EXHIBIT 13.1
ANNUAL REPORT OF NORTHEAST UTILITIES
Management's Discussion and Analysis
FINANCIAL CONDITION
Overview
Consolidated: Northeast Utilities and subsidiaries (NU or the company) reported
2002 earnings of $152.1 million, or $1.18 per share compared with earnings of
$243.5 million, or $1.79 per share in 2001 and a loss of $28.6 million, or $0.20
per share in 2000. In 2002 and 2001, the divestiture of nuclear generation
assets in which NU had a significant ownership interest had a material positive
impact on the company's financial results. All per share amounts are reported on
a fully diluted basis.
During 2002, NU recorded after-tax gains totaling $24.5 million, or $0.19 per
share, associated with the sale of its ownership interest in the Seabrook
nuclear units (Seabrook) and the elimination of reserves associated with its
ownership share of Seabrook assets. During 2001, NU recorded a net after-tax
gain of $115.6 million, or $0.85 per share, associated with the sale of its
ownership interest in the Millstone nuclear units (Millstone).
During 2002 and 2001, NU recorded various other charges. During 2002, NU
recorded an after-tax loss of $11 million, or $0.09 per share, primarily
associated with the write-down of investments in NEON Communications, Inc.
(NEON) and Acumentrics Corporation (Acumentrics). During 2001, NU recorded an
after-tax 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
loss of $35.4 million, or $0.26 per share, associated with an agreement with two
financial institutions to repurchase NU common shares. Excluding the
aforementioned nuclear generation asset divestitures and other charges, NU
earned $138.6 million in 2002, compared with $185.7 million in 2001.
NU's revenues for 2002 decreased to $5.2 billion from revenues of $6 billion for
2001. The decrease in revenues is due to lower competitive energy subsidiary
revenues and lower regulated subsidiary revenues. The decrease in the
competitive energy subsidiaries' revenues is primarily due to lower wholesale
marketing revenues from Select Energy, Inc. and subsidiary (Select Energy) full
requirements contracts, primarily due to lower energy prices. The decrease in
the regulated subsidiaries' revenues is due to lower regulated wholesale and
retail revenues. Regulated wholesale revenues decreased primarily due to lower
sales associated with purchase-power contracts, lower wholesale sales in New
Hampshire and the 2001 revenue associated with the sale of Millstone output. The
decrease in regulated retail revenue is primarily related to a rate decrease at
Public Service Company of New Hampshire (PSNH), a decrease of the Western
Massachusetts Electric Company (WMECO) standard offer rate and a decrease in
Yankee Gas Services Company (Yankee Gas) revenues associated with lower gas
sales and lower 2002 rates.
NU's earnings per share (EPS) continued to benefit from the company's ongoing
share repurchase program. During 2002 NU repurchased 3.7 million shares at an
average price of $15.78 in addition to the 14.3 million shares repurchased in
2001 at an average price of $20.34. The company had 127.6 million shares
outstanding at December 31, 2002, compared to 130.1 million outstanding shares
on December 31, 2001.
In January and February 2003, NU repurchased an additional 1.1 million shares at
an average price of $14.44 and can repurchase an additional 6 million shares
through June 30, 2003, under an existing resolution approved by the NU Board of
Trustees.
The share repurchase program is part of a fundamental restructuring of NU's
earnings base that has taken place since 1999. Over the past four years, NU's
regulated subsidiaries have sold nearly 5,000 megawatts (MW) of New England
electric generation to unaffiliated companies for approximately $2 billion and
have securitized more than $2 billion of stranded costs. The proceeds from those
sales and securitizations have allowed NU to reduce its combined level of debt
and preferred stock by nearly 50 percent since the end of 1997. However, the
reduction of NU's generation plant and lower level of regulatory assets also has
significantly reduced the earnings power of NU's regulated electric businesses.
NU has partially offset that lower regulated earnings base by acquiring Yankee
Energy System, Inc. (Yankee) in 2000, lowering debt and preferred stock levels,
repurchasing common shares, making needed investments in its regulated electric
distribution and transmission infrastructure, and expanding into the competitive
energy business in the Northeast United States. To date, the success of those
efforts has been mixed. The retirement of debt has significantly improved NU's
consolidated balance sheets, and NU's credit ratings are higher than they have
been in at least three decades. Share repurchases have been accretive, and
Yankee has been well integrated into NU. NU is in the early stages of its
regulated distribution and transmission investment program. As this program
progresses, the regulated earnings base will increase over the next several
years. However, NU's investment of more than $500 million of equity into its
competitive energy businesses has not yet produced the long-term return on
investment management requires. A key focus of management in 2003 will be to
improve competitive business performance significantly.
Regulated Utilities: Performance among NU's five regulated subsidiaries varied
in 2002 with three posting lower results than in 2001 and two posting stronger
results. Net income before the payment of preferred dividends totaled $85.6
million at The Connecticut Light and Power Company (CL&P), compared with $109.8
million in 2001. The lower 2002 net income was largely attributable to an
after-tax gain of $17.7 million CL&P recorded in 2001 associated with the sale
of Millstone. Net income before the payment of preferred dividends at PSNH
totaled $62.9 million in 2002, compared with $81.8 million in 2001. The lower
2002 net income was largely due to an after-tax gain of $15.5 million PSNH
recorded in 2001 as a result of the sale of PSNH's share of the Millstone 3
nuclear unit. Net income at Yankee totaled $15.9 million in 2002, compared with
$25.8 million in 2001. The lower 2002 net income was primarily due to the mild
first quarter of 2002, usually Yankee Gas' most profitable period of the year,
and to the after-tax recognition of approximately $10 million in 2001 related to
a favorable property tax settlement.
WMECO recorded net income before the payment of preferred dividends of $37.7
million in 2002, compared with $15 million in 2001. The improved 2002 results
were largely due to the recognition of $13 million in investment tax credits and
the elimination of $9 million of reserves, both in 2002, as a result of
regulatory decisions. North Atlantic Energy Corporation (NAEC) earned $26.3
million in 2002, compared with $4.2 million in 2001. The improved 2002 results
were largely due to the elimination of a Seabrook-related reserve during 2002.
On November 1, 2002, NAEC sold its 35.98 percent share of Seabrook.
Subsequently, a portion of NAEC's equity was repaid to NU. NAEC's operations
will not have a material impact on NU's consolidated financial results in 2003
or thereafter.
Competitive Energy Subsidiaries: The decline in NU's 2002 earnings was primarily
a result of disappointing results at NU's competitive energy subsidiaries. In
2002, those businesses lost $54.1 million, or $0.42 per share, compared with
earnings prior to the charge associated with the adoption of SFAS No. 133 of $5
million, or $0.04 per share, in 2001 and a contribution towards NU's
consolidated earnings of $13.6 million, or $0.10 per share, in 2000. Select
Energy's wholesale marketing business was essentially break-even in 2002,
following a loss of approximately $13 million in 2001. Those results include the
performance of Northeast Generation Company (NGC) and Holyoke Water Power
Company (HWP). Select Energy's retail marketing business experienced weaker
performance during 2002, with losses of approximately $28 million, compared with
2001 losses of approximately $8 million, excluding the loss associated with the
adoption of SFAS No. 133, as amended. Select Energy's trading business also lost
approximately $24 million in 2002 compared with earnings of $19 million in 2001.
NU's energy services businesses, including Northeast Generation Services Company
(NGS) and Select Energy Services, Inc. (SESI), were essentially break-even in
2002. SESI earned $3 million while NGS lost $3.2 million. In 2001, SESI earned
$2.4 million and NGS earned $4.6 million. In 2002, NU Enterprises, Inc. (NUEI)
and the energy services subsidiaries of Yankee lost approximately $2 million.
Future Outlook
Consolidated: NU estimates that it will earn between $1.10 per share and $1.30
per share in 2003.
Regulated Utilities: The earnings range of between $1.10 and $1.30 per share
includes earnings of between $1.05 per share and $1.15 per share at the
regulated businesses, compared with aggregate earnings of $1.72 per share at the
regulated businesses in 2002. The primary reason for the earnings reduction at
the regulated businesses in 2003 is the sale of Seabrook in 2002 and the
resulting elimination of operating earnings at NAEC in 2003, the recording of
$13 million of tax credits at WMECO in 2002, and a significant reduction in the
projected level of pension income in 2003 and forward.
NU recorded $73.4 million of pre-tax pension income in 2002, approximately 30
percent of which was capitalized and reflected as a reduction to the cost of
capital expenditures with the remainder being recognized in the consolidated
statements of income as reductions to operating expenses. In 2003, as a result
of continued poor performance in the equity markets, NU is projecting the total
level of pre-tax pension income to decline to approximately $31 million, with a
similar percentage being reflected as a reduction to the cost of capital
expenditures. Pension income is annually adjusted during the second quarter
based upon updated actuarial valuations, and the 2003 estimate may be modified.
The lower pre-tax pension income will be partially offset by a reduction in
workforce at NU. In 2002, NU reduced its workforce by approximately 200
employees and commenced an effort to reduce the number of non-employee vendors
it currently employs by approximately 50 percent. Together these efforts are
expected to reduce costs by approximately $20 million annually on a pre-tax
basis. Management believes that most of the cost of the workforce reduction,
which was approximately $13 million, is recoverable from ratepayers as a
stranded cost related to industry restructuring.
Competitive Energy Subsidiaries: NU projects that the financial performance of
its competitive energy subsidiaries will improve in 2003 and that those
subsidiaries will earn between $0.15 per share and $0.25 per share. NU believes
that its wholesale marketing business, including NGC and HWP, will be
profitable. Management also projects that its retail marketing business will
break-even and its trading business will be modestly profitable in 2003, and
that financial performance at its energy services businesses, NGS and SESI, will
also be profitable in the aggregate.
NU also projects that parent company expenses, primarily related to three
long-term debt issuances, will cost the company approximately $0.10 per share in
2003.
Liquidity
Consolidated: The year 2002 represented the final year of a four-year process of
selling most of the regulated generation assets owned by NU. The sale of those
assets and the sale of more than $2.1 billion of rate reduction bonds and
certificates to securitize stranded costs resulted in the inflow of more than
$4.3 billion over a 40-month period ending with the sale of NU's 40.04 percent
ownership of Seabrook, 35.98 percent by NAEC and 4.06 percent by CL&P, on
November 1, 2002. NU received approximately $367 million of total cash proceeds
from the sale of Seabrook and another approximately $17 million from Baycorp
Holdings, Ltd. as a result of the sale of its 15 percent interest in Seabrook. A
portion of this cash was used to repay all $90 million of NAEC's outstanding
debt and other short-term debt, to return a portion of NAEC's equity to NU and
will be used to pay approximately $95 million in taxes. The remaining proceeds
received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As
a result, NU remained at a high level of liquidity during 2002, despite rising
capital investments in its regulated electric and gas segments. At December 31,
2002, NU had $2.4 billion of long-term and short-term debt and capital lease
obligations outstanding, excluding rate reduction bonds, compared with $2.7
billion of debt and capital lease obligations outstanding at December 31, 2001.
Aside from the rate reduction bonds outstanding, NU has a very modest level of
sinking fund payments and debt maturities due between 2003 and 2011, averaging
approximately $38 million annually and totaling $56.9 million in 2003. Most of
the debt that must be repaid during that period of time was issued by NU parent,
NGC and Yankee Gas. No CL&P, PSNH or WMECO debt issues mature during that
nine-year period. Because of NU's current high level of liquidity and modest
level of debt maturities in the coming years, management does not expect to
experience the severe credit and refinancing issues that many other energy
industry companies have faced in the past two years.
NU's net cash flows provided by operating activities increased to $612.6 million
in 2002, compared with $328.6 million in 2001 and $599.8 million in 2000. Cash
flows provided by operating activities increased primarily due to increases in
working capital items, primarily accrued taxes, offset by a reduction in net
income, primarily due to the gain associated with the sale of Millstone in 2001.
Accrued taxes increased because the taxes related to the sale of Seabrook will
not be paid until March of 2003. The decrease in cash flows provided by
operating activities in 2001 related primarily to increases in receivables and
unbilled revenues associated with the sales growth of NU's competitive energy
subsidiaries.
There was a lower level of investing and financing activities in 2002
as compared to 2001, primarily due to the issuance of long-term debt, issuance
of rate reduction bonds and certificates and the buyout and buydown of
independent power producer contracts in 2001. The level of common dividends
totaled $67.8 million in 2002, compared with $60.9 million in 2001 and $57.4
million in 2000. The increase resulted from NU paying a $0.125 per share
quarterly common dividend in the first two quarters of 2002 and a $0.1375 per
share quarterly dividend in the last two quarters of 2002. The level of
quarterly common dividend payments during 2001 was $0.10 per share during the
first two quarters of 2001 and $0.125 during the last two quarters of 2001. The
increase in the common dividend was partially offset by a decrease in
outstanding shares.
Management expects to continue to increase the dividend level, subject to NU's
ability to meet earnings targets and the judgment of its Board of Trustees at
the time the dividends are declared. On January 13, 2003, the NU Board of
Trustees approved the payment of a $0.1375 per share dividend payable on March
31, 2003, to shareholders of record at March 1, 2003.
Despite the increase in the common dividend, NU parent ended the year with a
high level of liquidity, all of which was loaned to subsidiaries through the NU
Money Pool or through direct loans. The parent company's cash levels increased
as a result of continued return of equity capital from its regulated
subsidiaries, as well as their payment of common dividends to the parent. In
2002, CL&P paid $60.1 million of dividends to NU parent and returned another
$100 million of equity capital through share repurchases. PSNH paid $45 million
of dividends in 2002, in addition to the return of another $37 million of equity
capital. As a result of the Seabrook sale, NAEC paid $5 million of dividends and
returned another $35 million of equity capital to NU. WMECO paid $16 million of
dividends and returned $14 million of equity capital to NU. The parent company
also received another $10 million in dividends from NGC through its parent
company, NUEI along with $3 million directly from NUEI. The parent company's
liquidity is reinforced by no debt maturities, a modest common dividend, and
minimal sinking fund payments of $23 million in 2003 and $24 million in 2004.
Equity capital transactions between NU parent and its subsidiaries are
eliminated in consolidation.
Regulated Utilities: NU's regulated utilities had a modest level of financings
in 2002. In January 2002, PSNH issued an additional $50 million in rate
reduction bonds and used the proceeds to repay short-term debt that was incurred
to buyout a purchased-power contract in December 2001. In April 2002, NU issued
$263 million of 7.25 percent senior unsecured notes due on April 1, 2012.
Proceeds from the refinancing were used to redeem a similar amount of variable
rate notes that were issued on February 28, 2001 related to the Yankee merger.
In November 2002, the regulated utilities renewed their $300 million credit
line, under terms similar to the arrangement that expired in November 2002. A
previous credit line had provided up to $350 million for the regulated
companies. There were $7 million in borrowings on this credit line at December
31, 2002.
In addition to its revolving credit arrangement, CL&P can access up to $100
million by selling certain of its accounts receivable. At December 31, 2002,
CL&P had $40 million outstanding under this arrangement. The current accounts
receivable arrangement is expected to be renewed in July 2003.
Rate reduction bonds are included on the consolidated balance sheets of NU,
CL&P, PSNH and WMECO, even though the debt is nonrecourse to these companies. At
December 31, 2002, these companies had a total of $1.9 billion in rate reduction
bonds outstanding, compared with $2 billion outstanding at December 31, 2001.
All outstanding rate reduction bonds of CL&P are scheduled to amortize by
December 30, 2010, with those of PSNH scheduled to fully amortize by May 1,
2013, and those of WMECO scheduled to fully amortize by June 1, 2013. Interest
on the rate reduction bonds totaled $115.8 million in 2002, compared with $87.6
million in 2001. Amortization of the rate reduction bonds totaled $169 million
in 2002, compared with $100 million in 2001. CL&P, PSNH and WMECO fully
recovered the amortization and interest payments from customers in 2002 and the
bonds had no impact on net income. Moreover, because the debt is nonrecourse to
these companies, the three rating agencies that rate their debt and preferred
stock securities do not include the revenues, expenses, or outstanding
securities related to the rate reduction bonds in establishing the credit
ratings of NU or its subsidiaries.
CL&P and Yankee Gas have embarked upon significant upgrade programs within their
service territories. Over the past five years, CL&P has increased its annual
level of investment in electric utility plant by approximately 50 percent. Much
of the additional investment has been devoted to improving the reliability of
CL&P's electric distribution system. Over the next several years, CL&P has
proposed a significant expansion of its 345,000 volt electric transmission
system into southwestern Connecticut at a cost that is likely to exceed $500
million. If Connecticut regulators approve the expansion, CL&P's construction
expenditures are projected to exceed $350 million annually from 2004 through
2007. Such a program would exceed CL&P's projections for internally generated
operating cash flows, and therefore, CL&P expects to access the capital markets
for financing during this period. In 2003, CL&P is expected to generate enough
cash internally to fund most, if not all, of its capital needs.
Yankee Gas, pursuant to the recommendations of the Connecticut Department of
Public Utility Control (DPUC) when it approved NU's acquisition of Yankee, has
embarked upon a significant expansion within its service territory. Yankee has
not paid a common dividend since it merged with NU in 2000, using its internally
generated cash to fund its expansion program. This expansion will likely require
Yankee Gas to issue new debt. Although Yankee Gas' debt is not currently rated,
management believes Yankee Gas would be able to attract capital at a reasonable
cost due to its regulated activities and strong balance sheet. At December 31,
2002, Yankee Gas had $215.4 million of common equity, excluding common equity
related to goodwill, and $151.4 million of long-term debt.
PSNH funded its capital expenditures through internally generated cash flows and
through proceeds returned from NAEC as a result of the sale of Seabrook. PSNH
returned $37 million of equity capital to NU in 2002. PSNH's capital
expenditures are expected to total $116.3 million in 2003 and remain largely
funded through internally generated cash flows.
WMECO has applied to the Massachusetts Department of Telecommunications and
Energy (DTE) to refinance approximately $100 million of short-term and spent
nuclear fuel obligations. A decision is expected in the first half of 2003. CL&P
also is considering refinancing approximately $200 million of spent nuclear fuel
obligations in 2003.
Competitive Energy Subsidiaries: In November 2002, NU renewed its $350 million
credit line for the competitive energy subsidiaries, under terms similar to the
arrangement that expired in November 2002. A previous credit line had provided
up to $300 million for the competitive energy subsidiaries. There were $49
million in borrowings on this credit line at December 31, 2002, and Select
Energy had approximately $6.7 million in letters of credit outstanding to
provide credit assurance for wholesale power transactions.
NU's competitive businesses have minimal capital expenditures. NGC's capital
expenditures totaled $16.4 million while HWP's totaled $1 million and other
capital expenditures totaled $5.8 million in 2002. In July 2002, NU's
competitive energy subsidiaries acquired certain assets and assumed certain
liabilities of Woods Electrical Co., Inc. (Woods Electrical), an electrical
services company, and Woods Network Services, Inc. (Woods Network), a network
products and services company, for an aggregate adjusted purchase price of $16.3
million (collectively Woods). NU made no other business acquisitions in 2002.
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 (the Merger Agreement). On March 12, 2001, NU filed suit
against Con Edison in the United States District Court for the Southern District
of New York (the District Court) seeking damages in excess of $1 billion arising
from Con Edison's breach of the Merger Agreement.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for
breach of contract, fraudulent inducement and negligent misrepresentation. Con
Edison has claimed that it is entitled to recover a portion of the merger
synergy savings estimated to have a net present value of in excess of $700
million. NU disputes both Con Edison's entitlement to any damages as well as its
method of computing its alleged damages.
The companies have completed discovery in the litigation. Motions for summary
judgment were argued before the District Court on February 4, 2003. No trial
date has been set. At this stage of the litigation, management can predict
neither the outcome of this matter nor its ultimate effect on NU.
For further information regarding this litigation, see NU's 2002 report on Form
10-K, Item 3, "Legal Proceedings."
Implementation of Standard Market Design
On March 1, 2003, the New England independent system operator (ISO) implemented
a new Standard Market Design (SMD). As part of this effort, locational marginal
pricing (LMP) will be utilized to assign value and causation to transmission
congestion. Transmission congestion costs will be assigned to the load zone in
which the congestion occurs. Those costs are now spread across virtually all New
England electric customers. In addition, the implementation of SMD will impact
wholesale energy contracts with respect to the energy delivery points contained
in those contracts.
Regulated Utilities: Connecticut has been designated a single load
zone. Due to the transmission constraints and inadequate generation, Connecticut
could experience significant additional congestion costs under SMD. The New
England ISO estimates that the costs of transmission congestion for 2003 in New
England under SMD will range between $50 million and $300 million. The New
England ISO estimates that the majority of this congestion and its costs will be
in Connecticut, where approximately 80 percent are expected to be paid by CL&P
beginning on March 1, 2003. CL&P believes that under the terms of its standard
offer service contracts with its standard offer suppliers these costs are its
responsibility. The contracts with the standard offer suppliers expire on
December 31, 2003. In addition, the determination of the energy delivery points
associated with the standard offer service contracts under SMD could also
produce significant costs for CL&P that management cannot determine at this
time.
Another factor affecting the level of congestion costs is the designation of
certain generating units by the New England ISO as units needed for system
reliability. Some of the companies owning these units have applied to the
Federal Energy Regulatory Commission (FERC) for "reliability must run" (RMR)
treatment. RMR treatment allows these units to receive cost of service-based
payments that recognize their reliability value. Prior to March 1, 2003, all RMR
costs were spread across New England with all utilities being billed by the New
England ISO based upon their share of New England's load. NU's regulated
electric utilities were responsible for approximately 25 percent of these costs.
Effective with the March 1, 2003 implementation of SMD by the New England ISO,
RMR costs will be allocated to the load zone in which the RMR unit is located.
At present, the only load zone that will experience a cost increase in which a
NU regulated electric company operates is Connecticut. With respect to the
Connecticut load zone, there are two generating units operating under a RMR
contract with an additional contract pending before FERC. These contracts are
for one year terms, and one contract contains an extension option. On a combined
basis, these two RMR contracts will result in an annual cost of approximately
$45 million to the Connecticut load zone. CL&P accounts for approximately 80
percent of the Connecticut load zone, and would be responsible for approximately
$36 million of this cost. In the near future, it is probable that there will be
significant new requests for RMR treatment in Connecticut which, if approved by
FERC, would add significant additional costs to the total cost of energy in
Connecticut. However, generating units operating under RMR contracts could
potentially mitigate the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of
providing regulated electric service in Connecticut. A DPUC regulatory
proceeding is expected to be initiated soon to determine the appropriate
recovery mechanism for these costs. If these costs are incurred before the final
recovery mechanism is established by the DPUC, CL&P expects to record a
regulatory asset for those costs incurred. See Critical Accounting Policies and
Estimates - Regulatory Accounting and Assets included in management's discussion
and analysis for further information.
Competitive Energy Subsidiaries: The implementation of SMD in New England will
create challenges and opportunities for Select Energy. The impact of SMD on its
wholesale marketing business could be significant. The determination of the
energy delivery points in many wholesale marketing contracts and the location of
sources of supply could have a significant effect. As more information regarding
the timing and impact of SMD becomes available, there could be additional
adverse effects that management cannot determine at this time.
Competitive Energy Subsidiaries
Subsidiaries: NU's competitive energy subsidiaries include HWP and NUEI, which
is the parent company of Select Energy and its subsidiary Select Energy New
York, Inc. (SENY), NGC, SESI, and NGS. Select Energy engages in wholesale and
retail energy marketing activities and energy trading activities.
NU's competitive energy subsidiaries own 1,438 MW of generation capacity,
consisting of 1,291 MW at NGC and 147 MW at HWP, which are used to support
Select Energy's wholesale marketing business.
SESI performs energy management services for large industrial, commercial and
institutional facilities, including the United States Department of Defense, and
engages in energy related construction services. NGS operates and maintains
NGC's and HWP's generation assets and provides third-party electrical,
mechanical, and engineering contracting services.
Outlook: NU is taking a number of steps to return the competitive energy
businesses to profitability in 2003 from the loss of $54.1 million in 2002. NU
has acquired additional energy services businesses and expects that after
essentially break-even earnings in 2002, they will be profitable in 2003.
Select Energy engages in energy trading activities primarily for price discovery
and risk management purposes. Select Energy has considerably reduced its
speculative trading activities and the amount of capital at risk in the trading
operation to a daily average of approximately $0.4 million from up to $6 million
in early 2002, and projects that the after-tax loss of approximately $24 million
in 2002 will turn into modest profits in 2003. The 2002 results were negatively
impacted by an increase in natural gas prices during March and April 2002.
Significant contributing factors to the 2002 loss in the retail marketing
business were unprofitable energy contracts and unusually mild weather which
significantly reduced natural gas sales. Many of the unprofitable contracts
expired in 2002. Select Energy plans to size the retail marketing organization
to fit the expected level of business and expects to better manage volumetric
risk, particularly in the winter heating months. As a result, management expects
to break-even in the retail marketing business in 2003, compared with a loss of
approximately $28 million in 2002. To achieve this result in 2003, Select Energy
must obtain new retail business and successfully manage its portfolio of retail
contracts.
In the wholesale marketing business, Select Energy, including NGC and HWP,
expects to be profitable in 2003, compared with essentially break-even
performance in 2002. Select Energy expects significant improvement to come from
improved results on its contract with CL&P, improved management of power supply
contracts, and a return to normal river conditions around NGC's conventional
hydroelectric plants. Select Energy expects the CL&P contract to be between
breakeven and a loss of $10 million in 2003 compared to a loss of $47 million in
2002. Near drought conditions in New England, particularly in the first three
quarters of 2002, lowered pre-tax earnings by approximately $6 million in 2002.
This earnings projection also assumes that Select Energy will be successful in
securing a significant amount of new business at acceptable margins and managing
its wholesale marketing portfolio. NGC owns 1,291 MW of primarily hydroelectric
generation capacity in Massachusetts and Connecticut and earned $30.4 million in
2002 and $42.3 million in 2001. HWP owns a 147 megawatt coal-fired plant in
Holyoke, Massachusetts and lost $0.9 million in 2002 following earnings of $4.4
million in 2001. Select Energy has wholesale contracts with NGC and HWP to
purchase all of the output of their generation assets. Accordingly, the results
of these companies are included in Select Energy's wholesale marketing business.
CL&P's standard offer service purchases from Select Energy represented
approximately $501 million of total competitive energy subsidiaries' revenues
for 2002, compared with approximately $497 million for 2001. Other transactions
between CL&P and Select Energy amounted to approximately $130 million in
revenues for Select Energy for 2002, compared with approximately $151 million in
2001. These amounts are eliminated in consolidation.
Additionally, WMECO's purchases from Select Energy represented approximately $14
million and $4 million of total competitive energy subsidiaries' revenues in
2002 and 2001, respectively.
In 2002, the competitive energy subsidiaries concluded a study of the
depreciable lives of certain generation assets. The impact of this study was to
lengthen the useful lives of those generation assets by 32 years to an average
of 70 remaining years. In addition, the useful lives of certain software was
revised and shortened to reflect a remaining life of 1.5 years. As a result of
these studies, NU's operating expenses decreased by approximately $5.1 million
in 2002 and are expected to decrease by approximately $9.4 million for 2003.
Competitive Energy Subsidiaries' Market and Other Risks
Overview: NU's competitive energy subsidiaries are exposed to certain market
risks inherent in their business activities. Certain competitive energy
subsidiaries, primarily Select Energy, enter into contracts of varying lengths
of time to buy and sell energy commodities, including electricity, natural gas
and oil. Market risk represents the risk of loss that may impact Select Energy's
financial results due to adverse changes in commodity market prices.
Risk management within the competitive energy subsidiaries, including Select
Energy, is organized by management to address the market, credit and operational
exposures arising from the company's primary business segments including
wholesale marketing, retail marketing and trading. The framework and degree to
which these risks are managed and controlled is consistent with the limitations
imposed by NU's Board of Trustees as established and communicated in NU's
overall risk management policies and procedures. As a means to monitor and
control compliance with these policies and procedures, NU has formed a Risk
Oversight Council (ROC) to monitor competitive energy risk management processes
independently from the businesses that create or manage these risks. The ROC
ensures that the polices pertaining to these risks are followed and makes
recommendations to the Board of Trustees regarding periodic adjustment to the
metrics used in measuring and controlling portfolio risk while also confirming
the methodologies employed by management to discern portfolio values.
Wholesale and Retail Marketing: A significant portion of Select Energy's
wholesale marketing business is providing energy to full requirements customers,
primarily regulated distribution companies. Under full requirements contract
terms, Select Energy is required to provide the total energy requirement for the
customers' load at all times. Wholesale and retail marketing transactions,
including the full requirements contracts, are intended to be part of Select
Energy's normal purchases and sales and are recognized on the accrual basis of
accounting.
An important component of Select Energy's risk management strategy is focused on
managing the volume and price risks of full requirements contracts. These risks
include significant fluctuations in supply and demand due to numerous factors
such as weather, plant availability, transmission congestion, and potentially
volatile price fluctuations. Select Energy uses energy contracts to hedge these
risks. While not classified as hedges for accounting purposes, these contracts,
which are included in the wholesale and retail marketing portfolios and are
subject to accrual accounting, are important to Select Energy's risk management.
As discussed above, Select Energy's 2002 results were negatively impacted by
weather patterns that resulted in contracted supply exceeding demand in the
warmer than expected winter and purchasing supply during certain summer months
at prices higher than those forecasted.
The competitive energy subsidiaries manage their portfolio of wholesale and
retail marketing contracts and assets to maximize value while maintaining an
acceptable level of risk. The lengths of contracts to buy and sell energy vary
in duration from daily/hourly to several years. At any point in time, the
wholesale and retail marketing portfolio may be long (purchases exceed sales) or
short (sales exceed purchases). Portfolio and risk management disciplines with
established policies and procedures are used to manage exposures to market
risks. At forward market prices in effect at December 31, 2002, the wholesale
marketing portfolio, which includes the CL&P standard offer service contract and
other contracts that extend to 2013, had a positive fair value. This positive
fair value indicates a positive impact on Select Energy's gross margin in the
future. However, there is significant volatility in the energy commodities
markets that will impact this position between now and when the contracts are
settled. Portfolio volatility reflects fluctuations in value due to changes in
energy prices in the region, new transactions entered into during the period and
positions settling during the period. Accordingly, there can be no assurances
that Select Energy will realize the gross margin corresponding to the present
positive fair value on its wholesale marketing portfolio. The gross margin
realized could be at a level that is not sufficient to cover Select Energy's
other operating costs, including the cost of corporate overhead.
Hedging: Select Energy utilizes derivative financial and commodity instruments,
including futures and forward contracts, to reduce market risk associated with
fluctuations in the price of electricity and natural gas purchases for firm
sales commitments to 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 retail supply
requirements. These derivatives have been designated as cash flow hedging
instruments and are used to reduce the market risk associated with fluctuations
in the price of electricity, natural gas or oil. A derivative that effectively
hedges exposure to the variable cash flows of a forecasted transaction (a cash
flow hedge) is initially recorded at fair value with changes in fair value
recorded in other comprehensive income, which is a component of equity. Hedges
impact earnings when the forecasted transaction being hedged occurs, when hedge
ineffectiveness is measured and recorded, when the forecasted transaction being
hedged is no longer probable of occurring, or when there is accumulated other
comprehensive loss and the hedge and the forecasted transaction being hedged are
in a loss position on a combined basis. At December 31, 2002, Select Energy had
hedging derivative assets of $22.8 million and hedging derivative liabilities of
$2 million. At December 31, 2001, Select Energy had hedging derivative assets of
$2.9 million and hedging derivative liabilities of $60.7 million. The change
from hedging derivative liabilities at December 31, 2001 to hedging derivative
assets at December 31, 2002 resulted primarily from increased natural gas prices
and the maturity or termination of hedge instruments existing at December 31,
2001.
Energy Trading: Energy trading transactions at Select Energy include financial
transactions and physical delivery transactions for electricity, natural gas and
oil in which Select Energy is attempting to profit from changes in market
prices. Energy trading contracts are recorded at fair value, and changes in fair
value impact earnings. For information regarding changes in accounting for
energy trading transactions, see Note 1C, "New Accounting Standards," to the
consolidated financial statements.
At December 31, 2002, Select Energy had trading derivative assets of $102.9
million and trading derivative liabilities of $61.9 million on a
counterparty-by-counterparty basis, for a net positive position of $41 million
on the entire trading portfolio. At December 31, 2001, Select Energy had trading
derivative assets of $147.2 million and trading derivative liabilities of $90.8
million on a counterparty-by-counterparty basis, for a net positive position of
$56.4 million on the entire trading portfolio. These amounts are combined with
other derivatives and are included in derivative assets and derivative
liabilities on the accompanying consolidated balance sheets. Information
regarding the other derivatives is included in Note 3, "Derivative Instruments,
Market Risk and Risk Management," to the consolidated financial statements.
There can be no assurances that Select Energy will actually realize cash
corresponding to the present positive net fair value of its trading portfolio.
Numerous factors could either positively or negatively affect the realization in
cash of the net fair value amount. These include the volatility of commodity
prices, changes in market design or settlement mechanisms, the outcome of future
transactions, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all trading positions to be
marked-to-market at the end of each trading day. Controls are in place
segregating responsibilities between individuals actually trading (front office)
and those confirming the trades (middle office). The determination of the
portfolio's fair value is the responsibility of the middle office independent
from the front office. The methods used to determine the fair value of energy
trading contracts are identified and segregated in the table of fair value of
contracts at December 31, 2002 and 2001 below. A description of each method is
as follows: 1) prices actively quoted primarily represent New York Mercantile
Exchange futures and options that are marked to closing exchange prices; 2)
prices provided by external sources primarily include over-the-counter forwards
and options, including bilateral contracts for the purchase or sale of
electricity or natural gas, and are marked to the mid-point of bid and ask
quotes; and 3) prices based on models or other valuation methods primarily
include forwards and options and other transactions for which specific quotes
are not available. These transactions are modeled using recognized option
pricing models. The option component of a forward electricity purchase contract
had a fair value of $4.5 million at December 31, 2002, and is the only amount
included in this method of determining fair value. The fair value of this
contract component at December 31, 2001 was not material. Broker quotes for
electricity are available through the year 2005, and models are generally used
for the years 2006 and thereafter. Select Energy has procured sourcing for the
contracts with maturities in excess of four years. Accordingly, the value of
these contracts and the related power supply contracts do not need to be
determined with a model. Broker quotes for natural gas are available through
2013. The decrease in the number of counterparties participating in the
market for long-term energy contracts continues to impact Select Energy's
ability to determine the estimated fair value of its long-term energy contracts.
Generally, valuations of short-term contracts derived from quotes or other
external sources are more reliable should there be a need to liquidate the
contracts, while valuations based on models or other methods for longer-term
contracts are less certain. Accordingly, there is a risk that contracts will not
be realized at the amounts recorded.
As of and for the years ended December 31, 2002 and 2001, respectively, the
sources of the fair value of trading contracts and the changes in fair value of
these trading contracts are included in the following tables. Intercompany
transactions are eliminated and not reflected in the amounts below.
(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2002
- --------------------------------------------------------------------------------
Maturity Maturity Maturity
Less Than of One to in Excess of Total
Sources of Fair Value One Year Four Years Four Years Fair Value
- --------------------------------------------------------------------------------
Prices actively quoted $(1.2) $ 0.1 $ -- $(1.1)
Prices provided by
external sources 2.8 20.2 14.6 37.6
Prices based on models
or other valuation methods -- 4.5 -- 4.5
- --------------------------------------------------------------------------------
Totals $ 1.6 $24.8 $14.6 $41.0
================================================================================
(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2001
- --------------------------------------------------------------------------------
Maturity Maturity Maturity
Less Than of One to in Excess of Total
Sources of Fair Value One Year Four Years Four Years Fair Value
- --------------------------------------------------------------------------------
Prices actively quoted $ 6.5 $ 6.8 $ -- $13.3
Prices provided by
external sources 6.5 15.8 20.8 43.1
Prices based on models
or other valuation methods -- -- -- --
- --------------------------------------------------------------------------------
Totals $13.0 $22.6 $ 20.8 $56.4
================================================================================
As indicated in the tables, the fair value of energy trading contracts
decreased $15.4 million from $56.4 million at December 31, 2001 to $41 million
at December 31, 2002. This decrease, combined with the realized losses on
positions taken and closed in 2002, is included in Select Energy's gross margin
and, after it is tax affected, is reflected in the $24 million that Select
Energy's trading business lost in 2002.
Years Ended December 31,
2002 2001
- -------------------------------------------------------------------------------
(Millions of Dollars) Total Fair Value
- --------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the beginning of the period $56.4 $13.8
Acquisition of SENY -- 10.9
Contracts realized or otherwise settled
during the period (4.0) (9.4)
Fair value of new contracts when entered
into during the period 13.7 58.6
Changes in fair values attributable to changes
in valuation techniques and assumptions (39.9) --
Changes in fair value of contracts 14.8 (17.5)
- --------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the end of the period $41.0 $56.4
================================================================================
During the first quarter of 2002, Select Energy terminated certain long-term
energy contracts. Coincident with these contract terminations, new contracts
were entered into with different terms and conditions. Select Energy also
entered into several new contracts with existing counterparties. These new
energy trading contracts are trading derivatives, and collectively they had a
positive fair value of $13.7 million when entered into. In 2001, Select Energy
entered into certain contracts with a fair value of $58.6 million when entered
into.
Effective October 1, 2002, Select Energy adopted a consensus reached by the
Emerging Issues Task Force (EITF) on October 25, 2002 in Issue No. 02-3,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." Adopting this consensus required management to conduct a thorough
review of contracts in the trading portfolio to determine if there were any
contracts in the trading portfolio that were not derivatives, as defined.
Management determined that there were no nonderivative contracts in the energy
trading portfolio, and as such, there was no cumulative effect of an accounting
change as of October 1, 2002.
In connection with management's review of the contracts in the trading
portfolio, the significant changes in the energy trading market and the change
in the focus of the energy trading business, certain long-term derivative energy
contracts that were included in the trading portfolio and valued at $33.9
million at November 30, 2002, were designated as normal purchases and sales. The
impact of this designation is that the contracts were adjusted to fair value at
November 30, 2002 and were not and will not be adjusted subsequently for changes
in fair value. The $33.9 million carrying value of these contracts was
reclassified from trading derivative assets to other long-term assets and will
be amortized on a straight-line basis to fuel, purchased and net interchange
power expense over the remaining terms of the contracts, some of which extend to
2011. This amount is included in changes in fair values attributable to changes
in valuation techniques and assumptions.
The other negative $6 million reflected in changes in fair value attributable to
changes in valuation techniques and assumptions relates to $12 million of
contracts held by SENY at acquisition that were determined to be held for
nontrading purposes by Select Energy. Accordingly the $12 million of contracts
were removed from the trading portfolio. Long-term trading contracts with
maturities in excess of four years and transmission congestion contracts were
revalued during the year based on the availability of market information, which
added $6 million to the value of the trading portfolio.
Late in the fourth quarter of 2002, Select Energy began to receive reliable
market information concerning the impact of LMP in New England with the
implementation of SMD, which is currently scheduled for March 1, 2003. Select
Energy began to use this market information in its valuation of contracts in the
trading portfolio. The impact of using this information was to reduce the
portfolio value by $10.3 million, which is reflected as a negative amount in
changes in fair value of contracts.
Nontrading: Nontrading derivative contracts are for delivery of energy related
to the competitive energy subsidiaries' retail and wholesale marketing
activities. At December 31, 2002, Select Energy had nontrading derivative assets
of $2.9 million and no nontrading derivative liabilities. At December 31, 2001,
Select Energy had no nontrading derivative assets or liabilities.
Changing Market: The breadth and depth of the market for energy trading and
marketing products in Select Energy's market has been adversely affected by the
withdrawal or financial weakening of a number of companies who have historically
done significant amounts of business with Select Energy. In general, the market
for such products has become shorter term in nature with less liquidity, and
participants are more often unable to meet Select Energy's credit standards
without providing cash or letter of credit support. Select Energy is being
adversely affected by these factors, and there could be a continuing adverse
impact on Select Energy's business prospects.
Changes are occurring in the administration of transmission systems in
territories in which Select Energy does business. Regional transmission
organizations (RTO) are being contemplated, and other changes are occurring
within transmission regions. For example, the impact of the implementation of
SMD on Select Energy's existing positions resulted in a decrease of $10.3
million in the fair value of Select Energy's trading portfolio. The impact of
SMD on its wholesale marketing business is potentially more significant. The
determination of the energy delivery points in many wholesale marketing
contracts and the location of generation assets included in the wholesale
marketing business could be significantly affected. As more information
regarding the timing and impact of SMD becomes available, there could be
additional adverse effects that management cannot determine at this time.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that
Select Energy would incur as a result of non-performance by counterparties
pursuant to the terms of their contractual obligations. Select Energy has
established written credit policies with regard to its counterparties to
minimize overall credit risk. These policies require an evaluation of potential
counterparties' financial conditions (including credit ratings), collateral
requirements under certain circumstances (including cash in advance, letters of
credit, and parent guarantees), and the use 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 Select Energy entering into trading activities. The appropriateness of these
limits is subject to continuing review.
Concentrations among these counterparties may impact Select Energy'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. At December 31, 2002, approximately 83 percent of Select
Energy's counterparty credit exposure to wholesale marketing and trading
counterparties is cash collateralized or rated BBB- or better. In excess of half
of the remaining credit exposure is to unrated municipalities.
At December 31, 2002, two positions with counterparties collectively represented
approximately 40 percent of the $102.9 million trading derivative assets. All
other counterparties represented less than 10 percent of the trading derivative
assets. Select Energy manages the credit risk of its trading portfolio in
accordance with established credit risk management policies and procedures.
Select Energy Credit: A number of Select Energy's contracts require the posting
of additional collateral in the form of cash or letters of credit in the event
NU's ratings were to decline and in increasing amounts dependent upon the
severity of the decline. At NU's present investment grade ratings, Select Energy
has not had to post any collateral based on credit downgrades. Were NU's
unsecured ratings to decline two to three levels to sub-investment grade, Select
Energy could, under its present contracts, be asked to provide approximately
$140 million of collateral or letters of credit to various unaffiliated
counterparties and approximately $80 million to several ISOs and unaffiliated
local distribution companies, which NU, under present circumstances, would be
able to provide from available sources. NU's ratings are currently stable, and
management does not believe that at this time there is a significant risk of a
ratings downgrade to sub-investment grade levels.
For further information regarding Select Energy's activities and risks see Note
3, "Derivative Instruments, Market Risk and Risk Management," and Note 11,
"Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial
statements.
Business Development and Capital Expenditures
Consolidated: NU anticipates that it will continue to increase its level
of capital expenditures at its regulated subsidiaries to meet customers'
increasing needs for additional and more reliable energy supplies. Investments
in regulated utility plant, excluding nuclear fuel, totaled $468.8 million in
2002, compared with $428.3 million in 2001 and $345.6 million in 2000. NU
expects that level to reach $640.2 million in 2003 and may be as high as $650
million in 2004, if CL&P's plans to expand its 345,000 volt transmission system
are approved.
Regulated Utilities: CL&P's capital expenditures, excluding nuclear fuel,
totaled $242.3 million in 2002, compared with $237.4 million in 2001 and $208.2
million in 2000. CL&P expects capital expenditures to increase to $326.9 million
in 2003. CL&P spent $141.2 million related to its overhead and underground
electric distribution system in 2002 and expects to spend a similar amount in
2003. CL&P spent $35.6 million to upgrade its transmission system in 2002, and
expects its transmission capital expenditures to increase to $95 million in
2003, if its current construction plans receive regulatory approval. CL&P also
spent $20 million on new meters and customer services, and $17 million on
substations in 2002.
In 2001, CL&P announced plans for three transmission projects. In September
2002, the Connecticut Siting Council (CSC) approved the first project, a plan to
replace an undersea electric transmission line between Norwalk, Connecticut and
Northport - Long Island, New York, at an estimated cost of $80 million. CL&P
owns 50 percent of the line with the Long Island Power Authority also owning 50
percent. The project still requires federal and New York state approvals. Given
the approval process and the uncertainty created by the recent damage to the
existing transmission line, the expected in-service date is currently under
evaluation. At December 31, 2002, CL&P has capitalized approximately $4.8
million related to this project.
In early 2003, the CSC completed hearings on the second project, a $135 million
proposal to build a new 345,000 volt transmission line between Norwalk,
Connecticut and Bethel, Connecticut. A decision is expected in April 2003. The
current cost estimate is based on building the entire transmission line
aboveground. Alternative proposals have been made to build all or part of the
line underground, which likely would result in significantly higher construction
costs. CL&P hopes to have the new transmission line operational by the summer of
2005. At December 31, 2002, CL&P has capitalized approximately $8.8 million
related to this project.
By mid-2003, CL&P expects to apply to the CSC for approval of a third project,
the installation of another 345,000 volt transmission line between Norwalk,
Connecticut and Middletown, Connecticut. Estimated construction costs of this
overhead line are approximately $500 million. CL&P will jointly construct this
project with United Illuminating with CL&P owning 80 percent or approximately
$400 million of the project. At December 31, 2002, CL&P has capitalized
approximately $2.4 million related to this project.
Construction of these three projects would significantly enhance CL&P's ability
to provide reliable electric service to the rapidly growing energy market in
southwestern Connecticut. Despite the need for such facilities, significant
opposition has been raised. As a result, management cannot be certain as to the
expected in-service dates or the ultimate cost of these projects. Should the
plans proceed, applicable law provides that CL&P will be able to recover its
operating cost and carrying costs through federally approved transmission
tariffs.
Yankee Gas has also proposed expansion of its gas distribution system in
Connecticut. Yankee Gas' capital expenditures totaled $70.8 million in 2002,
compared with $47.8 million in 2001 and $21.6 million in 2000. Yankee Gas
expects capital expenditures to total $72.9 million in 2003 as it continues to
expand its distribution system and expects to begin work on a liquefied natural
gas storage facility proposed in Waterbury, Connecticut.
The expectation that PSNH will retain its generation assets, at least through
2004, will result in higher near-term capital expenditures at PSNH. PSNH's
capital expenditures, excluding nuclear fuel, totaled $109.8 million in 2002,
compared with $92.6 million in 2001 and $69.5 million in 2000. Capital
expenditures are expected to total $116.3 million in 2003, as PSNH continues to
upgrade and expand its distribution and transmission system and upgrade its
generation plants.
On December 5, 2002, PSNH announced an agreement to acquire the franchise and
electric system of Connecticut Valley Electric Company, Inc. (CVEC), a
subsidiary of Central Vermont Public Service Corporation (CVPS) that serves
approximately 10,000 customers in western New Hampshire. Under the agreement,
PSNH will pay CVPS approximately $9 million for its assets and an additional $21
million to terminate a wholesale power contract between CVPS and CVEC. Customers
of CVEC will become customers of PSNH, whose residential rates are now
approximately 20 percent lower than those of CVEC. PSNH will be allowed to
recover the $21 million payment with a return consistent with Part 3 stranded
cost treatment under the "Agreement to Settle PSNH Restructuring" (Restructuring
Settlement). Part 3 stranded costs are nonsecuritized regulatory assets which
must be recovered by a recovery end date determined in accordance with the
Restructuring Settlement or be written off. The sale agreement is supported by
the New Hampshire Governor's Office, New Hampshire Public Utilities Commission
(NHPUC) staff, the state Office of Consumer Advocate, the City of Claremont, and
New Hampshire Legal Assistance. The FERC and the NHPUC must approve the sale,
which is expected to become effective on January 1, 2004.
As a result of a lower projected growth rate and an adequately sized
transmission system to meet near term needs, WMECO does not forecast significant
changes in its construction program. WMECO's capital expenditures, excluding
nuclear fuel, totaled $23.4 million in 2002, compared with $30.9 million in 2001
and $27.3 million in 2000. WMECO's capital expenditures are expected to total
$28.1 million in 2003.
Competitive Energy Subsidiaries: Capital expenditures at NU's competitive
generation subsidiaries, NGC and HWP, are expected to be modest in 2003, with
$12.1 million at NGC and $3.8 million at HWP. In 2002, NGC's and HWP's capital
expenditures totaled $16.4 million and $1 million, respectively.
In recent years, NU has considered several additional investments in the
competitive energy business. In 2001, NU proposed constructing a completely new
direct current cable between Norwalk, Connecticut and Long Island, New York to
serve the merchant power market. However, because of growing financial distress
in the merchant power industry, NU concluded that such a project was not
feasible at the time and withdrew its proposal from the FERC in November 2002.
NU also has considered investing in additional peaking or intermediate
generation in the New York and the Mid-Atlantic states. However, NU concluded in
2002 that potential returns on such investments were not adequate given the
likely purchase prices.
NU continues to examine niche acquisitions in the energy services business. In
2002, NU acquired Woods Electrical and Woods Network for an aggregate adjusted
purchase price of $16.3 million. In 2001, NU acquired the E.S. Boulos Company
(Boulos), a high-voltage electrical contractor based in Maine, and Niagara
Mohawk Energy Marketing, Inc., an energy marketing company based in New York
that was subsequently renamed SENY. Both Boulos and SENY were profitable, with
Boulos earning $2.7 million and SENY earning $17.2 million for the year ended
December 31, 2002. Since acquisition on July 1, 2002, Woods earned $0.1 million.
Regional Transmission Organization
The FERC has required all transmission owning utilities to voluntarily start
forming RTOs or to state why this process has not begun.
NU has been discussing with the other transmission owners in New England the
potential to form an Independent Transmission Company (ITC). If formed, 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 regarding the energy market and short-term reliability. Together, the
ITC, if formed, and ISO would form the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their intention to
form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to
FERC. The New England ISO intends to make an RTO filing with the transmission
owners in New England in 2003.
The agreements needed to create the RTO and to define the working relationships
among the ISO and the transmission owners should be created in 2003, and will
allow the RTO to begin operation shortly thereafter. The agreements are expected
to include provisions for the future creation of one or more ITCs within the
RTO. The creation of the 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. At December 31, 2002, NU capitalized $1.3 million related to RTO formation
activities.
Merchant Energy Company Counterparty Exposures
Certain subsidiaries of NU, including CL&P, Yankee Gas, Select Energy, and NGS,
have entered into various transactions with subsidiaries of NRG Energy, Inc.
(NRG). NRG's credit rating has been downgraded to below investment grade by all
three major rating agencies, and NRG is presently in default on debt service
payments. Management does not expect that the resolution of the transactions
with NRG will have a material adverse effect on NU's consolidated financial
condition or results of operations. Additionally, NU does not have a significant
level of exposure to other merchant energy companies. For further information
regarding these transactions, see NU's 2002 report on Form 10-K, Item 1,
"Business."
Restructuring and Rate Matters
Connecticut - CL&P: Since retail competition began in Connecticut in 2000, an
extremely small number of customers have opted to choose an alternate supplier.
At December 31, 2002, virtually all of CL&P's customers were procuring their
electricity through CL&P's standard offer service. In 2003, Select Energy will
continue to supply 50 percent of CL&P's standard offer supply service with NRG
Power Marketing, Inc. (NRG-PM), a subsidiary of NRG, contracted to supply 45
percent and a subsidiary of Duke Energy, Inc. contracted to supply the remaining
5 percent of service. On November 18, 2001, at NRG-PM's request, CL&P filed an
application with the DPUC to raise the standard offer rate from an average of
$0.0495 per kilowatt-hour (kWh) to $0.0595 per kWh to help promote competition
in advance of the January 1, 2004 termination of the standard offer period and
to provide financial relief to 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 competition in Connecticut and the financial condition of
the suppliers. The first docket culminated in a joint study report issued in a
DPUC decision on February 15, 2002, which provided the DPUC's and the Office of
Consumer Counsel's findings on how to best structure default service and other
issues related to electric industry restructuring. In the second docket, the
DPUC concluded on June 17, 2002, that it would not commence further proceedings.
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new
proposal with the DPUC to maintain current total rates, but to shift $0.007 per
kWh from being used to recover stranded costs to instead provide additional
payments to NRG-PM and Select Energy to ensure electric reliability in
southwestern Connecticut. On July 26, 2002, the DPUC denied the proposal.
CL&P continues to evaluate NRG-PM's ability to meet its obligations under the
standard offer service contract. If CL&P is required to seek an alternate source
of supply, CL&P would pursue recovery of any additional costs associated with
obtaining such supply from NRG-PM pursuant to the contract and may be required
to seek DPUC approval to flow through any such costs to customers. Management
believes that recovery of these costs, should they be incurred, would be
permitted under the provisions of Connecticut's electric utility restructuring
legislation and with the DPUC's prior decisions. On February 21, 2003, Fitch
Ratings lowered its rating outlook on CL&P to negative as a result of its
concern over timely recovery of purchased-power costs if NRG-PM were to default
on its CL&P standard offer obligations and CL&P needed to acquire replacement
supply service at significantly higher prices.
On September 27, 2001, CL&P filed its application with the DPUC for approval of
the disposition of the proceeds in the amount of approximately $1.2 billion from
the sale of the Millstone units. 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. The DPUC's final decision regarding this application was
issued on February 27, 2003, and increased the amount of net proceeds used to
reduce stranded costs by $26.9 million. The earnings impact of the final
decision will be reflected in 2003 earnings and will result in an increase in
first quarter net income of $2.6 million.
On November 1, 2002, CL&P sold its interest in Seabrook to a subsidiary of FPL
Group, Inc. (FPL). The gain on the sale was used to reduce stranded costs.
CL&P continues to be subject to the earnings sharing mechanism implemented by
the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on
equity will be shared equally by shareholders and ratepayers.
CL&P expects to file a distribution rate case with the DPUC in mid-2003 that
would be effective January 1, 2004. Also in the second half of 2003, CL&P will
need to secure bids for power supply contracts for 2004 to meet the needs of its
customers. Management has not yet identified what level of rates it will request
in 2004, but believes that several factors could combine to result in a
significant increase in supply costs in 2004. The first is the expiration of
current standard offer supply contracts. Another factor is the likely impact of
LMP in New England with the implementation of SMD. Implementation of such
pricing, which occurred on March 1, 2003, will force Connecticut electric
customers to bear the significant additional costs of serving southwestern
Connecticut with less efficient local generation because of insufficient
transmission capacity to bring cheaper energy into the region. CL&P's completed
and planned reliability improvements and transmission construction program will
also impact the level of rates management will request in 2004.
Connecticut - Yankee Gas: Following rate proceedings that began in 2001, the
DPUC ordered a $4 million rate decrease effective April 1, 2002. The decision
endorsed Yankee Gas' distribution expansion plan, subject to annual reviews, and
approved, with some conditions, its capital investment ratemaking recovery
mechanism, the Infrastructure Expansion Rate Mechanism (IERM). The final
decision also authorized an 11 percent return on equity for Yankee Gas and a
sharing formula between shareholders and ratepayers for earnings above that
level from 2002 through 2005.
On October 1, 2002, Yankee Gas filed supplemental testimony and exhibits to its
original IERM filing with the DPUC on August 1, 2002. This filing reflected
those 2001 through 2003 system expansion projects that Yankee Gas has undertaken
or plans to undertake by December 31, 2003, and that meet certain financial
criteria outlined by the DPUC. Yankee Gas is currently proposing no IERM charge
for 2003 and that any over-collection for 2003 be carried forward to the 2004
IERM period. A final decision from the DPUC regarding this filing is expected in
the first quarter of 2003.
A schedule has been set in Yankee Gas' proceeding before the DPUC to obtain rate
approval to build a two billion cubic foot liquefied natural gas storage and
production facility in Waterbury, Connecticut. The schedule includes hearings in
March 2003 with a final decision in the second quarter of 2003. If approved,
construction on the facility, which could cost approximately $60 million, could
begin in the fourth quarter of 2003.
In December 2002, the DPUC opened a new docket concerning Yankee Gas
overearnings. Hearings related to this docket are scheduled to be held in March
2003 with a final decision scheduled for May 2003, and management cannot
determine the ultimate impact of this docket.
New Hampshire: In July 2001, the NHPUC opened a docket to review the fuel and
purchased-power adjustment clause (FPPAC) costs incurred between August 2, 1999,
and April 30, 2001. Under the Restructuring Settlement, FPPAC deferrals are
recovered as a Part 3 stranded cost through the stranded cost recovery charge.
On December 31, 2002, the NHPUC issued its final order allowing recovery of
virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge
reconciliation filing with the NHPUC for the period May 1, 2001, through
December 31, 2001. This filing reconciles stranded cost revenues against actual
stranded cost charges with any difference being credited against stranded costs
or deferred for future recovery. Included in the stranded cost charges are the
generation costs for the filing period. The generation costs included in this
filing were subject to a prudence review by the NHPUC. In January 2003, PSNH
entered into a settlement agreement with the Office of Consumer Advocate and the
staff of the NHPUC that resolved all outstanding issues. In conjunction with the
settlement agreement, the NHPUC staff recommended no disallowances resulting
from their review of the outages at PSNH's generating plants. A final order
approving the settlement agreement was issued by the NHPUC in February 2003. The
NHPUC order approved PSNH's reconciliation of stranded costs as outlined within
the Settlement Agreement and had no impact on PSNH's earnings.
On September 12, 2002, the NHPUC issued a final decision approving the auction
results in the sale of Seabrook to FPL. On November 1, 2002, the sale was
consummated. The proceeds received by NAEC, after NAEC repaid its outstanding
debt, were refunded to PSNH through the Seabrook Power Contracts. PSNH used the
proceeds received from NAEC to recover stranded costs and repay debt with the
remaining proceeds to be returned to NU. As a result of the Seabrook sale, PSNH
expects its wholesale electric sales to decline significantly in 2003. However,
PSNH expects to generate most of the electricity it needs to serve retail
customers from its own generating plants or purchased-power obligations and to
purchase the remainder in the wholesale market.
On February 1, 2003, in accordance with the Restructuring Settlement, PSNH
raised the transition service rate for residential and small commercial
customers to $0.0460 per kWh from $0.0440 per kWh. On the same date, PSNH also
raised its transition service rate for large commercial and industrial customers
to $0.0467 per kWh from $0.0440 per kWh. PSNH expects these rates to be adequate
to recover its generation and purchased-power costs, including the recovery of
carrying costs on PSNH's generation investment. If recoveries exceed PSNH's
costs, those overrecoveries will be credited against PSNH's Part 3 stranded cost
balance. If actual costs exceed those recoveries, PSNH will defer those costs
for future recovery from customers through its Stranded Cost Recovery Charge.
PSNH's delivery rates are fixed until February 1, 2004. Under the Restructuring
Settlement, PSNH must file a rate case by December 31, 2003, for the purpose of
commencing a review of PSNH's delivery rates. Also, under New Hampshire electric
industry restructuring statutes, PSNH cannot divest its nonnuclear generation
assets until at least February 1, 2004. At this time, management does not expect
PSNH to propose selling its 1,200 MW of generation assets.
Massachusetts: In December 2001, the DTE approved approximately a 14 percent
reduction in WMECO's overall rates for standard offer service, primarily
reflecting a reduction in WMECO's standard offer service supply costs in 2002 to
approximately $0.048 per kWh from approximately $0.073 per kWh. In December
2002, the DTE approved an overall increase of approximately 1.8 percent in
WMECO's non-contract standard offer rates, primarily reflecting slightly
increased standard offer and default service costs as well as other inflationary
factors. Select Energy won the bid to supply WMECO with standard offer service
in 2003 at an average rate of approximately $0.050 per kWh. An unaffiliated
company won a bid to serve WMECO with default service for the period of January
1, 2003, through June 30, 2003, at an average price of $0.051 per kWh.
On June 7, 2002, the DTE issued its decision on WMECO's 1998 through 1999
stranded cost reconciliation. The decision included, among other things, a
conclusion that investment tax credits associated with generation assets that
have been divested should not be returned to ratepayers. As a result, WMECO
recognized approximately $13 million in tax credits during the second quarter of
2002.
On March 30, 2001, WMECO filed its second annual stranded cost
reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO
filed its 2001 annual transition cost reconciliation with the DTE. This filing
reconciled the recovery of stranded generation costs for calendar year 2001 and
includes sales proceeds from WMECO's portion of the Millstone units, the impact
of securitization and approximately a $13 million benefit to ratepayers from
WMECO's nuclear performance-based ratemaking process.
Subsequently, WMECO and the office of the Massachusetts Attorney General reached
a settlement resolving all transition charge issues for the 1998 through 2001
reconciliations. This settlement was filed for DTE review on December 3, 2002
and approved on December 27, 2002. The settlement had a positive impact of $9
million on WMECO 2002 pretax earnings.
For further information regarding commitments and contingencies related to
restructuring, see Note 8A, "Commitments and Contingencies - Restructuring and
Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interest in Seabrook.
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC)
consummated the sale of its nuclear generating unit. NU subsidiaries CL&P, PSNH,
and WMECO combined own 17 percent of VYNPC.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1
and 2 and CL&P, PSNH and WMECO sold their ownership interests in Millstone 3.
Under the terms of these asset divestitures, the purchasers agreed to assume
responsibility for decommissioning their respective units. For further
information regarding these divestitures and nuclear decommissioning, see Note
7, "Nuclear Generation Asset Divestitures," and Note 8F, "Nuclear
Decommissioning and Plant Closure Costs," to the consolidated financial
statements. For further information regarding spent nuclear fuel disposal costs,
see Note 8C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal
Costs," to the consolidated financial statements.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates, assumptions and at times difficult, subjective or complex judgments.
Changes in these estimates, assumptions and judgments, in and of themselves,
could materially impact the financial condition of NU. The following describes
accounting policies and estimates that management believes are the most critical
in nature:
Presentation: In accordance with current accounting pronouncements, NU's
consolidated financial statements include all subsidiaries upon which
significant control is maintained and all intercompany transactions between
these subsidiaries are eliminated as part of the consolidation process. NU has
less than 50 percent ownership interests in the Connecticut Yankee Atomic Power
Company, Yankee Atomic Electric Company, Maine Yankee Atomic Power Company,
VYNPC, two companies that transmit electricity imported from the Hydro-Quebec
system, NEON, Acumentrics, and R.M. Services, Inc., which are classified as
variable interest entities under Financial Accounting Standards Board
Interpretation No. 46, "Consolidation of Variable Interest Entities," and for
which NU was not classified as the primary beneficiary. As a result, management
does not expect the adoption of Interpretation No. 46 to result in the
consolidation of any currently unconsolidated entities or to have any other
material impacts on NU's consolidated financial statements.
Revenue Recognition: Regulated utility revenues are based on rates approved by
the state regulatory commissions. These regulated rates are applied to
customers' accounts based on their use of energy. In general, rates can only be
changed through formal proceedings with the state regulatory commissions.
The determination of the energy sales to individual customers is based on the
reading of their meters, which occurs on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. This unbilled revenue is estimated each month based on
generation volumes, estimated customer usage by class, line losses, and
applicable customer rates.
Competitive energy subsidiary revenues are recognized at different times for the
different businesses. Wholesale and retail marketing revenues are recognized
when energy is delivered. Trading revenues are recognized as the fair value of
trading contracts changes. Service revenues are recognized as services are
provided, often on a percentage of completion basis.
Energy Trading and Derivative Accounting: On October 1, 2002, NU adopted EITF
Issue No. 02-3. The consensuses in EITF Issue No. 02-3 require net reporting of
trading revenues and expenses, and rescinded EITF Issue No. 98-10, "Accounting
for Energy Trading and Risk Management Activities," which had allowed contracts
to be marked-to-market based on trading intent. On July 1, 2002, NU adopted net
reporting of trading revenues and expenses, as then allowed by EITF Issue No.
98-10. The rescission of EITF Issue No. 98-10 by EITF Issue No. 02-3 also
required that contracts that are not derivatives as defined under SFAS No. 133
be removed from the consolidated balance sheets as a cumulative effect of
accounting change and no longer recorded at fair value. The adoption of EITF
Issue No. 02-3 did not have a material impact on NU's consolidated financial
statements.
However, in implementing EITF Issue No. 02-3, Select Energy performed a review
of all contracts previously recorded under EITF Issue No. 98-10. In connection
with management's review of the contracts in the trading portfolio, the
significant changes in the energy trading market and the change in the focus of
the energy trading business, certain long-term derivative energy contracts that
were included in the trading portfolio and valued at $33.9 million at November
30, 2002, were designated as normal purchases and sales. The impact of the
normal purchases and sales designation is that the contracts were adjusted to
fair value at November 30, 2002 and were not and will not be adjusted
subsequently for changes in fair value. The $33.9 million carrying value of
these contracts was reclassified from trading derivative assets to other
long-term assets and will be amortized on a straight-line basis to fuel,
purchased and net interchange power expense over the remaining terms of the
contracts, some of which extend to 2011.
Select Energy uses derivative investments in its trading, wholesale, and retail
marketing businesses. The application of derivative accounting under SFAS No.
133 is complex and requires management judgment in the following respects:
identification of derivatives and embedded derivatives, election and designation
of the normal purchases and sales exceptions, identifying hedge relationships
and assessing hedge effectiveness, determining the fair value of derivatives,
and measuring hedge ineffectiveness. All of these judgments, depending upon
their timing and effect, can have a significant impact on NU's consolidated net
income.
During 2002, approximately $7 million of transmission congestion contracts,
which were included in Select Energy's marketing portfolio, were determined to
be derivatives. These contracts were recorded at fair value using a valuation
model and, at the same time, a valuation reserve on these contracts was recorded
due to the lack of available market data. Management continues to believe the
amount paid for the contracts best represents their market value. If these
assumptions regarding the classification of the contracts change or if new
accounting guidance is issued, there may be an impact on NU's consolidated
financial statements.
Regulatory Accounting and Assets: The accounting policies of NU's regulated
utility 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." 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 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 companies no longer meets the criteria of regulatory accounting
under SFAS No. 71, that portion of the company will have to discontinue
regulatory accounting and write off regulatory assets. Such a write-off could
have a material impact on NU's consolidated financial statements.
The application of SFAS No. 71 results in the deferral of costs as regulatory
assets that, in some cases, have not yet been approved for recovery by the
applicable regulatory commission. Management must conclude that any costs
deferred as regulatory assets are probable of future recovery in rates. However,
regulatory commissions can reach different conclusions about the recovery of
costs, which can have a material impact on NU's consolidated financial
statements. Management believes it is probable that NU's regulated utility
companies will recover their investments in long-lived assets, including
regulatory assets.
Goodwill and Other Intangible Assets: On January 1, 2002, NU adopted SFAS No.
142, "Goodwill and Other Intangible Assets." SFAS No. 142 requires that
management determine reporting units that carry goodwill. The determination of
reporting units requires judgment based on how the business segments are
managed. SFAS No. 142 also requires that goodwill and intangible assets deemed
to have indefinite useful lives be reviewed for impairment upon adoption and at
least annually thereafter by applying a fair value-based test. The fair
value-based test involves estimating the fair value of the reporting units by
using both discounted cash flow methodologies and an analysis of comparable
companies or transactions. The discounted cash flow methodologies that are
utilized involve critical assumptions and estimates made by management. If these
assumptions are changed there could be a significant impact on NU's consolidated
financial statements.
Pension and Postretirement Benefit Obligations: NU's subsidiaries participate in
a uniform noncontributory defined benefit retirement plan (Plan) covering
substantially all regular NU 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. 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.
Pre-tax periodic pension income for the Plan, excluding settlements,
curtailments, and special termination benefits, totaled $73.4 million and $101
million for the years ended December 31, 2002 and 2001, respectively. Pension
income is calculated based upon a number of actuarial assumptions, including an
expected long-term rate of return on Plan assets of 9.25 percent for 2002 and
9.5 percent for 2001. NU expects to use a long-term rate of return assumption of
8.75 percent for 2003. The pension income amounts exclude one-time items
recorded under SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits,"
associated with early termination programs and the sale of the Millstone and
Seabrook nuclear units. Net SFAS No. 88 items totaled $22.2 million of income
and $2.6 million in expense for the years ended December 31, 2002 and 2001,
respectively. Approximately 30 percent of net pension income is capitalized as a
reduction to capital additions to utility plant.
In developing the expected long-term rate of return assumption, NU evaluated
input from actuaries, consultants and economists as well as long-term inflation
assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's
expected long-term rate of return on Plan assets is based on target asset
allocation assumptions of 45 percent in United States equities and 14 percent in
non-United States equities, both with an expected long-term rates of return of
9.25 percent, 3 percent in emerging market equities with an expected long-term
return of 10.25 percent, 20 percent in fixed income securities with an expected
long-term rate of return of 5.5 percent, 5 percent in high yield fixed income
securities with expected long-term rates of return of 7.5 percent, 8 percent in
private equities with expected long-term rates of return of 14.25 percent, and 5
percent in real estate with expected long-term rates of return of 7.5 percent.
The combination of these target allocations and expected returns results in the
overall assumed long-term rate of return of 8.75 percent for 2003. The actual
asset allocation at December 31, 2002, was close to these target asset
allocations, and NU regularly reviews the actual asset allocations and
periodically rebalances the investments to the targeted allocation when
appropriate. NU reduced the long-term rate of return assumption by 0.5 percent
and 0.25 percent, respectively, each of the last two years due to lower rate of
return assumptions for most asset classes. NU believes that 8.75 percent is a
reasonable long-term rate of return on Plan assets for 2003. NU will continue to
evaluate the actuarial assumptions, including the expected rate of return, at
least annually, and will adjust the appropriate assumptions as necessary.
NU bases the actuarial determination of Plan pension income/expense on a
market-related valuation of assets, which reduces year-to-year volatility. This
market-related valuation recognizes investment gains or losses over a four-year
period from the year in which they occur. Investment gains or losses for this
purpose are the difference between the expected return calculated using the
market-related value of assets and the actual return based on the fair value of
assets. Since the market-related value of assets recognizes gains or losses over
a four-year period, the future value of the market-related assets will be
impacted as previously deferred gains or losses are recognized. There will be no
impact on the fair value of Plan assets. At December 31, 2002, the Plan had
cumulative unrecognized investment losses of $507.9 million, which will increase
pension expense over the next four years by reducing the expected return on Plan
assets. At December 31, 2002, the Plan also had cumulative unrecognized
actuarial gains of $89 million, which will reduce pension expense over the
expected future working lifetime of active Plan participants, or approximately
13 years. The combined total of unrecognized investment losses and actuarial
gains at December 31, 2002 is $418.9 million. This amount impacts the
actuarially determined prepaid pension amount recorded on the consolidated
balance sheet but has no impact on expected Plan funding.
The discount rate that is utilized in determining future pension obligations is
based on a basket of long-term bonds that receive one of the two highest ratings
given by a recognized rating agency. To compensate for the Plan's longer
duration 0.25 percent was added to this rating. The discount rate determined on
this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent
at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an expected
rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent
and various other assumptions, NU estimates that pension income/expense for the
Plan will be approximately $31 million in income, approximately $7 million in
expense and approximately $39 million in expense in 2003, 2004 and 2005,
respectively. Future actual pension income/expense will depend on future
investment performance, changes in future discount rates and various other
factors related to the populations participating in the plan.
The effect of lowering the expected long-term rate of return on Plan assets by
0.5 percent would have reduced pension income for 2002 by approximately $11
million. The effect of lowering the discount rate by 0.5 percent would have also
reduced pension income for 2002 by approximately $11 million.
The compensation increase assumption used for 2002 was based on the expected
increase in payroll for personnel covered by the Plan. The effect of lowering
the compensation increase assumption by 0.5 percent would have increased pension
income for 2002 by approximately $5 million.
The value of the Plan assets has decreased from $2 billion at December 31, 2001
to $1.6 billion at December 31, 2002. The investment performance returns and
declining discount rates have reduced the funded status of the Plan on a
projected benefit obligation (PBO) basis from an overfunded position of $302.8
million at December 31, 2001 to an underfunded position of $157.5 million at
December 31, 2002. The PBO includes expectations of future employee service and
compensation increases. The significant deterioration in the funded position of
the Plan will likely result in Plan contributions sooner than previously
expected. NU has not made contributions since 1991. This deterioration could
also lead to the requirement under defined benefit plan accounting to record an
additional minimum liability. The accumulated benefit obligation (ABO) of the
Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the
obligation for employee service provided through December 31, 2002. If the ABO
exceeds Plan assets, NU will record an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated in each of the jurisdictions in
which NU operates for each period for which a statement of income is presented.
This process involves estimating NU's actual current tax exposures as well as
assessing temporary differences resulting from differing treatment of items,
such as timing of the deduction of expenses for tax and book accounting
purposes. These differences result in deferred tax assets and liabilities, which
are included in the consolidated balance sheets. NU must also assess the
likelihood that the deferred tax assets will be recovered from future taxable
income, and to the extent that recovery is not likely, a valuation allowance
must be established. Significant management judgment is required in determining
income tax expense, deferred tax assets and liabilities and valuation
allowances. NU accounts for deferred taxes under SFAS No. 109, "Accounting for
Income Taxes." For temporary differences recorded as deferred tax liabilities
that will be recovered in rates in the future, NU has established a regulatory
asset. This asset amounted to $331.9 million and $301.3 million at December 31,
2002 and 2001, respectively.
Depreciation: Depreciation expense is calculated based on an asset's useful
life, and judgment is involved when estimating the useful lives of certain
assets. A change in the estimated useful lives of these assets could have a
material impact on NU's consolidated financial statements.
Environmental Matters: At December 31, 2002, NU has recorded a reserve for
various environmental liabilities. NU's environmental liabilities are based on
the best estimate of the amounts to be incurred for the investigation,
remediation and monitoring of the remediation sites. It is possible that future
cost estimates will either increase or decrease as additional information
becomes known. Changes in future cost estimates will have a smaller impact on
NU's subsidiaries that have regulatory mechanisms to recover environmental
remediation costs. These subsidiaries include PSNH and Yankee Gas. Yankee Gas
recorded an environmental liability for former manufactured gas plant sites of
$19.4 million and $22.9 million at December 31, 2002 and 2001, respectively.
Special Purpose Entities and Off-Balance Sheet Financing: NU has a total of
seven special purpose entities (SPE), all of which are currently consolidated in
the financial statements. During 2001 and 2002, to facilitate the issuance of
rate reduction bonds and certificates intended to finance certain stranded
costs, NU established four SPEs, CL&P Funding LLC, PSNH Funding LLC, PSNH
Funding LLC 2, and WMECO Funding LLC (the funding companies). The funding
companies were created as part of state sponsored securitization programs. The
funding companies are restricted from engaging in non-related activities and are
required to operate in a manner intended to reduce the likelihood that they
would be included in their respective parent company's bankruptcy estate if they
ever become involved in such bankruptcy proceedings.
The CL&P Receivables Corporation (CRC) is an SPE that was incorporated on
September 5, 1997, and is a wholly owned subsidiary of CL&P. The CRC was
established for the sole purpose of selling CL&P's accounts receivable and is
included in the consolidation of NU's financial statements. On July 10, 2002 the
CRC renewed its Receivables Purchase and Sale Agreement with CL&P and a
subsidiary of Citigroup, Inc. (Citigroup). The agreement gives the CRC the right
to sell and Citigroup the right to purchase up to $100 million in receivables
through July 9, 2003. At December 31, 2002 there was $40 million outstanding
under this facility. Sales of receivables to Citigroup under this arrangement
meet the accounting criteria for derecognition from the consolidated balance
sheets. Accordingly, the $40 million outstanding under this facility is not
reflected as debt or included in the consolidated financial statements.
During 2001, SESI established an SPE, HEC/CJTS Energy Center LLC (HEC/CJTS), to
provide a bankruptcy-remote entity in connection with an energy project
constructed for the State of Connecticut (State). This SPE was established for
financing purposes with cooperation from the State Treasurer. HEC/CJTS is
limited in the transactions it may enter into and may not initiate an event of
bankruptcy without a vote of its sole member and all directors, including
independent directors. Pursuant to an engineering, procurement, and construction
agreement with the State, SESI constructed a power plant to provide energy and
heat to the Connecticut Juvenile Training School (Project), in return for the
State entering into a 30-year lease. SESI assigned its interest in the lease
with the State to HEC/CJTS in exchange for payments totaling $17.7 million.
During 2001, HEC/CJTS transferred its interest in the lease with the State to
unaffiliated investors in exchange for the issuance of $19.2 million of
Certificates of Participation (Certificates). This transfer was accounted for as
a sale at the beginning of the lease term. HEC/CJTS is included in the
accompanying consolidated financial statements, however, upon transfer of the
interest in the lease, the debt of $19.2 million created upon issuance of the
Certificates was derecognized. No gain or loss was recorded. Proceeds from the
issuance of the Certificates, net of issuance costs and net construction
interest, were transferred to SESI as payment for the Project construction.
During 1999, SESI established another SPE, HEC/Tobyhanna Energy Project, LLC
(HEC/Tobyhanna), to provide a bankruptcy-remote entity in connection with a
federal energy savings performance project located at the United States Army
Depot in Tobyhanna, Pennsylvania. HEC/Tobyhanna sold $26.5 million of
Certificates related to the project and used the funds to repay SESI for the
costs of the project.
HEC/Tobyhanna's activities are limited to those related to the project and
HEC/Tobyhanna, including the Certificates, is included in the accompanying
consolidated financial statements.
For further information regarding these types of activities, see Note 1,
"Summary of Significant Accounting Policies," Note 3, "Derivative Instruments,
Market Risk and Risk Management," Note 4, "Employee Benefits," Note 5, "Goodwill
and Other Intangible Assets," Note 6, "Sale of Customer Receivables," and Note
8B, "Commitments and Contingencies - Environmental Matters," to the consolidated
financial statements.
Other Matters
Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 8, "Commitments and Contingencies," to
the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding NU's
contractual obligations and commercial commitments at December 31, 2002, is
summarized through 2007 as follows:
(Millions of Dollars) 2003 2004 2005 2006 2007
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Notes payable to banks $ 56.0 $ -- $ -- $ -- $ --
Long-term debt 56.9 61.7 88.7 26.6 8.3
Capital leases 3.1 3.0 2.8 2.7 2.6
Operating leases 23.1 20.6 18.4 16.2 9.8
Long-term contractual arrangements 567.8 551.3 533.0 517.1 364.2
Select Energy purchase agreements 3,302.0 612.6 290.1 68.7 69.2
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Totals $4,008.9 $1,249.2 $933.0 $631.3 $454.1
=================================================================================================================================
Select Energy's purchase agreement amounts can exceed the amount expected to be
reported in fuel, purchased and net interchange power because energy trading
purchases are classified in revenues.
Rate reduction bond amounts are not included in this table. 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 10, "Leases," and Note 8E, "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 weather patterns, changes in laws, developments
in legal or public policy doctrines, technological developments, volatility in
electric and natural gas commodity markets, 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 2002 over/(under) 2001 2001 over/(under) 2000
---------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
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Operating Revenues $(752) (13)% $ 92 2%
Operating Expenses:
Fuel, purchased and net interchange power (610) (17) 332 10
Other operation (21) (3) (93) (11)
Maintenance 5 2 3 1
Depreciation 4 2 (39) (16)
Amortization (521) (53) 706 (a)
Taxes other than income taxes 8 4 (19) (8)
Gain on sale of utility plant 455 71 (642) (100)
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Total operating expenses (680) (13) 248 5
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Operating Income (72) (13) (156) (22)
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Interest expense, net (9) (3) (19) (7)
Other income/(loss), net (144) (77) 202 (a)
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Income before tax expense (207) (46) 65 17
Income tax expense (92) (53) 12 8
Preferred dividends of subsidiaries (2) (23) (7) (49)
- -----------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary loss and accounting change (113) (43) 60 30
Extraordinary loss, net of tax benefit -- -- 234 100
Cumulative effect of accounting change, net of tax benefit 22 100 (22) (100)
- -----------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ (91) (38)% $ 272 (a)
===================================================================================================================================
(a) Percent greater than 100.
Operating Revenues
Total revenues decreased by $752 million or 13 percent in the year 2002,
compared with the year 2001, primarily due to lower competitive energy revenues
($377 million after intercompany eliminations) and lower regulated subsidiaries
revenues due to lower wholesale and transmission revenues ($240 million after
intercompany eliminations), and lower regulated retail revenues ($135 million).
The competitive energy companies' revenue decrease in 2002 is primarily due to
lower wholesale marketing revenues from Select Energy full requirements
contracts, primarily due to lower energy prices. The decrease in regulated
wholesale revenues is primarily due to lower sales associated with
purchased-power contracts ($91 million), lower PSNH wholesale sales ($94
million), primarily due to a reduction in prices and a lower volume of bilateral
transactions and sales of excess capacity and energy, and the 2001 revenue
associated with the sale of Millstone output ($42 million). The regulated retail
revenue decrease is primarily due to the May 2001 rate decrease for PSNH ($22
million), and the 2002 decrease in the WMECO standard offer energy rate ($77
million), lower Yankee revenue due to lower purchased gas adjustment clause
revenue ($59 million) and a combination of the April 2002 rate decrease and
lower gas sales ($27 million), partially offset by an increase resulting from
the collection of CL&P deferred fuel costs ($25 million) and higher retail
electric sales ($25 million). Regulated retail electric kWh sales increased by
1.3 percent, and firm natural gas volume sales decreased by 4.3 percent in 2002.
Total revenues increased by $92 million or 2 percent in the year 2001, compared
with the year 2000, primarily due to higher revenues from the competitive energy
subsidiaries ($164 million after intercompany eliminations), 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 wholesale energy contracts. The Yankee Gas increase was
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.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased by $610 million or
17 percent in the year 2002, primarily due to lower wholesale sales from the
competitive businesses ($301 million after intercompany eliminations), lower
Yankee expense primarily due to lower gas prices ($69 million), and lower
purchased-power costs for the regulated subsidiaries ($240 million net of
eliminations).
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 ($347 million, which reflects eliminations of purchases from
other NU subsidiaries), 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).
Other Operation and Maintenance
Other operation and maintenance expenses (O&M) decreased $16 million in 2002,
primarily due to lower expenses associated with the regulated businesses ($56
million), partially offset by higher competitive companies' expenses associated
with Select Energy's costs of goods sold and the expansion of new businesses
($42 million). The regulated O&M decrease is primarily due to lower nuclear
expenses as a result of the sale of the Millstone units at the end of the first
quarter in 2001 ($55 million).
Other 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 an acquisition made by NGS
($49 million).
Depreciation
Depreciation increased $4 million in 2002, primarily due to higher expense
resulting from higher regulated plant balances ($11 million), partially offset
by the Millstone unit decommissioning expenses recorded in 2001 ($8 million).
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).
Amortization
Amortization decreased $521 million in 2002, primarily due to the amortization
in 2001 related to the gain on sale of the Millstone units ($642 million) and
lower amortization related to recovery of the Millstone investment ($45
million), partially offset by the higher PSNH amortization in 2002 primarily
related to the gain on the sale of Seabrook ($155 million) and higher
amortization related to the regulated companies recovery of stranded costs ($23
million).
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 ($642 million) and higher amortization related to restructuring.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $8 million in 2002, primarily due to
CL&P's payments to the Town of Waterford for its loss of property tax revenue
resulting from electric utility restructuring ($15 million) and the favorable
2001 property tax settlement with the City of Meriden for CL&P and Yankee, which
decreased 2001 taxes ($15 million). These increases were partially offset by the
2002 recognition of a Connecticut sales and use tax audit settlement for the
years 1993 through 2001 ($8 million), lower gross earnings taxes ($6 million),
lower New Hampshire franchise taxes ($3 million) and lower property taxes ($4
million).
Taxes other than income taxes decreased by $19 million in 2001, primarily due
to the reduction in property tax for CL&P and WMECO due to the sale of the
Millstone units ($16 million), the property tax settlement with the City of
Meriden for CL&P and Yankee in 2001 ($15 million), and lower New Hampshire
franchise tax ($5 million), partially offset by higher Connecticut gross
earnings taxes ($14 million) on higher CL&P revenues.
Gain on Sale of Utility Plant
Gain on the sale of utility plant decreased $455 million in 2002 primarily due
to the gain recognized in the 2001 sale of CL&P's and WMECO's ownership
interests in the Millstone units ($642 million), partially offset by CL&P's and
NAEC's 2002 sale of Seabrook ($187 million).
Interest Expense, Net
Interest expense, net decreased $9 million in 2002, primarily due to NAEC's
reduction of debt.
Interest charges, 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 in 2001 ($88 million).
Other Income/(Loss), Net
Other income/(loss), net decreased $144 million in 2002 primarily due to the
2001 gain related to the Millstone sale ($202 million) and the 2002 investment
write-downs ($18 million), partially offset by the 2002 Seabrook related gains
($39 million) and the 2001 loss on share repurchase contracts ($35 million).
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 a
subsidiary of Dominion Resources, Inc. (the pre-tax amount of $189 million is
included in other income with an offsetting income tax expense impact of $73
million), higher interest and dividend income ($20 million), lower nuclear
related costs in 2001 ($18 million), and lower environmental reserve expense in
2001 ($10 million), partially offset by the charge related to the forward
purchase of 10.1 million NU common shares ($35 million).
Income Taxes
The consolidated statement of income taxes provides a reconciliation of actual
and expected tax expense. The tax effect of temporary differences is accounted
for in accordance with the rate-making treatment of the applicable regulatory
commissions. In past years, this rate-making treatment has required the company
to provide the customers with a portion of the tax benefits associated with
accelerated tax depreciation in the year it is generated (flow-through
depreciation). As these flow-through differences turn around, higher tax expense
is recorded.
Income tax expense decreased by $92 million in 2002, primarily due to the
recognition of WMECO investment tax credits in the second quarter of 2002 and
the tax impacts of the Millstone sale in 2001, partially offset by tax impacts
of the sale of Seabrook in 2002.
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 open tax years. For further information regarding
income taxes, see the Consolidated Statements of Income Taxes.
Preferred Dividends of Subsidiaries
Preferred dividends decreased in 2001 and 2002 primarily due to lower preferred
stock outstanding.
Extraordinary Loss, Net of Tax Benefit
The extraordinary loss in 2000 is primarily due to an after-tax write-off by
PSNH of approximately $225 million of stranded costs under the 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 discontinuance of SFAS No. 71 at HWP and the
sale of its 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, as amended ($22
million).
Company Report
Management is responsible for the preparation, integrity, and fair presentation
of the accompanying consolidated financial statements of Northeast Utilities and
subsidiaries and other sections of this annual report. These financial
statements, which were audited by Deloitte & Touche LLP in 2002 and 2001, and
Arthur Andersen LLP in 2000, have been prepared in conformity with accounting
principles generally accepted in the United States of America 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.
Management is responsible for maintaining a system of internal control over
financial reporting, which is designed to provide reasonable assurance, at an
appropriate cost-benefit relationship, 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 regularly with management, the internal
auditors and the independent auditors to review the activities of each and to
discuss audit matters, financial reporting matters, and the system of internal
control. The Audit Committee also meets periodically with the internal auditors
and the independent auditors without management present.
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 control 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. Additionally, management believes that
its disclosure controls and procedures are in place and operating effectively.
Disclosure controls and procedures are designed to ensure that information
included in reports such as this annual report is recorded, processed,
summarized, and reported within the time periods required and that information
disclosed is accumulated and reviewed by management for discussion and approval.
Independent Auditors' Report
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 and subsidiaries (a
Massachusetts trust) (the "Company") as of December 31, 2002 and 2001, and the
related consolidated statements of income, comprehensive income, shareholders'
equity, cash flows and income taxes for the years then ended. The consolidated
financial statements of the Company as of December 31, 2000, and for the year
then ended were audited by other auditors who have ceased operations. Those
auditors expressed an unqualified opinion on those financial statements in their
report dated January 22, 2002. 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 of America. 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 2002 and 2001 consolidated financial statements present
fairly, in all material respects, the financial position of Northeast Utilities
and subsidiaries (a Massachusetts trust) as of December 31, 2002 and 2001, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 1C to the consolidated financial statements, effective
January 1, 2001, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
as amended. In 2002, the Company adopted Emerging Issues Task Force Issue 02-3,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," and, retroactively, restated the 2001 consolidated financial
statements. Also, as discussed in Note 5, the Company adopted SFAS No. 142,
"Goodwill and Other Intangible Assets," as of January 1, 2002.
As discussed above, the consolidated financial statements of the Company as of
December 31, 2000 and for the year then ended were audited by other auditors who
have ceased operations. As described in Note 5, the 2001 and 2000 consolidated
financial statements have been revised to include the transitional disclosures
required by SFAS No. 142, which was adopted by the Company as of January 1,
2002. Our audit procedures with respect to the disclosures in Note 5 with
respect to 2000 included i) agreeing the previously reported net income to the
previously issued consolidated financial statements and the adjustments to
reported net income representing amortization expense (including any related tax
effects) recognized in that period related to goodwill and intangible assets
that are no longer being amortized as a result of initially applying SFAS No.
142 (including any related tax effects) to the Company's underlying records
obtained from management, and ii) testing the mathematical accuracy of the
reconciliation of adjusted net income to reportednet income, and the related
earnings-per-share amounts. In our opinion, the disclosures in Note 5 are
appropriate. However, we were not engaged to audit, review, or apply any
procedures to the 2000 consolidated financial statements of the Company other
than with respect to such disclosures and, accordingly, we do not express an
opinion or any other form of assurance on the 2000 consolidated
financial statements taken as a whole.
/s/ DELOITTE & TOUCHE LLP
---------------------
DELOITTE & TOUCHE LLP
Hartford, Connecticut
January 28, 2003
(February 27, 2003 as to Note 8A)
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
Readers of these consolidated financial statements should be aware that this
report is a copy of a previously issued Arthur Andersen LLP report and that this
report has not been reissued by Arthur Andersen LLP. Furthermore, this report
has not been updated since January 22, 2002, and Arthur Andersen LLP completed
its last post-audit review of December 31, 2001, consolidated financial
information on May 13, 2002.
Readers should also be aware that amounts previously reported have been
reclassified with the adoption of net reporting, which is discussed in Note 1C
to the consolidated financial statements. The 2001 consolidated financial
statements have been reaudited by Deloitte & Touche LLP.
Consolidated Balance Sheets
At December 31,
(Thousands of Dollars) 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
Assets
Current Assets:
Cash and cash equivalents $ 85,393 $ 96,658
Investments in securitizable assets 178,908 206,367
Receivables, less provision for uncollectible
accounts of $15,425 in 2002 and $16,353 in 2001 767,089 659,759
Unbilled revenues 126,236 126,398
Fuel, materials and supplies, at average cost 119,853 108,516
Special deposits 2,455 60,261
Derivative assets 130,929 150,299
Prepayments and other 110,261 67,910
- -----------------------------------------------------------------------------------------------------------------------------------
1,521,124 1,476,168
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric utility 5,141,887 5,743,575
Gas utility 679,055 634,884
Competitive energy 866,294 850,061
Other 205,115 195,741
- -----------------------------------------------------------------------------------------------------------------------------------
6,892,351 7,424,261
Less: Accumulated depreciation 2,484,549 3,273,737
- -----------------------------------------------------------------------------------------------------------------------------------
4,407,802 4,150,524
Construction work in progress 320,567 289,889
Nuclear fuel, net -- 32,564
- -----------------------------------------------------------------------------------------------------------------------------------
4,728,369 4,472,977
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets:
Regulatory assets 2,910,029 3,287,537
Goodwill and other purchased intangible assets, net 345,867 333,123
Prepaid pension 328,890 232,398
Nuclear decommissioning trusts, at market -- 61,713
Other 433,338 468,007
- -----------------------------------------------------------------------------------------------------------------------------------
4,018,124 4,382,778
- -----------------------------------------------------------------------------------------------------------------------------------
Total Assets $10,267,617 $10,331,923
===================================================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
Consolidated Balance Sheets
At December 31,
(Thousands of Dollars) 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Capitalization
Current Liabilities:
Notes payable to banks $ 56,000 $ 290,500
Long-term debt - current portion 56,906 50,462
Accounts payable 766,128 608,705
Accrued taxes 141,667 27,371
Accrued interest 40,597 35,659
Derivative liabilities 63,900 151,648
Other 179,154 161,277
- -----------------------------------------------------------------------------------------------------------------------------------
1,304,352 1,325,622
- -----------------------------------------------------------------------------------------------------------------------------------
Rate Reduction Bonds 1,899,312 2,018,351
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,436,507 1,491,394
Accumulated deferred investment tax credits 106,471 120,071
Deferred contractual obligations 354,469 216,566
Other 552,641 633,523
- -----------------------------------------------------------------------------------------------------------------------------------
2,450,088 2,461,554
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Long-Term Debt 2,287,144 2,292,556
- -----------------------------------------------------------------------------------------------------------------------------------
Preferred Stock - Nonredeemable 116,200 116,200
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000 shares;
149,375,847 shares issued and 127,562,031 shares outstanding in 2002
and 148,890,640 shares issued and 130,132,136 shares outstanding in 2001 746,879 744,453
Capital surplus, paid in 1,108,338 1,107,609
Deferred contribution plan - employee stock ownership plan (87,746) (101,809)
Retained earnings 765,611 678,460
Accumulated other comprehensive income/(loss) 14,927 (32,470)
Treasury stock, 18,022,415 shares in 2002 and 14,359,628 in 2001 (337,488) (278,603)
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity 2,210,521 2,117,640
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization 4,613,865 4,526,396
- -----------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 8)
Total Liabilities and Capitalization $10,267,617 $10,331,923
===================================================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
Consolidated Statements of Income
For the Years Ended December 31,
(Thousands of Dollars, except share information) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $5,216,321 $5,968,220 $5,876,620
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 3,026,102 3,635,736 3,303,995
Other 752,482 773,058 866,742
Maintenance 263,487 258,961 255,884
Depreciation 205,646 201,013 239,798
Amortization 461,544 983,037 276,821
Taxes other than income taxes 227,518 219,197 238,587
Gain on sale of utility plant (187,113) (641,956) --
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 4,749,666 5,429,046 5,181,827
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Income 466,655 539,174 694,793
Interest Expense:
Interest on long-term debt 134,471 140,497 194,406
Interest on rate reduction bonds 115,791 87,616 --
Other interest 20,249 51,545 104,896
- -----------------------------------------------------------------------------------------------------------------------------------
Interest expense, net 270,511 279,658 299,302
- -----------------------------------------------------------------------------------------------------------------------------------
Other Income/(Loss), Net 43,828 187,627 (14,309)
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Income Tax Expense 239,972 447,143 381,182
Income Tax Expense 82,304 173,952 161,725
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Preferred Dividends of Subsidiaries 157,668 273,191 219,457
Preferred Dividends of Subsidiaries 5,559 7,249 14,162
- -----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change
and Extraordinary Loss, Net of Tax Benefits 152,109 265,942 205,295
Cumulative effect of accounting change, net of tax benefit of $14,908 -- (22,432) --
Extraordinary loss, net of tax benefit of $169,562 -- -- (233,881)
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 152,109 $ 243,510 $ (28,586)
===================================================================================================================================
Basic Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting change and extraordinary loss, net of tax benefits $ 1.18 $ 1.97 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
- -----------------------------------------------------------------------------------------------------------------------------------
Basic Earnings/(Loss) Per Common Share $ 1.18 $ 1.80 $ (0.20)
===================================================================================================================================
Fully Diluted Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting change and extraordinary loss, net of tax benefits $ 1.18 $ 1.96 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
- -----------------------------------------------------------------------------------------------------------------------------------
Fully Diluted Earnings/(Loss) Per Common Share $ 1.18 $ 1.79 $ (0.20)
===================================================================================================================================
Basic Common Shares Outstanding (average) 129,150,549 135,632,126 141,549,860
===================================================================================================================================
Fully Diluted Common Shares Outstanding (average) 129,341,360 135,917,423 141,967,216
===================================================================================================================================
Consolidated Statements of Comprehensive Income
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $152,109 $243,510 $(28,586)
- -----------------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income/(Loss), Net of Tax:
Qualified cash flow hedging instruments 52,360 (36,859) --
Unrealized (losses)/gains on securities (5,121) 2,620 245
Minimum pension liability adjustments 158 -- --
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income/(loss), net of tax 47,397 (34,239) 245
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income/(Loss) $199,506 $209,271 $(28,341)
===================================================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
Consolidated Statements of Shareholders' Equity
Accumulated
Capital Deferred Retained Other
Common Surplus, Contribution Earnings Comprehensive Treasury
(Thousands of Dollars) Shares Paid In Plan - ESOP (a) Income/(Loss) Stock Total
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2000 $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
Allocation of benefits - ESOP (2,296) 12,654 10,358
Repurchase of common shares (293,452) (293,452)
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
- -----------------------------------------------------------------------------------------------------------------------------------
Net income for 2002 152,109 152,109
Cash dividends on common shares -
$0.525 per share (67,793) (67,793)
Issuance of 485,207 common shares,
$5 par value 2,426 5,032 7,458
Allocation of benefits -
ESOP and restricted stock (4,679) 14,063 2,835 12,219
Repurchase of common shares (58,885) (58,885)
Capital stock expenses, net 376 376
Other comprehensive income 47,397 47,397
- -----------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2002 $746,879 $1,108,338 $ (87,746) $765,611 $ 14,927 $(337,488) $2,210,521
- -----------------------------------------------------------------------------------------------------------------------------------
(a) Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount of
retained earnings available for NU common dividends. At December 31, 2002,
retained earnings available for payment of dividends totaled $318.3 million.
The accompanying notes are an integral part of these consolidated financial
statements.
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Activities:
Income before preferred dividends of subsidiaries $ 157,668 $ 273,191 $ 219,457
Adjustments to reconcile to net cash flows provided by operating activities:
Depreciation 205,646 201,013 239,798
Deferred income taxes and investment tax credits, net (149,325) (116,704) (16,117)
Amortization 461,544 983,037 276,821
Net amortization/(deferral) of recoverable energy costs 27,623 (2,005) (30,603)
Gain on sale of utility plant (187,113) (641,956) --
Cumulative effect of accounting change, net of tax -- (22,432) --
Prepaid pension (96,492) (92,852) (138,877)
Net other sources/(uses) of cash 10,707 (65,064) 88,967
Changes in working capital:
Receivables and unbilled revenues, net (102,181) (301,068) (104,868)
Fuel, materials and supplies (27,590) 55,195 12,450
Accounts payable 153,450 100,277 171,148
Accrued taxes 114,296 (27,439) (128,107)
Investments in securitizable assets 27,459 61,779 9,474
Other working capital (excludes cash) 16,953 (76,366) 254
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 612,645 328,606 599,797
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (468,842) (428,312) (345,596)
Competitive energy assets (23,150) (15,368) (7,140)
Nuclear fuel (465) (14,275) (61,286)
- -----------------------------------------------------------------------------------------------------------------------------------
Cash flows used for investments in plant (492,457) (457,955) (414,022)
Investments in nuclear decommissioning trusts (9,876) (105,076) (39,550)
Net proceeds from the sale of utility plant 366,786 1,045,284 --
Buyout/buydown of IPP contracts (5,152) (1,157,172) --
Payment for acquisitions, net of cash acquired (16,351) (31,699) (260,347)
Other investment activities, net 15,234 (51,677) (28,478)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (141,816) (758,295) (742,397)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Issuance of common shares 7,458 1,751 4,269
Repurchase of common shares (57,800) (291,789) --
Issuance of long-term debt 310,648 703,000 26,477
Issuance of rate reduction bonds 50,000 2,118,400 --
Retirement of rate reduction bonds (169,039) (100,049) --
Net (decrease)/increase in short-term debt (234,500) (1,019,477) 961,977
Reacquisitions and retirements of long-term debt (314,773) (714,226) (685,555)
Reacquisitions and retirements of preferred stock -- (60,768) (126,771)
Retirement of monthly income preferred securities -- (100,000) --
Retirement of capital lease obligation -- (180,000) --
Cash dividends on preferred stock (5,559) (7,249) (14,162)
Cash dividends on common shares (67,793) (60,923) (57,358)
Other financing activities, net (736) 37,660 (21,414)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash flows (used in)/provided by financing activities (482,094) 326,330 87,463
- -----------------------------------------------------------------------------------------------------------------------------------
Net decrease in cash and cash equivalents (11,265) (103,359) (55,137)
Cash and cash equivalents - beginning of year 96,658 200,017 255,154
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 85,393 $ 96,658 $ 200,017
===================================================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
Consolidated Statements
of Capitalization
At December 31,
(Thousands of Dollars) 2002 2001
- --------------------------------------------------------------------------------
Common Shareholders' Equity $2,210,521 $2,117,640
- --------------------------------------------------------------------------------
Preferred Stock:
CL&P Preferred Stock Not Subject
to Mandatory Redemption -
$50 par value - authorized 9,000,000
shares in 2002 and 2001; 2,324,000
shares outstanding in 2002 and 2001;
Dividend rates of $1.90 to $3.28; Current
redemption prices of $50.50 to $54.00 116,200 116,200
- --------------------------------------------------------------------------------
Long-Term Debt: (a)
First Mortgage Bonds -
Final Maturity Interest Rates
- --------------------------------------------------------------------------------
2005 5.00% to 6.75% 116,000 140,000
2009-2012 6.20% to 7.19% 80,000 80,000
2019-2024 7.88% to 10.07% 254,995 255,945
2026 8.81% 320,000 320,000
- --------------------------------------------------------------------------------
Total First Mortgage Bonds 770,995 795,945
- --------------------------------------------------------------------------------
Other Long-Term Debt -
Pollution Control Notes
and Other Notes - (b)
2003-2012 6.24% to 8.58%
and Adjustable Rate 358,400 381,500
2016-2018 5.90% 25,400 25,400
2021-2022 Adjustable Rate and
1.55% to 6.00% 428,285 428,285
2028 5.85% to 5.95% 369,300 369,300
2031 Adjustable Rate 62,000 62,000
- --------------------------------------------------------------------------------
Total Pollution Control
Notes and Other Notes 1,243,385 1,266,485
Fees and interest due for spent nuclear
fuel disposal costs (c) 253,638 249,314
Other 80,181 36,257
- --------------------------------------------------------------------------------
Total Other Long-Term Debt 1,577,204 1,552,056
- --------------------------------------------------------------------------------
Unamortized premium and discount, net (4,149) (4,983)
- --------------------------------------------------------------------------------
Total Long-Term Debt 2,344,050 2,343,018
Less: Amounts due within one year 56,906 50,462
- --------------------------------------------------------------------------------
Long-Term Debt, Net 2,287,144 2,292,556
- --------------------------------------------------------------------------------
Total Capitalization $4,613,865 $4,526,396
================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
Notes to Consolidated Statements of Capitalization
(a) Long-term debt maturities and cash sinking fund requirements on debt
outstanding at December 31, 2002, for the years 2003 through 2007 and
thereafter, excluding fees and interest due for spent nuclear fuel disposal
costs of $253.6 million and unamortized premiums and discounts of $4.1
million are $56.9 million, $61.7 million, $88.7 million, $26.6 million,
$8.3 million, and $1,852.4 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 Pollution Control Revenue Bonds (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, 2002 and 2001, $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.
(b) The average effective interest rate on the variable-rate pollution control
notes ranged from 1.2 percent to 1.7 percent for 2002 and 1.2 percent to
3.8 percent for 2001. NU's variable rate long-term debt maturities and cash
sinking fund requirements are $178.5 million in 2021 and $62 million in
2031.
(c) For information regarding fees and interest due for spent nuclear fuel
disposal costs, see Note 8C, "Commitments and Contingencies - Spent Nuclear
Fuel Disposal Costs," to the consolidated financial statements.
Consolidated Statements of Income Taxes
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
The components of the federal and state income tax provisions are:
Current income taxes:
Federal $ 197,426 $244,501 $154,790
State 34,204 46,155 23,052
- ------------------------------------------------------------------------------------------------------------------------------------
Total current 231,630 290,656 177,842
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (108,524) (80,968) 7,297
State (14,210) (15,644) (5,529)
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred (122,734) (96,612) 1,768
- ------------------------------------------------------------------------------------------------------------------------------------
Investment tax credits, net (26,592) (20,092) (17,885)
- ------------------------------------------------------------------------------------------------------------------------------------
Total income tax expense $ 82,304 $173,952 $161,725
====================================================================================================================================
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
Depreciation, leased nuclear fuel, settlement credits and disposal costs 89,621 (185,850) 9,514
Regulatory deferral (141,592) (33,187) (34,486)
Regulatory disallowance 345 2,323 --
Sale of generation assets (20,500) (225,019) --
Pension (1,720) 24,183 25,751
Loss on bond redemptions (1,084) 12,396 655
Securitized contract termination costs and other (23,044) 279,673 --
Contract settlements (14,991) 16,640 (4,442)
Other (9,769) 10,023 3,213
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net $(122,734) $(96,612) $ 1,768
====================================================================================================================================
A reconciliation between income tax expense and the expected
tax expense at the statutory rate is as follows:
Expected federal income tax $ 81,400 $156,500 $133,413
Tax effect of differences:
Depreciation 10,404 5,313 2,882
Amortization of regulatory assets 13,540 5,748 16,835
Investment tax credit amortization (26,592) (20,092) (17,885)
State income taxes, net of federal benefit 12,996 19,832 11,390
Dividends received deduction (3,237) (3,382) (8,618)
Tax asset valuation allowance/reserve adjustments (1,310) (7,000) (2,136)
Merger-related expenditures -- (4,589) 5,829
Amortization of PSNH acquisition costs 1,426 4,512 9,946
Nondeductible stock expenses -- 12,388 --
Other, net (6,323) 4,722 10,069
- ------------------------------------------------------------------------------------------------------------------------------------
Total income tax expense $ 82,304 $173,952 $161,725
====================================================================================================================================
The accompanying notes are an integral part of these consolidated 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'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), previously sold 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).
Seabrook was sold on November 1, 2002. Other subsidiaries include Holyoke Water
Power Company (HWP), a company engaged in the production of electric power, and
Yankee Energy System, Inc. (Yankee), the parent company of Yankee Gas Services
Company (Yankee Gas), Connecticut's largest natural gas distribution system.
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 is
subject to the provisions of the 1935 Act. Arrangements among NU's companies,
outside agencies and other utilities covering interconnections, interchange of
electric power and sales of utility property are subject to regulation by the
Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating
subsidiaries are subject to further regulation for rates, accounting and other
matters by the FERC and/or applicable state regulatory commissions.
NU Enterprises, Inc. (NUEI) is a wholly owned subsidiary of NU and acts as the
holding company for certain of NU's competitive energy subsidiaries. These
subsidiaries include Select Energy, Inc., and subsidiary (Select Energy), a
corporation engaged in the trading, marketing, transportation, storage, and sale
of energy commodities, at wholesale and retail, in designated geographical
areas; Northeast Generation Company (NGC), a corporation that acquires and
manages generation facilities; Select Energy Services, Inc. and subsidiaries
(SESI), a provider of energy management, demand-side management and related
consulting services for commercial, industrial and institutional electric
companies and electric utility companies, and; Northeast Generation Services
Company and subsidiaries (NGS), a corporation that maintains and services fossil
or hydroelectric facilities and provides third-party electrical, mechanical, and
engineering contracting services.
In July 2002, the competitive energy subsidiaries acquired certain assets and
assumed certain liabilities of Woods Electrical Co. Inc., (Woods Electrical), an
electrical services company, and Woods Network Services, Inc. (Woods Network), a
network products and services company for an aggregate adjusted purchase price
of $16.3 million. Woods Electrical is wholly owned by NGS, and Woods Network is
wholly owned by NUEI.
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 NU's
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 NU's companies. Until the sale of Seabrook on
November 1, 2002, North Atlantic Energy Service Corporation (NAESCO) had
operational responsibility for Seabrook. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by NU's companies.
B. Presentation
The consolidated financial statements of NU 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 of America 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
Energy Trading and Risk Management Activities: In June 2002, the Emerging Issues
Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a
consensus on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," requiring companies engaged in energy
trading activities to classify revenues and expenses associated with energy
trading contracts on a net basis in revenues, rather than recording revenues for
sales and expenses for purchases. While this consensus was subsequently
rescinded by the EITF on October 25, 2002, NU chose to adopt net reporting of
energy trading revenues and expenses for contracts that physically settle
effective July 1, 2002. Operating revenues and fuel, purchased and net
interchange power for the year ended December 31, 2002 reflect net reporting,
and the adoption of net reporting was applied retroactively to 2001 operating
revenues and fuel, purchased and net interchange power but had no effect on net
income.
The impact on previously reported amounts in 2001 is as follows:
(Millions of Dollars)
- ---------------------------------------------------
Operating Revenues:
As previously reported $6,873.8
Impact of reclassification (905.6)
- ---------------------------------------------------
As currently reported $5,968.2
===================================================
Fuel, Purchased and Net Interchange
Power:
As previously reported $4,541.3
Impact of reclassification (905.6)
- ---------------------------------------------------
As currently reported $3,635.7
===================================================
Operating revenues and fuel, purchased and net interchange power for the year
ended December 31, 2000 were not adjusted, as the impact of net reporting was
not material to NU's consolidated results of operations in 2000.
On October 25, 2002, the EITF reached additional consensuses in EITF Issue No.
02-3. These consensuses supercede the consensuses the EITF reached in June 2002.
The first consensus rescinds EITF Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities for Energy Trading
Activities," under which Select Energy previously accounted for energy trading
activities. This consensus requires companies engaged in energy trading
activities to discontinue fair value accounting effective January 1, 2003, for
contracts that do not meet the definition of a derivative in Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, effective January 1, 2003. NU
adopted this consensus effective October 1, 2002. Management determined that
there were no trading contracts subject to fair value accounting that did not
meet the definition of a derivative in SFAS No. 133. Accordingly, there was no
cumulative effect of an accounting change.
The second consensus requires that companies engaged in energy trading
activities classify revenues and expenses associated with energy trading
contracts on a net basis in revenues effective January 1, 2003. NU adopted net
reporting effective July 1, 2002, before this consensus was reached by the EITF.
Asset Retirement Obligations: In June 2001, the FASB issued SFAS No. 143,
"Accounting for Asset Retirement Obligations."This statement requires that legal
obligations associated with the retirement of property, plant and equipment be
recognized as a liability at fair value when incurred and when a reasonable
estimate of the fair value of the liability can be made. SFAS No. 143 is
effective on January 1, 2003, for NU. Management has completed its review
process for potential asset retirement obligations (AROs) and has not identified
any material AROs which have been incurred. However, management has identified
certain removal obligations which arise in the ordinary course of business that
either have a low probability of occurring or are not material in nature. These
types of obligations primarily relate to transmission and distribution lines and
poles, telecommunication towers, transmission cables and certain FERC or state
regulatory agency re-licensing issues.
A portion of NU's regulated utilities' rates is intended to recover the cost of
removal of certain utility assets. The amounts recovered do not represent AROs.
At December 31, 2002, NU maintained approximately $321 million in cost of
removal regulatory liabilities, which are included in the accumulated provision
for depreciation.
Stock-Based Compensation: In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure." This
statement amends SFAS No. 123, "Accounting for Stock-Based Compensation," to
provide alternative methods of transition for a voluntary change to the fair
value-based method of accounting for stock-based employee compensation and
requires prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. SFAS No. 148 is effective for
2002, and NU included the disclosures required by SFAS No. 148 in this annual
report. For the required disclosures, see Note 1K, "Summary of Significant
Accounting Policies - Stock-Based Compensation" and Note 4D, "Employee Benefits
- - Stock-Based Compensation" to the consolidated financial statements. At this
time, NU has not elected to transition to the fair value-based method of
accounting for stock-based employee compensation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires
that disclosures be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued and
clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee
contracts, such as residual value guarantees provided by lessees in capital
leases, guarantees that are accounted for as derivatives, guarantees that
represent contingent consideration in a business combination, guarantees issued
between either parents and their subsidiaries or corporations under common
control, a parent's guarantee of a subsidiary's debt to a third party, and a
subsidiary's guarantee of the debt owed to a third party by either its parent or
another subsidiary of that parent. The initial recognition and initial
measurement provisions of Interpretation No. 45 are applicable to NU on a
prospective basis to guarantees issued or modified after January 1, 2003.
Currently, management does not expect the adoption of the initial recognition
and initial measurement provisions of Interpretation No. 45 to have a material
impact on NU's consolidated financial statements. The disclosure requirements in
Interpretation No. 45 are effective for 2002. For further information regarding
these disclosures, see Note 2, "Short-Term Debt" to the consolidated financial
statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB issued
Interpretation No. 46, "Consolidation of Variable Interest Entities."
Interpretation No. 46 addresses the consolidation and disclosure requirements
for companies that hold an equity interest in a variable interest entity (VIE),
regardless of the date on which the VIE was created. Interpretation No. 46
requires consolidation of a VIE's assets, liabilities and noncontrolling
interests at fair value when a company is the primary beneficiary, which is
defined as a company that absorbs a majority of the expected losses, risks and
revenues from the VIE as a result of holding a contractual or other financial
interest in the VIE. Consolidation is not required under Interpretation No. 46
for those companies that hold a significant equity interest in a VIE but are not
the primary beneficiary. Interpretation No. 46 is effective for NU beginning in
the third quarter of 2003. At December 31, 2002, NU held equity interests in
various VIEs, for which NU was not the primary beneficiary, as NU does not
absorb a majority of the expected losses, risks and revenues from the VIEs or
provide a substantial portion of financial support. As a result, management
does not expect the adoption of Interpretation No. 46 to have a material impact
on NU's consolidated financial statements. For further information regarding
NU's investments in its VIEs, see Note 1D, "Equity Investments and Jointly
Owned Electric Utility Plant" to the consolidated financial statements.
Derivative Instruments: Effective January 1, 2001, NU adopted SFAS No. 133, 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.
D. Equity 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). NU's ownership interests
in the Yankee Companies at December 31, 2002 and 2001, which are accounted for
on the equity method 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 17 percent of
the Vermont Yankee Nuclear Power Corporation (VYNPC). NU's total equity
investment in the Yankee Companies and its exposure to loss as a result of
these investments at December 31, 2002 and 2001, is $48.9 million and $52.5
million, respectively. These investments are VIE's under FASB Interpretation
No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee
Company owns a single decommissioned nuclear generating plant. On July 31,
2002, VYNPC consummated the sale of its nuclear generating plant to a
subsidiary of Entergy Corporation for approximately $180 million.
Seabrook: CL&P and NAEC together previously had a 40.04 percent joint ownership
interest in Seabrook, a 1,148 megawatt nuclear generating unit. On November 1,
2002, CL&P, NAEC, and certain other joint owners consummated the sale of their
ownership interests in Seabrook to a subsidiary of FPL Group, Inc. (FPL). At
December 31, 2001, plant-in-service and the accumulated provision for
depreciation for NU's share of Seabrook totaled $912.5 million and $840.6
million, respectively.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest and an exposure
to loss as a result of this investment totaling $12 million and $13.6 million at
December 31, 2002 and 2001, respectively, in two companies that transmit
electricity imported from the Hydro-Quebec system in Canada. This investment is
a VIE under the FASB Interpretation No. 46.
Other Investments: NU also maintains certain cost method, equity method, and
other investments in NEON Communications, Inc. (NEON), a provider of
high-bandwidth fiber optic telecommunications services, Acumentrics Corporation
(Acumentrics), a privately owned producer of advanced power generation and power
protection technologies applicable to homes, telecommunications, commercial
businesses, industrial facilities, and the auto industry, R.M. Services, Inc.
(RMS), a provider of consumer collection services for companies throughout the
United States, and BMC Energy LLC (BMC), an operator of renewable energy
projects. These investments have a combined total carrying value of $29.1
million and $54 million at December 31, 2002 and 2001, respectively. During
2002, after-tax impairment write-offs were recorded to reduce the carrying
values of NEON, Acumentrics and RMS to their net realizable values. Excluding
BMC, these investments are VIEs under FASB Interpretation No. 46, and NU's
exposure to loss as a result of these investments totaled $24.4 million and
$49.3 million at December 31, 2002 and 2001, respectively. In 2001, based on a
reduction in its ownership share in NEON, NU changed from the equity method of
accounting to the cost method of accounting for this investment.
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 which range primarily from 3 years to 75 years, 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 utility plant-in-service are equivalent to a
composite rate of 3.2 percent in 2002 and 3.1 percent in 2001 and 2000.
In 2002, the competitive energy subsidiaries concluded a study of the
depreciable lives of certain generation assets. The impact of this study was to
lengthen the useful lives of those generation assets by 32 years to an average
of 70 remaining years. In addition, the useful lives of certain software was
revised and shortened to reflect a remaining life of 1.5 years. As a result of
these studies, NU's operating expenses decreased by approximately $5.1 million
or $0.04 per share on a fully diluted basis in 2002.
In 2000, HWP discontinued SFAS No. 71, "Accounting for the Effect of Certain
Types of Regulation," and recorded a charge to accumulated depreciation for the
plant carrying value 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 rates approved by the state regulatory
commissions. These regulated rates are applied to customer's accounts based on
their use of energy. In general, rates can only be changed through formal
proceedings with the state regulatory commissions.
The determination of the energy sales to individual customers is based on the
reading of their meters, which occurs on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. This unbilled revenue is estimated each month based on
generation volumes, estimated customer usage by class, line losses, and
applicable customer rates.
Competitive energy subsidiary revenues are recognized at different times for the
different businesses. Wholesale and retail marketing revenues are recognized
when energy is delivered. Trading revenues are recognized as the fair value of
trading contracts changes. Service revenues are recognized as services are
provided, often on a percentage of completion basis.
G. Regulatory Accounting and Assets
The accounting policies of NU's regulated utilities conform to accounting
principles generally accepted in the United States of America 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 NU's operating companies will
recover their investments in long-lived assets, including regulatory assets. In
addition, all material regulatory assets are earning a return, except for
securitized regulatory assets. The components of NU's regulatory assets are as
follows:
At December 31,
(Millions of Dollars) 2002 2001
- --------------------------------------------------------------------------------
Recoverable nuclear costs $ 85.4 $ 243.1
Securitized regulatory assets 1,891.8 2,004.1
Income taxes, net 331.9 301.3
Unrecovered contractual obligations 239.3 78.3
Recoverable energy costs, net 299.6 327.2
Other 62.0 333.5
- --------------------------------------------------------------------------------
Totals $2,910.0 $3,287.5
================================================================================
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. The purchase price of the hydroelectric
generation assets is reflected in competitive energy property, plant and
equipment, and NGC is depreciating the plant assets over their estimated useful
life.
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 a total unamortized balance of $13.1 million and
$158.1 million at December 31, 2002 and 2001, respectively. Additionally, PSNH
recorded a regulatory asset in conjunction with the sale of the Millstone units
with an unamortized balance of $36.8 million and $40.5 million at December 31,
2002 and 2001, which is also included in recoverable nuclear costs. Also
included in recoverable nuclear costs for 2002 and 2001 are $35.5 million and
$44.5 million, respectively, primarily related to Millstone 1 recoverable
nuclear costs associated with the recoverable portion of the undepreciated plant
and related assets.
In 2000, PSNH discontinued the application of SFAS No. 71 for its generation
business and created a regulatory asset for Seabrook over market generation. 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 is reflected in
securitized regulatory assets at December 31, 2002 and 2001. On May 22, 2001,
the Governor of New Hampshire signed a bill modifying the state's electric
utility industry restructuring laws delaying the sale of PSNH's fossil and
hydroelectric generation assets until at least February 1, 2004. Since then
there has been no regulatory action, and management currently has no plans to
divest these generation assets. As the NHPUC has allowed and is expected to
continue to allow rate recovery of a return of and on these generation assets,
as well as all operating expenses, PSNH again meets the criteria for the
application of SFAS No. 71 for the generation portion of its business.
Accordingly, costs related to the generation assets, to the extent not currently
recovered in rates, are deferred as Part 3 stranded costs under the "Agreement
to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs
are nonsecuritized regulatory assets which must be recovered by a recovery end
date determined in accordance with the Restructuring Settlement or be written
off.
In March 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. In May 2001, WMECO issued $155 million in rate
reduction certificates and used $80 million of those proceeds to buyout an
independent power producer contract. In January 2002, PSNH issued an additional
$50 million in rate reduction bonds and used the proceeds from this issuance to
repay short-term debt that was incurred to buyout a purchased-power contract in
December 2001. 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 for CL&P and WMECO was
securitized in 2001 and is included in securitized regulatory assets. These
remaining amounts for PSNH are recovered as stranded costs. During 2002, NU was
notified by the Yankee Companies that the estimated cost of decommissioning
their units had increased over prior estimates due to higher anticipated costs
for spent fuel storage, security and liability and property insurance. In
December 2002, NU recorded an additional $171.6 million in deferred contractual
obligations and a corresponding increase in the unrecovered contractual
obligations regulatory asset as a result of these increased costs.
CL&P, PSNH, WMECO, and NAEC, under the Energy Policy Act of 1992 (Energy Act),
were 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) when they owned nuclear generating plants. 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 and WMECO are currently recovering these costs through
rates. At December 31, 2002 and 2001, NU's total D&D Assessment deferrals were
$21.9 million and $28.1 million, respectively, and have been recorded as
recoverable energy costs, net.
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.
CL&P's energy costs deferred and not yet collected under the energy adjustment
clause amounted to $31.7 million and $59 million at December 31, 2002 and 2001,
respectively, which have been recorded as recoverable energy costs, net. On
July 26, 2001, the Connecticut Department of Public Utility Control (DPUC)
authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour
(kWh) from August 2001 through December 2003 to collect these costs. In
conjunction with the implementation of restructuring under the Restructuring
Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause
(FPPAC) was discontinued. At December 31, 2002 and 2001, PSNH had $179.6
million and $183.3 million, respectively, of recoverable energy costs deferred
under the FPPAC, including previous deferrals of purchases from independent
power producers. Under the Restructuring Settlement, the FPPAC deferrals are
recovered as a Part 3 stranded cost through a stranded cost recovery charge.
Also included in PSNH's recoverable energy costs are costs associated with
certain contractual purchases from independent power producers that had
previously been included in the FPPAC. These costs are treated as Part 3
stranded costs and amounted to $62.1 million and $68.1 million at December 31,
2002 and 2001, respectively.
The regulated rates of Yankee Gas include a purchased gas adjustment clause
under which gas costs above or below base rate levels are charged to or credited
to customers. Differences between the actual purchased gas costs and the current
rate recovery are deferred and recovered in or refunded in future periods. These
amounts are recorded as recoverable energy costs, net.
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 and SFAS No. 109, "Accounting for Income Taxes."
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) 2002 2001
- --------------------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $ 493.7 $ 577.5
Regulatory assets:
Nuclear stranded investment
and other asset divestitures 270.9 324.6
Securitized contract termination
costs and other 255.4 279.7
Income tax gross-up 194.6 190.0
Other 221.9 119.6
- --------------------------------------------------------------------------------
Totals $1,436.5 $1,491.4
================================================================================
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 on the intended use of the particular
contract and on whether or not the contracts are derivatives.
Nonderivative contracts that are entered into for the normal purchase or sale of
energy to customers that will result in physical delivery are recorded at the
point of delivery under accrual accounting. Derivative contracts that are
entered into for the normal purchase and sale of energy and meet the "normal
purchase and sale" exception to derivative accounting, as defined in SFAS No.
133, are also recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for trading purposes are recorded on
the consolidated balance sheets at fair value, and changes in fair value impact
earnings. Revenues and expenses for these contracts are recorded on a net basis.
Other contracts that are derivatives that do not qualify as normal purchases and
sales or hedges are also recorded on the consolidated balance sheets at fair
value with changes in fair value reflected in operating revenues for sales and
fuel, purchased and net interchange power for purchases.
Revenues and expenses for derivative contracts that are not entered into for
trading purposes are recorded at gross amounts when these transactions settle.
Competitive energy contracts that are hedging an underlying transaction and
qualify as cash flow hedges are recorded on the consolidated balance sheets at
fair value with changes in fair value generally reflected in other comprehensive
income. Hedges impact earnings when the forecasted transaction being hedged
occurs, when hedge ineffectiveness is measured and recorded, when the forecasted
transaction being hedged is no longer probable of occurring, or when there is an
accumulated other comprehensive loss and when the hedge and the forecasted
transaction being hedged are in a loss position on a combined basis.
For further information regarding accounting for competitive energy contracts,
see Note 3, "Derivative Instruments, Market Risk and Risk Management," to the
consolidated financial statements.
K. Stock-Based Compensation
At December 31, 2002, NU maintains an Employee Stock Purchase Plan (ESPP) and
other long-term incentive plans which are described more fully in Note 4D,
"Employee Benefits - Stock-Based Compensation" to the consolidated financial
statements. NU accounts for these plans under the recognition and measurement
principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations. No stock-based employee
compensation cost for stock options is reflected in net income, as all options
granted under those plans had an exercise price equal to the market value of the
underlying common stock on the date of grant. The following table illustrates
the effect on net income and earnings per share (EPS) if NU had applied the fair
value recognition provisions of SFAS No. 123 to stock-based employee
compensation.
(Millions of Dollars, For the Years Ended December 31,
except per share amounts) 2002 2001 2000
- --------------------------------------------------------------------------------
Net income/(loss), as reported $152.1 $243.5 $(28.6)
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related tax effects (5.3) (4.4) (5.3)
- --------------------------------------------------------------------------------
Pro forma net income/(loss) $146.8 $239.1 $(33.9)
- --------------------------------------------------------------------------------
Earnings/(loss) per share:
Basic - as reported $ 1.18 $ 1.80 $(0.20)
Basic - pro forma $ 1.14 $ 1.76 $(0.24)
Diluted - as reported $ 1.18 $ 1.79 $(0.20)
Diluted - pro forma $ 1.14 $ 1.76 $(0.24)
================================================================================
L. Other Income/(Loss), Net
The pre-tax components of NU's other income/(loss), net items are as follows:
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Seabrook-related gains $ 38.7 $ -- $ --
Investment write-downs (18.4) -- --
Gain related to Millstone sale -- 201.9 --
Loss on share repurchase contracts -- (35.4) --
Investment income 25.4 19.3 42.4
Other, net (1.9) 1.8 (56.7)
- --------------------------------------------------------------------------------
Totals $ 43.8 $187.6 $(14.3)
================================================================================
Other, net in 2000 primarily relates to nuclear related costs and adjustments to
NU's environmental reserves.
M. 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
Debt assumed (234.0)
NU common shares issued (217.1)
- --------------------------------------------------------------------------------
Cash paid $ 261.4
================================================================================
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Cash paid during the year for:
Interest, net of amounts capitalized $259.9 $275.3 $269.7
Income taxes $114.4 $321.0 $253.4
================================================================================
2. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by NU and its
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. At
December 31, 2002, CL&P's charter permits CL&P to incur $480 million of
additional unsecured debt. PSNH is authorized by the New Hampshire Public
Utilities Commission (NHPUC) to incur short-term borrowings up to a maximum of
$100 million. Prior to the sale of Seabrook, NAEC had NHPUC authorization to
incur short-term borrowings up to a maximum of $260 million. Currently, NAEC has
no plans to incur any future short-term borrowings.
Regulated Companies Credit Agreement: On November 12, 2002, CL&P, PSNH, WMECO,
and Yankee Gas entered into a 364-day unsecured revolving credit facility for
$300 million. This facility replaced a $350 million facility for CL&P, PSNH,
WMECO and Yankee Gas, which expired on November 15, 2002. CL&P may draw up to
$150 million under the facility and PSNH, WMECO and Yankee Gas each may draw up
to $100 million, subject to the $300 million maximum borrowing limit under the
facility. Unless extended, the credit facility will expire on November 11, 2003.
At December 31, 2002 and 2001, there were $7 million and $160.5 million,
respectively, in borrowings under these facilities.
NU Parent Credit Agreement: NU replaced its $300 million 364-day unsecured
revolving credit facility, which was to expire on November 15, 2002, with a
364-day unsecured revolving credit facility on November 12, 2002. This facility
provides a total commitment of $350 million, which is available subject to two
overlapping sub-limits. First, subject to the notional amount of any letters of
credit outstanding, amounts up to $350 million are available for advances.
Second, subject to the advances outstanding, letters of credit may be issued in
notional amounts up to $250 million, an increase of $50 million over the prior
facility in the name of NU or any of its subsidiaries. Unless extended, this
credit facility will expire on November 11, 2003. At December 31, 2002 and 2001,
there were $49 million and $40 million, respectively, in borrowings under these
facilities. With regard to credit support, NU had $6.7 million and $45 million,
respectively, in letters of credit issued under these facilities at December 31,
2002 and 2001.
NAEC Credit Agreement: On November 9, 2001, NAEC entered into an unsecured
364-day term credit agreement for $90 million. The term credit agreement
contained a mandatory prepayment provision requiring 100 percent prepayment of
the aggregate amount outstanding within two days of the sale of Seabrook. On
November 1, 2002, NAEC consummated the sale of its ownership interest in
Seabrook and repaid its $90 million in borrowings under this credit agreement.
The agreement expired on November 8, 2002. At December 31, 2001, there were $90
million in borrowings under this term credit agreement.
Under the aforementioned credit agreements, NU and its subsidiaries 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 rates on NU's notes payable to banks
outstanding on December 31, 2002 and 2001, were 4.25 percent and 3.38 percent,
respectively.
These credit agreements provide that NU and its subsidiaries must comply with
certain financial and nonfinancial covenants as are customarily included in such
agreements, including, but not limited to, 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 in the normal course of business for the financial performance
obligations of certain of its competitive energy subsidiaries of which most are
revocable with no term specifications. NU would be required to perform under
these guarantees in the event of non-performance under these obligations by the
competitive energy subsidiaries. NU currently has authorization from the SEC to
provide up to $500 million of guarantees through September 30, 2003, and has
applied for authority to increase this amount to $750 million. At December 31,
2002, payments guaranteed by NU, primarily on behalf of its competitive
businesses, totaled $183.1 million. Additionally, NU had $6.7 million of letters
of credit outstanding at December 31, 2002 and in conjunction with its
investment in RMS, NU guarantees a $3 million line of credit through 2005. Also,
in conjunction with its investment in SESI, NU guarantees up to $30 million of
SESI debt under arrangements with a third-party financing of long-term
receivables.
3. DERIVATIVE INSTRUMENTS, MARKET RISK AND RISK MANAGEMENT
A. Derivative Instruments
Effective January 1, 2001, NU adopted SFAS No. 133, as amended. Derivatives that
are utilized for trading purposes are recorded at fair value with changes in
fair value included in earnings. Other contracts that are derivatives but do not
meet the definition of a cash flow hedge and cannot be designated as being used
for normal purchases or normal sales are also recorded at fair value with
changes in fair value included in earnings. For those contracts that meet the
definition of a derivative and meet the cash flow hedge requirements, the
changes in the fair value of the effective portion of those contracts are
generally recognized in accumulated other comprehensive income until the
underlying transactions occur. For contracts that meet the definition of a
derivative but do not meet the hedging requirements, and for the ineffective
portion of contracts that meet the cash flow hedge requirements, the changes in
fair value of those contracts are recognized currently in earnings. Derivative
contracts that are entered into as a normal purchase or sale and will result in
physical delivery, and are documented as such, are recorded under accrual
accounting. For information regarding accounting changes related to trading
activities, see Note 1C, "Summary of Significant Accounting Policies - New
Accounting Standards," to the consolidated financial statements.
During 2002, a positive $17 million, net of tax, was reclassified from other
comprehensive income in connection with the consummation of the underlying
hedged transactions and recognized in earnings. An additional $0.9 million, net
of tax, was recognized in earnings for those derivatives that were determined to
be ineffective and for the ineffective portion of cash flow hedges. Also during
2002, new cash flow hedge transactions were entered into which hedge cash flows
through 2005. As a result of these new transactions and market value changes
since January 1, 2002, other comprehensive income increased by $52.4 million,
net of tax. Accumulated other comprehensive income at December 31, 2002, was a
positive $15.5 million, net of tax (increase to equity), relating to hedged
transactions, and it is estimated that $9.3 million of this balance, net of tax,
will be reclassified as an increase to earnings within the next twelve months.
Cash flows from the hedge contracts are reported in the same category as cash
flows from the underlying hedged transaction.
There have been changes to interpretations of SFAS No. 133, and the FASB
continues to consider changes and amendments which could affect the way NU
records and discloses derivative and hedging activities in the future.
During 2001, a positive $4.5 million, net of tax, was reclassified from other
comprehensive income in connection with the consummation of the underlying
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 and for the ineffective portion of cash flow hedges. 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 $36.9 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 of this balance, net of
tax, will be reclassified as a decrease to earnings within the next twelve
months. Cash flows from the hedge contracts are reported in the same category as
cash flows from the underlying hedged transaction.
The tables below summarize the derivative assets and liabilities at December 31,
2002 and 2001. These amounts do not include premiums paid, which are recorded as
prepayments and amounted to $26.6 million and $8.3 million at December 31, 2002
and 2001, respectively. These amounts also do not include premiums received,
which are recorded as liabilities and amounted to $29.5 million and $44.2
million at December 31, 2002 and 2001, respectively. These amounts relate
primarily to energy trading activities.
At December 31, 2002
(Millions of Dollars) Assets Liabilities Total
- --------------------------------------------------------------------------------
Competitive Energy Subsidiaries:
Trading $102.9 $ (61.9) $41.0
Nontrading 2.9 -- 2.9
Hedging 22.8 (2.0) 20.8
Regulated Gas Utility:
Hedging 2.3 -- 2.3
- --------------------------------------------------------------------------------
Total $130.9 $ (63.9) $67.0
================================================================================
At December 31, 2001
(Millions of Dollars) Assets Liabilities Total
- --------------------------------------------------------------------------------
Competitive Energy Subsidiaries:
Trading $147.2 $ (90.8) $56.4
Hedging 2.9 (58.4) (55.5)
Regulated Gas Utility:
Hedging 0.2 (2.3) (2.1)
NU Parent:
Hedging -- (0.1) (0.1)
- --------------------------------------------------------------------------------
Total $150.3 $(151.6) $(1.3)
================================================================================
Competitive Energy Subsidiaries Trading: As a market participant in the
Northeast United States, Select Energy conducts energy trading activities in
electricity, natural gas and oil, and therefore, experiences net open positions.
Select Energy manages these open positions with strict policies that limit its
exposure to market risk and require daily reporting to management of potential
financial exposure. Derivatives used in trading activities are recorded at fair
value and included in the consolidated balance sheets as derivative assets or
liabilities. Changes in fair value are recognized in operating revenues in the
consolidated statements of income in the period of change. The net fair value
positions of the trading portfolio at December 31, 2002 and 2001 were assets
of $41 million and $56.4 million, respectively.
The competitive energy subsidiaries trading portfolio includes New York
Mercantile Exchange (NYMEX) futures and options, the fair value of which is
based on closing exchange prices; over-the-counter forwards and options, the
fair value of which is based on the mid-point of bid and ask quotes; and
bilateral contracts for the purchase or sale of electricity or natural gas, the
fair value of which is modeled using available information from external sources
based on recent transactions and validated with a gas forward curve and an
estimated heat rate conversion. The competitive energy subsidiaries trading
portfolio also includes transmission congestion contracts. The fair value of
certain transmission congestion contracts is based on market inputs. Market
information for other transmission congestion contracts is not available, and
those contracts cannot be reliably valued. Management believes the amounts paid
for these contracts are equal to their fair value and has established a
valuation reserve for changes in fair value in excess of cost.
Management conducted a thorough review of the contracts in the trading portfolio
in order to adopt EITF Issue No. 02-3 as of October 1, 2002. Based on this
review, the significant changes in the energy trading market, and the change in
the focus of the energy trading business, certain long-term derivative energy
contracts that were previously included in the trading portfolio and valued at
$33.9 million as of November 30, 2002 were determined to be nontrading and
subsequently designated as normal purchases and sales, as defined by SFAS No.
133, as of that date. Management was able to make this designation based on the
high probability that these contracts will result in physical delivery. The
impact of the normal purchases and sales designation is that these contracts
were adjusted to fair value as of November 30, 2002 and were not and will not be
adjusted subsequently for changes in fair value. The $33.9 million carrying
value as of November 30, 2002 was reclassified from trading derivative assets to
other long-term assets and will be amortized on a straight-line basis to fuel,
purchased and net interchange power expense over the remaining terms of the
contracts, which extend to 2011.
Competitive Energy Subsidiaries Nontrading: Nontrading derivative contracts are
for delivery of energy related to the competitive energy subsidiaries' retail
and wholesale marketing activities. These contracts are not entered into for
trading purposes, but are subject to fair value accounting because these
contracts are derivatives that cannot be designated as normal purchases or
sales, as defined by SFAS No. 133. These contracts cannot be designated as
normal purchases or sales either because they are included in the New York
energy market that settles financially or because the normal purchase and sale
designation was not elected by management. The fair value of nontrading
derivatives was an asset of $2.9 million at December 31, 2002. The competitive
energy subsidiaries held no nontrading derivatives at December 31, 2001.
Competitive Energy Subsidiaries Hedging: Select Energy utilizes derivative
financial and commodity instruments, including futures and forward contracts, to
reduce market risk associated with fluctuations in the price of electricity and
natural gas purchased to meet firm sales commitments to 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 retail supply
requirements. These derivatives have been designated as cash flow hedging
instruments and are used to reduce the market risk associated with fluctuations
in the price of electricity, natural gas, or oil. A derivative that hedges
exposure to the variable cash flows of a forecasted transaction (a cash flow
hedge) is initially recorded at fair value with changes in fair value recorded
in other comprehensive income. Hedges impact earnings when the forecasted
transaction being hedged occurs, when hedge ineffectiveness is measured and
recorded, when the forecasted transaction being hedged is no longer probable of
occurring, or when there is accumulated other comprehensive loss and the hedge
and the forecasted transaction being hedged are in a loss position on a combined
basis.
Select Energy 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 futures
contracts. Under these contracts, which also extend through 2004, the purchase
price of a specified quantity of gas is effectively fixed over the term of the
gas service agreements. At December 31, 2002 and 2001, the NYMEX futures
contracts had notional values of $30.9 million and $91.3 million, respectively,
and were recorded at fair value as a derivative asset of $12.2 million at
December 31, 2002, and as a derivative liability of $24.5 million at December
31, 2001.
During 2002, Select Energy determined that cash flow hedges related to the CL&P
standard offer service contract were ineffective. These hedges were natural gas
derivatives that were used to hedge off-peak electricity purchases for CL&P
standard offer sales. As a result of this ineffectiveness, Select Energy
transferred $3.9 million related to these cash flow hedges from accumulated
other comprehensive income to fuel, purchased and net interchange power expense.
Also in 2002, Select Energy terminated these cash flow hedges and realized
pre-tax income of $5.6 million. In 2001, Select Energy had a liability related
to these standard offer contract hedges of $31.3 million with a corresponding
accumulated other comprehensive loss.
In the fourth quarter of 2002, Select Energy designated new hedges with a
derivative asset value of $5.6 million as hedging full requirements contracts in
the New York market.
Regulated Gas Utility Hedging: Yankee Gas maintains a master swap agreement with
a financial counterparty to purchase gas at fixed prices. Under this master swap
agreement, the purchase price of a specified quantity of gas for two
unaffiliated customers is effectively fixed over the term of the gas service
agreements with those customers for a period of time not extending beyond 2005.
At December 31, 2002 and 2001, the commodity swap agreement had notional values
of $10.7 million and $16.9 million, respectively, and was recorded at fair value
as a derivative asset of $2.3 million at December 31, 2002, and as a derivative
liability of $2.3 million at December 31, 2001.
In 2001 Yankee Gas also held two interest rate swaps with a fair value
derivative asset amount of $0.2 million. These swaps were terminated in 2002.
NU Parent Hedging: At December 31, 2001, NU Parent maintained a treasury
interest rate lock agreement, which was recorded as a fair value liability of
$0.1 million. This agreement was terminated in 2002.
B. Market Risk Information
Select Energy utilizes the sensitivity analysis methodology to disclose
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. 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, fair 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 fair value
based on closing exchange prices.
Competitive Energy Subsidiaries Trading Portfolio: At December 31, 2002, 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 $2.6 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 non-quantifiable. Such risks principally
include credit risk, which is not reflected in this sensitivity analysis.
Competitive Energy Subsidiaries Retail and Wholesale Marketing Portfolio: When
conducting sensitivity analyses of the change in the fair value of Select
Energy's electricity, natural gas and oil nontrading derivatives portfolio,
which would result from a hypothetical change in the future market price of
electricity, natural gas and oil, the fair values of the contracts are
determined from models that 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
retail and wholesale marketing portfolio, which includes cash flow hedges and
electricity, natural gas and oil contracts, assuming a 10 percent unfavorable
change in forward market prices. At December 31, 2002, an unfavorable 10 percent
change in market price would have resulted in a decline in fair value of
approximately $4.4 million.
The impact of a change in electricity, natural gas and oil prices on Select
Energy's retail and wholesale marketing portfolio at December 31, 2002, is not
necessarily representative of the results that will be realized when these
contracts are physically delivered.
C. Other Risk Management Activities
Interest Rate Risk Management: NU manages its interest rate risk exposure by
maintaining a mix of fixed and variable rate debt. At December 31, 2002,
approximately 79 percent of NU's long-term debt, including the current portion
and fees and interest due for spent nuclear fuel disposal costs, is at a fixed
interest rate. Fixed interest rate debt is subject to interest rate risk in a
falling interest rate environment. The remaining long-term debt is variable-rate
and is subject to interest rate risk that could result in earnings volatility.
Assuming a one percentage point increase in NU's variable interest rates, annual
interest expense would have increased by $4.9 million. At December 31, 2002, NU
does not have any derivative contracts outstanding to manage interest rate risk.
Credit Risk Management: 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. 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
margin accounts. This wide customer and supplier mix generates a need for a
variety of contractual structures, products and terms which, in turn, 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.
NU's regulated utilities have a lower level of credit risk related to providing
electric and gas distribution service than NU's competitive energy subsidiaries.
Credit risks and market risks at the competitive energy subsidiaries are
monitored regularly by a Risk Oversight Council operating outside of the
business 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 fair
value and other risk management methodologies that utilize forward price curves
in the energy markets to estimate the size and probability of future potential
exposure.
NYMEX traded futures and option contracts are guaranteed by the NYMEX and have a
lower credit risk. Select Energy 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 ratings), collateral requirements under
certain circumstances (including cash in advance, letters of credit, and parent
guarantees), and the use 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.
4. EMPLOYEE BENEFITS
A. Pension Benefits and Postretirement Benefits Other Than Pensions
Pension Benefits: NU's subsidiaries participate in a uniform noncontributory
defined benefit retirement plan (Plan) covering substantially all regular NU
employees. Benefits are based on years of service and the employees' highest
eligible compensation during 60 consecutive months of employment. Pre-tax
pension income, approximately 30 percent of which was credited to utility plant,
was $73.4 million in 2002, $101 million in 2001, and $90.9 million in 2000.
These amounts exclude pension settlements, curtailments and net special
termination income of $22.2 million in 2002, expense of $2.6 million in 2001,
and income of $7 million in 2000.
Pension income attributable to earnings is as follows:
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(73.4) $(101.0) $(90.9)
Net pension income
capitalized as utility plant (a) 22.0 30.3 27.3
- --------------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination benefits (51.4) (70.7) (63.6)
Settlements, curtailments and
special termination benefits
reflected in earnings -- 7.5 --
- --------------------------------------------------------------------------------
Total pension income
included in earnings $(51.4) $ (63.2) $(63.6)
================================================================================
(a) Net pension income capitalized as utility plant was calculated utilizing an
average of 30 percent.
On November 1, 2002, CL&P, NAEC and certain other joint owners consummated the
sale of their ownership interests in Seabrook to a subsidiary of FPL. NAESCO, a
wholly owned subsidiary of NU, ceased having operational responsibility for
Seabrook at that time. NAESCO employees were transferred to FPL, which
significantly reduced the expected service lives of NAESCO employees who
participated in the Plan. As a result, NAESCO recorded pension curtailment
income of $29.1 million in 2002. As the curtailment related to the operation of
Seabrook, NAESCO credited the joint owners of Seabrook with this amount. CL&P
recorded its $1.2 million share of this income as a reduction to stranded costs,
and as such, there was no impact on 2002 CL&P earnings. PSNH was credited with
its $10.5 million share of this income through the Seabrook Power Contracts with
NAEC. PSNH also credited this income as a reduction to stranded costs, and as
such, there was no impact on 2002 PSNH earnings.
Additionally, in conjunction with the divestiture of its generation assets, NU
recorded $1.2 million in curtailment income in 2002 and $6.6 million of
curtailment income and $0.4 million of special termination benefits income in
2000.
Effective February 1, 2002, certain CL&P and utility group employees who were
displaced were eligible for a Voluntary Retirement Program (VRP). The VRP
supplements NU's Plan and provides special provisions. Eligible employees
include non-bargaining unit employees or employees belonging to a collective
bargaining unit that has agreed to accept the VRP who are active participants in
NU's Plan at January 1, 2002, and that have been displaced as part of the
reorganization between January 22, 2002 and March 2003. Eligible employees
received a special retirement benefit under the VRP whose value was roughly
equivalent to a multiple of base pay based on years of credited service. During
2002, NU recorded an expense of $8.1 million associated with special pension
termination benefits related to the VRP. NU believes that the cost of the VRP is
probable of recovery through regulated utility rates, and accordingly, the $8.1
million was recorded as a regulatory asset with no impact on 2002 earnings.
In conjunction with the Voluntary Separation Program (VSP) that was announced in
December 2000, NU recorded $26 million in settlement income and $64.7 million in
curtailment income 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 non-bargaining unit employees who, by February 1, 2002,
were at least age 50, with a minimum of five years of credited service, and at
December 15, 2000, were assigned to certain groups and in eligible job
classifications.
One component of the VSP included special pension termination benefits equal to
the greater of five years added to both age and credited service of eligible
participants or two weeks of pay for each year of service subject to a minimum
level of 12 weeks and a maximum of 52 weeks for eligible participants. The
special pension termination benefits expense associated with the VSP totaled
$93.3 million in 2001. The net total of the settlement and curtailment income
and the special termination benefits expense was $2.6 million, of which $7.5
million of costs were included in operating expenses, $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.
Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries also
provide certain health care benefits, primarily medical and dental, and life
insurance benefits through a benefit plan to retired employees. These benefits
are available for employees retiring from NU 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. NU annually
funds postretirement costs through external trusts with amounts that have been
rate-recovered and which also are tax deductible.
In 2002, NU recorded PBOP special termination benefits income of $1.2 million
related to the sale of Seabrook. CL&P and PSNH recorded their shares of this
curtailment as reductions to stranded costs. In 2001, NU recorded PBOP
curtailment expense and special termination benefits expense totaling $11.9
million in connection with the VSP. This amount was recorded as a regulatory
asset and collected through regulated utility rates in 2002.
Additionally, in conjunction with the divestiture of its generation assets, NU
recorded $0.4 million in special termination benefits income in 2000.
In 2002, the PBOP plan was amended to change the claims experience basis, to
increase minimum retiree contributions and to reduce the cap on the company's
subsidy to the dental plan. These amendments resulted in a $34.2 million
decrease in NU's benefit obligation under the PBOP plan at December 31, 2002.
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) 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(1,687.6) $(1,670.9) $(400.0) $(335.3)
Service cost (37.2) (35.7) (6.2) (6.2)
Interest cost (119.8) (119.7) (29.2) (27.2)
Plan amendment (11.4) -- 34.2 --
Actuarial loss (117.7) (72.1) (44.0) (76.2)
Benefits paid - excluding lump sum payments 97.3 94.5 44.0 38.0
Benefits paid - lump sum payments 50.2 133.8 -- --
Curtailments and settlements 44.5 75.8 3.4 6.9
Special termination benefits (8.1) (93.3) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(1,789.8) $(1,687.6) $(397.8) $(400.0)
====================================================================================================================================
Change in plan assets
Fair value of plan assets at beginning of year $ 1,990.4 $ 2,319.4 $ 171.1 $ 197.6
Actual return on plan assets (213.1) (100.7) (14.4) (17.1)
Employer contribution -- -- 35.0 28.6
Plan asset transfer in 2.5 -- -- --
Benefits paid - excluding lump sum payments (97.3) (94.5) (44.0) (38.0)
Benefits paid - lump sum payments (50.2) (133.8) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 1,632.3 $ 1,990.4 $ 147.7 $ 171.1
====================================================================================================================================
Funded status at December 31 $ (157.5) $ 302.8 $(250.1) $(228.9)
Unrecognized transition (asset)/obligation (2.6) (3.6) 118.5 159.1
Unrecognized prior service cost 70.1 72.8 (5.9) --
Unrecognized net loss/(gain) 418.9 (139.6) 124.8 55.4
- ------------------------------------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 328.9 $ 232.4 $ (12.7) $ (14.4)
====================================================================================================================================
The following actuarial assumptions were used in calculating the plans' year end
funded status:
At December 31,
Pension Benefits Postretirement Benefits
-------------------------------------------------------------------
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
====================================================================================================================================
(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 (income)/expense are as follows:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Service cost $ 37.2 $ 35.7 $ 41.2 $ 6.2 $ 6.2 $ 6.8
Interest cost 119.8 119.7 118.5 29.2 27.2 23.7
Expected return on plan assets (204.9) (214.1) (205.1) (16.6) (17.0) (14.1)
Amortization of unrecognized net
transition (asset)/obligation (1.4) (1.5) (1.4) 13.6 14.5 15.1
Amortization of prior service cost 7.7 6.9 7.9 (0.1) -- --
Amortization of actuarial gain (31.8) (47.7) (52.0) -- -- --
Other amortization, net -- -- -- 2.2 (2.6) (4.3)
- ------------------------------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before settlements,
curtailments and special termination benefits (73.4) (101.0) (90.9) 34.5 28.3 27.2
- ------------------------------------------------------------------------------------------------------------------------------------
Settlement income -- (26.0) -- -- -- --
Curtailment (income)/expense (30.3) (64.7) (6.6) -- 3.3 --
Special termination benefits expense/(income) 8.1 93.3 (0.4) (1.2) 8.6 (0.4)
- ------------------------------------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits (22.2) 2.6 (7.0) (1.2) 11.9 (0.4)
- ------------------------------------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $ (95.6) $ (98.4) $(97.9) $ 33.3 $ 40.2 $ 26.8
====================================================================================================================================
For calculating pension and postretirement benefit income and expense amounts,
the following assumptions were used:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 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 $ 0.9 $ (0.8)
Effect on postretirement
benefit obligation $12.2 $(11.0)
================================================================================
Currently, NU's 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.
Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.
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 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 shares. The matching contributions made by NU were
$11.1 million in 2002, $11.7 million in 2001, and $13.6 million in 2000.
C. Employee Stock Ownership Plan
NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating
shares to employees participating in the NU's 401(k) Savings Plan. Under this
arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250
million, the proceeds of which were loaned 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 first and second quarters of 2001, NU declared a $0.10 per share
quarterly dividend. During the third quarter of 2001 through the second quarter
of 2002, NU declared a $0.125 per share quarterly dividend. NU declared a
$0.1375 per share dividend during the third and fourth quarters of 2002.
In 2002 and 2001, the ESOP trust issued 607,475 and 546,610 of NU common shares,
respectively, to satisfy 401(k) Savings Plan obligations to employees. At
December 31, 2002 and 2001, total allocated ESOP shares were 7,008,784 and
6,401,309, respectively, and total unallocated ESOP shares were 3,791,401 and
4,398,876, respectively. The fair market value of unallocated ESOP shares at
December 31, 2002 and 2001, was $57.5 million and $77.6 million, respectively.
D. Stock-Based Compensation
Employee Share Purchase Plan: Since July 1998, NU has maintained an ESPP for all
eligible employees. Under the ESPP, NU common shares 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 as of the beginning of the purchase period.
Effective January 1, 2001, the ESPP was terminated because of a 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. During 2002, employees purchased 188,774
shares at discounted prices of $14.15 and $15.39. At December 31, 2002,
1,811,226 shares remained registered for future issuance under the ESPP.
Incentive Plans: NU has long-term incentive plans authorizing various types of
awards, including stock options and performance units, to be made to eligible
employees and board members. The exercise price of stock options, as set at the
time of grant, is equal to the fair market value per share at the date of grant,
and therefore no stock-based compensation cost is reflected in net income. A
liability of $1.3 million was recorded at December 31, 2002, for the fair value
of the performance units earned. Under the Northeast Utilities Incentive Plan
(Incentive Plan), the number of shares which may be utilized for or made subject
to issuance pursuant to grants and awards granted during a given calendar year
may not exceed the aggregate of one percent of the total number of shares of NU
common shares outstanding as of the first day of that calendar year and the
shares not utilized in previous years. At December 31, 2002 and 2001, NU had
2,440,339 and 2,692,633 shares of common stock, respectively, registered for
issuance under the Incentive Plan.
Stock option transactions for 2002, 2001 and 2000, including those options
acquired in connection with the Yankee merger, are as follows:
Exercise Price Per Share
---------------------------------------------
Options Range Weighted Average
- ------------------------------------------------------------------------------------------------------------------------------------
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 and cancelled (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 and cancelled (132,467) $14.8750 - $21.0300 $18.2217
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding - December 31, 2001 3,009,916 $ 9.6250 - $22.2500 $16.4467
- ------------------------------------------------------------------------------------------------------------------------------------
Granted 1,337,345 $16.5500 - $19.8700 $17.8284
Exercised (262,800) $10.0134 - $19.5000 $15.4666
Forfeited and cancelled (247,152) $14.9375 - $22.2500 $18.3473
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding - December 31, 2002 3,837,309 $ 9.6250 - $22.2500 $16.8738
====================================================================================================================================
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
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable - December 31, 2002 1,956,555 $ 9.6250 - $22.2500 $15.3758
====================================================================================================================================
In 1997, 500,000 options with a weighted average exercise price of $9.625 were
granted. These options, which are all exercisable at December 31, 2002, have a
remaining contractual life of 4.63 years. Excluding these options from those
outstanding at December 31, 2002, the resulting range of exercise prices is
$14.9375 to $22.25.
For certain options that were granted in 2002, 2001 and 2000, the vesting
schedule for these options is ratably over three years from the date of grant.
Additionally, certain options granted in 2002, 2001 and 2000 vest 50 percent at
the date of grant and 50 percent one year from the date of grant, while other
options granted in 2002 vest 100 percent after five years.
NU has also made several small grants of restricted stock and other
incentive-based stock compensation under the Incentive Plan. During 2002, 2001
and 2000, $1 million, $1.2 million and $1.9 million, respectively, was expensed
related to this stock-based compensation.
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:
2002 2001 2000
- --------------------------------------------------------------------------------
Risk-free interest rate 4.86% 5.34% 6.56%
Expected life 10 years 10 years 10 years
Expected volatility 23.71% 25.47% 26.15%
Expected dividend yield 2.11% 2.11% 1.82%
================================================================================
The weighted average grant date fair values of options granted during 2002, 2001
and 2000 were $5.64, $6.94 and $7.50, respectively. The weighted average
remaining contractual lives for those options outstanding at December 31, 2002
and 2001 are 7.50 years.
For further information regarding stock-based compensation, see Note 1C,
"Summary of Significant Accounting Policies - New Accounting Standards," and
Note 1K, "Summary of Significant Accounting Policies - Stock-Based
Compensation," to the consolidated financial statements.
E. Supplemental Executive Retirement and Other Plans
NU has maintained a Supplemental Executive Retirement Plan (SERP) since 1987.
The SERP provides its participants, who are executives of NU, with benefits that
would have been provided to them under NU's retirement plan if certain Internal
Revenue Code and other limitations were not imposed. The SERP liability of $20.1
million and $18 million at December 31, 2002 and 2001, respectively, represents
NU's actuarially determined obligation under the SERP. For information regarding
the SERP investments, see Note 9, "Fair Value of Financial Instruments," to the
consolidated financial statements.
NU maintains a plan for retirement and other benefits for certain current and
past company officers. The actuarially determined liability for this plan was
$32.2 million and $25.2 million at December 31, 2002 and 2001, respectively.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which ceases amortization of goodwill and certain intangible
assets with indefinite useful lives. SFAS No. 142 also requires that goodwill
and intangible assets deemed to have indefinite useful lives be reviewed for
impairment upon adoption of SFAS No. 142 and at least annually thereafter by
applying a fair value-based test. Under SFAS No. 142, goodwill impairment is
deemed to exist if the net book value of a reporting unit exceeds its estimated
fair value and if the implied fair value of goodwill based on the estimated fair
value of the reporting unit is less than the carrying amount of the goodwill.
On July 1, 2002, the competitive energy subsidiaries acquired certain assets and
assumed certain liabilities of Woods Electrical, an electrical services company
and Woods Network, a network products and services company, for an aggregate
adjusted purchase price of $16.3 million. The aggregate adjusted purchase price
consisted of $4.2 million of tangible net assets, $0.1 million of intangible
assets subject to amortization, consisting of customer backlog and employment
related agreements, $6.8 million of indefinite lived intangible assets not
subject to amortization consisting of $3.8 million associated with customer
relationships acquired and $3 million associated with tradenames acquired, and
$5.2 million of goodwill. The customer backlog and employment related agreements
are being amortized over periods of one and three years, respectively, and have
a weighted average amortization period of 1.6 years. This purchase price
allocation is preliminary and has been adjusted since the acquisition date.
Financial results of the acquired companies are included in NU's results of
operations since July 1, 2002. The goodwill recognized in these transactions in
the aggregate amount of $5.2 million was assigned to the competitive energy
subsidiaries reportable segment and is expected to be fully deductible for tax
purposes. Additionally, as part of these purchase agreements, an additional
payment of not more than $9.2 million would be contingently payable by 2005 if
certain earnings targets are met. Any contingent payments made will be accounted
for as part of the purchase price.
NU's reporting units that maintain goodwill are generally consistent with the
operating segments underlying the reportable segments identified in Note 13,
"Segment Information," to the consolidated financial statements. During the
fourth quarter of 2002, consistent with changes in the way management reviews
the operating results of its reporting units, NU's reporting units under the
competitive energy subsidiaries reportable segment were revised to include: 1)
the wholesale marketing reporting unit, 2) the retail marketing reporting unit,
3) the trading reporting unit, and 4) the services reporting unit. The wholesale
marketing, retail marketing and trading reporting units are comprised of the
operations of Select Energy, NGC and HWP, and the services reporting unit is
comprised of the operations of SESI, NGS and its newly acquired subsidiary Woods
Electrical, Woods Network, and the nonenergy related subsidiaries of Yankee,
including YESCO. As a result, NU's revised reporting units that maintain
goodwill are as follows: Yankee Gas, classified under the regulated utilities -
gas reportable segment, the wholesale and retail marketing reporting unit and
the services reporting unit which are both classified under the competitive
energy subsidiaries reportable segment. The goodwill balances of these reporting
units are included in the table herein.
On November 30, 2001, Select Energy acquired Niagara Mohawk Energy Marketing,
Inc. (NMEM) for $31.7 million. NMEM was subsequently renamed Select Energy New
York, Inc. (SENY). During 2002, as a result of subsequent adjustments to SENY's
purchase price allocation as a result of changes in the fair value of the assets
and liabilities acquired, $3.2 million of goodwill was recorded. This goodwill
amount is included in the wholesale and retail marketing reporting unit at
December 31, 2002.
NU has completed its initial and subsequent impairment analyses, on January 1,
2002 and October 1, 2002, respectively, for all reporting units that maintain
goodwill under SFAS No. 142. YESCO holds a note from an entity that purchased
certain YESCO assets. Cash flows for YESCO support the investment but not the
goodwill recorded.
As a result, in 2002, a goodwill impairment loss totaling $0.4 million was
recognized in the services reporting unit. For all other reporting units, NU has
determined that no impairment exists. In completing these analyses, the fair
values of the reporting units were estimated using both discounted cash flow
methodologies and an analysis of comparable companies or transactions. Except
for the aforementioned acquisitions and YESCO impairment, there were no other
impairments or adjustments to these goodwill balances in 2002.
Inclusive of the aforementioned acquisitions and the YESCO goodwill write-off,
at December 31, 2002, NU maintained $321 million of goodwill that is no longer
being amortized, $18.1 million of identifiable intangible assets which continue
to be amortized over an average period of 8.5 years and $6.8 million of
intangible assets not subject to amortization. Primarily based on revised
financial information, the remaining period of amortization related to the
exclusivity agreement and the customer list were reduced from 15 years to 8.5
years during the fourth quarter of 2002, resulting in a prospective increase to
amortization expense related to these intangible assets of $2 million annually.
At December 31, 2001, NU maintained $313 million of goodwill and $20.1 million
of identifiable intangible assets. Amortization of goodwill ceased on January 1,
2002.
These amounts are included on the consolidated balance sheets as goodwill and
other purchased intangible assets, net. A summary of NU's goodwill balances at
December 31, 2002 and 2001, by reportable segment and reporting unit is as
follows:
At December 31,
(Millions of Dollars) 2002 2001
- --------------------------------------------------------------------------------
Regulated Utilities - Gas:
Yankee Gas $287.6 $287.6
Competitive Energy Subsidiaries:
Services 30.2 25.4
Wholesale and Retail Marketing 3.2 --
- --------------------------------------------------------------------------------
Totals $321.0 $313.0
================================================================================
At December 31, 2002 and December 31, 2001, NU's intangible assets and related
accumulated amortization consisted of the following:
At December 31, 2002
- --------------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
- --------------------------------------------------------------------------------
Intangible assets subject to amortization:
Exclusivity agreement $17.7 $4.6 $13.1
Customer list 6.6 1.7 4.9
Customer backlog and
employment related agreements 0.1 -- 0.1
- --------------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
================================================================================
Intangible assets not subject
to amortization:
Customer relationships $ 3.8
Trade names 3.0
- -------------------------------------------------
Totals $ 6.8
=================================================
At December 31, 2001
- --------------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
- --------------------------------------------------------------------------------
Intangible assets subject to amortization:
Exclusivity agreement $17.7 $3.1 $14.6
Customer list 6.6 1.1 5.5
- --------------------------------------------------------------------------------
Totals $24.3 $4.2 $20.1
================================================================================
NU recorded amortization expense of $2.1 million and $1.6 million for the years
ended December 31, 2002 and 2001, respectively, related to these intangible
assets. Based on the current amount of intangible assets subject to
amortization, the estimated annual amortization expense for each of the
succeeding 5 years from 2003 through 2007 is $3.7 million in 2003 and $3.6
million in subsequent years. These amounts may vary as purchase price
allocations are finalized and acquisitions and dispositions occur in the future.
The results for the years ended December 31, 2001 and 2000, on a historical
basis, do not reflect the provisions of SFAS No. 142. Had NU adopted SFAS
No. 142 on January 1, 2000, historical income before the cumulative effect
of an accounting change and extraordinary loss, net income and basic and fully
diluted EPS amounts would have been adjusted as follows:
Net Basic Fully
(Millions of Dollars, except share information) Income EPS Diluted EPS
- -----------------------------------------------------------------------------------------------
Year Ended December 31, 2002 $152.1 $ 1.18 $ 1.18
- -----------------------------------------------------------------------------------------------
Year Ended December 31, 2001:
Reported income before cumulative
effect of accounting change $265.9 $ 1.97 $ 1.96
Add back: goodwill amortization 9.0 0.07 0.07
- -----------------------------------------------------------------------------------------------
Adjusted income before cumulative
effect of accounting change $274.9 $ 2.04 $ 2.03
===============================================================================================
Reported net income $243.5 $ 1.80 $ 1.79
Add back: goodwill amortization 9.0 0.07 0.07
- -----------------------------------------------------------------------------------------------
Adjusted net income $252.5 $ 1.87 $ 1.86
===============================================================================================
Year Ended December 31, 2000:
Reported income before
extraordinary loss $205.3 $ 1.45 $ 1.45
Add back: goodwill amortization 7.5 0.05 0.05
- -----------------------------------------------------------------------------------------------
Adjusted income before
extraordinary loss $212.8 $ 1.50 $ 1.50
===============================================================================================
Reported net loss $(28.6) $(0.20) $(0.20)
Add back: goodwill amortization 7.5 0.05 0.05
- -----------------------------------------------------------------------------------------------
Adjusted net loss $(21.1) $(0.15) $(0.15)
===============================================================================================
6. SALE OF CUSTOMER RECEIVABLES
At December 31, 2002, CL&P had sold accounts receivable of $40 million to a
subsidiary of Citigroup, Inc. with limited recourse through the CL&P Receivables
Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at December
31, 2002, $3.8 million of assets were designated as collateral and restricted
under the agreement with the CRC and included in the consolidated balance sheets
as cash and cash equivalents. Concentrations of credit risk to the purchaser
under this agreement with respect to the receivables are limited due to CL&P's
diverse customer base within its service territory. At December 31, 2002,
amounts sold to CRC from CL&P but not sold to the Citgroup, Inc. subsidiary
totaling $178.9 million are included in investments in securitizable assets on
the consolidated balance sheets. No amounts were sold in 2001.
7. NUCLEAR GENERATION ASSET DIVESTITURES
Seabrook: On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04
percent combined ownership interest in Seabrook to a subsidiary of FPL. CL&P,
NAEC and certain other of the joint owners collectively sold 88.2 percent of
Seabrook to FPL. NU received approximately $367 million of total cash proceeds
from the sale of Seabrook and another approximately $17 million from Baycorp
Holdings, Ltd. (Baycorp), as a result of the sale of its 15 percent interest in
Seabrook. A portion of this cash was used to repay all $90 million of NAEC's
outstanding debt and other short-term debt, to return a portion of NAEC's equity
to NU and will be used to pay approximately $95 million in taxes. The remaining
proceeds received by NAEC were refunded to PSNH through the Seabrook Power
Contracts. As part of the sale, FPL assumed responsibility for decommissioning
Seabrook. In connection with the sale, NAEC and CL&P recorded a gain in the
amount of approximately $187 million, which was primarily used to offset
stranded costs.
In the third quarter of 2002, CL&P and NAEC received regulatory approvals for
the sale of Seabrook from the DPUC and the NHPUC. As a result of these
approvals, CL&P and NAEC eliminated $0.6 million and $13.9 million,
respectively, on an after-tax basis, of reserves related to their respective
ownership shares of certain Seabrook assets.
On October 10, 2000, NU reached an agreement with Baycorp, a 15 percent joint
owner of Seabrook, under which NU guaranteed a minimum sale price and NU and
Baycorp would share the excess proceeds if the sale of Seabrook resulted in
proceeds of more than $87.2 million related to the sale of this 15 percent
ownership interest. The agreement also limited any top-off amount required to be
funded by Baycorp for decommissioning as part of the sale process. NU received
approximately $17 million in the fourth quarter of 2002 in connection with this
agreement. This amount is included in the $38.7 million of pre-tax
Seabrook-related gains included in other income/(loss), net.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating
plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180
million. As part of the sale, Entergy assumed responsibility for decommissioning
VYNPC's nuclear generating unit. Under the terms of the sale, CL&P, PSNH and
WMECO will continue to buy approximately 16 percent of the plant's output
through March 2012 at a range of fixed prices.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1
and 2 to a subsidiary of Dominion Resources, Inc. (Dominion). CL&P, PSNH and
WMECO sold their ownership interests in Millstone 3 to Dominion along with all
of the unaffiliated joint ownership interests in Millstone 3. NU 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, Dominion 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.
8. COMMITMENTS AND CONTINGENCIES
A. Restructuring and Rate Matters
Connecticut: On September 27, 2001, CL&P filed its application with the DPUC for
approval of the disposition of the proceeds in the amount of approximately $1.2
billion from the sale of the Millstone units to a subsidiary of Dominion. 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. The DPUC's final
decision regarding this application was received on February 27, 2003, and did
not have a material impact on NU's 2002 results of operations.
New Hampshire: In July 2001, the NHPUC opened a docket to review the FPPAC costs
incurred between August 2, 1999, and April 30, 2001. Under the Restructuring
Settlement, FPPAC deferrals are recovered as a Part 3 stranded cost through the
stranded cost recovery charge. On December 31, 2002, the NHPUC issued its final
order allowing recovery of virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge
reconciliation filing with the NHPUC for the period May 1, 2001, through
December 31, 2001. This filing reconciles stranded cost revenues against actual
stranded cost charges with any difference being credited against stranded costs
or deferred for future recovery. Included in the stranded cost charges are the
generation costs for the filing period. The generation costs included in this
filing were subject to a prudence review by the NHPUC. In January 2003, PSNH
entered into a settlement agreement with the Office of Consumer Advocate and the
staff of the NHPUC which resolved all outstanding issues. In conjunction with
the settlement agreement, the NHPUC staff recommended no disallowances resulting
from their review of the outages at PSNH's generating plants. A final order
approving the settlement agreement was issued by the NHPUC in February 2003. The
NHPUC order approved PSNH's reconciliation of stranded costs as outlined within
the settlement agreement and had no impact on PSNH's earnings.
Massachusetts: On March 30, 2001, WMECO filed its second annual stranded cost
reconciliation with the Massachusetts Department of Telecommunications and
Energy (DTE) for calendar year 2000. On March 29, 2002, WMECO filed its 2001
annual transition cost reconciliation with the DTE. This filing reconciled the
recovery of stranded generation costs for calendar year 2001 and includes sales
proceeds from WMECO's portion of the Millstone units, the impact of
securitization and approximately a $13 million benefit to ratepayers from
WMECO's nuclear performance-based ratemaking process.
WMECO and the office of the Massachusetts Attorney General reached a settlement
resolving all transition charge issues for the 1998 through 2001
reconciliations. The DTE approved this settlement on December 27, 2002. The
settlement had a positive impact of $9 million on WMECO 2002 pre-tax earnings.
B. Environmental Matters
NU 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, NU 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 NU 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 NU's consolidated financial statements.
Based upon currently available information for the estimated remediation costs
at December 31, 2002 and 2001, the liability recorded by NU for its estimated
environmental remediation costs amounted to $41.9 million and $46.2 million,
respectively. These amounts include $28.1 million and $32.2 million at December
31, 2002 and 2001, respectively, for remediation of former manufactured gas
plants.
PSNH and Yankee Gas have regulatory recovery mechanisms for environmental costs.
Accordingly, regulatory assets have been recorded for certain environmental
liabilities.
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. At December 31, 2002 and 2001, fees due to the DOE for
the disposal of Prior Period Fuel were $253.6 million and $249.3 million,
respectively, including interest costs of $171.5 million and $167.2 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. At December 31, 2002, as
NU's ownership shares of Millstone and Seabrook have been sold, NU is no longer
responsible for fees relating to current fuel burned at these facilities.
D. Nuclear Insurance Contingencies
In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002,
NU terminated its nuclear insurance related to these plants, and NU has no
further exposure for potential assessments related to Millstone and Seabrook.
However, through its continuing association with Nuclear Electric Insurance
Limited (NEIL) and CYAPC and VYNPC, NU is subject to potential retrospective
assessments totaling $0.8 million under its respective NEIL insurance policies.
E. Long-Term Contractual Arrangements
VYNPC: Previously, under the terms of their agreements, NU's 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 to VYNPC and recorded these
costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale
of its nuclear generating unit to a subsidiary of Entergy for approximately $180
million. Under the terms of the sale, CL&P, PSNH and WMECO will continue to buy
approximately 16 percent of the plant's output through March 2012 at a range of
fixed prices. The total cost of purchases under contracts with VYNPC amounted to
$27.6 million in 2002, $25.3 million in 2001, and $24.9 million in 2000.
Electricity Procurement Contracts: CL&P, PSNH and WMECO have entered into
various arrangements for the purchase of electricity. The total cost of
purchases under these arrangements amounted to $278.3 million in 2002, $363.9
million in 2001, and $482.1 million in 2000. These amounts are for independent
power producer contracts and do not include contractual commitments related to
CL&P's standard offer, PSNH's short-term power supply management or WMECO's
standard offer and default service.
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. The total cost of Yankee Gas' procurement portfolio,
including these contracts, amounted to $158 million in 2002, $195.8 million in
2001, and $148.2 million in 2000.
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 Future Annual Costs: The estimated future annual costs of NU's
significant long-term contractual arrangements are as follows:
(Millions of Dollars) 2003 2004 2005 2006 2007
- --------------------------------------------------------------------------------
VYNPC $ 30.8 $ 29.4 $ 27.1 $ 28.3 $ 27.4
Electricity
Procurement
Contracts 338.5 345.1 350.0 349.9 278.2
Gas Procurement
Contracts 172.2 151.3 130.9 116.2 36.9
Hydro-Quebec 26.3 25.5 25.0 22.7 21.7
- --------------------------------------------------------------------------------
Totals $567.8 $551.3 $533.0 $517.1 $364.2
================================================================================
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 $4.3 billion at December 31, 2002 as follows:
(Millions of Dollars)
- --------------------------------------------------------------------------------
Year
2003 $3,302.0
2004 612.6
2005 290.1
2006 68.7
2007 69.2
- --------------------------------------------------------------------------------
Total $4,342.6
================================================================================
Select Energy's purchase contract amounts can exceed the amount expected to be
reported in fuel, purchased and net interchange power because energy trading
purchases are classified net in revenues.
F. Nuclear Decommissioning and Plant Closure Costs
In conjunction with the Millstone, Seabrook and VYNPC nuclear generation asset
divestitures, the applicable liabilities and nuclear decommissioning trusts were
transferred to the purchasers and the purchasers agreed to assume responsibility
for decommissioning their respective units.
During 2002, NU, along with the other joint owners, were notified by the Yankee
Companies that the estimated cost of decommissioning the units owned by CYAPC,
YAEC and MYAPC increased in total by approximately $380 million over prior
estimates due to higher anticipated costs for spent fuel storage, security and
liability and property insurance. NU's share of this increase would total $171.6
million. Following rate cases to be filed by the Yankee Companies with the FERC,
NU will seek recovery of the higher decommissioning costs from retail customers
through the appropriate state regulatory agency. At December 31, 2002 and 2001,
NU's remaining estimated obligations, for decommissioning for the units owned by
CYAPC, YAEC and MYAPC, which have been shut down were $354.5 million and $216.6
million, respectively.
G. 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. (Con Edison).
On March 5, 2001, 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 (the Merger
Agreement). On March 12, 2001, NU filed suit against Con Edison in the United
States District Court for the Southern District of New York (the District Court)
seeking damages in excess of $1 billion arising from Con Edison's breach of the
Merger Agreement.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for
breach of contract, fraudulent inducement and negligent misrepresentation. Con
Edison has claimed that it is entitled to recover a portion of the merger
synergy savings estimated to have a net present value of in excess of $700
million. NU disputes both Con Edison's entitlement to any damages as well as its
method of computing its alleged damages.
The companies have completed discovery in the litigation. Motions for summary
judgment were argued before the District Court on February 4, 2002. No trial
date has been set. At this stage of the litigation, management can predict
neither the outcome of this matter nor its ultimate effect on NU.
For further information regarding this litigation, see NU's 2002 report on Form
10-K, Item 3, "Legal Proceedings."
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash and Cash Equivalents: The carrying amounts approximate fair value due to
the short-term nature of cash and cash equivalents.
SERP Investments: Investments held for the benefit of the SERP are recorded at
fair market value based upon quoted market prices. The investments having a cost
basis of $17.9 million and $7.4 million held for benefit of the SERP were
recorded at their fair market values at December 31, 2002 and 2001, of $17.8
million and $9 million, respectively. For information regarding the SERP
liabilities, see Note 4E, "Employee Benefits - Supplemental Executive Retirement
and Other Plans" to the consolidated financial statements.
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of NU'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 NU's financial
instruments and the estimated fair values are as follows:
At December 31, 2002
(Millions of Dollars) Carrying Amount Fair Value
- --------------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 84.0
Long-term debt -
First mortgage bonds 771.0 810.0
Other long-term debt 1,577.2 1,597.8
Rate reduction bonds 1,899.3 2,080.6
================================================================================
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
================================================================================
Other Financial Instruments: The carrying value of financial instruments
included in current assets and current liabilities, including investments in
securitizable assets, approximates their fair value.
10. LEASES
NU has entered into lease agreements, some of which are capital leases, for the
use of data processing and office equipment, vehicles, and office space. The
provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $1.7 million in
2002, $13.1 million in 2001, and $50.1 million in 2000. Interest included in
capital lease rental payments was $0.6 million in 2002, $4.7 million in 2001,
and $11.6 million in 2000. Operating lease rental payments charged to expense
were $7.8 million in 2002, $7 million in 2001, and $10.1 million in 2000.
Future minimum rental payments excluding executory costs, such as property
taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, at December 31, 2002 are as follows:
(Millions of Dollars) Capital Operating
Year Leases Leases
- --------------------------------------------------------------------------------
2003 $ 3.1 $ 23.1
2004 3.0 20.6
2005 2.8 18.4
2006 2.7 16.2
2007 2.6 9.8
After 2007 22.4 26.9
- --------------------------------------------------------------------------------
Future minimum lease payments $36.6 $115.0
Less amount representing interest 19.8
- --------------------------------------------------------------------------------
Present value of future
minimum lease payments $16.8
================================================================================
11. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The accumulated balance for each other comprehensive income/(loss) item is as
follows:
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
- --------------------------------------------------------------------------------
Qualified cash flow
hedging instruments $(36.9) $52.4 $15.5
Unrealized gains/(losses) on securities 5.0 (5.1) (0.1)
Minimum pension liability adjustments (0.6) 0.1 (0.5)
- --------------------------------------------------------------------------------
Accumulated other
comprehensive (loss)/income $(32.5) $47.4 $14.9
================================================================================
Current
December 31, Period December 31,
(Millions of Dollars) 2000 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)
================================================================================
The changes in the components of other comprehensive income/(loss) are reported
net of the following income tax effects:
(Millions of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Qualified cash flow
hedging instruments $(33.1) $24.3 $ --
Unrealized gains/(losses) on securities 3.3 (1.9) (0.2)
Minimum pension liability adjustments -- -- --
- --------------------------------------------------------------------------------
Accumulated other
comprehensive income/(loss) $(29.8) $22.4 $(0.2)
================================================================================
Accumulated other comprehensive income/(loss) fair value adjustments of NU's
qualified cash flow hedging instruments are as follows:
At December 31,
(Millions of Dollars, Net of Tax) 2002 2001
- --------------------------------------------------------------------------------
Balance at beginning of year $(36.9) $ --
- --------------------------------------------------------------------------------
Cumulative effect of adopting SFAS No. 133 -- 12.3
Hedged transactions recognized into earnings 17.0 4.5
Change in fair value 29.2 (29.6)
Cash flow transactions entered into for the period 6.2 (24.1)
- --------------------------------------------------------------------------------
Net change associated with the current period
hedging transactions 52.4 (36.9)
- --------------------------------------------------------------------------------
Total fair value adjustments included in
accumulated other comprehensive income/(loss) $ 15.5 $(36.9)
================================================================================
12. 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) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
Income before preferred dividends of subsidiaries $157.7 $273.2 $219.5
Preferred dividends of subsidiaries 5.6 7.3 14.2
- ------------------------------------------------------------------------------------------------------------------
Income before cumulative effect of accounting change
and extraordinary loss 152.1 265.9 205.3
Cumulative effect of accounting change, net of tax benefit -- (22.4) --
Extraordinary loss, net of tax benefit -- -- (233.9)
- ------------------------------------------------------------------------------------------------------------------
Net income/(loss) $152.1 $243.5 $(28.6)
==================================================================================================================
Basic EPS common shares outstanding (average) 129,150,549 135,632,126 141,549,860
Dilutive effect of employee stock options 190,811 285,297 417,356
- ------------------------------------------------------------------------------------------------------------------
Fully diluted EPS common shares outstanding (average) 129,341,360 135,917,423 141,967,216
- ------------------------------------------------------------------------------------------------------------------
Basic earnings/(loss) per common share:
Income before cumulative effect of accounting change
and extraordinary loss $ 1.18 $ 1.97 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
- ------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 1.18 $ 1.80 $(0.20)
==================================================================================================================
Fully diluted earnings/(loss) per common share:
Income before cumulative effect of accounting change
and extraordinary loss $ 1.18 $ 1.96 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
- ------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 1.18 $ 1.79 $(0.20)
==================================================================================================================
13. SEGMENT INFORMATION
NU is organized between regulated utilities (electric and gas since the March 1,
2000 acquisition of Yankee) and competitive energy subsidiaries based on the
regulatory environment of each segment. The regulated utilities segment
represents approximately 78 percent, 78 percent, and 85 percent of NU's total
revenues for each of the three years in the period ended December 31, 2002,
respectively, and primarily includes the operations of CL&P, PSNH and WMECO,
whose complete financial statements are included in NU's combined report on Form
10-K. The regulated gas utilities segment includes the operations of Yankee Gas.
The reclassification of trading revenues and expenses, which has been
retroactively applied to 2001, resulted in an increase in these percentages from
amounts reported in prior periods. Regulated utility revenues from the sale of
electricity and natural gas primarily are derived from residential, commercial
and industrial customers and are not dependent on any single customer.
On January 1, 2000, Select Energy began serving one half of CL&P's standard
offer load for a four-year period through December 31, 2003, at fixed prices.
Total Select Energy revenues from CL&P for CL&P's standard offer load and for
other transactions with CL&P, represented approximately $631 million or 38
percent in 2002, approximately $648 million or 31 percent in 2001 and
approximately $652 million or 34 percent in 2000, of total competitive energy
subsidiaries' revenues. Total CL&P purchases from the competitive energy
subsidiaries are eliminated in consolidation. Additionally, Select Energy
revenues from NSTAR represented $277.3 million or 13 percent and $285.1 million
or 15 percent of total competitive energy subsidiaries' revenues for the years
ended December 31, 2001 and 2000, respectively. Beginning in 2002, Select Energy
also provided basic generation service in the New Jersey market. Select Energy
revenues related to these contracts represented $207.4 million or 12 percent of
total competitive energy subsidiaries' revenues for the year ended December 31,
2002. No other individual customer represented in excess of 10 percent of the
competitive energy subsidiaries revenues for 2002, 2001 and 2000.
Additionally, WMECO's purchases from Select Energy represented approximately $14
million and $4 million of total competitive energy subsidiaries' revenues in
2002 and 2001, respectively.
The competitive energy subsidiaries segment includes the operations
of Select Energy, a corporation engaged in the trading, marketing,
transportation, storage, and sale of energy commodities, at wholesale and
retail, in designated geographical areas; NGC, a corporation that acquires and
manages generation facilities; SESI, a provider of energy management,
demand-side management and related consulting services for commercial,
industrial and institutional electric companies and electric utility companies;
NGS, including Woods Electrical, a corporation that maintains and services
fossil or hydroelectric facilities and provides third-party electrical,
mechanical, and engineering contracting services; HWP, a company engaged in the
production of electric power; and Woods Network and the competitive energy
subsidiaries of Yankee.
Other in the following table includes the results for Mode 1, an investor in
fiber-optic communications network, the results of the nonenergy-related
subsidiaries of Yankee and the company's investment in Accumentrics Corporation.
Interest expense included in Other primarily relates to the debt of NU parent.
Inter-segment eliminations of revenues and expenses are also included in Other.
For the Year Ended December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
- ----------------------------------------------------------------------------------------------------------------------------
Operating revenues $3,778.1 $293.3 $1,669.8 $(524.9) $ 5,216.3
Depreciation and amortization (618.9) (24.1) (22.0) (2.2) (667.2)
Other operating expenses (2,679.8) (229.3) (1,684.5) 511.2 (4,082.4)
- ----------------------------------------------------------------------------------------------------------------------------
Operating income/(loss) 479.4 39.9 (36.7) (15.9) 466.7
Other income/(loss), net 42.1 (0.8) (2.0) 4.5 43.8
Interest expense, net (187.2) (14.2) (43.9) (25.2) (270.5)
Income tax (expense)/benefit (121.7) (7.3) 28.5 18.2 (82.3)
Preferred dividends (5.6) -- -- -- (5.6)
- ----------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 207.0 $ 17.6 $ (54.1) $ (18.4) $ 152.1
- ----------------------------------------------------------------------------------------------------------------------------
Total assets $7,549.0 $963.0 $1,973.2 $(217.6) $10,267.6
- ----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 380.6 $ 70.6 $ 23.2 $ 18.1 $ 492.5
============================================================================================================================
For the Year Ended December 31, 2001
- ----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
- ----------------------------------------------------------------------------------------------------------------------------
Operating revenues $4,282.7 $378.0 $2,074.8 $ (767.3) $ 5,968.2
Depreciation and amortization (1,619.3) (33.3) (10.4) 478.9 (1,184.1)
Other operating expenses (2,171.9) (294.6) (2,019.5) 241.0 (4,245.0)
- ----------------------------------------------------------------------------------------------------------------------------
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 $1,728.0 $(1,016.4) $10,331.9
- ----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 380.6 $ 47.8 $ 15.4 $ 14.2 $ 458.0
============================================================================================================================
For the Year Ended December 31, 2000
- ----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
- ----------------------------------------------------------------------------------------------------------------------------
Operating revenues $4,738.5 $251.2 $1,894.9 $(1,008.0) $ 5,876.6
Depreciation and amortization (483.5) (21.7) (8.4) (3.0) (516.6)
Other operating expenses (3,594.6) (202.5) (1,821.6) 953.5 (4,665.2)
- ----------------------------------------------------------------------------------------------------------------------------
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)/benefit (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
- ----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 373.5 $ 21.6 $ 7.1 $ 11.8 $ 414.0
============================================================================================================================
Consolidated Statements Of Quarterly Financial Data (Unaudited)
Quarter Ended (a)
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share information) March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------------------------------------
2002
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,284,461 $1,141,928 $1,414,304 $1,375,628
Operating Income 114,286 94,051 118,095 140,223
Net Income 18,642 28,857 48,575 56,035
Basic and Fully Diluted Earnings per Common Share $ 0.14 $ 0.22 $ 0.38 $ 0.44
- ----------------------------------------------------------------------------------------------------------------------------------
2001
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,708,436 $1,422,549 $1,544,375 $1,292,860
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 and Fully Diluted Earnings 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
==================================================================================================================================
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation. The summation of quarterly data may not
equal annual data due to rounding. Operating revenue amounts have been
reclassified from those reported in the first and second quarters related to the
adoption of EITF Issue No. 02-3.
Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and share information) 2002 2001 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Property, Plant and Equipment, Net $ 4,728,369 $ 4,472,977 $ 3,547,215 $ 3,947,434 $ 6,170,881
Total Assets 10,267,617 10,331,923 10,217,149 9,688,052 10,387,381
Total Capitalization (a) 4,670,771 4,576,858 4,739,417 5,216,456 6,030,402
Obligations Under Capital Leases (a) 16,803 17,539 159,879 181,293 209,279
- ------------------------------------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues $ 5,216,321 $ 5,968,220 $ 5,876,620 $ 4,471,251 $ 3,767,714
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits 152,109 265,942 205,295 34,216 (146,753)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (22,432) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (233,881) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 152,109 $ 243,510 $ (28,586) $ 34,216 $ (146,753)
====================================================================================================================================
Common Share Data:
Basic Earnings/(Loss) Per Common Share:
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits $ 1.18 $ 1.97 $ 1.45 $ 0.26 $ (1.12)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (0.17) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (1.65) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.18 $ 1.80 $ (0.20) $ 0.26 $ (1.12)
====================================================================================================================================
Fully Diluted Earnings/(Loss)
Per Common Share:
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits $ 1.18 1.96 1.45 0.26 (1.12)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (0.17) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (1.65) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.18 $ 1.79 $ (0.20) $ 0.26 $ (1.12)
====================================================================================================================================
Basic Common Shares Outstanding (Average) 129,150,549 135,632,126 141,549,860 131,415,126 130,549,760
Fully Diluted Common Shares Outstanding (Average) 129,341,360 135,917,423 141,967,216 132,031,573 130,549,760
Dividends Per Share $ 0.53 $ 0.45 $ 0.40 $ 0.10 $ --
Market Price - Closing (high) (c) $ 20.57 $ 23.75 $ 24.25 $ 22.00 $ 17.25
Market Price - Closing (low) (c) $ 13.20 $ 16.80 $ 18.25 $ 13.56 $ 11.69
Market Price - Closing (end of year) (c) $ 15.17 $ 17.63 $ 24.25 $ 20.56 $ 16.00
Book Value Per Share (end of year) $ 17.33 $ 16.27 $ 15.43 $ 15.80 $ 15.63
Tangible Book Value Per Share (end of year) $ 14.62 $ 13.71 $ 13.09 $ 15.53 $ 15.63
Rate of Return Earned on Average Common Equity (%) 7.0 11.2 (1.3) 1.6 (7.0)
Market-to-Book Ratio (end of year) 0.9 1.1 1.6 1.3 1.0
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity 47% 46% 47% 40% 34%
Preferred Stock (a) (b) 3 3 4 5 5
Long-Term Debt (a) 50 51 49 55 61
- ------------------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100%
====================================================================================================================================
(a) Includes portions due within one year.
(b) Excludes $100 million of Monthly Income Preferred Securities.
(c) Market price information reflects closing prices as presented in the Wall
Street Journal.
Consolidated Electric Sales Statistics (Unaudited)
2002 2001 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $1,512,397 $1,490,487 $1,469,439 $1,517,913 $1,475,363
Commercial 1,294,943 1,303,351 1,256,126 1,272,969 1,273,146
Industrial 485,592 549,808 566,625 560,801 568,913
Other Utilities 1,190,396 1,761,324 1,884,082 926,056 336,623
Streetlighting and Railroads 43,679 43,889 45,998 45,564 47,682
Nonfranchised Sales -- (3,438) 16,932 24,659 22,479
Miscellaneous 41,357 67,809 96,666 52,357 16,429
- ------------------------------------------------------------------------------------------------------------------------------------
Total Electric 4,568,364 5,213,230 5,335,868 4,400,319 3,740,635
Gas 466,596 566,814 461,716 -- --
Other 181,361 188,176 79,036 70,932 27,079
- ------------------------------------------------------------------------------------------------------------------------------------
Total $5,216,321 $5,968,220 $5,876,620 $4,471,251 $3,767,714
====================================================================================================================================
Sales: (kWh - Millions)
Residential 13,923 13,322 12,940 12,912 12,162
Commercial 14,103 13,751 13,023 12,850 12,477
Industrial 6,265 6,790 7,130 7,050 6,948
Other Utilities 85,224 51,789 42,127 33,575 9,742
Streetlighting and Railroads 344 332 333 314 320
Nonfranchised Sales -- -- 107 147 193
- ------------------------------------------------------------------------------------------------------------------------------------
Total 119,859 85,984 75,660 66,848 41,842
====================================================================================================================================
Customers: (Average)
Residential 1,614,239 1,610,154 1,576,068 1,569,932 1,555,013
Commercial 183,577 171,218 166,114 164,932 162,500
Industrial 7,763 7,730 7,701 7,721 7,847
Other 3,949 3,969 3,917 3,908 3,890
- ------------------------------------------------------------------------------------------------------------------------------------
Total Electric 1,809,528 1,793,071 1,753,800 1,746,493 1,729,250
Gas 190,855 190,998 185,328 -- --
Total 2,000,383 1,984,069 1,939,128 1,746,493 1,729,250
====================================================================================================================================
Average Annual Use Per
Residential Customer (kWh) 8,611 8,251 8,233 8,243 7,799
====================================================================================================================================
Average Annual Bill Per
Residential Customer $ 934.90 $ 923.70 $ 934.94 $ 969.38 $ 946.80
====================================================================================================================================
Average Revenue Per kWh:
Residential 10.86[cents] 11.20[cents] 11.36[cents] 11.76[cents] 12.14[cents]
Commercial 9.18 9.48 9.65 9.91 10.20
Industrial 7.75 8.10 7.95 7.95 8.19
====================================================================================================================================