. Under the Settlement
Agreement, the FPPAC deferrals are recovered as a Part 3 regulatory asset
through a stranded cost recovery charge. At December 31, 2001 and 2000, PSNH
had $183.3 million and $145.9 million, respectively, of recoverable deferred
energy costs deferred under the FPPAC, excluding previous deferrals of
purchases from independent power producers. Management does not expect the
outcome of these hearings to have a material impact on its earnings.
Massachusetts: During the first quarter of 2000, WMECO filed its first
annual stranded cost reconciliation filing covering the period March 1, 1998
through December 31, 1999. The hearing and briefing processes related to this
filing were completed during the second quarter of 2001. A Massachusetts
Department of Telecommunications and Energy (DTE) decision is expected in the
first half of 2002. On March 30, 2001, WMECO also filed its second annual
stranded cost reconciliation with the DTE for calendar year 2000 with the
related review and hearing processes anticipated to be scheduled for the first
half of 2002. The cumulative deferral of unrecovered stranded costs, as filed
through calendar year 2000, is approximately $4 million. Management believes
these costs are fully recoverable.
WMECO is in the process of finalizing its 2001 annual transition cost
reconciliation which is expected to be filed with the DTE on March 29, 2002.
This filing reconciles the recovery of stranded generation costs for calendar
year 2001. Also included in this filing are the sales proceeds from WMECO's
portion of Millstone, the impact of securitization and an approximate $13
million benefit to ratepayers from WMECO's nuclear performance-based ratemaking
process. The inclusion of these items as part of the reconciliation filing
allows WMECO to accelerate the recovery of total stranded generation assets.
Management anticipates a formal hearing in 2002 regarding this filing after a
period of data discovery by the DTE and other intervenors.
B. 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 the environment. As such, the NU system has active environmental
auditing and training programs and believes it is substantially in compliance
with the current laws and regulations.
However, the normal course of operations may 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, 2001 and 2000, the liability recorded by
the NU system for its estimated environmental remediation costs amounted to
$46.2 million and $58.2 million, respectively.
C. 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.
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, 2001 and 2000, fees
due to the DOE for the disposal of Prior Period Fuel were $249.3 million and
$240.3 million, respectively, including interest costs of $167.2 million and
$158.2 million, respectively.
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. NU remains
responsible for fees to be paid for fuel burned until the divestiture of the
Millstone and Seabrook nuclear units.
D. 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 $4.3 million, $1.4 million
and $6.7 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 interest in Seabrook, the NU system's
maximum liability, including any additional assessments, would be $34.9 million
per incident, of which payments would be limited to $4.8 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.
NU expects to terminate its nuclear insurance upon the divestiture of
its remaining nuclear units.
E. Long-Term Contractual Arrangements
Yankee Companies: 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. The total cost of purchases under
contracts with VYNPC amounted to $25.3 million in 2001, $24.9 million in 2000,
and $29.2 million in 1999. VYNPC is in the process of selling its nuclear unit.
Upon completion of the sale, it is expected that these long-term contracts
will be replaced with different contracts with the new buyer.
Energy Procurement Contracts: CL&P, PSNH and WMECO have entered into
various arrangements for the purchase of capacity and energy. The total cost of
purchases under these arrangements amounted to $363.9 million in 2001, $482.1
million in 2000 and $461.8 million in 1999.
Gas Procurement Contracts: Yankee Gas has entered into long-term
contracts for the purchase of a specified quantity of gas in the normal course
of business as part of its portfolio to meet its actual sales commitments.
These contracts extend through 2006.
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.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements, absent the effects of any
contract terminations, buydowns or buyouts, or sales of generation assets are
as follows:
- -----------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2003 2004 2005 2006 Totals
- -----------------------------------------------------------------------------------------------------
VYNPC $ 30.9 $ 29.4 $ 33.5 $ 34.0 $ 30.8 $ 158.6
Energy
Procurement
Contracts 331.5 341.1 345.6 350.5 350.1 1,718.8
Gas Procurement
Contracts 52.6 54.2 55.2 53.6 9.3 224.9
Hydro-Quebec 27.1 26.1 25.0 24.1 21.7 124.0
- -----------------------------------------------------------------------------------------------------
Totals $ 442.1 $ 450.8 $ 459.3 $ 462.2 $ 411.9 $2,226.3
=====================================================================================================
Select Energy: Select Energy maintains long-term agreements to
purchase energy in the normal course of business as part of its portfolio of
resources to meet its actual or expected sales commitments. The aggregate
amount of these purchase contracts was $3.5 billion at December 31, 2001.
These contracts extend through 2006 as follows:
- --------------------------------------------------------------
(Millions of Dollars)
- --------------------------------------------------------------
Year
- --------------------------------------------------------------
2002 $ 2,416.2
2003 836.2
2004 145.9
2005 95.7
2006 34.8
- --------------------------------------------------------------
Total $ 3,528.8
==============================================================
F. Consolidated Edison, Inc. Merger Litigation
Certain gain and loss contingencies exist with regard to the litigation related
to the merger agreement between NU and Consolidated Edison, Inc. For further
information regarding this litigation, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Consolidated
Edison, Inc. Merger Litigation."
8. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Seabrook: Seabrook has a service life that is expected to end in 2026, and upon
retirement, must be decommissioned. The NU system's ownership share of the
estimated cost of decommissioning Seabrook, in year end 2001 dollars, is $222.5
million. Nuclear decommissioning costs are accrued over the expected service
life of the unit and are included in depreciation expense and the accumulated
provision for depreciation. Nuclear decommissioning expenses for Seabrook
amounted to $7.8 million in 2001, $7.7 million in 2000 and $7.6 million in
1999. Through December 31, 2001 and 2000, total decommissioning expenses of
$52.5 million and $44.7 million, respectively, have been collected from
customers related to Seabrook and are reflected in the accumulated provision
for depreciation. 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.
As of December 31, 2001 and 2000, $52 million and $44.2 million,
respectively, have been transferred to the Seabrook external decommissioning
trust. Earnings on the decommissioning trust increase the decommissioning trust
balance and the accumulated provision for depreciation. Unrealized gains and
losses associated with the decommissioning trust also impact the balance of the
trust and the accumulated provision for depreciation. The fair values of the
amounts in the Seabrook external decommissioning trust were $61.7 million and
$56.6 million at December 31, 2001 and 2000, respectively. Upon divestiture,
the balance in the Seabrook decommissioning trust will be transferred to the
buyer.
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 2001 dollars, of decommissioning this
unit is $75.4 million. In August 2001, VYNPC agreed to sell its nuclear
generating unit for $180 million, including $35 million for nuclear fuel, to
an unaffiliated company. Among other commitments, the acquiring company agreed
to assume the obligation to decommission the unit after it is taken out of
service and agreed to provide the current level of output from the unit through
2012. The sale is subject to the approval of the Vermont Public Service Board,
the Nuclear Regulatory Commission, the FERC and other regulatory authorities.
The closing on the sale is expected to be in the first half of 2002.
As of December 31, 2001 and 2000, NU's remaining estimated
obligations, including decommissioning for the units owned by CYAPC, YAEC
and MYAPC, which have been shut down were $216.6 million and $244.6 million,
respectively.
9. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS
Competitive Energy Subsidiaries: Select Energy provides both firm requirement
energy services to its customers and engages in energy trading and marketing
activities. Select Energy manages its exposure to risk from existing
contractual commitments and provides risk management services to its customers
through forward contracts, futures, over-the-counter swap agreements, and
options (commodity derivatives).
Select Energy has utilized the sensitivity analysis methodology to
disclose the quantitative information for its commodity price risks.
Sensitivity analysis provides a presentation of the potential loss of future
earnings, fair values or cash flows from market risk-sensitive instruments over
a selected time period due to one or more hypothetical changes in commodity
prices, or other similar price changes.
Commodity Price Risk - Trading Activities: As a market participant in
the Northeast United States, Select Energy conducts commodity-trading
activities in electricity and its related products, natural gas and oil and,
therefore, experiences net open positions. Select Energy manages these open
positions with strict policies which limit its exposure to market risk and
require daily reporting to management of potential financial exposure.
Commodity derivatives utilized for trading purposes are accounted for using
the mark-to-market method, under EITF Issue No. 98-10. Under this methodology,
these instruments are adjusted to market value, and the unrealized gains and
losses are recognized in income in the current period in the consolidated
statements of income as fuel, purchased and net interchange power and in the
consolidated balance sheets as prepayments and other. The mark-to-market
positions at December 31, 2001 and 2000, were a positive $44.4 million and a
positive $13.8 million, respectively.
Under sensitivity analysis, the fair value of the portfolio is a
function of the underlying commodity, contract prices and market prices
represented by each derivative commodity contract. For swaps, forward contracts
and options, market value reflects management's best estimates considering
over-the-counter quotations, time value and volatility factors of the
underlying commitments. Exchange-traded futures and options are recorded at
market, based on closing exchange prices.
As of December 31, 2001, Select Energy has calculated the market price
resulting from a 10 percent unfavorable change in forward market prices. That
10 percent change would result in approximately a $0.6 million decline in the
fair value of the Select Energy trading portfolio. In the normal course of
business, Select Energy also faces risks that are either nonfinancial or
nonquantifiable. Such risks principally include credit risk, which is not
reflected in the sensitivity analysis above.
Commodity Price Risk - Nontrading Activities: Select Energy utilizes
derivative financial and commodity instruments (derivatives), including futures
and forward contracts, to reduce market risk associated with fluctuations in
the price of electricity and natural gas sold under firm commitments with
certain customers. Select Energy also utilizes derivatives, including price
swap agreements, call and put option contracts, and futures and forward
contracts, to manage the market risk associated with a portion of its
anticipated supply requirements. These derivative instruments have been
designated as cash flow hedging instruments.
When conducting sensitivity analysis of the change in the fair value
of Select Energy's electricity, natural gas and oil nontrading portfolio, which
would result from a hypothetical change in the future market price of
electricity, natural gas and oil, the fair value of the contracts are
determined from models which take into account estimated future market prices
of electricity, natural gas and oil, the volatility of the market prices in
each period, as well as the time value factors of the underlying commitments.
In most instances, market prices and volatility are determined from quoted
prices on the futures exchange.
Select Energy has determined a hypothetical change in the fair value
for its nontrading electricity, natural gas and oil contracts, assuming a 10
percent unfavorable change in forward market prices. As of December 31, 2001,
an unfavorable 10 percent change in forward market price would have resulted
in a decrease in fair value of approximately $29 million.
The impact of a change in electricity, natural gas and oil prices on
Select Energy's nontrading contracts on December 31, 2001, is not necessarily
representative of the results that will be realized when these contracts are
physically delivered.
Select Energy also maintains natural gas service agreements with
certain customers to supply gas at fixed prices for terms extending through
2004. Select Energy has hedged its gas supply risk under these agreements
through NYMEX contracts. Under these contracts, the purchase price of a
specified quantity of gas is effectively fixed over the term of the gas service
agreements, which extend through 2004. As of December 31, 2001, the NYMEX
contracts had a notional value of $91.3 million and a negative after-tax
mark-to-market position of $14.7 million.
Derivative Cash Flow Hedge Accounting: Derivative instruments recorded
which were effective cash flow hedges resulted in an increase in other
comprehensive income of $12.3 million, net of tax, upon the adoption of SFAS
No. 133. During 2001, a positive $4.5 million, net of tax, was reclassified
from other comprehensive income upon the conclusion of these hedged
transactions and recognized in earnings. An additional $1.3 million, net of
tax, was recognized in earnings for those derivatives that were determined to
be ineffective. Also, during 2001, new cash flow hedge transactions were
entered into which hedge cash flows through 2027. As a result of these new
transactions and market value changes since January 1, 2001, other
comprehensive income decreased by $53.7 million, net of tax. Accumulated other
comprehensive income at December 31, 2001, was a negative $36.9 million, net of
tax (decrease to equity), relating to hedged transactions and it is estimated
that $29.4 million, net of tax, will be reclassified as a charge to earnings
within the next twelve months. Cash flows from the hedge contracts are reported
in the same category as cash flows from the hedged assets.
Credit Risk: NU serves a wide variety of customers and suppliers that
include independent power producers, industrial companies, gas and electric
utilities, oil and gas producers, financial institutions, and other energy
marketers. Margin accounts exist within this diverse group, and NU realizes
interest receipts and payments related to balances outstanding in these
accounts. This wide customer and supplier mix generates a need for a variety of
contractual structures, products and terms. This multifaceted book of business
requires NU to manage the portfolio of market risk inherent in those
transactions in a manner consistent with the parameters established by NU's
risk management process. Market risks are monitored regularly by a Risk
Oversight Council operating outside of the units that create or actively manage
these risk exposures to ensure compliance with NU's stated risk management
policies.
NU tracks and re-balances the risk in its portfolio in accordance with
mark-to-market and other risk management methodologies that utilize forward
price curves in the energy markets to estimate the size and probability of
future potential exposure.
Credit risk relates to the risk of loss that NU would incur as a
result of non-performance by counterparties pursuant to the terms of their
contractual obligations. New York Mercantile Exchange (Exchange) traded futures
and option contracts are guaranteed by the Exchange and have a modest credit
risk. NU has established written credit policies with regard to its
counterparties to minimize overall credit risk on all types of transactions.
These policies require an evaluation of potential counterparties' financial
conditions (including credit rating), collateral requirements under certain
circumstances (including cash in advance, letters of credit, and parent
guarantees), and theuse of standardized agreements, which allow for the netting
of positive and negative exposures associated with a single counterparty. This
evaluation results in establishing credit limits prior to NU entering into
trading activities. The appropriateness of these limits is subject to
continuing review. Concentrations among these counterparties may impact NU's
overall exposure to credit risk, either positively or negatively in that the
counterparties may be similarly affected by changes to economic, regulatory
or other conditions.
Regulated Entities:
Interest Rate Risk - Nontrading Activities: NU manages its interest rate risk
exposure by maintaining a mix of fixed and variable rate debt. In addition,
Yankee has entered into an interest rate sensitive derivative. Yankee uses swap
instruments with financial institutions to exchange fixed-rate interest
obligations to a blend between fixed and variable-rate obligations without
exchanging the underlying notional amounts. These instruments convert fixed
interest rate obligations to variable rates. The notional amounts parallel the
underlying debt levels and are used to measure interest to be paid or received
and do not represent the exposure to credit loss. As of December 31, 2001,
Yankee had outstanding agreements with a total notional value of $48 million
and a positive mark-to-market position of $0.2 million, which is included
within the $36.9 million reported for accumulated other comprehensive income
related to hedging activities.
Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a
master swap agreement with one customer to supply gas at fixed prices for a
10-year term extending through 2005. Under this master swap agreement, the
purchase price of a specified quantity of gas is effectively fixed over the
term of the gas service agreement, which extends through 2005. As of
December 31, 2001, the commodity swap agreement had a notional value of $16.9
million and a negative mark-to-market position of $1.4 million, net of tax,
which is included within the $36.9 million reported for accumulated other
comprehensive income related to hedging activities.
10. 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 in CL&P LP, as a general partner, and was
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 was eliminated, and the MIPS securities were accounted for
as a minority interest. In the second quarter of 2001, CL&P repaid the $100
million in notes associated with the MIPS.
11. 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 $6.3 million and $6.5 million held for
benefit of the SERP were recorded at their fair market values at December 31,
2001 and 2000, of $9 million and $10.1 million, respectively.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were marked-to-market by a negative
$2.5 million as of December 31, 2001, and a positive $117.6 million as of
December 31, 2000, with corresponding offsets to the accumulated provision for
depreciation.
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, 2001
- ------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- ------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 62.4
Long-term debt--
First mortgage bonds 795.9 847.2
Other long-term debt 1,552.1 1,554.6
Rate reduction bonds 2,018.4 2,061.8
============================================================
- ------------------------------------------------------------
At December 31, 2000
- ------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- ------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 136.2 $ 159.9
Preferred stock subject to
mandatory redemption 40.8 42.0
Long-term debt--
First mortgage bonds 1,008.1 1,012.5
Other long-term debt 1,342.2 1,290.6
MIPS 100.0 100.5
============================================================
12. OTHER COMPREHENSIVE INCOME
The accumulated balance for each other comprehensive income item is as follows:
- -----------------------------------------------------------------------------
December 31, Current December 31,
(Millions of Dollars) 2000 Period Change 2001
- -----------------------------------------------------------------------------
Qualified cash flow
hedging instruments $ -- $(36.9) $(36.9)
Unrealized gains
on securities 2.4 2.6 5.0
Minimum pension
liability adjustments (0.6) -- (0.6)
- -----------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 1.8 $(34.3) $(32.5)
=============================================================================
- -----------------------------------------------------------------------------
December 31, Current December 31,
(Millions of Dollars) 1999 Period Change 2000
- -----------------------------------------------------------------------------
Qualified cash flow
hedging instruments $ -- $ -- $ --
Unrealized gains
on securities 2.1 0.3 2.4
Minimum pension
liability adjustments (0.6) -- (0.6)
- -----------------------------------------------------------------------------
Accumulated other
comprehensive income $ 1.5 $ 0.3 $ 1.8
=============================================================================
The changes in the components of other comprehensive income are
reported net of the following income tax effects:
- -----------------------------------------------------------------------------
(Millions of Dollars) 2001 2000 1999
- -----------------------------------------------------------------------------
Qualified cash flow
hedging instruments $ 2.3 $ -- $ --
Unrealized gains
on securities (1.9) (0.2) (0.1)
Minimum pension
liability adjustments -- -- --
- -----------------------------------------------------------------------------
Accumulated other
comprehensive income/
(loss) $ 0.4 $(0.2) $(0.1)
============================================================================
Accumulated other comprehensive income mark-to-market adjustments of NU's
qualified cash flow hedging instruments are as follows:
- -------------------------------------------------------------------------------
(Millions of Dollars, Net of Tax) December 31, 2001
- -------------------------------------------------------------------------------
Balance at January 1, 2001 (inception date) $ 12.3
- -------------------------------------------------------------------------------
Hedged transactions recognized into earnings 4.5
Change in fair value (29.6)
Cash flow transactions entered into
for the period (24.1)
- -------------------------------------------------------------------------------
Net change associated with the current period
hedging transactions (49.2)
- -------------------------------------------------------------------------------
Total mark-to-market adjustments included in
accumulated other comprehensive loss $ (36.9)
===============================================================================
13. EARNINGS PER SHARE
EPS is computed based upon the weighted average number of common shares
outstanding during each year. Diluted EPS 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) 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Income before preferred dividends of subsidiaries $ 273.2 $ 219.5 $ 57.0
Preferred dividends of subsidiaries 7.3 14.2 22.8
- ----------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary loss and cumulative effect of accounting change 265.9 205.3 34.2
Extraordinary loss, net of tax benefit -- (233.9) --
Cumulative effect of accounting change, net of tax benefit (22.4) -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 243.5 $ (28.6) $ 34.2
==================================================================================================================================
Basic EPS common shares outstanding (average) 135,632,126 141,549,860 131,415,126
Dilutive effect of employee stock options 285,297 417,356 616,447
- ----------------------------------------------------------------------------------------------------------------------------------
Fully diluted EPS common shares outstanding (average) 135,917,423 141,967,216 132,031,573
- ----------------------------------------------------------------------------------------------------------------------------------
Basic earnings/(loss) per common share:
Income before extraordinary loss and cumulative effect of accounting change $ 1.97 $ 1.45 $ 0.26
Extraordinary loss, net of tax benefit -- (1.65) --
Cumulative effect of accounting change, net of tax benefit (0.17) -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 1.80 $ (0.20) $ 0.26
==================================================================================================================================
Fully diluted earnings/(loss) per common share:
Income before extraordinary loss and cumulative effect of accounting change $ 1.96 $ 1.45 $ 0.26
Extraordinary loss, net of tax benefit -- (1.65) --
Cumulative effect of accounting change, net of tax benefit (0.17) -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 1.79 $ (0.20) $ 0.26
==================================================================================================================================
14. SEGMENT INFORMATION
The NU system is organized between regulated utilities (electric and gas since
March 1, 2000) and competitive energy subsidiaries. The regulated utilities
segment represents approximately 68 percent and 85 percent of the NU system's
total revenues for the years ended December 31, 2001 and 2000, respectively,
and is comprised of several business units.
Regulated utilities revenues primarily are derived from residential,
commercial and industrial customers and are not dependent on any single
customer. In 2001, the competitive energy subsidiaries segment had one customer
with revenues in excess of 10 percent of its total revenues, CL&P. The
purchases by CL&P represented approximately 22 percent, of total competitive
energy subsidiaries' revenues for the year ended December 31, 2001. In 2000,
the purchases by two customers, one unaffiliated company and CL&P, represented
approximately 15 percent and 34 percent, respectively, of total competitive
energy subsidiaries' revenues for the year ended December 31, 2000.
The competitive energy subsidiaries segment in the following table includes
SES, a provider of energy management, demand-side management and related
consulting services for commercial, industrial and institutional electric
companies and electric utility companies; HWP, a company engaged in the
production of electric power; NGC, a corporation that acquires and manages
generation facilities; NGS, a corporation that maintains and services any
fossil or hydroelectric facility that is acquired or contracted with for fossil
or hydroelectric generation services, and; Select Energy, a corporation engaged
in the marketing, transportation, storage, and sale of energy commodities, at
wholesale, in designated geographical areas and in the marketing of electricity
to retail customers.
Other in the following table includes the results for Mode 1, an investor
in a fiber-optic communications network. Other also includes the results of the
nonenergy related subsidiaries of Yankee. Interest expense included in Other
primarily relates to the debt of NU parent. Inter-segment eliminations are also
included in Other.
- -----------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2001
- -----------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
------------------- Energy and
(Millions of Dollars) Electric Gas Subsidiaries Other Total
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 4,287.0 $ 378.0 $ 2,964.0 $ (755.2) $ 6,873.8
Operating expenses (3,795.5) (327.9) (2,919.1) 707.8 (6,334.7)
- -----------------------------------------------------------------------------------------------------------
Operating income/(loss) 491.5 50.1 44.9 (47.4) 539.1
Other income, net 72.8 4.1 5.8 104.9 187.6
Interest expense, net (199.3) (14.0) (42.9) (23.4) (279.6)
Income tax expense (154.3) (14.3) (2.8) (2.5) (173.9)
Preferred dividends (7.3) -- -- -- (7.3)
- -----------------------------------------------------------------------------------------------------------
Income before cumulative
effect of accounting change 203.4 25.9 5.0 31.6 265.9
Cumulative effect of accounting
change, net of tax benefit -- -- (22.0) (0.4) (22.4)
- -----------------------------------------------------------------------------------------------------------
Net income/(loss) $ 203.4 $ 25.9 $ (17.0) $ 31.2 $ 243.5
- -----------------------------------------------------------------------------------------------------------
Total assets $ 8,730.3 $ 890.0 $ 1,017.9 $ (396.8) $10,241.4
===========================================================================================================
- --------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2000
- --------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
------------------- Energy and
(Millions of Dollars) Electric Gas Subsidiaries Other Total
- --------------------------------------------------------------------------------------------------------
Operating revenues $ 4,738.5 $ 251.2 $ 1,894.9 $(1,008.0) $ 5,876.6
Operating expenses (4,078.1) (224.2) (1,830.0) 950.5 (5,181.8)
- --------------------------------------------------------------------------------------------------------
Operating income/(loss) 660.4 27.0 64.9 (57.5) 694.8
Other (loss)/income, net (11.6) (7.1) (4.7) 9.1 (14.3)
Interest expense, net (191.9) (12.2) (53.4) (41.8) (299.3)
Income tax expense (173.4) (6.5) (0.1) 18.3 (161.7)
Preferred dividends (14.2) -- -- -- (14.2)
- --------------------------------------------------------------------------------------------------------
Income/(loss) before
extraordinary loss 269.3 1.2 6.7 (71.9) 205.3
Extraordinary loss, net of
tax benefit (214.2) -- (19.7) -- (233.9)
- --------------------------------------------------------------------------------------------------------
Net income/(loss) $ 55.1 $ 1.2 $ (13.0) $ (71.9) $ (28.6)
- --------------------------------------------------------------------------------------------------------
Total assets $ 9,620.0 $ 912.6 $ 684.1 $ (999.6) $10,217.1
========================================================================================================
- -----------------------------------------------------------------------------------------------
For the Year Ended December 31, 1999
- -----------------------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
------------------- Energy and
(Millions of Dollars) Electric Subsidiaries Other Total
- -----------------------------------------------------------------------------------------------
Operating revenues $3,846.1 $ 648.8 $ (23.7) $4,471.2
Operating expenses (3,241.4) (713.5) 9.1 (3,945.8)
- ----------------------------------------------------------------------------------------------
Operating income/(loss) 604.7 (64.7) (14.6) 525.4
Other (loss)/income, net (105.2) 5.6 (6.6) (106.2)
Interest expense, net (245.5) (3.2) (14.9) (263.6)
Income tax expense (150.9) 25.3 27.0 (98.6)
Preferred dividends (22.8) -- -- (22.8)
- ----------------------------------------------------------------------------------------------
Net income/(loss) $ 80.3 $ (37.0) $ (9.1) $ 34.2
- ----------------------------------------------------------------------------------------------
Total assets $9,302.6 $ 308.2 $ 77.3 $9,688.1
==============================================================================================
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
- -----------------------------------------------------------------------------------------------------------------------------
Quarter Ended (a) (b)
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share information) March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------------------------------------------------
2001
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 1,800,544 $ 1,583,294 $ 1,723,894 $ 1,766,094
Operating Income 159,595 133,472 113,378 132,729
Income Before Cumulative Effect of Accounting Change 134,595 46,732 34,631 49,984
Cumulative Effect of Accounting Change,
Net of Tax Benefit (22,432) -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 112,163 $ 46,732 $ 34,631 $ 49,984
=============================================================================================================================
Basic Earnings/(Loss) per Common Share:
Income Before Cumulative Effect of Accounting Change $ 0.93 $ 0.35 $ 0.26 $ 0.38
Cumulative Effect of Accounting Change,
Net of Tax Benefit (0.15) -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 0.78 $ 0.35 $ 0.26 $ 0.38
=============================================================================================================================
Diluted Earnings/(Loss) per Common Share:
Income Before Cumulative Effect of Accounting Change $ 0.93 $ 0.35 $ 0.26 $ 0.38
Cumulative Effect of Accounting Change,
Net of Tax Benefit (0.15) -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 0.78 $ 0.35 $ 0.26 $ 0.38
- -----------------------------------------------------------------------------------------------------------------------------
2000
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 1,382,321 $ 1,414,973 $ 1,581,947 $ 1,497,379
Operating Income 197,834 146,537 177,343 173,079
Income Before Extraordinary Loss 74,587 12,206 65,543 52,959
Extraordinary Loss, Net of Tax Benefit -- -- -- (233,881)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 74,587 $ 12,206 $ 65,543 $ (180,922)
=============================================================================================================================
Basic Earnings/(Loss) Per Common Share:
Income Before Extraordinary Loss $ 0.55 $ 0.09 $ 0.46 $ 0.37
Extraordinary Loss, Net of Tax Benefit -- -- -- (1.63)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 0.55 $ 0.09 $ 0.46 $ (1.26)
=============================================================================================================================
Diluted Earnings/(Loss) Per Common Share:
Income Before Extraordinary Loss $ 0.55 $ 0.08 $ 0.45 $ 0.37
Extraordinary Loss, Net of Tax Benefit -- -- -- (1.63)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 0.55 $ 0.08 $ 0.45 $ (1.26)
=============================================================================================================================
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
(b) Summation of quarterly data may not equal annual data due to rounding.
SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except
percentages and share information) 2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA:
Property, Plant and Equipment, Net $ 3,822,139 $ 3,547,215 $ 3,947,434 $ 6,170,881 $ 6,463,158
Total Assets 10,241,409 10,217,149 9,688,052 10,387,381 10,414,412
Total Capitalization (a) 4,576,858 4,739,417 5,216,456 6,030,402 6,472,504
Obligations Under Capital Leases (a) 17,539 159,879 181,293 209,279 207,731
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME DATA:
Operating Revenues $ 6,873,826 $ 5,876,620 $ 4,471,251 $ 3,767,714 $ 3,834,806
Income/(Loss) Before Extraordinary Loss and
Cumulative Effect of Accounting Change,
Net of Tax Benefits 265,942 205,295 34,216 (146,753) (129,962)
Extraordinary Loss, Net of Tax Benefit -- (233,881) -- -- --
Cumulative Effect of Accounting Change,
Net of Tax Benefit (22,432) -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 243,510 $ (28,586) $ 34,216 $ (146,753) $ (129,962)
==================================================================================================================================
COMMON SHARE DATA:
Basic Earnings/(Loss) Per Common Share:
Income/(Loss) Before Extraordinary Loss and
Cumulative Effect of Accounting Change,
Net of Tax Benefits $ 1.97 $ 1.45 $ 0.26 $ (1.12) $ (1.01)
Extraordinary Loss, Net of Tax Benefit -- (1.65) -- -- --
Cumulative Effect of Accounting Change,
Net of Tax Benefit (0.17) -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.80 $ (0.20) $ 0.26 $ (1.12) $ (1.01)
==================================================================================================================================
Fully Diluted Earnings/(Loss) per Common Share:
Income/(Loss) Before Extraordinary Loss and
Cumulative Effect of Accounting Change,
Net of Tax Benefits $ 1.96 $ 1.45 $ 0.26 $ (1.12) $ (1.01)
Extraordinary Loss, Net of Tax Benefit -- (1.65) -- -- --
Cumulative Effect of Accounting Change,
Net of Tax Benefit (0.17) -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.79 $ (0.20) $ 0.26 $ (1.12) $ (1.01)
==================================================================================================================================
Basic Common Shares Outstanding
(Average) 135,632,126 141,549,860 131,415,126 130,549,760 129,567,708
Fully Diluted Common Shares
Outstanding (Average) 135,917,423 141,967,216 132,031,573 130,549,760 129,567,708
Dividends Per Share $ 0.45 $ 0.40 $ 0.10 $ -- $ 0.25
Market Price - Closing (high) (c) $ 23.75 $ 24.25 $ 22.00 $ 17.25 $ 14.25
Market Price - Closing (low) (c) $ 16.80 $ 18.25 $ 13.56 $ 11.69 $ 7.63
Market Price - Closing (end of year) (c) $ 17.63 $ 24.25 $ 20.56 $ 16.00 $ 11.81
Book Value Per Share (end of year) $ 16.27 $ 15.43 $ 15.80 $ 15.63 $ 16.67
Rate of Return Earned on Average
Common Equity (%) 11.2 (1.3) 1.6 (7.0) (5.8)
Market-to-Book Ratio (end of year) 1.1 1.6 1.3 1.0 0.7
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Common Shareholders' Equity 46% 47% 40% 34% 34%
Preferred Stock (a) (b) 3 4 5 5 6
Long-Term Debt (a) 51 49 55 61 60
- ----------------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100%
==================================================================================================================================
(a) Includes portions due within one year.
(b) Excludes $100 million of MIPS.
(c) Market price information reflects closing prices as presented in the Wall
Street Journal.
CONSOLIDATED ELECTRIC SALES STATISTICS (UNAUDITED)
- ------------------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
REVENUES: (THOUSANDS)
Residential $ 1,490,487 $1,469,439 $1,517,913 $1,475,363 $1,499,394
Commercial 1,303,351 1,256,126 1,272,969 1,273,146 1,266,449
Industrial 549,808 566,625 560,801 568,913 560,782
Other Utilities 2,663,930 1,884,082 926,056 336,623 329,764
Streetlighting and Railroads 43,889 45,998 45,564 47,682 48,867
Nonfranchised Sales (438) 16,932 24,659 22,479 21,476
Miscellaneous 115,196 96,666 52,357 16,429 47,446
- ------------------------------------------------------------------------------------------------------------------------------
Total Electric 6,166,223 5,335,868 4,400,319 3,740,635 3,774,178
Gas 566,814 461,716 -- -- --
Other 140,789 79,036 70,932 27,079 60,628
- ------------------------------------------------------------------------------------------------------------------------------
Total $ 6,873,826 $5,876,620 $4,471,251 $3,767,714 $3,834,806
==============================================================================================================================
SALES: (kWh - MILLIONS)
Residential 13,322 12,940 12,912 12,162 12,099
Commercial 13,751 13,023 12,850 12,477 12,091
Industrial 6,790 7,130 7,050 6,948 6,801
Other Utilities 51,789 42,127 33,575 9,742 8,034
Streetlighting and Railroads 332 333 314 320 318
Nonfranchised Sales -- 107 147 193 241
- ------------------------------------------------------------------------------------------------------------------------------
Total 85,984 75,660 66,848 41,842 39,584
==============================================================================================================================
CUSTOMERS: (AVERAGE)
Residential 1,610,154 1,576,068 1,569,932 1,555,013 1,535,134
Commercial 171,218 166,114 164,932 162,500 159,350
Industrial 7,730 7,701 7,721 7,847 7,804
Other 3,969 3,917 3,908 3,890 3,929
- ------------------------------------------------------------------------------------------------------------------------------
Total Electric 1,793,071 1,753,800 1,746,493 1,729,250 1,706,217
Gas 190,998 185,328 -- -- --
- ------------------------------------------------------------------------------------------------------------------------------
Total 1,984,069 1,939,128 1,746,493 1,729,250 1,706,217
==============================================================================================================================
AVERAGE ANNUAL USE PER
RESIDENTIAL CUSTOMER (kWh) 8,251 8,233 8,243 7,799 7,898
==============================================================================================================================
AVERAGE ANNUAL BILL PER
RESIDENTIAL CUSTOMER $ 923.70 $ 934.94 $ 969.38 $ 946.80 $ 978.72
==============================================================================================================================
AVERAGE REVENUE PER kWh:
Residential 11.20(cent) 11.36(cent) 11.76(cent) 12.14(cent) 12.39(cent)
Commercial 9.48 9.65 9.91 10.20 10.47
Industrial 8.10 7.95 7.95 8.19 8.25
==============================================================================================================================