EXHIBIT 13.1
ANNUAL REPORT OF NORTHEAST UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION AND BUSINESS ANALYSIS
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OVERVIEW
Consolidated: Northeast Utilities and subsidiaries (NU or the company)
reported 2003 earnings of $116.4 million, or $0.91 per share, compared with
earnings of $152.1 million, or $1.18 per share, in 2002 and $243.5 million,
or $1.79 per share, in 2001. All earnings per share (EPS) amounts are
reported on a fully diluted basis.
The 2003 earnings of $116.4 million, or $0.91 per share include a charge of
$36.9 million, or $0.29 per share, associated with a loss recorded for the
settlement of a wholesale power contract dispute between The Connecticut
Light and Power Company (CL&P) and its three 2003 standard offer power
suppliers, including an NU subsidiary, Select Energy, Inc. For more
information about this contract dispute and the settlement, see the "Impacts
of Standard Market Design" section of this Management's Discussion and
Analysis. Also included in 2003 earnings was a negative $4.7 million after-
tax cumulative effect of an accounting change as a result of the adoption of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46,
"Consolidation of Variable Interest Entities." Excluding the effects of
these two items, net income would have been $158 million, or $1.24 per share.
NU's 2003 results benefited from improved performance at NU Enterprises and
lower corporate-wide interest costs. The better performance at NU
Enterprises reflected improved margins on Select Energy, Inc.'s (Select
Energy) energy supply contracts, higher volumes, improved operation of NU
Enterprises' generating facilities, and the absence of natural gas trading
losses that occurred in the first half of 2002. Those factors were offset by
lower pension income and the absence of earnings related to the Seabrook
nuclear unit (Seabrook).
During 2003, pre-tax pension income for NU declined $41.6 million, from a
credit of $73.4 million in 2002 to a credit of $31.8 million in 2003. Of the
$31.8 million and $73.4 million of pension credits recorded during 2003 and
2002, $16.4 million and $47.2 million, respectively, were recognized in the
consolidated statements of income as reductions to operating expenses. The
remaining $15.4 million in 2003 and $26.2 million in 2002 relate to employees
working on capital projects and were reflected as reductions to capital
expenditures. The pre-tax $30.8 million decrease in pension income that
reduces operating expenses was reflected evenly throughout 2003, resulting in
a decline of $4.6 million in net income per quarter during 2003.
NU's EPS also benefited modestly from a share repurchase program. In the
first quarter of 2003, NU repurchased approximately 1.5 million of its shares
at an average price of $13.73. There were no share repurchases during the
remainder of 2003. On May 13, 2003, the company's Board of Trustees
authorized the repurchase of up to 10 million shares through July 1, 2005.
NU had 127.7 million shares outstanding at December 31, 2003.
NU's revenues for 2003 increased to $6.1 billion from $5.2 billion in 2002,
or an increase of $0.9 billion. Of the $0.9 billion increase in NU's
revenues, $0.8 billion related to NU Enterprises. NU Enterprises' revenues
in 2003 increased primarily due to higher wholesale and retail sales volumes
of $0.4 billion and higher prices of $0.3 billion. The increase in revenues
is also due to increases in electric sales at the Utility Group in 2003 as
compared to 2002.
Earnings decreased $91.4 million for the year ended December 31, 2002 as
compared to 2001. This decrease is primarily the result of several items
recorded in 2001, including an after-tax gain of $115.6 million, or $0.85 per
share associated with the sale of the Millstone nuclear units (Millstone),
offset by an after-tax loss of $22.4 million, or $0.17 per share related to
the adoption of Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended,
and a charge of $35.4 million, or $0.26 per share related to an agreement
with two financial institutions to repurchase NU common shares. This
earnings decrease is also attributable to after-tax losses totaling $11
million, or $0.09 per share recorded in 2002, associated with the write-down
of investments in NEON Communications, Inc. (NEON) and Acumentrics
Corporation (Acumentrics), offset by after-tax gains totaling $24.5 million,
or $0.19 per share, associated with the sale of Seabrook, which were also
recorded in 2002.
Utility Group: Earnings at all of NU's Utility Group subsidiaries were lower
in 2003 as compared with 2002. The Utility Group is comprised of CL&P,
Public Service Company of New Hampshire (PSNH), Western Massachusetts
Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), and
Yankee Gas Services Company (Yankee Gas). Utility Group net income was lower
due to the absence of approximately $13 million of investment tax credits
(ITC) that were reflected in the second quarter of 2002 at WMECO, as well as
lower pension income and the loss of earnings related to Seabrook. Lower
pension income and the lack of Seabrook earnings resulted in a net income
decrease in 2003 as compared to 2002 of $18.4 million and $16.3 million,
respectively. These decreases were partially offset by lower Utility Group
controllable operation and maintenance costs.
As a result of an adjustment to estimated unbilled electric revenues
resulting from a process to validate and update the assumptions used to
estimate unbilled revenues, 2003 Utility Group retail electric sales
increased 3.6 percent compared to 2002. Absent that adjustment, Utility
Group retail electric sales increased 2.1 percent. Adjustments to estimated
unbilled revenues had a negative impact on Yankee Gas. Yankee Gas firm gas
sales decreased 0.6 percent in 2003 as compared to 2002. Absent those
adjustments, Yankee Gas firm gas sales increased 7.8 percent. Combined, the
adjustments to estimated unbilled revenues increased NU's net income by
approximately $4.6 million for 2003. For further information regarding the
estimate of unbilled revenues, see "Critical Accounting Policies and
Estimates - Utility Group Unbilled Revenues," included in this Management's
Discussion and Analysis.
CL&P earnings before preferred dividends totaled $68.9 million in 2003,
compared with $85.6 million in 2002. The lower income was primarily
attributable to lower pension income, after-tax write-offs of approximately
$5 million related to a distribution rate case that was decided in December
2003, and a loss of approximately $1 million recorded for the settlement of
the wholesale power contract dispute.
PSNH earned $45.6 million in 2003, compared with $62.9 million in 2002. The
decline in earnings is due to a lower level of regulatory assets earning a
return, the positive resolution of certain contingencies related to a
regulatory proceeding decided in 2002, and higher pension costs. Also, as a
result of the sale of Seabrook, earnings at NAEC were essentially eliminated
in 2003, compared with earnings of $26.3 million for 2002. NAEC's 2002
earnings included $13.9 million related to the elimination of reserves
associated with its ownership share of Seabrook assets.
WMECO earnings were $16.2 million in 2003 compared to $37.7 million in 2002.
The decline in earnings related primarily to the recognition of $13 million
of ITC in the second quarter of 2002 and to the positive financial impact of
an approval of a regulatory settlement in the fourth quarter of 2002.
Yankee Gas earned $7.3 million in 2003, compared with $17.6 million in 2002.
Yankee Gas earnings were reduced by $6.2 million in 2003 as a result of both
the aforementioned downward adjustments in estimated unbilled revenues and
certain gas cost adjustments.
NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy,
Northeast Generation Company (NGC), Select Energy Services, Inc. (SESI),
Northeast Generation Services Company (NGS), and their respective
subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which
are collectively referred to as "NU Enterprises." The generation operations
of Holyoke Water Power Company (HWP) are also included in the results of NU
Enterprises. The companies included in the NU Enterprises segment are
grouped into two business lines: the merchant energy business line and the
energy services business line.
The financial performance of NU Enterprises improved in 2003, losing $3.5
million, or $0.03 per share, compared with losses of $53.2 million, or $0.41
per share in 2002 and earnings of $6.1 million, or $0.05 per share in 2001,
prior to the negative cumulative effect of an accounting change associated with
the adoption of SFAS No. 133. The 2003 loss of $3.5 million includes an
after-tax loss of approximately $36 million, or $0.28 per share, related to
Select Energy's share of the cost of settling the contract dispute between
affiliate CL&P and its suppliers over the responsibility for costs related to
the March 2003 implementation of Standard Market Design (SMD) in New England.
The settlement was filed with the Federal Energy Regulatory Commission (FERC)
on March 3, 2004 and is expected to be approved by the FERC in the first half
of 2004. Excluding the settlement loss, NU Enterprises earned $32.2 million
or $0.25 per share.
NU Enterprises' net income improved due to increased margins on wholesale and
retail contracts, improved performance at NGC, which owns nearly 1,300
megawatts (MW) of primarily hydroelectric and pumped storage generating
capacity in Massachusetts and Connecticut, and the absence of natural gas
trading losses in 2003. Natural gas trading positions in the first half of
2002 resulted in $17.6 million of trading losses. Over the past year, Select
Energy has significantly reduced its trading activities, which are now
limited primarily to price discovery and transaction and risk management for
the merchant energy business line.
FUTURE OUTLOOK
Consolidated: NU estimates that it will earn between $1.20 per share and
$1.40 per share in 2004, including approximately $0.10 per share of parent
company interest and other expenses.
In 2004, NU is projecting to record pre-tax pension expense of $2.9 million.
Pension expense is annually adjusted during the second quarter based on
updated actuarial valuations, and the 2004 estimate may change.
Utility Group: The NU consolidated earnings estimate of $1.20 per share to
$1.40 per share includes Utility Group earnings of between $1.08 per share
and $1.20 per share. The range reflects uncertainties over the outcome of a
pending PSNH rate case before the New Hampshire Public Utilities Commission
(NHPUC) and the outcome of the NU transmission rate case before the FERC.
Management expects both cases to be decided in the second half of 2004. The
earnings range also reflects a continued reduction in pension income.
NU Enterprises: NU projects that the financial performance of NU Enterprises
will continue to improve in 2004. The NU consolidated earnings range of
$1.20 per share to $1.40 per share for 2004 reflects projected earnings of
between $0.22 per share and $0.30 per share at NU Enterprises.
LIQUIDITY
Consolidated: After four years of reducing its indebtedness, NU's total
debt, excluding rate reduction bonds, rose to $2.7 billion at the end of
2003, compared with $2.4 billion at the end of 2002. The higher debt levels
reflect the issuance of new debt by NU parent, WMECO and SESI during 2003, as
well as a $49 million increase in borrowings on NU's revolving credit lines.
NU parent sold $150 million of notes at a coupon rate of 3.3 percent during
2003. These notes mature in 2008. The proceeds from this issuance were
primarily used to refinance Select Energy's short-term debt.
At December 31, 2003, NU had $105 million in notes payable to banks, compared
with $56 million of notes payable to banks at December 31, 2002. In
addition, NU had $83.7 million of cash, including cash and cash equivalents
and unrestricted cash from counterparties at December 31, 2003, compared with
$67.2 million at December 31, 2002.
NU's net cash flows provided by operating activities totaled $573.6 million
in 2003 as compared to $589.7 million in 2002 and $302.4 million in 2001.
Cash flows provided by operating activities in 2003 decreased due to
decreases in working capital items, primarily accounts payable and accrued
taxes. Accrued taxes decreased as the taxes related to the 2002 sale of
Seabrook were paid in March of 2003. Accounts payable decreased as a result
of the timing of payments on amounts outstanding at NU Enterprises. The
decreases in these working capital items were offset by an increase in
regulatory overrecoveries in 2003 as compared to 2002, primarily associated
with CL&P's Competitive Transition Assessment (CTA), Generation Service
Charge (GSC) and System Benefits Charge (SBC), as well as PSNH's Stranded
Cost Recovery Charge (SCRC). For a description of the costs recovered through
these mechanisms, see Note 1H - "Summary of Significant Accounting Policies -
Utility Group Regulatory Accounting," to the consolidated financial statements.
Cash flows provided by operating activities in 2002 increased 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 due to the taxable gain on the
sale of Seabrook. Those taxes were not paid until March of 2003. The
increase in cash flows provided by operating activities in 2002 related
primarily to more collections of receivables and unbilled revenues in 2002
compared to 2001 associated with the sales growth of NU Enterprises.
NU projects that cash flows provided by operating activities will decline
significantly in 2004 from 2003, even if net income increases, as a result of
expected refunds to CL&P's customers or applications of previous
overcollections to current costs as a result of recent regulatory decisions.
There was a lower level of investing and financing activity in 2003 as
compared to 2002, which was primarily due to the sale of Seabrook, the
acquisition of Woods Electrical Co., Inc. (Woods Electrical) and Woods
Network and the issuance of rate reduction bonds in 2002. Cash flows used
for investments in plant increased to $550 million in 2003 from $485 million
in 2002 and $451.4 million in 2001 as a result of increased levels of capital
expenditures at the Utility Group. NU expects capital expenditures to reach
$738 million in 2004.
There was a lower level of investing and financing activity in 2002 as
compared to 2001, primarily due to the following items that occurred in 2001:
the issuance of long-term debt, the issuance of rate reduction bonds, the
use of proceeds from the sale of Millstone, the buyout and buydown of
independent power producer (IPP) contracts, the retirement of preferred stock
and other preferred securities and the retirement of certain other capital
lease obligations.
The retirement of rate reduction bonds does not equal the amortization of
rate reduction bonds because the retirement represents principal payments,
while the amortization represents amounts recovered from customers for future
principal payments. The timing of recovery does not exactly match the
expected principal payments.
Aside from the rate reduction bonds outstanding, NU has a modest level of
sinking fund payments and debt maturities due between 2004 and 2011,
averaging $56.3 million annually and totaling $64.9 million in 2004. Most of
the debt that must be repaid during that time was issued by NU parent, NGC,
Yankee Gas, and SESI. No CL&P, PSNH or WMECO debt issues mature during that
eight-year period.
The level of common dividends totaled $73.1 million in 2003, compared with
$67.8 million in 2002 and $60.9 million in 2001. The 2003 increase resulted
from NU paying a dividend of $0.1375 per share in the first two quarters of
2003 and $0.15 per share in the second two quarters of 2003. The level of
dividends in 2002 was $0.125 per share in the first two quarters and $0.1375
per share in the second two quarters. 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 dividends are declared.
In recent years, NU's Trustees have addressed dividend increases at the
company's annual meeting, the next of which is on May 11, 2004. On January 12,
2004, the NU Board of Trustees approved the payment of a dividend of
$0.15 per share on March 31, 2004, to shareholders of record at March 1,
2004.
Overall liquidity remained high at December 31, 2003, despite the increase in
the common dividend and the repurchase of 1.5 million shares in 2003 at a
cost of $20.5 million, due primarily to cash earnings from the Utility Group
subsidiaries. NU's liquidity was also strengthened by the aforementioned
issuance of $150 million in notes by NU parent.
Excluding rate reduction bonds as they are non-recourse to NU, NU's
consolidated capitalization was comprised of 46 percent common shareholders'
equity, and 54 percent preferred stock and long-term debt at December 31,
2003, as compared with 47 percent common shareholders' equity and 53 percent
preferred stock and long-term debt at December 31, 2002. As a result of the
Utility Group's proposed expansion plans, management expects capital
requirements to increase over the next several years but will continue to
target a 45 percent equity and 55 percent debt capitalization structure.
Utility Group: NU's higher debt levels reflect the sale of $55 million of 10-
year senior unsecured notes by WMECO on September 30, 2003, at a coupon rate
of 5.0 percent. WMECO used the proceeds from this debt issue to reduce its
level of short-term borrowings from the NU Money Pool. On October 1, 2003,
CL&P fixed the interest rate on $62 million of variable-rate, tax-exempt
notes for five years at 3.35 percent. These notes mature in 2031. On
January 30, 2004, Yankee Gas closed on the private placement of $75 million
of 10-year first-mortgage bonds carrying an interest rate of 4.8 percent.
The proceeds from these bonds were used to reduce short-term debt.
By the end of 2003, NU had completed the first stage of a comprehensive
restructuring of its business profile. For CL&P that marked the sale of all
electric generation in the period of 1999 through 2002 and the recovery of
almost all of its unsecuritized stranded costs. The sale of assets and
recovery of stranded costs have provided CL&P with extremely strong cash
flows over the past five years. Those proceeds allowed CL&P to repay more
than half of its debt and preferred securities and to return hundreds of
millions of dollars of equity capital to NU. CL&P has not issued any new
long-term debt since mid-1997. Aided by relatively low cost power supply
contracts from 2000 through 2003, CL&P was able to maintain retail rates that
were relatively low for New England and generally 10 percent below those
charged by CL&P in 1996.
The year 2004, however, will show a significant change in CL&P's financial
statements, even if net income remains relatively stable. The settlement of
the dispute between CL&P and its standard offer service suppliers over a
portion of the incremental costs incurred following the implementation of SMD
on March 1, 2003, will have a significant negative impact on CL&P's cash
flows in 2004 as compared to 2003. In 2003, CL&P was withholding payment of
a portion of the incremental SMD costs from suppliers pending resolution but
was recovering the costs from ratepayers at the same time. Through January
31, 2004, CL&P collected approximately $155 million from customers. Of this
amount, $31.1 million was used in CL&P's operating cash flows and is secured
by a surety bond. The remaining $124 million was deposited into an escrow
account, and escrow account deposits through December 31, 2003 were $93.6
million and are included in restricted cash - LMP costs on the accompanying
consolidated balance sheets. As a result of the settlement, CL&P will pay
approximately $83 million to suppliers and return the remainder to its
customers.
Another significant negative impact to CL&P's cash flows will be the refund
of previously overcollected stranded costs to CL&P's customers. The
Connecticut Department of Public Utility Control (DPUC) stated in CL&P's
transitional standard offer (TSO) docket that CL&P should either refund $262
million of overcollections back to customers or use these overcollections to
pay for cash expenses over the next four years, beginning in 2004.
These refunds or applications of past cash collections to future expenses,
combined with CL&P's capital expansion program, will require CL&P to issue
debt securities and receive equity infusions from NU parent over the next
several years. CL&P is expected to issue up to $250 million of first
mortgage bonds in 2004.
CL&P will continue to increase its distribution and transmission construction
program to meet Connecticut's electric service reliability needs. CL&P
projects capital spending of approximately $440 million in 2004, compared
with $314.6 million in 2003 and $239.6 million in 2002. Over time, the
capital program will add to CL&P's asset base and net income.
Under FERC policy, transmission owners cannot bill customers for new plant
until it enters service. However, transmission owners may capitalize debt
and equity costs during the construction period through an allowance for
funds used during construction (AFUDC). Debt costs capitalized offset
interest expense with no impact on net income, while equity costs capitalized
increase net income. CL&P expects to fund its construction expenditures with
approximately 45 percent equity and 55 percent debt. As a result of the size
of the projects and the duration of the construction, a growing level of
CL&P's earnings over the next four years is expected to be in the form of
equity-related AFUDC. While the return on and recovery of the capitalized
debt and equity AFUDC benefits earnings and cash flows after the projects
enter service, AFUDC has no positive effect on cash flows until the projects
are reflected in rates.
Capital spending at PSNH totaled $105.6 million in 2003, compared with $108.7
million in 2002. In 2003, PSNH spent over $20 million to buy down contracts
with 14 small power producers and funded $30.1 million to acquire the assets
of Connecticut Valley Electric Company (CVEC) and buy out a related wholesale
power contract. The $30.1 million was placed in escrow at December 31, 2003
and is included in special deposits on the accompanying consolidated balance
sheets. PSNH expects to increase its capital spending to approximately $160
million in 2004, assuming it receives satisfactory regulatory approval for a
$70 million conversion of a 50 megawatt generating unit at its Schiller Station
to burn wood chips. Such a level of spending is likely to require PSNH to
issue in 2004 its first new debt since it exited bankruptcy in 1991.
Yankee Gas has also been investing heavily in its infrastructure since it was
acquired by NU in March 2000. In November 2003, Yankee Gas received
regulatory support to build a 1.2 billion cubic foot natural gas storage
facility in Waterbury, Connecticut. As a result of that project and other
initiatives, Yankee Gas projects $60 million of capital expenditures in 2004,
compared with $55.2 million in 2003.
In November 2003, the Utility Group renewed its $300 million credit line
under terms similar to the previous arrangement that expired in November
2003. There were $40 million in borrowings outstanding on this credit line
at December 31, 2003.
In addition to its revolving credit line, CL&P has an arrangement with a
financial institution under which CL&P can sell up to $100 million of
accounts receivable. At December 31, 2003 and 2002, CL&P had sold accounts
receivable of $80 million and $40 million, respectively, to that financial
institution. For more information on the sale of receivables, see "Off-
Balance Sheet Arrangements" in this Management's Discussion and Analysis and
Note 1P, "Summary of Significant Accounting Policies - Sale of Customer
Receivables" to the consolidated financial statements.
In November 2003, CL&P received approval from its preferred shareholders for
an extension of a 10-year waiver that allows CL&P's unsecured debt to rise to
20 percent of total capitalization. CL&P preferred shareholders approved a
similar waiver in 1993 that will expire in March 2004. The approval waives a
requirement that unsecured debt represent no more than 10 percent of total
capitalization.
Rate reduction bonds are included on the consolidated balance sheets of NU,
CL&P, PSNH, and WMECO, even though the debt is non-recourse to these
companies. At December 31, 2003, these companies had a total of $1.7 billion
in rate reduction bonds outstanding, compared with $1.9 billion outstanding
at December 31, 2002. All outstanding rate reduction bonds of CL&P are
scheduled to amortize by December 30, 2010. PSNH's rate reduction bonds are
scheduled to fully amortize by May 1, 2013, and those of WMECO are scheduled
to fully amortize by June 1, 2013. Interest on the bonds totaled $108.4
million in 2003, compared with $115.8 million in 2002 and $87.6 million in
2001, the year of issuance. Cash flows from the amortization of rate
reduction bonds totaled $153.2 million in 2003, compared with $148.6 million
in 2002 and $98.4 million in 2001. Over the next several years, retirement
of rate reduction bonds will increase, and interest payments will steadily
decrease, resulting in no material changes to debt service costs on the
existing issues. CL&P, PSNH and WMECO fully recover the amortization and
interest payments from customers through stranded cost revenues each year,
and the bonds have no impact on net income. Moreover, as the rate reduction
bonds are non-recourse, the three rating agencies that rate the debt and
preferred stock securities of these companies do not reflect the revenues,
expenses, or outstanding securities related to the rate reduction bonds in
establishing the credit ratings of these companies or of NU.
NU Enterprises: NU's higher debt levels reflect SESI borrowings of $63.4
million in 2003 to finance the implementation of energy saving improvements
at customer facilities. Cash flows from SESI's share of customer energy
savings will repay the debt. While NU parent guarantees SESI's performance
under most of the contracts, NU parent does not guarantee repayment of the
debt, nor is the debt recourse to NU parent.
Select Energy was one of CL&P's standard offer service suppliers that
incurred incremental locational marginal pricing (LMP) costs during 2003.
CL&P did not pay Select Energy for these costs, which negatively impacted the
operating cash flows of NU Enterprises in 2003. If the FERC approves the
settlement of the wholesale power contract dispute over the responsibility
for LMP costs, then there will be a positive impact on NU Enterprises' cash
flows in 2004.
In November 2003, NU parent renewed its $350 million credit line with terms
similar to its previous arrangement that expired in November 2003. There
were $65 million in borrowings outstanding on this credit line at December
31, 2003. In addition, Select Energy had $106.9 million in letters of credit
outstanding under this credit line primarily to support its marketing
activities.
NU Enterprises continues to have a minimal level of capital spending. In
2002, NU Enterprises acquired certain assets and assumed certain liabilities
of Woods Electrical, an electrical services company, and Woods Network, a
network design, products and service company. The acquisitions were for
$16.3 million in cash. NU Enterprises made no other business acquisitions in
2002 or 2003.
IMPACTS OF STANDARD MARKET DESIGN
On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented SMD. As part of SMD, LMP is utilized to assign value and
causation to transmission congestion and line losses. Transmission congestion
costs represent the additional costs incurred due to the need to run uneconomic
generating units in certain areas that have transmission constraints, which
prevent these areas from obtaining alternative lower-cost generation. Line
losses represent losses of electricity as it is sent over transmission lines.
The costs associated with transmission congestion and line losses are now
assigned to the pricing zone in which they occur, and the calculation of line
losses is now based on an economic formula. Prior to March 1, 2003, those
costs were spread across virtually all New England electric customers based on
engineering data of actual line losses experienced. As part of the
implementation of SMD, ISO-NE established eight separate pricing zones in
New England: three in Massachusetts and one in each of the five other New
England states. The three components of the LMP for each zone are 1) an energy
cost, 2) congestion costs and 3) line loss charges assigned to the zone. LMP
is increasing costs in zones that have inadequate or less cost-efficient
generation and/or transmission constraints, such as Connecticut, and decreasing
costs in zones that have sufficient or excess generation, such as Maine.
CL&P was billed $186 million of incremental LMP costs by its standard offer
service suppliers or by ISO-NE. CL&P recovered a portion of these costs
through an additional charge on customer bills beginning on May 1, 2003.
Billings were on a two-month lag and were recorded as operating revenues when
billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the
responsibility for the $186 million of incremental LMP costs incurred. NU
recorded a pre-tax loss in 2003 of approximately $60 million (approximately
$37 million after-tax) related to the settlement of this dispute. A
settlement agreement was reached among all the parties involved. This
settlement agreement was filed with the FERC on March 3, 2004 and will not be
final until the FERC approves it. Management expects to receive FERC
approval in the first half of 2004.
The pre-tax loss of approximately $60 million was reflected in two line items
on the consolidated statements of income. Approximately $58 million was
recorded as a reduction to operating revenues, and approximately $2 million
was recorded in operating expenses.
NRG ENERGY, INC. EXPOSURES
Certain subsidiaries of NU have entered into various transactions with
subsidiaries of NRG Energy, Inc. (NRG). On May 14, 2003, NRG and certain of
its subsidiaries filed voluntary bankruptcy petitions in the United States
Bankruptcy Court for the Southern District of New York. On December 5, 2003,
NRG emerged from bankruptcy. NRG-related exposures to certain subsidiaries
of NU as a result of these transactions are as follows:
Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PMI)
contracted with CL&P to supply 45 percent of CL&P's standard offer service
load through December 31, 2003. In May 2003, NRG-PMI attempted to terminate
the contract with CL&P, but the FERC ordered NRG-PMI to continue serving CL&P
under its standard offer service contract. Subsequently, NRG-PMI received a
temporary restraining order from the United States District Court for the
Southern District of New York (District Court) and stopped serving CL&P with
standard offer supply on June 12, 2003. NRG-PMI was ultimately ordered by
the FERC and the District Court to resume serving CL&P's standard offer
service load and did so on July 2, 2003. During the period NRG-PMI did not
serve CL&P under its standard offer service contract, CL&P's net replacement
power cost amounted to $8.5 million, which was collected by CL&P from its
customers and withheld from standard offer service contract payments to NRG-
PMI.
On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the
Office of Consumer Counsel, and the attorney general of Connecticut entered
into a comprehensive settlement agreement. Under the settlement agreement,
approved by the bankruptcy court and the FERC on November 21, 2003 and
December 18, 2003, respectively, NRG was required to continue to deliver
power to CL&P under the terms and conditions of the standard offer service
contract through the end of its term, which was December 31, 2003, in
exchange for a commitment by CL&P to make payments to NRG on a revised weekly
schedule. The settlement agreement also allowed CL&P to retain the
aforementioned $8.5 million withheld from NRG for replacement power purchased
by CL&P during the period June 12, 2003 through July 2, 2003. CL&P will seek
to refund this amount to its customers in 2004 pending DPUC approval. On
January 19, 2004, CL&P paid NRG-PMI its last weekly payment.
Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit
against NRG in Connecticut Superior Court seeking judgment for unpaid pre-
March 1, 2003 congestion charges under its standard offer supply contract.
On August 5, 2002, CL&P withheld the then unpaid congestion charges from
payments due to NRG for standard offer service and continued to withhold
those amounts through December 31, 2003, the end of the contract term. The
total amount of congestion costs withheld from NRG was $28.4 million. If it
is ultimately concluded that CL&P is responsible for pre-March 1, 2003
congestion costs, then management believes that CL&P would be allowed to
recover these costs from its customers. This litigation is ongoing.
Station Service: Since December 1999, CL&P has provided NRG's Connecticut
generating plants with station service, which includes energy and/or delivery
services provided when a generator is off-line or unable to satisfy its
station service energy requirements. Pursuant to the parties'
interconnection agreement dated July 1, 1999, CL&P provides this service at
DPUC-approved retail rates. In October 2002, CL&P filed a complaint with the
FERC seeking interpretation of a FERC-filed interconnection agreement in
which NRG agreed to pay CL&P's applicable retail rates for station service
and delivery services. The FERC issued a decision on December 20, 2002 that
agreed that station service from CL&P would be subject to CL&P's applicable
retail rates and that states have jurisdiction over the delivery of power to
end users even where, as with station service, power is not delivered by
distribution facilities. NRG disputed its obligation and refused to pay
CL&P.
In September 2003, the bankruptcy court approved a stipulation between CL&P
and NRG to submit the station service dispute to arbitration, and arbitration
proceedings have been initiated by the parties. No hearing dates have been
scheduled. On December 17, 2003, the DPUC determined that CL&P had
appropriately administered its station service rates in providing NRG station
service. In unrelated proceedings, the FERC has issued decisions with
conflicting policy direction. In January 2004, CL&P filed a request with the
FERC for further clarification of this issue.
Management will continue to pursue recovery from NRG of the station service
balance, including approximately $4 million NRG placed in an escrow account
related to this matter. In 2003, as a result of NRG's bankruptcy, the amount
due from NRG in excess of the escrow amount was reserved. Management
believes that amounts not collected from NRG are ultimately recoverable from
CL&P's customers. Therefore, a regulatory asset of $11.4 million was
recorded. At December 31, 2003, NRG owed CL&P $16 million for station
service. The $16 million owed to CL&P includes $0.6 million billed to NRG
subsequent to its emergence from bankruptcy on December 5, 2003.
Legal Costs: Through December 31, 2003, legal costs incurred by CL&P related
to NRG's bankruptcy and the SMD dispute amounted to $2.3 million. This
amount has been recorded as a regulatory asset, and CL&P received approval to
recover $1.6 million in its recent rate case. CL&P will continue to defer
these legal costs as they are incurred, and management believes that amounts
in excess of $1.6 million will also be recovered from customers.
Meriden Gas Turbines, LLC: Yankee Gas, E.S. Boulos Company (Boulos), which
is a subsidiary of NGS, and CL&P are or have been involved in ongoing
litigation with Meriden Gas Turbines, LLC (MGT), an NRG subsidiary that was
not included in NRG's voluntary bankruptcy proceeding, related to the
construction of a generating plant that MGT stated it was abandoning.
Yankee Gas has expended costs in excess of $16 million in the construction of
a natural gas pipeline to the generating plant that MGT was constructing.
Yankee Gas drew down on an MGT $16 million letter of credit (LOC) when MGT
stated that it was abandoning construction of the generating plant. MGT has
contested the draw down on the LOC in a lawsuit filed in Connecticut Superior
Court. Yankee Gas has a counterclaim pending against MGT to recover
additional monies in accordance with the contract that are in excess of the
$16 million LOC. This litigation is ongoing.
Boulos has a 50 percent interest in a joint venture that was building
switchyards for the MGT generating plant. In the fourth quarter of 2003,
Boulos settled all outstanding claims against MGT with no material financial
impact.
MGT also currently owes CL&P $0.5 million for work on the South Kensington
switching station, which was to be the interconnection point for the MGT
generating plant. CL&P has joined pending foreclosure proceedings in an
effort to recover the outstanding balance.
Management does not expect that the resolution of the aforementioned NRG
exposures will have a material adverse effect on the financial condition or
results of operations of NU and its subsidiaries.
NU ENTERPRISES
Business Lines: NU Enterprises aligns its activities into two business
lines, the merchant energy business line and the energy services business
line. The merchant energy business line includes Select Energy's wholesale
and retail marketing activities. Also included are 1,440 MW of generation
capacity, consisting of 1,293 MW at NGC and 147 MW at HWP, which support the
merchant energy business line. The energy services business line includes
the operations of SESI, NGS, and Woods Network.
SESI performs energy management services for large commercial customers,
institutional facilities and the United States government. SESI engages in
energy-related construction services. NGS operates and maintains NGC's and
HWP's generation assets and provides third-party electrical services. In
2003, NGS also performed engineering contracting services.
Results and Outlook: Financial performance at NU Enterprises improved in
2003, losing $3.5 million, compared with losses of $53.2 million in 2002.
The 2003 loss includes the after-tax loss of approximately $36 million
associated with the aforementioned settlement of the wholesale power contract
dispute with CL&P. Excluding that loss, NU Enterprises earned $32.2 million
in 2003. During 2004, NU expects that NU Enterprises will continue to be
successful and will produce net income in the range of $28 million to $38
million, or $0.22 to $0.30 per share. Management estimates that between $24
million and $31 million of those earnings in 2004 will come from the merchant
energy business line and between $4 million and $7 million from the energy
services business line. Those ranges are heavily dependent on NU
Enterprises' ability to achieve targeted wholesale and retail origination
margins, successfully manage its contract portfolios and achieve targeted
growth in the energy services business line.
Select Energy's merchant energy business line includes wholesale marketing
and retail marketing activities. Wholesale marketing activities include
wholesale origination, portfolio management and the operation of more than
1,400 MW of pumped storage, hydroelectric and coal-fired generation assets.
Wholesale marketing activities earned $31.8 million in 2003, excluding the
after-tax loss associated with the settlement of the aforementioned wholesale
power contract dispute, compared to losses of $24.7 million in 2002. NGC
earned $38.5 million in 2003, compared with $30.4 million in 2002. HWP lost
$0.5 million in 2003 compared with a loss of $0.9 million in 2002. NGC's
results benefit from an above-market contract with Select Energy. The above-
market price continues through 2005, but the contract has been extended
through 2006, though at a lower cost to Select Energy. NU parent will
continue to guarantee the performance of Select Energy in that contract
through 2006. Wholesale marketing activities benefited from above-average
precipitation in western New England during 2003, which increased conventional
hydroelectric output, as compared with near drought conditions during 2002.
This increase in output resulted in $5 million of additional net income in
2003, as compared to 2002. Wholesale marketing activities also benefited
from the absence of natural gas trading losses in 2003.
Select Energy signed a number of wholesale marketing contracts in 2003 for
delivery to electric utilities in 2004. All contracts were won in competitive
bidding processes. Total wholesale sales in 2004 are expected to exceed 40
million megawatt-hours, based on the contracts in effect as of January 1, 2004.
The most significant contracts are with CL&P, NSTAR, National Grid USA, WMECO,
Jersey Central Power & Light, and Atlantic City Electric Co. Most of the
contracts noted above will expire in 2004. Select Energy will bid on
additional contracts in 2004 that will take effect in 2004 and beyond.
Select Energy's ability to secure a significant amount of wholesale load is a
critical factor in NU Enterprises' overall profitability. Select Energy must
realize enough gross margin from its sales to cover its overhead and taxes and
produce a reasonable profit for NU. Overhead includes personnel and facility
costs, credit requirements and carrying costs on NGC and HWP generation.
The Northfield Mountain pumped storage facility, a 1,080 megawatt unit in
Northfield, Massachusetts, plays a critical role in the success of Select
Energy. Northfield's ability to generate large amounts of on-peak energy using
water that was pumped uphill during off-peak hours and its ability to react
rapidly to changing demand allow Select Energy to economically hedge much of
the 2004 earnings risk that results from entering into full requirements supply
obligations. As a result of a new competitively bid contract, Select Energy
will continue to be CL&P's largest wholesale supplier in 2004, but at a
significantly higher rate. Management expects that the improved terms of
Select Energy's new CL&P contract will have a positive impact on NU
Enterprises' 2004 earnings.
The second activity included in NU Enterprises' merchant energy business line
is retail marketing, which also improved its financial performance in 2003
compared to 2002. Select Energy's retail marketing activities had a $25.9
million improvement in financial performance during 2003 compared to 2002 with
losses of $1.8 million and $27.7 million in 2003 and 2002, respectively.
The 2003 improved retail results are primarily due to improved margins and
growth in retail electric sales, along with improved management of retail gas
contracts. Over time, management expects that Select Energy's retail sales
and financial performance will improve as more commercial and industrial
customers move from buying energy through their electric distribution company
to purchasing energy directly from suppliers such as Select Energy. Select
Energy does not sell electricity or natural gas to residential customers, but
actively markets energy to commercial and industrial customers throughout the
Northeast between Maine and Maryland with the exception of Vermont. Vermont
does not allow retail customers to choose their electric suppliers.
NU Enterprises' energy services business line, including SESI, NGS, and Woods
Network earned approximately $2.6 million in 2003 as compared to 2002 when
this business line was essentially breakeven. Financial performance at SESI
continues to benefit from an expanding level of business with the United States
Department of Defense, with net income rising to $4.6 million in 2003 from $3
million in 2002. NGS, which continues to be negatively affected by the lower
level of electrical contracting resulting from the slow economy in New England,
lost $2.2 million in 2003, following a loss of $3.2 million in 2002. Woods
Network earned $0.2 million in both 2003 and 2002.
NU Enterprises parent costs totaled $0.4 million in 2003, compared to $0.8
million in 2002.
In 2002, NU Enterprises 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 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
Enterprises' operating expenses decreased by $8.6 million in 2003 and $5.1
million in 2002 as compared to 2001.
Intercompany Transactions: CL&P's standard offer purchases from Select
Energy represented approximately $558 million of revenues in 2003, compared
with $501 million in 2002. CL&P's TSO purchases from Select Energy in 2004
are expected to total approximately $500 million. Other transactions between
CL&P and Select Energy totaled $130 million in 2003 and 2002. Additionally,
WMECO's purchases from Select Energy represented approximately $143 million in
2003, compared with $14 million in 2002. All of these amounts are eliminated
in consolidation. The CL&P standard offer amounts have been reduced by the
loss related to the wholesale power contract settlement.
NU ENTERPRISES' MARKET AND OTHER RISKS
Overview: NU Enterprises is exposed to certain market risks inherent in its
business activities. The merchant energy business line enters into contracts
of varying lengths of time to buy and sell energy commodities, including
electricity, natural gas, and oil. Market risk represents the loss that may
affect Select Energy's financial results due to adverse changes in commodity
market prices.
Risk management within Select Energy is organized to address the market,
credit and operational exposures arising from the merchant energy business
line, including wholesale marketing activities (which include limited energy
trading for market and price discovery purposes) and retail marketing
activities. 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 risk management policies and
procedures. As a means to monitor and control compliance with these policies
and procedures, NU's Risk Oversight Council (ROC) monitors NU Enterprises' risk
management processes independently from the business lines that create or
manage risks. The ROC ensures that the policies 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. The ROC also confirms methodologies employed to estimate
portfolio values.
Wholesale and Retail Marketing Activities: A significant portion of Select
Energy's wholesale marketing activities is providing energy to full
requirements customers, primarily regulated distribution companies. Under
full requirements contract terms, Select Energy is required to provide 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 focuses on
managing the volume and price risks of full requirements contracts. These
risks include significant fluctuations in both 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 mitigate these risks. 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.
Select Energy manages its portfolio of wholesale and retail marketing
contracts and assets to maximize value while maintaining an acceptable level
of risk. At forward market prices in effect at December 31, 2003, the
wholesale marketing portfolio, which includes the CL&P TSO service contract
that extends through December 31, 2004 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 may be significant volatility in the energy commodities markets that
may affect this position between now and when the contracts are settled.
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.
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 financial swap agreements, call and put
option contracts, and futures and forward contracts, to manage the market
risk associated with a portion of its anticipated supply and delivery
requirements. These derivatives have been designated as cash flow hedging
instruments for accounting purposes 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, 2003, Select Energy had hedging derivative
assets of $55.8 million and hedging derivative liabilities of $12.7 million.
At December 31, 2002, Select Energy had hedging derivative assets of $22.8
million and hedging derivative liabilities of $2 million.
The increase in hedging derivative assets and liabilities from December 31,
2002 to December 31, 2003 resulted primarily from new financial contracts
entered into during 2003 to hedge gas-indexed power purchases in New England
and new financial transmission rights (FTR) contracts to hedge congestion in
both New England and the Pennsylvania, New Jersey, Maryland, and Delaware
(PJM) regions.
Non-trading: Non-trading derivative contracts are used for delivery of
energy related to wholesale and retail marketing activities. These contracts
are not entered into for trading purposes, but are subject to fair value
accounting because these contracts cannot be designated as normal purchases
and sales, as defined in applicable accounting principles or because
management has not elected hedge accounting or normal purchases and sales
accounting. At December 31, 2003, Select Energy had non-trading derivative
assets of $1.6 million and non-trading derivative liabilities of $0.8
million, compared to non-trading derivative assets of $2.9 million and no non-
trading derivative liabilities at December 31, 2002. Changes to the non-
trading derivatives portfolio, which are not significant, were recognized in
revenues.
Wholesale Contracts Defined as "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 affect net income.
At December 31, 2003, Select Energy had trading derivative assets of $123.9
million and trading derivative liabilities of $91.4 million on a counterparty-
by-counterparty basis, for a net positive position of $32.5 million for the
entire trading portfolio. At December 31, 2002, trading derivative assets
were $102.9 million and trading derivative liabilities were $61.9 million.
The increase in both asset and liability amounts relates primarily to price
increases, as trading activity has decreased. These amounts are combined
with other derivatives and are included in derivative assets and derivative
liabilities on the accompanying consolidated balance sheets.
There can be no assurances that Select Energy will realize cash corresponding
to the present positive net fair value of its trading positions. Numerous
factors either could positively or negatively affect the realization of the
net fair value amount in cash. 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 business day and segregating
responsibilities between the 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, 2003. 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 market prices;
and 3) prices based on models or other valuation methods primarily include
transactions for which specific quotes are not available. The option component
of a forward electricity purchase contract had a fair value of $4.5 million at
December 31, 2002, and was the only amount included in this method of
determining fair value at December 31, 2002. The fair value of the option
component of this contract was reduced to zero in 2003 with a credit reserve
that was established in 2003, and at December 31, 2003, Select Energy has no
other contracts for which fair value is determined based on a model or other
valuation method. Broker quotes for electricity are available through the
year 2005. Broker quotes for natural gas are available through 2013.
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 for longer-term contracts are less certain.
Accordingly, there is a risk that contracts will not be realized at the
amounts recorded. However, Select Energy has obtained corresponding purchase
or sale contracts for substantially all of the trading contracts that have
maturities in excess of one year. Because these contracts are sourced,
changes in the value of these contracts due to changes in commodity prices
are not expected to affect Select Energy's earnings.
As of and for the years ended December 31, 2003 and 2002, 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, 2003
- --------------------------------------------------------------------------------------------------------------------
Maturity Less Than Maturity of One to Maturity in Excess
Sources of Fair Value One Year Four Years of Four Years Total Fair Value
- --------------------------------------------------------------------------------------------------------------------
Prices actively quoted $0.2 $0.1 $ - $ 0.3
Prices provided by external sources 6.9 9.6 15.7 32.2
Prices based on models or other
valuation methods - - - -
- --------------------------------------------------------------------------------------------------------------------
Totals $7.1 $9.7 $15.7 $32.5
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2002
- --------------------------------------------------------------------------------------------------------------------
Maturity Less Than Maturity of One to Maturity in Excess
Sources of Fair Value One Year Four Years of Four Years Total 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
- --------------------------------------------------------------------------------------------------------------------
As indicated in the tables above and below, the fair value of energy trading
contracts decreased $8.5 million from $41 million at December 31, 2002 to
$32.5 million at December 31, 2003. The change in the fair value of the
trading portfolio is attributable to several items, including the termination
and realization in 2003 of a contract with a positive fair value of $5.7
million and the establishment of a credit reserve on a long-term trading
contract. The change in fair value attributable to changes in valuation
techniques and assumptions of $2.3 million in 2003 resulted from a change in
the discount rate management uses to determine the fair value of trading
contracts. In the second quarter of 2003, the rate was changed from a fixed
rate of 5 percent to a market-based LIBOR discount rate to better reflect
current market conditions.
In 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 activities, 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 is being 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 Select Energy New York, Inc. at acquisition that in 2002
were determined to be held for non-trading 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 (TCC) were revalued during 2002
based on the availability of market information, which added $6 million to
the value of the trading portfolio.
- -------------------------------------------------------------------------------
Years Ended December 31,
- -------------------------------------------------------------------------------
2003 2002
- -------------------------------------------------------------------------------
(Millions of Dollars) Total Portfolio Fair Value
- -------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the beginning of the year $41.0 $56.4
Contracts realized or otherwise settled
during the period (10.7) (4.0)
Fair value of new contracts when entered
into during the year - 13.7
Changes in fair values attributable to changes
in valuation techniques and assumptions 2.3 (39.9)
Changes in fair value of contracts (0.1) 14.8
- -------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the end of the year $32.5 $41.0
- -------------------------------------------------------------------------------
Changing Market: The breadth and depth of the market for energy trading and
marketing products in Select Energy's markets continue to be 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, market pricing information is becoming less
readily available, and participants are more often unable to meet Select
Energy's credit standards without providing cash or LOC support. Select
Energy is being adversely affected by these factors, and there could be a
continuing adverse impact on Select Energy's business lines. The decrease in
the number of counterparties participating in the market for long-term energy
contracts also continues to affect Select Energy's ability to estimate the
fair value of its long-term wholesale energy contracts.
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 in market
design are occurring within transmission regions. For example, SMD was
implemented in New England on March 1, 2003 and has created both challenges
and opportunities for Select Energy. For information regarding the effects
of SMD on Select Energy, see "Impacts of Standard Market Design" in this
Management's Discussion and Analysis. As the market continues to evolve,
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 because 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 advances,
letters of credit, and parent guarantees), and the use of standardized
agreements that 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 contracts.
The appropriateness of these limits is subject to continuing review.
Concentrations among these counterparties may affect 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, 2003, approximately 89 percent of
Select Energy's counterparty credit exposure to wholesale and trading
counterparties was cash collateralized or rated BBB- or better. Another one
percent of the counterparty credit exposure was to unrated municipalities.
Select Energy held $46.5 million and $16.9 million of counterparty cash
advances at December 31, 2003 and 2002, respectively.
Asset Concentrations: At December 31, 2003, positions with four
counterparties collectively represented approximately $89 million, or 72
percent, of the $123.9 million trading derivative assets. The largest
counterparty's position is secured with letters of credit and cash
collateral. Select Energy holds parent company guarantees at investment
grade ratings supporting the remaining positions of the counterparties. None
of the other counterparties represented more than 10 percent of trading
derivative assets at December 31, 2003.
Select Energy's 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 $231 million of collateral or letters of credit to various
unaffiliated counterparties and approximately $65 million to several
independent system operators and unaffiliated local distribution companies,
which management believes NU would currently be able to provide. NU's credit
ratings outlooks are currently stable or negative, but management does not
believe that at this time there is a significant risk of a ratings downgrade
to sub-investment grade levels.
NU has applied to the Securities and Exchange Commission (SEC) for authority
to expand its financial support of NU Enterprises. NU primarily seeks to 1)
increase its allowable investments in certain of its unregulated businesses,
presently 15 percent of its consolidated capitalization as permitted by SEC
regulation, by an additional $500 million, 2) increase the limit for its
guarantees of all of its competitive affiliates from $500 million to $750
million, and 3) increase its allowable investments in exempt wholesale
generators (EWGs) from $481 million to $1 billion.
If granted, the SEC's order would permit NU's future investment in Select
Energy above the amount now allowed. NU has no present plans to
significantly expand its EWG portfolio at this time. However, if an
investment opportunity becomes available, NU would be able to pursue it
within the new allowable EWG investment level. NU expects SEC approval in
early 2004.
If the application is not granted in early 2004 as management expects, then
there could be a negative impact on the merchant energy business line's
ability to achieve its 2004 earnings estimate. This business line depends on
NU parent guarantees to support the energy contracts that make up both its
revenues and expenses. At December 31, 2003, NU parent could guarantee an
additional $211.5 million of merchant energy business line contracts, but
guarantee levels constantly fluctuate with the market value of the contracts
that are guaranteed, and NU's ability to issue new guarantees may be
constrained due to the aforementioned SEC limitation.
For further information regarding Select Energy's activities and risks, see
Note 3, "Derivative Instruments, Market Risk and Risk Management," and Note
10, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated
financial statements.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
Utility Group: NU anticipates that it will continue to increase its level of
capital expenditures at the Utility Group to meet customers' increasing needs
for additional and more reliable energy supplies. Investments in Utility
Group plant totaled $505.8 million in 2003, compared with $447 million in
2002 and $411.9 million in 2001.
Connecticut - CL&P: Over the next several years, the majority of NU's
capital spending will be at CL&P, where the company is seeking to upgrade and
expand an aging and, in some locations, stressed distribution and
transmission system. CL&P's capital expenditures totaled $314.6 million in
2003, compared with $239.6 million in 2002 and $236.2 million in 2001. CL&P
expects capital expenditures to increase to $440 million in 2004. CL&P spent
$246 million on distribution in 2003 and anticipates spending $228 million on
distribution in 2004.
In its final 2003 CL&P rate decision, the DPUC authorized rate recovery of
distribution capital expenditures totaling $236 million in 2004, $220 million
in 2005, $216 million in 2006, and $225 million in 2007.
On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000
volt transmission line project from Bethel, Connecticut to Norwalk,
Connecticut, proposed in October 2001 by CL&P. The configuration of the new
transmission line, enhancements to an existing 115,000 volt transmission
line, and work in related substations are estimated to cost approximately
$200 million. The line will alleviate identified reliability issues in
southwest Connecticut and help reduce congestion costs for all of
Connecticut. An appeal of the CSC decision by the City of Norwalk is
pending, but management does not expect the appeal to be successful. CL&P
anticipates placing the new transmission line in service by the end of 2005.
This project is exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. At
December 31, 2003, CL&P has capitalized $12.4 million associated with this
project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a
separate 345,000 volt transmission line from Norwalk, Connecticut to
Middletown, Connecticut. Estimated construction costs of this project are
approximately $620 million. CL&P will jointly site this project with UI, and
CL&P will own 80 percent, or approximately $496 million, of the project.
This project is also exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. CL&P expects
the CSC to rule on the application in 2004 and for construction to occur from
2005 through 2007. At December 31, 2003, CL&P has capitalized $9.2 million
related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric
transmission line between Norwalk, Connecticut and Northport - Long Island,
New York, at an estimated cost of $90 million. CL&P and the Long Island
Power Authority each own approximately 50 percent of the line. The project
still requires federal and New York state approvals. Given the approval
process, changing pricing and operational rules in the New England and New
York energy markets and pending business issues between the parties, the
expected in-service date remains under evaluation. This project is also
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. At December 31, 2003, CL&P
has capitalized $5.2 million associated with 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.
Management believes that construction of the 345,000 volt projects is
critical to maintaining service reliability in southwest Connecticut. The
345,000 volt projects, in addition to additional transmission spending
planned between 2004 and 2007, also represent a significant source of
potential earnings growth for NU. Management believes that if the projects
now being considered are all built over the next four years, NU's net
transmission plant investment would triple. Revenues and earnings for NU's
transmission system are established by the FERC.
Connecticut - Yankee Gas: Yankee Gas has also proposed expansion of its
natural gas distribution system in Connecticut. Yankee Gas' capital
expenditures totaled $55.2 million in 2003, compared with $70.6 million in
2002 and $47.8 million in 2001. Yankee Gas expects capital expenditures to
total $60 million in 2004 as it continues to expand its distribution system
and begins work on two major projects; a liquefied natural gas storage
facility in Waterbury, Connecticut and a new 9-mile pipeline in southeast
Connecticut to connect the existing Yankee Gas delivery system with that of
the New England Gas Company (NEGASCO), a Rhode Island natural gas delivery
company. The NEGASCO project would cost approximately $5 million, provide
Yankee Gas with additional revenue, improve service reliability in the
Stonington, Connecticut area, and expand natural gas delivery into additional
areas of southeastern Connecticut. Construction of this project is
contingent upon receiving satisfactory regulatory approval.
Yankee Gas received a decision from the DPUC supporting the construction and
operation of a 1.2 billion cubic foot liquefied natural gas storage and
production facility in Waterbury, Connecticut. Construction of the facility,
which is expected to take approximately three years, could begin in the
second half of 2004. The decision allows for the deferral of prudently
incurred costs related to the project and requires Yankee Gas to file a rate
case to recover this investment when the facility is placed in service. This
project is also exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. At December
31, 2003, Yankee Gas has capitalized approximately $1.9 million related to
this project.
New Hampshire: PSNH capital spending totaled $105.6 million in 2003 and is
projected to total $160 million in 2004. The primary reason for the increase
is PSNH's proposal to convert a 50 megawatt oil and coal burning unit at
Schiller Station in Portsmouth, New Hampshire to burn wood chips. The $70
million project will commence if PSNH receives satisfactory approval from the
NHPUC. PSNH believes that the conversion can be accomplished without
impacting retail rates because of certain government incentives to promote
renewable resource projects. Another reason for the projected increase in
capital spending is PSNH's transmission projects.
Effective January 1, 2004, PSNH completed the purchase of the electric system
and retail franchise of CVEC, a subsidiary of Central Vermont Public Service
Corporation (CVPS), for $30.1 million. CVEC's 11,000 customers in western
New Hampshire have been added to PSNH's customer base of more than 460,000
customers. The purchase price included the book value of CVEC's plant assets
of approximately $9 million and an additional $21 million to terminate an
above-market wholesale power purchase agreement CVEC had with CVPS. CVEC is
expected to add approximately $1.1 million to PSNH's annual earnings.
Massachusetts: WMECO's capital expenditures totaled $30.4 million in 2003,
compared with $23.1 million in 2002 and $30.7 million in 2001. WMECO's
capital expenditures are expected to total $38 million in 2004.
NU Enterprises: Capital expenditures at NU Enterprises generation
subsidiaries, NGC and HWP, are expected to be modest in 2004, with $13
million at NGC and $1 million at HWP. In 2003, NGC's and HWP's capital
expenditures totaled $11.1 million and $1.8 million, respectively. NU
continues to examine acquisitions in the energy services business. In 2002,
NU acquired Woods Electrical and Woods Network for $16.3 million.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities to voluntarily form
RTOs or to state why this process has not begun.
On October 31, 2003, ISO-NE, along with NU and six other New England
transmission companies filed a proposal with the FERC to create a RTO for
New England. The RTO is intended to strengthen the independent and efficient
management of the region's power system while ensuring that customers in New
England continue to have the most reliable system possible to realize the
benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and will
also become the transmission provider for New England by exercising
operational control over New England's transmission facilities pursuant to a
detailed contractual arrangement with the New England transmission owners.
Under this contractual arrangement, the RTO will have clear authority to
direct the transmission owners to operate their facilities in a manner that
preserves system reliability, including requiring transmission owners to
expand existing transmission lines or build new ones when needed for
reliability. Transmission owners will retain their rights over revenue
requirements, rates and rate designs. The filing requests that the FERC
approve the RTO arrangements for an effective date of March 1, 2004.
In a separate filing made on November 4, 2003, NU along with six other New
England transmission owners requested, consistent with the FERC's pricing
policy for RTOs and Order-2000-compliant independent system operators, that
the FERC approve a single return on equity (ROE) for regional and local rates
that would consist of a base ROE as well as incentive adders of 50 basis
points for joining a RTO and 100 basis points for constructing new
transmission facilities approved by the RTO. If the FERC approves the
request, then the transmission owners would receive a 13.3 percent ROE for
existing transmission facilities and a 14.3 percent ROE for new transmission
facilities. The outcome of this request and its impact on NU cannot be
determined at this time.
RESTRUCTURING AND RATE MATTERS
Utility Group: On August 26, 2003, NU's electric operating companies filed
their first transmission rate case at the FERC since 1995. In the filing, NU
requested implementation of a formula rate that would allow recovery of
increasing transmission expenditures on a timelier basis and that the
changes, including a $23.7 million annual rate increase through 2004, take
effect on October 27, 2003. NU requested that the FERC maintain NU's
existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this filing
implementing the proposed rates subject to refund effective on October 28,
2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution
companies through FERC-approved transmission rates. Electric distribution
companies pass through higher transmission rates to retail customers as
approved by the appropriate state regulatory commission. Distribution
companies need to file for retail rate increases if transmission costs exceed
what is currently allowed in rates. Currently, WMECO has a tracking
mechanism to reset rates annually for transmission costs with overcollections
refunded to customers and undercollections deferred and then collected from
customers in later years. In its 2003 rate case, CL&P sought a tracking
mechanism to allow it to recover changes in transmission expenses on a timely
basis. While the DPUC approved a $28.4 million increase in transmission
rates for CL&P's retail customers effective January 1, 2004, it did not grant
a tracking mechanism in rates. As a result, CL&P will need to reapply to the
DPUC to adjust transmission rates when its revenues are not adequate to
recover transmission costs. PSNH requested a tracking mechanism from the
NHPUC when it filed its rate case on December 29, 2003, which will allow it to
recover changes in transmission expenses on a timely basis.
Connecticut - CL&P:
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor
of Connecticut signed into law Public Act No. 03-135 (Act) that amended
Connecticut's 1998 electric utility industry legislation. Among key
features, the Act created a TSO period from 2004 through 2006 that allowed
the base rate cap to return to 1996 levels, which represented a potential
increase of up to 11.1 percent. Additional costs related to Federally
Mandated Congestion Charges (FMCC) are not included in the cap.
Additionally, if energy supply costs were to exceed levels established in the
TSO rate, these costs could be recovered through an energy adjustment clause
or through the FMCC. The Act also allowed CL&P to collect a procurement fee
of at least 0.50 mills per kilowatt-hour (kWh) from customers who continue to
purchase TSO service. That fee can increase to 0.75 mills if CL&P beats
certain regional benchmarks. Management expects that the procurement fee
will be between $11 million and $12 million annually, which will add $6
million to $7 million to CL&P's net income. One mill is equal to one-tenth
of a cent.
ISO-NE and the New England Power Pool are currently debating the
implementation of locational installed capacity (LICAP). LICAP is the
requirement that CL&P support enough generation to meet peak demand (plus a
reserve to protect against higher demand than expected or generating plant
outages) in its service territory. Connecticut, because of its lack of
sufficient generation and transmission, is expected to have high LICAP costs.
LICAP rules are subject to the jurisdiction of the FERC. ISO-NE filed a
proposal with the FERC on March 1, 2004 for implementation in June 2004.
Until the exact proposal is approved by the FERC, the financial impact on
CL&P's customers cannot be determined. CL&P expects to recover LICAP from
its customers as a FMCC.
On July 1, 2003, CL&P filed with the DPUC to establish TSO service and to set
the TSO rates equal to December 31, 1996 total rate levels. On December 19,
2003, the DPUC issued a final decision setting the average TSO rate at
$0.1076 per kWh for 2004, which the DPUC found to be within the statutory
cap. That rate incorporated nine key elements, which combined produced the
average TSO rate. The most significant element was an average GSC of
$0.05744 per kWh. That charge will allow CL&P to fully recover from
customers the amounts to be paid in 2004 to its five TSO suppliers. These
suppliers include Select Energy, which was awarded 37.5 percent of CL&P's TSO
load through a request for proposal process overseen by the DPUC, and four
other suppliers, all of which are investment grade rated by major rating
agencies.
The Act also required CL&P to file a four-year transmission and distribution
plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case
that amended rate schedules and proposed changes to increase distribution
rates. On December 19, 2003, the DPUC issued its final decision in the rate
case. In that decision, the DPUC chose to apply $120 million of
overcollections from CL&P's customers in prior years against higher
distribution rates in the form of credits of $30 million per year. Net of
those overcollections, the DPUC ordered that distribution rates be lowered by
$1.9 million in 2004 and be raised by $25.1 million in 2005, $11.9 million in
2006, and $7 million in 2007. The decision approved a transmission rate
increase of $28.4 million in 2004, but did not allow the tracking mechanism
and did not set transmission rates beyond 2004. The DPUC also approved rate
recovery of approximately $900 million of CL&P's proposed $1 billion
distribution capital budget over the four-year period. The decision set
CL&P's authorized ROE at 9.85 percent. Earnings above 9.85 percent will be
shared equally by shareholders and ratepayers. The sharing mechanism is not
affected by earnings from the procurement fee.
CL&P filed a petition for reconsideration of certain items in the rate case
on December 31, 2003. Other parties also filed petitions for
reconsideration. On January 21, 2004, the DPUC agreed to reconsider CL&P's
items; however, CL&P also filed an appeal with the Connecticut Superior Court
on January 30, 2004, which was within the time frame required by law. The
appeal was filed in the event that the DPUC's reconsideration is still not
acceptable to CL&P.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook
nuclear unit on November 1, 2002. The net proceeds in excess of the book
value of Seabrook of $16 million were recorded as a regulatory liability and,
after being offset by accelerated decommissioning funding and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September 2003,
and a draft decision was received on February 3, 2004. The final decision,
which was received on March 3, 2004, did not have a material effect on CL&P's
net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual
CTA and SBC reconciliation with the DPUC. For the year ended December 31,
2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue
requirement by $93.5 million. This amount was recorded as a regulatory
liability. For the same period, SBC revenues exceeded the SBC revenue
requirement by $22.4 million. In compliance with a prior decision of the
DPUC, a portion of the SBC overcollection reduced regulatory assets, and the
remaining overcollection of $18.6 million was applied to the CTA. The DPUC's
December 19, 2003 TSO decision addressed $41 million of SBC overcollections and
$64 million of CTA overcollections that had been estimated as of December 31,
2003. In its decision, the DPUC ordered that $80 million of the
overcollections be used to reduce CTA costs during the 2004 through 2006 TSO
period. The DPUC also ordered that $25 million of the overcollections be used
to offset SBC costs during the TSO period. The DPUC also ordered that $37
million of GSC overcollections be used to pay CL&P's 0.50 mill per kWh
procurement fee during the TSO period.
Connecticut - Yankee Gas:
Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC
issued a final decision in the 2002 IERM docket. The DPUC concluded that the
basic concept of IERM is valid, appropriate and beneficial. The DPUC ordered
Yankee Gas to provide a credit to customers for 2002 and 2003
overcollections. That credit was recorded as a regulatory liability and
refunded to Yankee Gas customers from December 2003 through February 2004.
On October 1, 2003, Yankee Gas filed with the DPUC its IERM compliance filing.
This filing is required annually on October 1 of each year to provide a
reconciliation of the system expansion program and the earnings sharing
mechanism projection.
Rate Case: In 2003, Yankee Gas earned a ROE below the DPUC-authorized level
of 11 percent. As a result of higher pension costs and other factors,
management expects that the financial performance will continue to underearn
the DPUC-authorized ROE. Yankee Gas is evaluating the filing of a rate case
before the end of 2004 for a rate increase to take effect in 2005.
New Hampshire:
Transition Energy Service: In accordance with the "Agreement to Settle PSNH
Restructuring" (Restructuring Settlement) and state law, PSNH must file for
updated transition energy service (TS) rates annually. The TS rate recovers
PSNH's generation and purchased power costs, including a return on PSNH's
generation investment. During the February 1, 2004 through January 31, 2005
time period when current rates will be effective, PSNH will defer any
difference between its TS revenues and the actual costs incurred. On
December 19, 2003, the NHPUC approved a $0.0536 per kWh TS rate effective
February 1, 2004.
Delivery Rate Case: PSNH's delivery rates were fixed by the Restructuring
Settlement until February 1, 2004. Consistent with the requirements of the
Restructuring Settlement and state law, PSNH filed a delivery service rate
case and tariffs with the NHPUC on December 29, 2003 to increase electricity
delivery rates by approximately $21 million, or approximately 2.6 percent,
effective February 1, 2004. In addition, PSNH is requesting that recovery of
FERC-regulated transmission costs be adjusted annually through a tracking
mechanism. The NHPUC suspended the proposed rate increase until the
conclusion of the delivery rate case. Hearings are expected in August 2004,
and a decision is expected in the third quarter of 2004 with rates
retroactively applied to February 1, 2004.
SCRC Reconciliation Filings: On an annual basis, PSNH files with the NHPUC
an SCRC reconciliation filing for the preceding calendar year. This filing
includes the reconciliation of stranded cost revenues with stranded costs,
and TS revenues with TS costs. The NHPUC reviews the filing, including a
prudence review of PSNH's generation operations.
On May 1, 2003, PSNH filed with the NHPUC an SCRC reconciliation filing for
the period January 1, 2002, through December 31, 2002. This filing included
the reconciliation of stranded cost revenues with stranded costs and a net
proceeds calculation related to the sale of NAEC's share of Seabrook and the
subsequent transfer of those net proceeds to PSNH. Upon the completion of
discovery and technical sessions with the NHPUC staff and the New Hampshire
Office of the Consumer Advocate (OCA), PSNH, the NHPUC Staff and the OCA
entered into a stipulation and settlement agreement that was filed with the
NHPUC on August 15, 2003. An order from the NHPUC approving the settlement
agreement on October 24, 2003 did not have a material impact on PSNH's net
income or financial position.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does
not expect the review of the 2003 SCRC filing to have a material effect on
PSNH's net income or financial position. The recovery of stranded costs is
expected to be a significant source of cash flow for PSNH through 2007. On
May 22, 2003, the NHPUC issued an order approving a settlement between PSNH,
owners of 14 small hydroelectric power producers, the NHPUC staff and the OCA
calling for the termination of PSNH's obligations to purchase power from the
hydroelectric units at above market prices. On May 30, 2003, under the terms
of this settlement, PSNH made lump sum payments to those owners amounting to
$20.4 million. The buyout payments were recorded as regulatory assets and will
be recovered, including a return, over the initial term of the obligations as
Part 2 stranded costs. PSNH is entitled to retain 20 percent of the estimated
savings from the buyouts. PSNH is expected to recover $21 million of the
purchase price of CVEC over the next three to four years.
Massachusetts:
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002
transition cost reconciliation with the Massachusetts Department of
Telecommunications and Energy (DTE). This filing reconciled the recovery of
generation-related stranded costs for calendar year 2002 and included the
renegotiated purchased power contract related to the Vermont Yankee nuclear
unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition
cost reconciliation, which addressed WMECO's cost tracking mechanisms. As
part of that order, the DTE directed WMECO to revise its 2002 annual
transition cost reconciliation filing. The revised filing was submitted to
the DTE on September 22, 2003. Hearings have been held, and the timing of a
final decision from the DTE is uncertain. Management does not expect the
outcome of this docket to have a material adverse impact on WMECO's net
income or financial position.
Standard Offer and Default Service: In December 2003, the DTE approved
WMECO's standard offer service rate of $0.05607 per kWh for the period of
January 1, 2004 through February 28, 2005. The DTE also approved a default
service rate of $0.05829 for the period of January 1, 2004 through June 30,
2004 for residential customers and a rate of $0.0616 for the period
January 1, 2004 through March 31, 2004 for commercial and industrial
customers.
For information regarding commitments and contingencies related to
restructuring and rate matters, see Note 7A, "Commitments and Contingencies -
Restructuring and Rate Matters," to the consolidated financial statements.
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' 1999 merger agreement. On March 12, 2001, NU filed suit against Con
Edison seeking damages in excess of $1 billion.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for
breach of contract, fraudulent inducement and negligent misrepresentation.
Con Edison claimed that it is entitled to recover a portion of the merger
synergy savings estimated to have a net present value 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 completed discovery in the litigation and both submitted
motions for summary judgment. The court denied Con Edison's motion in its
entirety, leaving NU's claim for breach of the merger agreement and partially
granted NU's motion for summary judgment by eliminating Con Edison's claims
against NU for fraud and negligent misrepresentation.
Various other motions in the case are pending. 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.
NUCLEAR GENERATION ASSET DIVESTITURES
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.
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interests in Seabrook.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation
(VYNPC) consummated the sale of its nuclear generating unit. In November
2003, CL&P, PSNH and WMECO collectively sold back to VYNPC their shares of
stock for approximately $1.5 million. CL&P, PSNH and WMECO continue to
purchase their respective shares of approximately 16 percent of the plant's
output under new contracts.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers of
NU's ownership shares of the Millstone, Seabrook and Vermont Yankee plants
assumed the obligation of decommissioning those plants, NU still has
significant decommissioning and plant closure cost obligations to the
companies that own the Yankee Atomic (YA), Connecticut Yankee (CY) and Maine
Yankee (MY) plants (collectively Yankee Companies). Each plant has been shut
down and is undergoing decommissioning. The Yankee Companies collect
decommissioning and closure costs through wholesale FERC-approved rates
charged under power purchase agreements to NU electric utility companies
CL&P, PSNH, and WMECO. These companies in turn pass these costs on to their
customers through state regulatory commission-approved retail rates. A
portion of the decommissioning and closure costs has already been collected,
but a substantial portion related to the decommissioning of CY has not yet
been filed at and approved for collection by the FERC. The cost estimate for
CY that has not yet been approved for recovery by the FERC at December 31,
2003 is $258.3 million.
NU cannot at this time predict the timing or outcome of the FERC proceeding
required for the collection of these remaining decommissioning and closure
costs or the Bechtel Power Corporation litigation referred to in Note 7G,
"Commitments and Contingencies - Nuclear Decommissioning and Plant Closure
Costs," to the consolidated financial statements. Although management
believes that these costs will ultimately be recovered from the customers of
CL&P, PSNH, and WMECO, there is a risk that the FERC may not allow these
costs, the estimates of which have increased significantly in 2003 and 2002,
to be recovered in wholesale rates. If the FERC does not allow these costs
to be recovered in wholesale rates, NU would expect the state regulatory
commissions to disallow these costs in retail rates as well.
OFF-BALANCE SHEET ARRANGEMENTS
Utility Group: The CL&P Receivables Corporation (CRC) was incorporated on
September 5, 1997, and is a wholly owned subsidiary of CL&P. CRC has an
arrangement with a highly rated financial institution under which CRC can
sell up to $100 million of accounts receivable. At December 31, 2003 and
2002, CRC had sold accounts receivable of $80 million and $40 million,
respectively, to that financial institution with limited recourse.
CRC was established for the sole purpose of selling CL&P's accounts
receivable and unbilled revenues and is included in the consolidation of NU's
financial statements. On July 9, 2003, CRC renewed its Receivables Purchase
and Sale Agreement with CL&P and the financial institution. The agreement
expires on July 7, 2004. Management plans to renew this agreement prior to
its expiration.
The transfer of receivables to the financial institution under this
arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities
- - A Replacement of SFAS No. 125." Accordingly, the $80 million and $40
million outstanding under this facility are not reflected as debt or included
in the consolidated financial statements at December 31, 2003 and 2002,
respectively.
This off-balance sheet arrangement is not significant to NU's liquidity or
other benefits. There are no known events, demands, commitments, trends, or
uncertainties that will, or are reasonably likely to, result in the
termination, or material reduction in the amount available to the company
under this off-balance sheet arrangement.
NU Enterprises: During 2001, SESI created HEC/CJTS Energy Center, LLC
(HEC/CJTS) which is a special purpose entity (SPE). Management decided to
create HEC/CJTS for the sole purpose of providing a bankruptcy-remote entity
for the financing of a construction project. The construction project was
the construction of an energy center to serve the Connecticut Juvenile
Training School (CJTS). The owner of CJTS, the State of Connecticut, entered
into a 30-year lease with HEC/CJTS for the energy center. Simultaneously,
HEC/CJTS transferred its interest in the lease with the State of Connecticut
to investors who are unaffiliated with NU in exchange for the issuance of
$19.2 million of Certificates of Participation. The transfer of HEC/CJTS's
interest in the lease was accounted for as a sale under SFAS No. 140. The
debt of $19.2 million created in relation to the transfer of interest and
issuance of the Certificates of Participation was derecognized and is not
reflected as debt or included in the consolidated financial statements. No
gain or loss was recorded. HEC/CJTS does not provide any guarantees or on-
going services, and there are no contingencies related to this arrangement.
SESI has a separate contract with the State of Connecticut to operate and
maintain the energy center. The transaction was structured in this manner to
obtain tax-exempt rate financing and therefore to reduce the State of
Connecticut's lease payments.
This off-balance sheet arrangement is not significant to NU's liquidity,
capital resources or other benefits. There are no known events, demands,
commitments, trends, or uncertainties that will, or are reasonably likely to,
result in the termination of this off-balance sheet arrangement.
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 statements of NU.
Management communicates to and discusses with NU's Audit Committee of the
Board of Trustees all critical accounting policies and estimates. The
following are the 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 control
is maintained and all variable interest entities (VIE) for which NU is the
primary beneficiary, as defined. 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, and two companies that transmit electricity imported from the
Hydro-Quebec system. NU does not control these companies and does not
consolidate them in its financial statements. NU accounts for the
investments in these companies using the equity method. Under the equity
method, NU records its ownership share of the earnings or losses at these
companies. Determining whether or not NU should apply the equity method of
accounting for an investee company requires management judgment.
NU has investments in NEON and Acumentrics. These investments are carried at
cost, and these companies are VIEs, as defined by FIN 46. NU adopted FIN 46
on July 1, 2003. FIN 46 requires that the party to a VIE that absorbs the
majority of the VIE's losses, defined as the primary beneficiary, consolidate
the VIE. NU is not the primary beneficiary of NEON or Acumentrics and is not
required to consolidate them.
NU also has a preferred stock investment in R. M. Services, Inc. (RMS). Upon
adoption of FIN 46, management determined that NU was the primary beneficiary
of RMS and that NU would have to consolidate RMS into its financial
statements. The consolidation of RMS resulted in a negative $4.7 million
after-tax cumulative effect of an accounting change in the third quarter of
2003. For more information on RMS, see Note 1E, "Summary of Significant
Accounting Policies - Accounting for R.M. Services, Inc. Variable Interest
Entity," to the consolidated financial statements.
The required adoption date of FIN 46 was delayed from July 1, 2003 to
December 31, 2003 for NU. However, NU elected to adopt FIN 46 at the
original adoption date, which impacted both the amount of the cumulative
effect of the accounting change and the classification of losses NU recorded
after RMS became a consolidated entity.
Determining whether the company is the primary beneficiary of a VIE is
subjective and requires management's judgment. There are certain variables
taken into consideration to determine whether the company is considered the
primary beneficiary to the VIE. A change in any one of these variables could
require the company to reconsider whether or not it is the primary
beneficiary of the VIE.
In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN
46R could result in fewer NU investments meeting the definition of a VIE.
FIN 46R is effective for NU for the first quarter of 2004, but is not
expected to have an impact on NU's consolidated financial statements.
Revenue Recognition: Utility Group retail revenues are based on rates
approved by the state regulatory commissions. These regulated rates are
applied to customers' use of energy to calculate a bill. In general, rates
can only be changed through formal proceedings with the state regulatory
commissions.
Certain Utility Group companies utilize regulatory commission-approved
tracking mechanisms to track the recovery of certain incurred costs. The
tracking mechanisms allow for rates to be changed periodically, with
overcollections refunded to customers or undercollections collected from
customers in future periods.
The determination of the energy sales to individual customers is based on the
reading of meters, which occurs on a systematic basis throughout the month.
Billed revenues are based on these meter readings. At the end of each month,
amounts of energy delivered to customers since the date of the last meter
reading are estimated, and an estimated amount of unbilled revenues is
recorded.
Wholesale transmission revenues are based on rates and formulas that are
approved by the FERC. Most of NU's wholesale transmission revenues are
collected through a combination of the New England Regional Network Service
(RNS) tariff and NU's Local Network Service (LNS) tariff. The RNS tariff,
which is administered by ISO-NE, recovers the revenue requirements associated
with transmission facilities that are deemed by the FERC to be Pool
Transmission Facilities. The LNS tariff which was accepted by the FERC on
October 22, 2003, provides for the recovery of NU's total transmission
revenue requirements, net of revenue credits received from various rate
components, including revenues received under the RNS rates.
NU Enterprises recognizes revenues at different times for its different
business lines. Wholesale and retail marketing revenues are recognized when
energy is delivered to customers. 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.
Revenues and expenses for derivative contracts that are entered into for
trading purposes are recorded on a net basis in revenues when these
transactions settle. The settlement of wholesale non-trading derivative
contracts for the sale of energy or gas by both the Utility Group and NU
Enterprises that are not related to customers' needs are recorded in operating
expenses. Derivative contracts that hedge an underlying transaction and that
qualify for hedge accounting affect 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. The settlement of hedge derivative contracts is
recorded in the same revenue or expense line as the transaction being hedged.
For further information regarding the accounting for these contracts, see
Note 1G, "Summary of Significant Accounting Policies - Accounting for Energy
Contracts," to the consolidated financial statements.
Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of
electricity or gas delivered to customers that has not been billed. Unbilled
revenues represent assets on the balance sheet that become accounts
receivable in the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can
significantly impact the amount of revenues recorded. Estimating the impact
of these factors is complex and requires management's judgment. The estimate
of unbilled revenues is important to NU's consolidated financial statements
as adjustments to that estimate could significantly impact operating revenues
and earnings. Two potential methods for estimating unbilled revenues are the
requirements and the cycle method.
The Utility Group estimates unbilled revenues monthly using the requirements
method. The requirements method utilizes the total monthly volume of
electricity or gas delivered to the system and applies a delivery efficiency
(DE) factor to reduce the total monthly volume by an estimate of delivery
losses in order to calculate total estimated monthly sales to customers. The
total estimated monthly sales amount less total monthly billed sales amount
results in a monthly estimate of unbilled sales. Unbilled revenues are
estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can have
a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for all Utility Group companies were
tested using the cycle method. The cycle method uses the billed sales from
each meter reading cycle and an estimate of unbilled days in each month based
on the meter reading schedule. The cycle method is historically more
accurate than the requirements method when used in a mostly weather-neutral
month. The cycle method resulted in adjustments to the estimate of unbilled
revenues that had a net positive after-tax earnings impact of approximately
$4.6 million in 2003. The positive after-tax impacts on CL&P, PSNH, and
WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There
was a negative after-tax impact on Yankee Gas of $6.2 million, including
certain gas cost adjustments.
The testing of the requirements method with the cycle method will be done on
at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133,
as amended.
Select Energy uses derivative instruments in its wholesale and retail
marketing activities, and many Utility Group contracts for the purchase or
sale of energy or energy-related products are derivatives. The application
of derivative accounting under SFAS No. 133, as amended, 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 exception, identifying hedge relationships, assessing
and measuring hedge ineffectiveness, and determining the fair value of
derivatives. All of these judgments, depending upon their timing and effect,
can have a significant impact on NU's consolidated net income.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amended existing
derivative accounting guidance. This new statement incorporates
interpretations that were included in previous Derivative Implementation
Group (DIG) guidance, clarifies certain conditions, and amends other existing
pronouncements. It was effective for contracts entered into or modified
after June 30, 2003. Management has determined that the adoption of SFAS No.
149 did not change NU's accounting for wholesale and retail marketing
contracts or the ability of NU Enterprises to elect the normal purchases and
sales exception. The adoption of SFAS No. 149 resulted in fair value
accounting for certain Utility Group contracts that are subject to unplanned
netting and do not meet the definition of capacity contracts. These non-
trading derivative contracts are recorded at fair value at December 31, 2003
as derivative assets and liabilities with offsetting amounts recorded as
regulatory liabilities and assets because the contracts are part of providing
regulated electric or gas service. The fair values of these Utility Group
contracts at December 31, 2003 were derivative assets of $1.6 million and
derivative liabilities of $1.6 million.
Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains
and Losses on Derivative Instruments That Are Subject to FASB Statement No.
133, and 'Not Held for Trading Purposes' as Defined in EITF Issue No. 02-3,"
was derived from EITF Issue No. 02-3, which requires net reporting in the
income statement of energy trading activities. Issue No. 03-11 addresses
income statement classification of revenues related to derivatives that
physically deliver and are not related to energy trading activities. Prior
to Issue No. 03-11, there was no specific accounting guidance that addressed
the classification in the income statement of Select Energy's retail
marketing and wholesale contracts or the Utility Group's power supply
contracts, many of which are non-trading derivatives.
On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that
determining whether realized gains and losses on contracts that physically
deliver and are not held for trading purposes should be reported on a net
(sales and purchases both in expenses) or gross (sales in revenues and
purchases in expenses) basis is a matter of judgment that depends on the
relevant facts and circumstances. The EITF indicated that existing
accounting guidance should be considered and provided no new guidance in
Issue No. 03-11. In Issue No. 03-11, the EITF did not provide transition
guidance, which management could have interpreted as becoming applicable on
October 1, 2003 for revenues from that date forward. However, management
applied its conclusion on net or gross reporting to all periods presented to
enhance comparability.
Select Energy reports the settlement of long-term derivative contracts that
physically deliver and are not held for trading purposes on a gross basis,
generally with sales in revenues and purchases in expenses. Short-term sales
and purchases represent power that is purchased to serve full requirements
contracts but is ultimately not needed based on the actual load of the full
requirements customers. This excess power is sold to the independent system
operator or to other counterparties. As of December 31, 2003, settlements
of short-term derivative contracts that are not held for trading purposes,
though previously reported in revenues, are reported on a net basis in
expenses. Select Energy applied the new classification to revenues for all
years presented in order to enhance comparability. Short-term and non-
requirements sales and other reclassifications that amounted to $595.7 million
for the first nine months of 2003 were reflected as revenues in quarterly
reporting but are now included in expenses.
Though previously reported on a gross basis, after reviewing the relevant
facts and circumstances, the Utility Group also reported the settlement of
all short-term sales contracts that are part of procurement activities on a
net basis in expenses. The Utility Group applied this new classification to
revenues for all years presented in order to enhance comparability. These
sales that amounted to $50.2 million for the first nine months of 2003 were
reflected as revenues in quarterly reporting but are now included in expenses.
The amounts reclassified from 2002 and 2001 revenues to operating expenses
are included in Note 1C, "Summary of Significant Accounting Policies - New
Accounting Standards," to the consolidated financial statements.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning
of "not clearly and closely related regarding contracts with a price
adjustment feature" as it relates to the election of the normal purchase and
sales exception to derivative accounting. The implementation of this
guidance was required for the fourth quarter of 2003 for NU. The
implementation of Issue No. C-20 resulted in CL&P recording the fair value of
two existing power purchase contracts as derivatives, one as a derivative
asset, and one as a derivative liability. An offsetting regulatory liability
and an offsetting regulatory asset were recorded, as these contracts are part
of stranded costs, and management believes that these costs will continue to
be recovered or refunded in rates. The fair values of these long-term power
purchase contracts include a derivative asset with a fair value of $112.4
million and a derivative liability with a fair value of $54.6 million at
December 31, 2003.
At December 31, 2003, Select Energy recorded approximately $4.3 million of
TCCs at fair value. Market information for these TCCs is not available, and
management believes the amounts paid for these contracts are equal to their
fair value. Select Energy, as well as CL&P and PSNH, hold FTR contracts to
mitigate the risk associated with the congestion price differences associated
with LMP in New England. FTR contracts in New England held by NU
subsidiaries were recorded at a fair value of $6.2 million. FTR contracts
held by Select Energy in the PJM region were recorded at a fair value of $0.8
million. Management continues to believe the amount to be paid for both the
TCC and the FTR contracts best represents their fair value. If new markets
for these contracts develop, then there may be an impact on NU's consolidated
financial statements in future periods.
Regulatory Accounting: 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." The transmission and distribution businesses of CL&P, PSNH and
WMECO, along with PSNH's generation business and Yankee Gas' distribution
business, 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 the respective
regulatory assets and liabilities. Such a write-off could have a material
impact on NU's consolidated financial statements.
The application of SFAS No. 71 results in recording regulatory assets and
liabilities. Regulatory assets represent the deferral of incurred costs that
are probable of future recovery in customer rates. In some cases, NU records
regulatory assets before approval for recovery has been received from the
applicable regulatory commission. Management must use judgment to conclude
that costs deferred as regulatory assets are probable of future recovery.
Management bases its conclusion on certain factors, including changes in the
regulatory environment, recent rate orders issued by the applicable
regulatory agencies and the status of any potential new legislation.
Regulatory liabilities represent revenues received from customers to fund
expected costs that have not yet been incurred or probable future refunds to
customers.
Management uses its best judgment when recording regulatory assets and
liabilities; however, regulatory commissions can reach different conclusions
about the recovery of costs, and those conclusions could have a material
impact on NU's consolidated financial statements. Management believes it is
probable that the Utility Group companies will recover the regulatory assets
that have been recorded.
Goodwill and Other Intangible Assets: SFAS No. 142, "Goodwill and Other
Intangible Assets," requires that goodwill balances be reviewed for
impairment at least annually by applying a fair value-based test. NU
selected October 1 as the annual goodwill impairment testing date. The
goodwill impairment analysis impacts the Utility Group - Gas and NU
Enterprises segments. 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. If goodwill is deemed
to be impaired it will be written off, which could have a significant impact
on NU's consolidated financial statements.
NU has completed its impairment analyses as of October 1, 2003, for all
reporting units that maintain goodwill and has determined that no impairments
exist.
In performing the impairment evaluation required by SFAS No. 142, NU
estimates the fair value of each reporting unit and compares it to the
carrying amount of the reporting unit, including goodwill. NU estimates the
fair values of its reporting units using discounted cash flow methodologies
and an analysis of comparable companies or transactions. The discounted cash
flow analysis requires the input of several critical assumptions, including
future growth rates, operating cost escalation rates, allowed ROE, a risk-
adjusted discount rate, and long-term earnings multiples of comparable
companies. These assumptions are critical to the estimate and are
susceptible to change from period to period.
Modifications to the aforementioned assumptions in future periods,
particularly changes in discount rates, could result in future impairments of
goodwill. Actual financial performance and market conditions in upcoming
periods could also impact future impairment analyses.
Pension and Postretirement Benefits Other Than Pensions (PBOP): NU's
subsidiaries participate in a uniform noncontributory defined benefit
retirement plan (Pension Plan) covering substantially all regular NU
employees. NU also participates in a postretirement benefit plan (PBOP Plan)
to 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
resulting 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.
Results: Pre-tax periodic pension income for the Pension Plan, excluding
settlements, curtailments and special termination benefits, totaled $31.8
million, $73.4 million and $101 million for the years ended December 31,
2003, 2002 and 2001, respectively. 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 in income for the year ended December 31, 2002. This amount was
recorded as a liability for refund to customers.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and
special termination benefits, totaled $35.1 million, $34.5 million and $28.3
million for the years ended December 31, 2003, 2002 and 2001, respectively.
The PBOP Plan cost excludes one-time items associated with the sale of the
Seabrook nuclear units. These items totaled $1.2 million in income for the
year ended December 31, 2002.
Long-Term Rate of Return Assumptions: In developing the expected long-term
rate of return assumptions, NU evaluated input from actuaries, consultants
and economists, as well as long-term inflation assumptions and NU's historical
20-year compounded return of approximately 11 percent. NU's expected long-term
rate of return on assets is based on certain target asset allocation
assumptions and expected long-term rates of return. The Pension Plan's and
PBOP Plan's target asset allocation assumptions and expected long-term rates
of return assumptions by asset category are as follows:
- -----------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
- -----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
- -----------------------------------------------------------------------------------------------------------------
The actual asset allocations at December 31, 2003 and 2002 approximated these
target asset allocations. NU regularly reviews the actual asset allocations
and periodically rebalances the investments to the targeted asset allocations
when appropriate. For information regarding actual asset allocations, see
Note 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits
Other Than Pensions," to the consolidated financial statements.
NU reduced the long-term rate of return assumption 50 basis points from 9.25
percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due to
lower expected market returns. NU believes that 8.75 percent is a reasonable
long-term rate of return on Pension Plan and PBOP Plan assets for 2003, and
NU expects to use 8.75 percent in 2004. 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.
Actuarial Determination of Income and Expense: NU bases the actuarial
determination of Pension Plan and PBOP Plan income/expense on a market-
related valuation of assets, which reduces year-to-year volatility. This
market-related valuation calculation 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 valuation
calculation 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
Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized investment
losses of $106 million, which will increase pension expense over the next
four years by reducing the expected return on Pension Plan assets. At
December 31, 2003, the Pension Plan also had cumulative unrecognized
actuarial losses of $189 million, which will increase pension expense over
the expected future working lifetime of active Pension Plan participants, or
approximately 13 years. The combined total of unrecognized investment and
actuarial losses at December 31, 2003 is approximately $295 million. These
losses impact the determination of pension expense and the actuarially
determined prepaid pension amount recorded on the consolidated balance sheets
but have no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment
losses of $11 million, which will increase PBOP Plan cost over the next four
years by reducing the expected return on plan assets. At December 31, 2003,
the PBOP Plan also had cumulative unrecognized actuarial losses of $103
million, which will increase PBOP Plan expense over the expected future
working lifetime of active PBOP Plan participants, or approximately 13 years.
The combined total of unrecognized investment and actuarial losses at
December 31, 2003 is approximately $114 million. These losses impact the
determination of PBOP Plan cost and the actuarially determined accrued PBOP
Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future
pension and PBOP 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 Pension Plan's longer duration, 25 basis points were
added to the benchmark. The discount rate determined on this basis has
decreased from 6.75 percent at December 31, 2002 to 6.25 percent at
December 31, 2003.
Expected Pension Expense: Due to the effect of the unrecognized actuarial
losses and based on an expected rate of return on Pension Plan assets of 8.75
percent, a discount rate of 6.25 percent and various other assumptions, NU
estimates that expected contributions to and pension expense for the Pension
Plan will be as follows (in millions):
- ----------------------------------------------------
Expected
Year Contributions Pension Expense
- ----------------------------------------------------
2004 $ - $ 2.9
2005 $ - $21.2
2006 $ - $26.6
- ----------------------------------------------------
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 Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to
the Pension Plan's reported cost and to the PBOP Plan's reported cost as a
result of the change in the following assumptions by 50 basis points (in
millions):
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
Pension Plan Postretirement Plan
- ---------------------------------------------------------------------
Assumption Change 2003 2002 2003 2002
- ---------------------------------------------------------------------
Lower long-term
rate of return $10.7 $10.7 $0.9 $1.1
Lower discount rate $12.3 $11.0 $1.0 $1.1
Lower compensation
increase $(5.9) $(5.0) N/A N/A
- ---------------------------------------------------------------------
Plan Assets: The value of the Pension Plan assets has increased from $1.6
billion at December 31, 2002 to $1.9 billion at December 31, 2003. The
investment performance returns, despite declining discount rates, have
increased the funded status of the Pension Plan on a projected benefit
obligation (PBO) basis from an underfunded position of $157.5 million at
December 31, 2002 to an overfunded position of $3.8 million at December 31,
2003. The PBO includes expectations of future employee compensation
increases. The accumulated benefit obligation (ABO) of the Pension Plan was
approximately $240 million less than Pension Plan assets at December 31, 2003
and approximately $78 million less than Pension Plan assets at December 31,
2002. The ABO is the obligation for employee service and compensation
provided through December 31, 2003. If the ABO exceeds Pension Plan assets
at a future plan measurement date, NU will record an additional minimum
liability. NU has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $147.7 million at December 31,
2002 to $178 million at December 31, 2003. The investment performance returns,
despite declining discount rates, have decreased the underfunded status of the
PBOP Plan on an accumulated projected benefit obligation basis from $250.1
million at December 31, 2002 to $227 million at December 31, 2003. NU has
made a contribution each year equal to the PBOP Plan's postretirement benefit
cost, excluding curtailments, settlements and special termination benefits.
Health Care Cost: The health care cost trend assumption used to project
increases in medical costs is 9 percent for 2003, decreasing one percentage
point per year to an ultimate rate of 5 percent in 2007. The effect of
increasing the health care cost trend by one percentage point would have
increased 2003 service and interest cost components of the PBOP Plan cost by
$0.8 million in 2003 and $0.9 million in 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8, 2003,
the President signed into law a bill that expands Medicare, primarily by
adding a prescription drug benefit and by adding a federal subsidy to
qualifying plan sponsors of retiree health care benefit plans. Management
believes that NU currently qualifies.
Specific authoritative accounting guidance on how to account for the effect
the Medicare federal subsidy has on NU's PBOP Plan has not been issued by the
FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003," required NU to make an election for 2003
financial reporting. The election was to either defer the impact of the
subsidy until the FASB issues guidance or to reflect the impact of the
subsidy on December 31, 2003 reported amounts. NU chose to reflect the
impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit
obligation by $19.5 million and increased actuarial gains by $19.5 million
with no impact on 2003 expenses, assets, or liabilities. The $19.5 million
actuarial gain will be amortized as a reduction to PBOP expense over 13 years
beginning in 2004. PBOP expense in 2004 will also reflect a lower interest
cost due to the reduction in the December 31, 2003 benefit obligation.
Management estimates that the reduction in PBOP expense in 2004 will be
approximately $2 million.
When accounting guidance is issued by the FASB, it may require NU to change
the accounting described above and change the information included in this
annual report.
Income Taxes: Income tax expense is calculated each year in each of the
jurisdictions in which NU operates. 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
and expenses for tax and book accounting purposes. These differences result
in deferred tax assets and liabilities, which are included in NU's
consolidated balance sheets. The income tax estimation process impacts all
of NU's segments. Adjustments made to income taxes could significantly
affect NU's consolidated financial statements. Management must also assess
the likelihood that 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. The regulatory asset amounted to $253.8 million and $326.4 million at
December 31, 2003 and 2002, respectively. Regulatory agencies in certain
jurisdictions in which NU's Utility Group companies operate require the tax
effect of specific temporary differences to be "flowed through" to utility
customers. Flow through treatment means that deferred tax expense is not
recorded on the consolidated statements of income. Instead, the tax effect
of the temporary difference impacts both amounts for income tax expense
currently included in customers' rates and the company's net income. Flow
through treatment can result in effective income tax rates that are
significantly different than expected income tax rates. Recording deferred
taxes on flow through items is required by SFAS No. 109, and the offset to
the deferred tax amounts is the regulatory asset referred to above. A
reconciliation from expected tax expense at the statutory federal income tax
rate to actual tax expense recorded is included on the accompanying
consolidated statements of income taxes.
The estimates that are made by management in order to record income tax
expense, accrued taxes and deferred taxes are compared each year to the
actual tax amounts filed on NU's income tax returns. The income tax returns
were filed in the fall of 2003 for the 2002 tax year. In the fourth quarter,
NU recorded differences between income tax expense, accrued taxes and
deferred taxes on its consolidated financial statements and the amounts that
were on its income tax returns. Recording these differences in income tax
expense resulted in a positive impact of approximately $6 million on NU's
2003 earnings.
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 absent timely rate
relief for Utility Group assets.
Accounting for Environmental Reserves: Environmental reserves are accrued
using a probabilistic model approach when assessments indicate that it is
probable that a liability has been incurred and an amount can be reasonably
estimated. The estimation of environmental liabilities impacts the Utility
Group - Electric and the Utility Group - Gas segments. Adjustments made to
environmental liabilities could have a significant effect on earnings. The
probabilistic model approach estimates the liability based on the most likely
action plan from a variety of available remediation options, ranging from
no action to remedies ranging from establishing institutional controls to
full site remediation and long-term monitoring. The probabilistic model
approach estimates the liabilities associated with each possible action plan
based on findings through various phases of site assessments. These
estimates are based on currently available information from presently enacted
state and federal environmental laws and regulations and several cost
estimates from outside engineering and remediation contractors. These
amounts also take into consideration prior experience in remediating
contaminated sites and data released by the United States Environmental
Protection Agency and other organizations.
These estimates are subjective in nature partly because there are usually
several different remediation options from which to choose when working on a
specific site. These estimates are subject to revisions in future periods
based on actual costs or new information concerning either the level of
contamination at the site or newly enacted laws and regulations. The amounts
recorded as environmental liabilities on the consolidated balance sheets
represent management's best estimate of the liability for environmental costs
based on current site information from site assessments and remediation
estimates. These liabilities are estimated on an undiscounted basis.
Under current rate-making policy, PSNH and Yankee Gas have regulatory
recovery mechanisms in place for environmental costs. Accordingly,
regulatory assets have been recorded for certain of PSNH's and Yankee Gas'
environmental liabilities. As of December 31, 2003 and 2002, $26.3 million
and $24.3 million, respectively, have been recorded as regulatory assets on
the accompanying consolidated balance sheets. CL&P recovers a certain level
of environmental costs currently in rates but does not have an environmental
cost recovery tracking mechanism. Accordingly, changes in CL&P's
environmental reserves impact CL&P's earnings. WMECO does not have a
regulatory mechanism to recover environmental costs from its customers, and
changes in WMECO's environmental reserves impact WMECO's earnings.
Asset Retirement Obligations: NU adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," on January 1, 2003. SFAS No. 143 requires that
legal obligations associated with the retirement of property, plant and
equipment be recorded as a liability on the balance sheet at fair value when
incurred and when a reasonable estimate of the fair value can be made. SFAS
No. 143 defines an asset retirement obligation (ARO) as a legal obligation
that is required to be settled due to an existing or enacted law, statute,
ordinance, or a written or oral promise to remove an asset. AROs may stem
from environmental laws, state laws and regulations, easement agreements,
building codes, contracts, franchise grants and agreements, oral promises
made upon which third parties have relied, or the dismantlement, restoration,
or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified
that management believes are AROs but either have not been incurred or are
not material. These removal obligations arise in the ordinary course of
business or have a low probability of occurring. The 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. There was no impact to NU's earnings
upon adoption of SFAS No. 143; however, if there are changes in certain laws
and regulations, orders, interpretations or contracts entered into by NU,
there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including NU's Utility Group
companies, currently recover amounts in rates for future costs of removal of
plant assets. Future removals of assets do not represent legal obligations
and are not AROs. Historically, these amounts were included as a component
of accumulated depreciation until spent. At December 31, 2003 and 2002,
these amounts totaling $334 million and $321 million, respectively, were
reclassified to regulatory liabilities on the accompanying consolidated
balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No. 143,
'Accounting for Asset Retirement Obligations', to Legislative Requirements on
Property Owners to Remove and Dispose of Asbestos or Asbestos-Containing
Materials." In the FSP, the FASB staff concludes that current legislation
creates a legal obligation for the owner of a building to remove and dispose
of asbestos-containing materials. In the FSP, the FASB staff also concludes
that this legal obligation constitutes an ARO that should be recognized as a
liability under SFAS No. 143. This FSP changes a FASB staff interpretation
of SFAS No. 143 that an obligating event did not occur until a building
containing asbestos was demolished. In November 2003, the FASB indicated
that, based on the diverse views it received in comment letters on the
proposed FSP, it was considering a proposal for a FASB agenda project to
address this issue. If this FSP is adopted in its current form, then NU
would be required to record an ARO. Management has not estimated this
potential ARO at December 31, 2003.
Special Purpose Entities: In addition to SPEs that are described in the "Off-
Balance Sheet Arrangements" section of this Management's Discussion and
Analysis, 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 became involved in a bankruptcy proceeding. The funding companies
and the securitization amounts are consolidated in the accompanying
consolidated financial statements.
During 1999, SESI established an SPE, HEC/Tobyhanna Energy Project, LLC
(HEC/Tobyhanna), 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 and Certificates are included in NU's consolidated financial
statements.
For further information regarding the matters in this "Critical Accounting
Policies and Estimates" section 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," and Note 7C, "Commitments and Contingencies -
Environmental Matters," to the consolidated financial statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 7, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding
NU's contractual obligations and commercial commitments at December 31, 2003
is summarized through 2008 and thereafter as follows:
- ------------------------------------------------------------------------------------------------------
(Millions of
Dollars) 2004 2005 2006 2007 2008 Thereafter
- ------------------------------------------------------------------------------------------------------
Notes payable
to banks (a) $ 105.0 $ - $ - $ - $ - $ -
Long-term debt (a) 64.9 92.1 27.8 9.6 161.2 1,941.7
Capital leases (b)(c) 3.1 3.1 2.9 2.6 2.3 20.1
Operating leases (c)(d) 21.9 19.6 17.6 14.2 12.0 27.4
Long-term contractual
arrangements (c)(d) 546.3 528.3 522.4 430.0 301.7 1,759.7
Select Energy
purchase
agreements (c)(d)(e) 4,471.0 761.5 142.9 84.3 84.7 275.4
- ------------------------------------------------------------------------------------------------------
Totals $5,212.2 $1,404.6 $713.6 $540.7 $561.9 $4,024.3
- ------------------------------------------------------------------------------------------------------
(a) Included in NU's debt agreements are usual and customary positive,
negative and financial covenants. Non-compliance with certain covenants, for
example the timely payment of principal and interest, may constitute an event
of default, which could cause an acceleration of principal in the absence of
receipt by the company of a waiver or amendment. Such acceleration would
change the obligations outlined in the table of contractual obligations and
commercial commitments.
(b) The capital lease obligations include imputed interest of $18.2 million.
(c) NU has no provisions in its capital or operating lease agreements or
agreements related to its long-term contractual arrangements or Select Energy
purchase commitments that could trigger a change in terms and conditions,
such as acceleration of payment obligations.
(d) Amounts are not included on NU's consolidated balance sheets.
(e) 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 non-recourse to NU, have no required payments
over the next five years and are not included in this table. The Utility
Group's standard offer service contracts and default service contracts and
NU's expected contribution to the PBOP Plan in 2004 of $41.3 million are also
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 9, "Leases," and Note 7F, "Commitments and Contingencies - 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, regulatory proceedings, 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.
Website: Additional financial information is available through NU's website
at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for
the consolidated statements of income included in this annual report for the
past two years.
<CAPTON>
- ---------------------------------------------------------------------------------------------------
Income Statement Variances 2003 over/(under) 2002 2002 over/(under) 2001
(Millions of Dollars) Amount Percent Amount Percent
- ---------------------------------------------------------------------------------------------------
Operating Revenues $832 16% $(524) (9)%
Operating Expenses:
Fuel, purchased and net interchange power 683 22 (382) (11)
Other operation 148 20 (21) (3)
Maintenance (31) (12) 5 2
Depreciation (1) (1) 5 2
Amortization (130) (42) (572) (65)
Amortization of rate reduction bonds 4 3 50 51
Taxes other than income taxes 5 2 8 4
Gain on sale of utility plant 187 100 455 71
- ---------------------------------------------------------------------------------------------------
Total operating expenses 865 18 (452) (9)
- ---------------------------------------------------------------------------------------------------
Operating Income (33) (7) (72) (13)
- ---------------------------------------------------------------------------------------------------
Interest expense, net (24) (9) (9) (3)
Other (loss)/income, net (44) (a) (144) (77)
- ---------------------------------------------------------------------------------------------------
Income before tax expense (53) (22) (207) (46)
Income tax expense (22) (27) (92) (53)
Preferred dividends of subsidiaries - - (2) (23)
- ---------------------------------------------------------------------------------------------------
Income before cumulative effect of
accounting changes, net of tax benefits (31) (20) (113) (43)
Cumulative effect of accounting changes,
net of tax benefits (5) (100) 22 100
- ---------------------------------------------------------------------------------------------------
Net income $(36) (23)% $ (91) (38)%
===================================================================================================
(a) Percent greater than 100.
OPERATING REVENUES
Total revenues increased $832 million in 2003, compared with 2002, due to
higher revenues from NU Enterprises ($775 million or $588 million after
intercompany eliminations), higher Utility Group electric revenues ($160
million or $165 million after intercompany eliminations) and higher Utility
Group gas revenues ($79 million).
The NU Enterprises' revenue increase is primarily due to higher wholesale and
retail requirements sales volumes ($386 million) and higher prices ($339
million).
The Utility Group revenue increase is primarily due to higher retail electric
revenue ($217 million), partially offset by lower wholesale revenue ($57
million). The regulated retail electric revenue increase is primarily due to
higher CL&P recovery of incremental LMP costs net of amounts to be returned
to customers ($72 million), higher sales volumes ($73 million), an adjustment
to unbilled revenues ($46 million) and a higher average price resulting from
the mix among customer classes for the regulated companies ($25 million).
The higher Yankee Gas revenue is primarily due to higher recovery of gas
costs ($77 million), higher gas sales volumes ($8 million) and price
variances among customer classes ($7 million), partially offset by an
adjustment to unbilled revenues ($13 million). Regulated retail electric kWh
sales increased by 2.1 percent, and firm natural gas sales increased by 7.8
percent in 2003, before the adjustments to unbilled revenues. The regulated
wholesale revenue decrease is primarily due to lower PSNH 2003 sales as a
result of the sale of Seabrook.
Total revenues decreased by $524 million in 2002, compared with 2001,
primarily due to lower competitive energy revenues ($245 million after
intercompany eliminations) and lower regulated subsidiaries revenues due to
lower wholesale and transmission revenues ($143 million after intercompany
eliminations), and lower regulated retail revenues ($136 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) 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 ($23 million), and the
2002 decrease in the WMECO standard offer energy rate ($77 million), lower
Yankee Gas 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.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $683 million in
2003, primarily due to higher wholesale energy purchases at NU Enterprises
($629 million), and higher gas costs ($77 million), partially offset by lower
nuclear fuel ($20 million).
Fuel, purchased and net interchange power expense decreased by $382 million
in 2002, primarily due to lower wholesale sales from the merchant energy
business line ($168 million after intercompany eliminations), lower Yankee
Gas expense primarily due to lower gas prices ($80 million), and lower
purchased-power costs for the regulated subsidiaries ($131 million after
intercompany eliminations).
OTHER OPERATION
Other operation expense increased $148 million in 2003, primarily due to
higher expenses for NU Enterprises resulting from service business growth
($57 million), higher regulated business administrative and general expenses,
primarily due to higher health care costs ($16 million), lower pension income
($31 million), higher reliability must run related transmission expense ($30
million), higher conservation and load management expenditures ($16 million),
higher distribution expense ($6 million), and higher load and dispatch
expenses ($6 million), partially offset by lower nuclear expense due to the
sale of Seabrook ($29 million).
Other operation expense decreased $21 million in 2002, 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 ($26 million), partially offset by higher load and
dispatch expenses ($7 million).
MAINTENANCE
Maintenance expense decreased $31 million in 2003, primarily due to lower
nuclear expense resulting from the sale of Seabrook ($26 million) and lower
competitive expenses associated with the services contracting business ($7
million), partially offset by higher gas distribution expenses ($2 million).
Maintenance expense increased $5 million in 2002, primarily due to higher
competitive companies' expenses associated with the expansion of new services
businesses ($23 million), higher fossil fuel expenses ($7 million) and higher
distribution expenses ($3 million), partially offset by lower nuclear
expenses as a result of the sale of the Millstone units at the end of the
first quarter in 2001 ($29 million).
DEPRECIATION
Depreciation decreased $1 million in 2003 primarily due to lower
decommissioning and depreciation expenses resulting from 2002 depreciation of
Seabrook as compared to no 2003 Seabrook-related depreciation ($7 million)
and lower NU Enterprises depreciation due to a study which resulted in
lengthening the estimated lives of certain generation assets ($3 million),
partially offset by higher Utility Group depreciation resulting from higher
plant balances ($9 million).
Depreciation increased $5 million in 2002, primarily due to higher expense
resulting from higher regulated plant balances ($11 million), partially
offset by the higher Millstone-related decommissioning expenses recorded in
2001 ($8 million).
AMORTIZATION
Amortization decreased $130 million in 2003 primarily due to the 2002
amortization of stranded costs upon the sale of Seabrook ($183 million),
partially offset by higher amortization in 2003 related to the Utility
Group's recovery of stranded costs ($53 million), in part resulting from
higher wholesale revenue from the sale of IPP related energy.
Amortization decreased $572 million in 2002, primarily due to the
amortization in 2001 related to the gain on sale of the Millstone units ($641
million) and Seabrook deferred returns ($39 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).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $4 million in 2003 due to the
repayment of principal.
Amortization of rate reduction bonds increased $50 million in 2002. All
amortization was fully recovered by payments from customers in 2002 and 2003,
and the bonds had no impact on net income.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5 million in 2003, primarily due to
a credit recorded in 2002 recognizing a Connecticut sales and use tax audit
settlement ($8 million), partially offset by a lower 2003 payment to
compensate the Town of Waterford for lost property tax revenue as a result of
the sale of Millstone ($4 million) and lower New Hampshire property taxes due
to the sale of Seabrook ($2 million).
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).
GAIN ON SALE OF UTILITY PLANT
Gain on the sale of utility plant decreased $187 million in 2003 due to the
gain recognized in 2002 resulting from CL&P's and NAEC's sale of Seabrook
($187 million).
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 $24 million in 2003 primarily due to lower
interest for the regulated subsidiaries resulting from lower rates ($12
million), lower interest at NU parent as a result of the interest rate swap
related to its $263 million fixed-rate senior notes ($8 million), capitalized
interest on prepayments for generator interconnections ($4 million) and lower
NAEC interest due to the retirement of debt ($3 million), partially offset by
higher competitive business interest as a result of higher debt levels ($6
million).
Interest expense, net decreased $9 million in 2002, primarily due to NAEC's
reduction of debt.
OTHER (LOSS)/INCOME, NET
Other (loss)/income, net decreased $44 million primarily due to the 2002
elimination of certain reserves associated with NU's ownership share of
Seabrook ($25 million), 2002 Seabrook related gains ($15 million), lower
equity in earnings from the Yankee companies in 2003 ($7 million), a higher
level of donations in 2003 ($5 million), RMS losses recorded in 2003 ($4
million) and lower 2003 conservation and load management incentive income
($2 million), partially offset by 2002 investment write-downs ($18 million).
Other (loss)/income, 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).
INCOME TAX EXPENSE
The consolidated statement of income taxes provides a reconciliation of
actual and expected tax expense. The tax effect of temporary differences is
accounted for in accordance with the rate-making treatment of the applicable
regulatory commissions. In past years, this rate-making treatment has
required the company to provide the customers with a portion of the tax
benefits associated with accelerated tax depreciation in the year it is
generated (flow through depreciation). As these flow through differences
turn around, higher tax expense is recorded.
Income tax expense decreased by $22 million in 2003, primarily due to lower
taxable income.
Income tax expense decreased by $92 million in 2002, primarily due to the
recognition of WMECO ITC 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.
PREFERRED DIVIDENDS OF SUBSIDIARIES
Preferred dividends decreased $2 million or 23 percent in 2002 primarily due
to a lower amount of preferred stock outstanding.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES, NET OF TAX BENEFITS
A cumulative effect of an accounting change, net of tax benefit ($5 million)
was recorded in the third quarter of 2003 in connection with the adoption of
FIN 46, which required NU to consolidate RMS into NU's financial statements and
adjust its equity interest as a cumulative effect of an accounting change.
The cumulative effect of an 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, 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 that 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 obtains information regarding compliance with policies
prohibiting conflicts of interest and policies segregating information
between regulated and unregulated subsidiary companies. The company has
standards of business conduct for all employees, as well as a code of ethics
for senior financial officers.
The Audit Committee of the Board of Trustees is composed entirely of
independent trustees and includes two members that the Board of Trustees
considers "audit committee financial experts." 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 controls over financial
reporting. 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 controls over financial reporting 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 the 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, 2003 and 2002, 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, 2003. 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, such consolidated financial statements present fairly, in all
material respects, the financial position of Northeast Utilities and
subsidiaries (a Massachusetts Trust) as of December 31, 2003 and 2002, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003, 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, and, in 2003, the Company adopted EITF 03-11,
Reporting Realized Gains and Losses on Derivative Instruments that are
Subject to FASB Statement No. 133 and not "Held for Trading Purposes" as
Defined in Issue No. 02-3, and retroactively restated the 2002 and 2001
consolidated financial statements. As discussed in Notes 1E and 5, the
Company adopted Financial Accounting Standards Board Interpretation No. 46,
Consolidation of Variable Interest Entities, effective July 1, 2003, and SFAS
No. 142, Goodwill and Other Intangible Assets, as of January 1, 2002,
respectively.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- -------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 37,196 $ 50,333
Unrestricted cash from counterparties 46,496 16,890
Restricted cash - LMP costs 93,630 -
Special deposits 79,120 30,716
Investments in securitizable assets 166,465 178,908
Receivables, less provision for uncollectible accounts
of $40,846 in 2003 and $15,425 in 2002 704,893 767,089
Unbilled revenues 125,881 126,236
Fuel, materials and supplies, at average cost 154,076 119,853
Derivative assets 301,194 130,929
Prepayments and other 63,780 110,261
------------- -------------
1,772,731 1,531,215
------------- -------------
Property, Plant and Equipment:
Electric utility 5,465,854 5,141,951
Gas utility 743,990 679,055
Competitive energy 885,953 866,294
Other 221,986 205,115
------------- -------------
7,317,783 6,892,415
Less: Accumulated depreciation 2,244,263 2,163,613
------------- -------------
5,073,520 4,728,802
Construction work in progress 356,396 320,567
------------- -------------
5,429,916 5,049,369
------------- -------------
Deferred Debits and Other Assets:
Regulatory assets 2,974,022 3,076,095
Goodwill 319,986 321,004
Purchased intangible assets, net 22,956 24,863
Prepaid pension 360,706 328,890
Other 428,567 433,444
------------- -------------
4,106,237 4,184,296
------------- -------------
Total Assets $ 11,308,884 $ 10,764,880
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
- ------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ 105,000 $ 56,000
Long-term debt - current portion 64,936 56,906
Accounts payable 768,783 776,219
Accrued taxes 51,598 141,667
Accrued interest 41,653 40,597
Derivative liabilities 164,689 63,900
Other 249,576 208,680
--------------- ---------------
1,446,235 1,343,969
--------------- ---------------
Rate Reduction Bonds 1,729,960 1,899,312
--------------- ---------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,287,354 1,436,507
Accumulated deferred investment tax credits 102,652 106,471
Deferred contractual obligations 469,218 354,469
Regulatory liabilities 1,164,288 740,195
Other 247,526 270,092
--------------- ---------------
3,271,038 2,907,734
--------------- ---------------
Capitalization:
Long-Term Debt 2,481,331 2,287,144
--------------- ---------------
Preferred Stock of Subsidiaries - Non-redeemable 116,200 116,200
--------------- ---------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000
shares; 150,398,403 shares issued and 127,695,999
shares outstanding in 2003 and 149,375,847 shares
issued and 127,562,031 shares outstanding in 2002 751,992 746,879
Capital surplus, paid in 1,108,924 1,108,338
Deferred contribution plan - employee stock
ownership plan (73,694) (87,746)
Retained earnings 808,932 765,611
Accumulated other comprehensive income 25,991 14,927
Treasury stock, 19,518,023 shares in 2003
and 18,022,415 in 2002 (358,025) (337,488)
--------------- ---------------
Common Shareholders' Equity 2,264,120 2,210,521
--------------- ---------------
Total Capitalization 4,861,651 4,613,865
--------------- ---------------
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization $ 11,308,884 $ 10,764,880
=============== ===============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Operating Revenues $ 6,069,156 $ 5,237,000 $ 5,760,949
----------------- ----------------- -----------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 3,730,416 3,046,781 3,428,465
Other 900,437 752,482 773,058
Maintenance 232,030 263,487 258,961
Depreciation 204,388 205,646 201,013
Amortization 182,675 312,955 884,624
Amortization of rate reduction bonds 153,172 148,589 98,413
Taxes other than income taxes 232,672 227,518 219,197
Gain on sale of utility plant - (187,113) (641,956)
----------------- ----------------- -----------------
Total operating expenses 5,635,790 4,770,345 5,221,775
----------------- ----------------- -----------------
Operating Income 433,366 466,655 539,174
Interest Expense:
Interest on long-term debt 126,259 134,471 140,497
Interest on rate reduction bonds 108,359 115,791 87,616
Other interest 11,740 20,249 51,545
----------------- ----------------- -----------------
Interest expense, net 246,358 270,511 279,658
----------------- ----------------- -----------------
Other(Loss)/Income, Net (435) 43,828 187,627
----------------- ----------------- -----------------
Income Before Income Tax Expense 186,573 239,972 447,143
Income Tax Expense 59,862 82,304 173,952
----------------- ----------------- -----------------
Income Before Preferred Dividends of Subsidiaries 126,711 157,668 273,191
Preferred Dividends of Subsidiaries 5,559 5,559 7,249
----------------- ----------------- -----------------
Income Before Cumulative Effect of
Accounting Changes, Net of Tax Benefits 121,152 152,109 265,942
Cumulative effect of accounting changes,
net of tax benefits of $2,553 in 2003 and
$14,908 in 2001 (4,741) - (22,432)
----------------- ----------------- -----------------
Net Income $ 116,411 $ 152,109 $ 243,510
================= ================= =================
Basic Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting changes, net of tax benefits $ 0.95 $ 1.18 $ 1.97
Cumulative effect of accounting changes,
net of tax benefits (0.04) - (0.17)
----------------- ----------------- -----------------
Basic Earnings Per Common Share $ 0.91 $ 1.18 $ 1.80
================= ================= =================
Fully Diluted Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting changes, net of tax benefits $ 0.95 $ 1.18 $ 1.96
Cumulative effect of accounting changes,
net of tax benefits (0.04) - (0.17)
----------------- ----------------- -----------------
Fully Diluted Earnings Per Common Share $ 0.91 $ 1.18 $ 1.79
================= ================= =================
Basic Common Shares Outstanding (average) 127,114,743 129,150,549 135,632,126
================= ================= =================
Fully Diluted Common Shares Outstanding (average) 127,240,724 129,341,360 135,917,423
================= ================= =================
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net Income $ 116,411 $ 152,109 $ 243,510
------------- ------------- -------------
Other comprehensive income/(loss), net of tax:
Qualified cash flow hedging instruments 9,274 52,360 (36,859)
Unrealized gains/(losses) on securities 2,093 (5,121) 2,620
Minimum supplemental executive retirement
pension liability adjustments (303) 158 -
------------- ------------- -------------
Other comprehensive income/(loss), net of tax 11,064 47,397 (34,239)
------------- ------------- -------------
Comprehensive Income $ 127,475 $ 199,506 $ 209,271
============= ============= =============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------------------------------------------------
Deferred
Common Shares Capital Contribution Retained
-------------------------- Surplus, Plan- Earnings
Shares Amount Paid In ESOP (a)
- ---------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance as of
January 1, 2001 143,820,405 $743,909 $1,106,580 $(114,463) $495,873
- ---------------------------------------------------------------------------------------------------------------------------
Net income for 2001 243,510
Cash dividends on common
shares - $0.45 per share (60,923)
Issuance of common shares, $5 par value 108,779 544 1,207
Allocation of benefits - ESOP 546,610 (2,296) 12,654
Repurchase of common shares (14,343,658)
Mark-to-market on forward
share purchase arrangement
Capital stock expenses, net 2,118
Other comprehensive loss
- ---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2001 130,132,136 744,453 1,107,609 (101,809) 678,460
- ---------------------------------------------------------------------------------------------------------------------------
Net income for 2002 152,109
Cash dividends on common
shares - $0.525 per share (67,793)
Issuance of common shares, $5 par value 485,207 2,426 5,032
Allocation of benefits - ESOP and
restricted stock 607,475 (4,679) 14,063 2,835
Repurchase of common shares (3,662,787)
Capital stock expenses, net 376
Other comprehensive income
- ---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2002 127,562,031 746,879 1,108,338 (87,746) 765,611
- ---------------------------------------------------------------------------------------------------------------------------
Net income for 2003 116,411
Cash dividends on common
shares - $0.575 per share (73,090)
Issuance of common shares, $5 par value 1,022,556 5,113 8,541
Allocation of benefits - ESOP 607,020 (4,030) 14,052
Issuance of restricted shares, net (c) (4,110)
Repurchase of common shares (1,495,608)
Capital stock expenses, net 185
Other comprehensive income
- ---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2003 127,695,999 $751,992 $1,108,924 $(73,694) $808,932
- ---------------------------------------------------------------------------------------------------------------------------
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------------------------
Accumulated
Other
Comprehensive Treasury
Income/ Stock
(Loss) (b) Total
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance as of
January 1, 2001 $ 1,769 $ (15,085) $2,218,583
- ---------------------------------------------------------------------------------------------------
Net income for 2001 243,510
Cash dividends on common
shares - $0.45 per share (60,923)
Issuance of common shares, $5 par value 1,751
Allocation of benefits - ESOP 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
Other comprehensive loss (34,239) (34,239)
- ---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2001 (32,470) (278,603) 2,117,640
- ---------------------------------------------------------------------------------------------------
Net income for 2002 152,109
Cash dividends on common
shares - $0.525 per share (67,793)
Issuance of common shares, $5 par value 7,458
Allocation of benefits - ESOP and
restricted stock 12,219
Repurchase of common shares (58,885) (58,885)
Capital stock expenses, net 376
Other comprehensive income 47,397 47,397
- ---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2002 14,927 (337,488) 2,210,521
- ---------------------------------------------------------------------------------------------------
Net income for 2003 116,411
Cash dividends on common
shares - $0.575 per share (73,090)
Issuance of common shares, $5 par value 13,654
Allocation of benefits - ESOP 10,022
Issuance of restricted shares, net (c) (4,110)
Repurchase of common shares (20,537) (20,537)
Capital stock expenses, net 185
Other comprehensive income 11,064 11,064
- ---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2003 $25,991 $(358,025) $2,264,120
- ---------------------------------------------------------------------------------------------------
(a) The Federal Power Act, the Public Utility Holding Act of 1935 (the 1935
Act), and certain state statutes limit the payment of dividends by CL&P,
PSNH, WMECO and NAEC to their respective retained earnings balances.
Yankee Gas is also subject to the restrictions under the 1935 Act.
Certain consolidated subsidiaries also have dividend restrictions imposed
by their long-term debt agreements. These restrictions limit the amount of
retained earnings available for NU common dividends. At December 31, 2003,
retained earnings available for payment of dividends totaled $353.3
million.
NGC is subject to certain dividend payment restrictions under its bond
covenants.
The Utility Group credit agreement also limits dividend payments subject
to the requirements that each subsidiaries' total debt to total
capitalization ratio does not exceed 65 percent.
(b) During 2003, 2002 and 2001, NU repurchased 1.5 million, 3.7 million and
14.3 million common shares, respectively. These repurchases are reflected
herein as reductions in the amount of common shares outstanding.
(c) Issuances of restricted stock totaled $6.1 million, and amortization
totaled $2.0 million.
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Income before preferred dividends of subsidiaries $ 126,711 $ 157,668 $ 273,191
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 204,388 205,646 201,013
Deferred income taxes and investment tax credits, net (120,603) (149,325) (116,704)
Amortization 182,675 312,955 884,624
Amortization of rate reduction bonds 153,172 148,589 98,413
Amortization/(deferral) of recoverable energy costs 43,874 27,623 (2,005)
Gain on sale of utility plant - (187,113) (641,956)
Increase in prepaid pension (31,816) (96,492) (92,852)
Cumulative effect of accounting change (4,741) - (22,432)
Regulatory overrecoveries/(refunds) 273,715 27,061 (74,179)
Other sources of cash 20,002 94,664 110,562
Other uses of cash (169,011) (148,027) (127,958)
Changes in current assets and liabilities:
Restricted cash - LMP costs (93,630) - -
Unrestricted cash from counterparties (29,606) 2,757 (19,624)
Receivables and unbilled revenues, net 62,551 (102,181) (301,068)
Fuel, materials and supplies (34,223) (27,590) 55,195
Investments in securitizable assets 12,443 27,459 61,779
Other current assets (excludes cash) (24,863) 6,547 (183,944)
Accounts payable (7,436) 163,541 100,277
Accrued taxes (90,069) 114,296 (27,439)
Other current liabilities 100,039 11,671 127,538
---------- ---------- -----------
Net cash flows provided by operating activities 573,572 589,749 302,431
---------- ---------- -----------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (532,251) (463,498) (422,490)
Competitive energy assets (17,707) (21,010) (14,639)
Nuclear fuel - (465) (14,275)
---------- ---------- -----------
Cash flows used for investments in plant (549,958) (484,973) (451,404)
Investments in nuclear decommissioning trusts - (9,876) (105,076)
Net proceeds from the sale of utility plant - 366,786 1,045,284
Buyout/buydown of IPP contracts (20,437) (5,152) (1,157,172)
Payment for acquisitions, net of cash acquired - (16,351) (31,699)
CVEC acquisition special deposit (30,104) - -
Other investment activities 21,698 15,234 (51,677)
---------- ---------- -----------
Net cash flows used in investing activities (578,801) (134,332) (751,744)
---------- ---------- -----------
Financing Activities:
Issuance of common shares 13,654 7,458 1,751
Repurchase of common shares (20,537) (57,800) (291,789)
Issuance of long-term debt 268,368 310,648 703,000
Issuance of rate reduction bonds - 50,000 2,118,400
Retirement of rate reduction bonds (169,352) (169,039) (100,049)
Increase/(decrease) in short-term debt 49,000 (234,500) (1,019,477)
Reacquisitions and retirements of long-term debt (65,600) (314,773) (714,226)
Reacquisitions and retirements of preferred stock - - (60,768)
Retirement of monthly income preferred securities - - (100,000)
Retirement of capital lease obligation - - (180,000)
Cash dividends on preferred stock of subsidiaries (5,559) (5,559) (7,249)
Cash dividends on common shares (73,090) (67,793) (60,923)
Other financing activities (4,792) (736) 37,660
---------- ---------- -----------
Net cash flows (used in)/provided by financing activities (7,908) (482,094) 326,330
---------- ----------- -----------
Net decrease in cash and cash equivalents (13,137) (26,677) (122,983)
Cash and cash equivalents - beginning of year 50,333 77,010 199,993
---------- ---------- -----------
Cash and cash equivalents - end of year $ 37,196 $ 50,333 $ 77,010
========== ========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
- ----------------------------------------------------------------------------------------------------------
Consolidated Statements of Capitalization
- ----------------------------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2003 2002
- ----------------------------------------------------------------------------------------------------------
Common Shareholders' Equity $2,264,120 $2,210,521
- ----------------------------------------------------------------------------------------------------------
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption -
$50 par value - authorized 9,000,000 shares in 2003 and 2002;
2,324,000 shares outstanding in 2003 and 2002;
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% 89,000 116,000
2009-2012 6.20% to 7.19% 80,000 80,000
2019-2024 7.88% to 10.07% 254,045 254,995
2026 8.81% 320,000 320,000
- ----------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 743,045 770,995
- ----------------------------------------------------------------------------------------------------------
Other Long-Term Debt: (b)
Pollution Control Notes:
2016-2018 5.90% 25,400 25,400
2021-2022 Adjustable Rate and 5.45% to 6.00% 428,285 428,285
2028 5.85% to 5.95% 369,300 369,300
2031 3.35% until 2008 (c) 62,000 62,000
Other: (d)
2003 6.24% - 1,400
2004-2007 6.11% to 8.81% 76,249 101,543
2008 3.30% 150,000 -
2010 5.95% to 8.23% 8,955 6,753
2012-2014 5.00% to 9.24% 320,627 263,876
2018-2019 6.00% to 6.23% 38,476 24,297
2021-2022 6.25% to 7.63% 39,461 40,712
2024 6.23% 9,368 -
2026 7.69% 26,164 -
- ----------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other 1,554,285 1,323,566
- ----------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds, Pollution Control Notes and Other 2,297,330 2,094,561
- ----------------------------------------------------------------------------------------------------------
Fees and interest due for spent nuclear fuel disposal costs (e) 256,438 253,638
Change in Fair Value (f) (3,577) -
Unamortized premium and discount, net (3,924) (4,149)
- ----------------------------------------------------------------------------------------------------------
Total Long-Term Debt 2,546,267 2,344,050
Less: Amounts due within one year 64,936 56,906
- ----------------------------------------------------------------------------------------------------------
Long-Term Debt, Net 2,481,331 2,287,144
- ----------------------------------------------------------------------------------------------------------
Total Capitalization $4,861,651 $4,613,865
- ----------------------------------------------------------------------------------------------------------
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, 2003, for the years 2004 through 2008 and
thereafter, are as follows:
--------------------------------------------
(Millions of Dollars)
--------------------------------------------
Year
--------------------------------------------
2004 $ 64.9
2005 92.1
2006 27.8
2007 9.6
2008 161.2
Thereafter 1,941.7
--------------------------------------------
Total $2,297.3
--------------------------------------------
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 its first
mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds
(PCRBs) with bond insurance and secured by the first mortgage bonds. For
financial reporting purposes, this debt is not considered to be first
mortgage bonds 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, 2003 and 2002, $407.3 million of the PCRBs were outstanding.
PSNH's obligation to repay each series of PCRBs is secured by bond
insurance and 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.
NU's long-term debt agreements provide that certain of its subsidiaries
must comply with certain financial and non-financial covenants as are
customarily included in such agreements, including but not limited to,
debt service coverage ratios and interest coverage ratios. The parties
to these agreements currently are and expect to remain in compliance with
these covenants.
(b) The weighted average effective interest rate on the variable-rate
pollution control notes ranged from 0.99 percent to 1.08 percent for 2003
and 1.39 percent to 1.42 percent for 2002.
(c) The interest rate of 3.35 percent is effective through October 1, 2008 at
which time the bonds will be remarketed, and the interest rate will be
adjusted.
(d) Other long-term debt - other at December 31, 2003, includes the issuance
of $150 million, $63.4 million and $55 million of long-term debt related to
NU parent, SESI and WMECO in 2003.
(e) For information regarding fees and interest due for spent nuclear fuel
disposal costs, see Note 7D, "Commitments and Contingencies - Spent
Nuclear Fuel Disposal Costs," to the consolidated financial statements.
(f) The fair value of the NU parent 7.25 percent amortizing note due 2012 in
the amount of $263 million is hedged with a fixed to floating interest
rate swap. The change in fair value of the debt was recorded as an
adjustment to long-term debt with an equal and offsetting adjustment to
derivative assets for the change in fair value of the fixed to floating
interest rate swap.
- ---------------------------------------------------------------------------------------------------
Consolidated Statements of Income Taxes
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------------------------------------
The components of the federal and
state income tax provisions are:
Current income taxes:
Federal $ 143,349 $ 197,426 $ 244,501
State 37,116 34,204 46,155
- ---------------------------------------------------------------------------------------------------
Total current 180,465 231,630 290,656
- ---------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (82,518) (108,524) (80,968)
State (34,266) (14,210) (15,644)
- ---------------------------------------------------------------------------------------------------
Total deferred (116,784) (122,734) (96,612)
- ---------------------------------------------------------------------------------------------------
Investment tax credits, net (3,819) (26,592) (20,092)
- ---------------------------------------------------------------------------------------------------
Total income tax expense $ 59,862 $ 82,304 $ 173,952
- ---------------------------------------------------------------------------------------------------
Deferred income taxes are comprised of the tax effects of
temporary differences as follows:
Deferred tax asset associated with net operating losses $ - $ - $ 2,206
Depreciation 55,002 51,146 (8,956)
Net regulatory deferral (149,087) (141,567) (44,127)
Sale of generation assets - (20,500) (225,019)
Pension (3,467) (1,720) 24,183
Loss on bond redemptions (3,487) (1,084) 12,396
Contract termination costs, net of amortization (9,121) (9,500) 113,719
Change in fair value of energy contracts (12,310) 20,691 15,780
Other 5,686 (20,200) 13,206
- ---------------------------------------------------------------------------------------------------
Deferred income taxes, net $(116,784) $(122,734) $ (96,612)
- ---------------------------------------------------------------------------------------------------
A reconciliation between income tax expense and the expected
tax expense at the statutory rate is as follows:
Expected federal income tax $ 65,301 $ 83,990 $ 156,500
Tax effect of differences:
Depreciation 4,010 10,404 5,313
Amortization of regulatory assets 6,487 14,966 10,260
Investment tax credit amortization (3,819) (26,592) (20,092)
State income taxes, net of federal benefit 1,853 12,996 19,832
Dividends received deduction (1,370) (3,237) (3,382)
Tax asset valuation allowance/reserve adjustments (5,379) (111) (7,000)
Merger-related expenditures - - (4,589)
Nondeductible stock expenses - - 12,388
Other, net (7,221) (10,112) 4,722
- ---------------------------------------------------------------------------------------------------
Total income tax expense $ 59,862 $ 82,304 $ 173,952
- ---------------------------------------------------------------------------------------------------
NU and its subsidiaries file a consolidated federal income tax return.
Likewise NU and its subsidiaries file state income tax returns, with some
filing in more than one state. NU and its subsidiaries are parties to a tax
allocation agreement under which each taxable subsidiary pays a quarterly
estimate (or settlement) of no more than it would have otherwise paid had it
filed a stand-alone tax return. Generally these quarterly estimated payments
are settled to actual payments within three months after filing the
associated return. Subsidiaries generating tax losses are similarly paid for
their losses when utilized.
The accompanying notes are also an integral part of these consolidated
financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- -------------------------------------------------------------------------------
A. ABOUT NORTHEAST UTILITIES
Consolidated: Northeast Utilities (NU or the company) is the parent company
of companies comprising the Utility Group and NU Enterprises. 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 the Utility
Group, NU Enterprises and other NU 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 Utility Group is subject to
further regulation for rates, accounting and other matters by the FERC and/or
applicable state regulatory commissions.
Several wholly owned subsidiaries of NU provide support services for NU's
companies. Northeast Utilities Service Company provides centralized
accounting, administrative, engineering, financial, information technology,
legal, operational, planning, purchasing, and other services to NU's
companies. Three other subsidiaries construct, acquire or lease some of the
property and facilities used by NU's companies.
Utility Group: The Utility Group furnishes franchised retail electric
service in Connecticut, New Hampshire and Massachusetts through three
companies: The Connecticut Light and Power Company (CL&P), Public Service
Company of New Hampshire (PSNH) and Western Massachusetts Electric Company
(WMECO). Another company, North Atlantic Energy Corporation (NAEC),
previously sold all of its entitlement to the capacity and output of the
Seabrook 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. Another Utility Group subsidiary is Yankee Gas Services
Company (Yankee Gas), which is Connecticut's largest natural gas distribution
system. The Utility Group includes two reportable segments: the regulated
electric utility segment and the regulated gas utility segment.
Effective January 1, 2004, PSNH completed the purchase of the electric system
and retail franchise of Connecticut Valley Electric Company (CVEC), a
subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1
million. CVEC's 11,000 customers in western New Hampshire have been added to
PSNH's customer base of more than 460,000 customers. The purchase price
included the book value of CVEC's plant assets of approximately $9 million
and an additional $21 million to terminate an above-market wholesale power
purchase agreement CVEC had with CVPS. The $21 million payment will be
recovered from PSNH's customers.
NU Enterprises: These companies include Select Energy, Inc. and subsidiary
(Select Energy), a company engaged in wholesale and retail marketing
activities; Northeast Generation Company (NGC) and Holyoke Water Power
Company (HWP), companies that maintain 1,293 megawatts (MW) and 147 MW,
respectively, of generation capacity that is used to support Select Energy's
merchant energy business line; Select Energy Services, Inc. and subsidiaries
(SESI), a company that performs energy management services for large
commercial customers, institutional facilities, and the United States
government and engages in energy-related construction services; Northeast
Generation Services Company and subsidiaries (NGS), a company that operates
and maintains NGC's and HWP's generation assets and provides third-party
electrical services; and Woods Network Services, Inc. (Woods Network), a
network design, products and service company. NU Enterprises is one
reportable segment that includes two business lines: the merchant energy
business line and the energy services business line.
B. PRESENTATION
The consolidated financial statements of NU and of its subsidiaries, as
applicable, include the accounts of all their respective 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 contingencies 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. Reclassifications were made to cost of
removal, regulatory asset and liability amounts and special deposits on the
accompanying consolidated balance sheets and operating revenues and fuel,
purchased and net interchange power on the accompanying consolidated
statements of income. Reclassifications have also been made to the
accompanying consolidated statements of cash flows and consolidated
statements of income taxes.
C. NEW ACCOUNTING STANDARDS
Derivative Accounting: Effective January 1, 2001, NU adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended resulting in a negative
cumulative effect of accounting change of $22.4 million. In April 2003, the
Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment
of Statement 133 on Derivative Instruments and Hedging Activities," which
amends SFAS No. 133. This new statement incorporates interpretations that
were included in previous Derivative Implementation Group (DIG) guidance,
clarifies certain conditions, and amends other existing pronouncements. It
is effective for contracts entered into or modified after June 30, 2003.
Management has determined that the adoption of SFAS No. 149 did not change
NU's accounting for wholesale and retail marketing contracts, or the ability
of NU Enterprises to elect the normal purchases and sales exception. The
adoption of SFAS No. 149 resulted in fair value accounting for certain of
Utility Group contracts that are subject to unplanned netting and do not meet
the definition of capacity contracts. These non-trading derivative contracts
are recorded at fair value at December 31, 2003, as derivative assets and
liabilities with offsetting amounts recorded as regulatory liabilities and
assets because the contracts are part of providing regulated electric or gas
service.
In August of 2003, the FASB ratified the consensus reached by its Emerging
Issues Task Force (EITF) in July 2003 on EITF Issue No. 03-11, "Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133 and Not `Held for Trading Purposes' as Defined in Issue No.
02-3." Prior to Issue No. 03-11, no specific guidance existed to address the
classification in the income statement of derivative contracts that are not
held for trading purposes. The consensus states that determining whether
realized gains and losses on contracts that physically deliver and are not
held for trading purposes should be reported on a net or gross basis is a
matter of judgment that depends on the relevant facts and circumstances. NU
Enterprises and the Utility Group have derivative sales contracts, and though
these contracts may result in physical delivery, management has determined,
based on the relevant facts and circumstances, that because these
transactions are part of the respective companies' procurement activities,
inclusion in operating expenses better depicts these sales activities. At
December 31, 2003, settlements of these derivative contracts that are not
held for trading purposes, though previously reported on a gross basis, are
reported on a net basis in expenses. Sales amounting to $645.9 million for
the first nine months of 2003 were reflected as revenues in quarterly
reporting but are now included in expenses.
In Issue No. 03-11, the EITF did not provide transition guidance, which
management could have interpreted as becoming applicable on October 1, 2003
for revenues from that date forward. However, management applied its
conclusion on net or gross reporting to all periods presented to enhance
comparability. Operating revenues and fuel, purchased and net interchange
power for the year ended December 31, 2003 reflect net reporting. The
adoption of net reporting had no effect on net income.
The impact on previously reported 2002 and 2001 amounts is as follows:
- -------------------------------------------------------------------------------
For the Years Ended December 31,
- -------------------------------------------------------------------------------
Millions of Dollars 2002 2001
- -------------------------------------------------------------------------------
Operating Revenues:
As previously reported $5,216.3 $5,968.2
Impact of reclassifications 20.7 (207.2)
- -------------------------------------------------------------------------------
As currently reported $5,237.0 $5,761.0
- -------------------------------------------------------------------------------
Fuel, Purchased and Net
Interchange Power:
As previously reported $3,026.1 $3,635.7
Impact of reclassifications 20.7 (207.2)
- -------------------------------------------------------------------------------
As currently reported $3,046.8 $3,428.5
- -------------------------------------------------------------------------------
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning
of "not clearly and closely related regarding contracts with a price
adjustment feature" as it relates to the election of the normal purchase and
sales exception to derivative accounting. The implementation of this
guidance was required to be adopted in the fourth quarter of 2003 for NU.
Issue No. C-20 resulted in CL&P recording the fair value of two existing
power purchase contracts as derivatives, one as a derivative asset and one
as a derivative liability with offsetting regulatory liabilities and assets,
as these contracts are part of stranded costs and as management believes that
these costs will continue to be recovered or refunded in rates. The fair
values of these long-term power purchase contracts include a derivative asset
with a fair value of $112.4 million and a derivative liability with a fair
value of $54.6 million at December 31, 2003.
Employers' Disclosures about Pensions and Other Postretirement Benefits: In
December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," (SFAS No.
132R). This statement revises employers' disclosures about pension plans and
other postretirement benefit plans, requires additional disclosures about the
assets, obligations, cash flows, and the net periodic benefit cost of defined
benefit pension plans and other defined benefit postretirement plans and
requires companies to disclose various elements of pension and postretirement
benefit costs in interim period financial statements. The revisions in SFAS
No. 132R are effective for 2003, and NU included the disclosures required by
SFAS No. 132R in this annual report. For the required disclosures, see Note
4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other
Than Pensions," to the consolidated financial statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity." SFAS No. 150 establishes standards on how to
classify and measure certain financial instruments with characteristics of
both liabilities and equity. SFAS No. 150 is effective for financial
instruments entered into or modified after May 31, 2003, and was otherwise
effective for NU for the third quarter of 2003. The adoption of SFAS No. 150
did not have an impact on NU's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB
issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation
of Variable Interest Entities," (FIN 46R). FIN 46R could result in fewer NU
investments meeting the definition of a variable interest entity (VIE). FIN
46R is effective for NU for the first quarter of 2004 but is not expected to
have an impact on NU's consolidated financial statements.
D. GUARANTEES
NU provides credit assurance in the form of guarantees and letters of credit
in the normal course of business, primarily for the financial performance
obligations of NU Enterprises. NU would be required to perform under these
guarantees in the event of non-performance by NU Enterprises, primarily
Select Energy. At December 31, 2003, the maximum level of exposure under
guarantees by NU, primarily on behalf of NU Enterprises, totaled $552.6
million. Additionally, NU had $106.9 million of letters of credit issued for
the benefit of NU Enterprises outstanding at December 31, 2003. In
conjunction with its investment in R. M. Services, Inc. (RMS), NU guarantees
a $3 million line of credit through 2005, of which $1.3 million was
outstanding at December 31, 2003, which is included in the $552.6 million of
total guarantees outstanding. Effective July 1, 2003, NU now consolidates
the financial statements of RMS and the line of credit balance with its
financial statements.
CL&P has obtained surety bonds in the amount of $31.1 million related to the
collection of March 2003 and April 2003 incremental locational marginal
pricing (LMP) costs in compliance with a Connecticut Department of Public
Utility Control (DPUC) order. At December 31, 2003, NU had outstanding
guarantees to the Utility Group of $48 million, including the LMP-related
surety bonds. This amount is included in the total outstanding NU guarantee
amount of $552.6 million.
The NU guarantees and surety bonds contain credit ratings triggers that would
require NU to post collateral in the event that NU's credit ratings are
downgraded.
NU currently has authorization from the SEC to provide up to $500 million of
guarantees for NU Enterprises through June 30, 2004, and has applied for
authority to increase this amount to $750 million through September 30, 2007.
The guarantees to the Utility Group are subject to a separate $50 million SEC
limitation apart from the current $500 million guarantee limit. The amount
of guarantees outstanding for compliance with the SEC limit for NU
Enterprises is $288.5 million, which is calculated using different criteria
than the maximum level of exposure required to be disclosed under FIN 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others."
E. ACCOUNTING FOR R.M. SERVICES, INC. VARIABLE INTEREST ENTITY
On June 30, 2001, NU sold RMS, a provider of consumer collection services,
for $10 million in the form of convertible cumulative 5 percent preferred
stock and a warrant to buy 25 percent of the outstanding common stock of RMS
for $1,000 that expires in 2021. NU also agreed to guarantee a $3 million
line of credit for RMS through 2005. Beginning in the second quarter of 2003,
RMS began drawing on this line of credit.
In January 2003, the FASB issued FIN 46, which was effective for NU on
July 1, 2003. RMS is a VIE, as defined. FIN 46 requires that the party to a
VIE that absorbs the majority of the VIE's losses, defined as the "primary
beneficiary," consolidate the VIE. Upon adoption of FIN 46 on July 1, 2003,
management determined that NU was the "primary beneficiary" of RMS under FIN
46 and that NU was now required to consolidate RMS into its financial
statements. To consolidate RMS, NU eliminated the carrying value of its
preferred stock investment in RMS and recorded the assets and liabilities of
RMS. This adjustment resulted in a negative $4.7 million after-tax
cumulative effect of an accounting change in the third quarter of 2003, and
is summarized as follows (in millions):
- -----------------------------------------------------------
Assets and Liabilities Recorded:
- -----------------------------------------------------------
Current assets $ 0.6
Net property, plant and equipment 1.7
Other noncurrent assets 1.5
Current liabilities (0.6)
- -----------------------------------------------------------
3.2
- -----------------------------------------------------------
Elimination of investment at July 1, 2003 10.5
- -----------------------------------------------------------
Pre-tax cumulative effect 7.3
Income tax effect (2.6)
- -----------------------------------------------------------
Cumulative effect of an accounting change $ 4.7
- -----------------------------------------------------------
Prior to the consolidation of RMS on July 1, 2003, NU recorded $0.9 million
of after-tax impairment losses on the investment balance. After RMS was
consolidated, $1.9 million of after-tax operating losses were included in
earnings.
NU has no other VIE's for which it is defined as the "primary beneficiary."
For further information regarding NU's investments in other VIEs, see Note
1K, "Summary of Significant Accounting Policies - Equity Investments and
Jointly Owned Electric Utility Plant," to the consolidated financial
statements.
F. REVENUES
Utility Group: Utility Group retail revenues are based on rates approved by
the state regulatory commissions. These regulated rates are applied to
customers' use of energy to calculate a bill. In general, rates can only be
changed through formal proceedings with the state regulatory commissions.
Certain Utility Group companies utilize regulatory commission-approved
tracking mechanisms to track the recovery of certain incurred costs. The
tracking mechanisms allow for rates to be changed periodically, with
overcollections refunded to customers or undercollections collected from
customers in future periods.
Unbilled revenues represent an estimate of electricity or gas delivered to
customers that has not been billed. Unbilled revenues represent assets on
the balance sheet that become accounts receivable in the following month as
customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The
requirements method utilizes the total monthly volume of electricity or gas
delivered to the system and applies a delivery efficiency factor to reduce
the total monthly volume by an estimate of delivery losses in order to
calculate total estimated monthly sales to customers. The total estimated
monthly sales amount less total monthly billed sales amount results in a
monthly estimate of unbilled sales. Unbilled revenues are estimated by
applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for all Utility Group companies were
tested using the cycle method. The cycle method uses the billed sales from
each meter reading cycle and an estimate of unbilled days in each month based
on the meter reading schedule. The cycle method is historically more
accurate than the requirements method when used in a mostly weather-neutral
month. The cycle method resulted in adjustments to the estimate of unbilled
revenues that had a net positive after-tax earnings impact of approximately
$4.6 million in 2003. The positive after-tax impacts on CL&P, PSNH, and
WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There
was a negative after-tax impact on Yankee Gas of $6.2 million including
certain gas cost adjustments.
Wholesale transmission revenues are based on rates and formulas that are
approved by the FERC. Most of NU's wholesale transmission revenues are
collected through a combination of the New England Regional Network Service
(RNS) tariff and NU's Local Network Service (LNS) tariff. The RNS tariff,
which is administered by the New England Independent System Operator (ISO-
NE), recovers the revenue requirements associated with transmission
facilities that are deemed by the FERC to be Pool Transmission Facilities.
The LNS tariff which was accepted by the FERC on October 22, 2003, provides
for the recovery of NU's total transmission revenue requirements, net of
revenue credits received from various rate components, including revenues
received under the RNS rates.
NU Enterprises: NU Enterprises' revenues are recognized at different times
for its different business lines. 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. ACCOUNTING FOR ENERGY CONTRACTS
The accounting treatment for energy contracts entered into varies between
contracts and depends on the intended use of the particular contract and on
whether or not the contracts are derivatives.
Non-derivative 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 and amended by SFAS No. 149 (normal),
are also recorded at the point of delivery under accrual accounting.
Both long-term non-derivative contracts and long-term derivative contracts
that are normal are recorded in revenues when these contracts represent
sales, and recorded in fuel, purchased and net interchange power when these
contracts represent purchases, except for sales contracts that relate to
procurement activities. These contracts are recorded in fuel, purchased and
net interchange power when settled.
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 in revenues. Derivative contracts that are not held for trading
purposes and that do not qualify as normal purchases and sales or hedges are
non-trading derivative contracts. These contracts 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 net in
revenues.
Contracts that are hedging an underlying transaction and that qualify as cash
flow hedges are recorded on the consolidated balance sheets at fair value
with changes in fair value generally reflected in accumulated 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 these contracts and their accounting, see
Note 3, "Derivative Instruments, Market Risk and Risk Management," to the
consolidated financial statements.
H. UTILITY GROUP REGULATORY ACCOUNTING
The accounting policies of NU's Utility Group 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, "Accounting for the Effects of
Certain Types of Regulation."
The transmission and distribution businesses of CL&P, PSNH and WMECO, along
with PSNH's generation business and Yankee Gas' distribution business,
continue to be cost-of-service rate regulated. The state's electric utility
industry restructuring laws have been modified to delay the sale of PSNH's
fossil and hydroelectric generation assets until at least April of 2006.
There has been no regulatory action to the contrary, and management currently
has no plans to divest these generation assets. As the New Hampshire Public
Utilities Commission (NHPUC) has allowed and is expected to continue to allow
rate recovery of a return on and recovery of these assets, as well as all
operating expenses, PSNH meets the criteria for the application of SFAS No.
71. Stranded costs related to 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.
Management believes the application of SFAS No. 71 to the portions of the
aforementioned 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 net regulatory assets are earning an equity return, except for
securitized regulatory assets, which are not supported by equity.
The components of regulatory assets are as follows:
- --------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
- --------------------------------------------------------------------------
Recoverable nuclear costs $ 82.4 $ 85.4
Securitized assets 1,721.1 1,891.8
Income taxes, net 253.8 326.4
Unrecovered contractual obligations 378.6 239.3
Recoverable energy costs 255.7 299.6
Other 282.4 233.6
- --------------------------------------------------------------------------
Totals $2,974.0 $3,076.1
- --------------------------------------------------------------------------
Additionally, the Utility Group had $12.3 million and $6.1 million of
regulatory assets at December 31, 2003 and 2002, respectively, that are
included in deferred debits and other assets - other on the accompanying
consolidated balance sheets. These amounts represent regulatory assets that
have not yet been approved by the applicable regulatory agency. Management
believes these assets are recoverable in future rates.
Recoverable Nuclear Costs: In March 2001, CL&P and WMECO sold their
ownership interests in the Millstone nuclear units (Millstone). The gains on
the sale in the amounts of $521.6 million and $119.8 million, respectively,
for CL&P and WMECO were used to offset recoverable nuclear costs, resulting
in unamortized balances of $22.5 million and $13.1 million at December 31,
2003 and 2002, respectively. Additionally, PSNH recorded a regulatory asset
in conjunction with the sale of the Millstone units with an unamortized
balance of $33.3 million and $36.8 million at December 31, 2003 and 2002,
respectively, which is also included in recoverable nuclear costs. Also
included in recoverable nuclear costs for 2003 and 2002 are $26.6 million
and $35.5 million, respectively, primarily related to Millstone 1 recoverable
nuclear costs associated with the undepreciated plant and related assets at
the time Millstone 1 was shut down.
Securitized Assets: In March 2001, CL&P issued $1.4 billion in rate
reduction certificates. CL&P used $1.1 billion of those proceeds to buy out
or buy down certain contracts with independent power producers (IPP). The
remaining balance is $960 million and $1.1 billion at December 31, 2003 and
2002, respectively. CL&P also securitized a portion of its SFAS No. 109,
"Accounting for Income Taxes," regulatory asset which had a balance of $164.1
million and $180.7 million at December 31, 2003 and 2002, respectively.
In April 2001, PSNH issued rate reduction certificates in the amount of $525
million. PSNH used the majority of this amount to buy down its power contract
with NAEC. The remaining balance is $427 million and $460 million at
December 31, 2003 and 2002, respectively.
In May 2001, WMECO issued $155 million in rate reduction certificates and
used $80 million of those proceeds to buy out an IPP contract. The remaining
balance is $132 million and $142 million at December 31, 2003 and 2002,
respectively.
In January 2002, PSNH issued an additional $50 million in rate reduction
certificates and used the proceeds from this issuance to repay short-term
debt that was incurred to buy out a purchased-power contract in December 2001.
The remaining balance is $38 million and $46 million at December 31, 2003 and
2002, respectively.
Securitized assets are being recovered over the amortization period of their
associated rate reduction bonds. All outstanding rate reduction bonds of
CL&P are scheduled to amortize by December 30, 2010, while PSNH rate
reduction bonds are scheduled to fully amortize by May 1, 2013, and those of
WMECO are scheduled to fully amortize by June 1, 2013.
Income Taxes, Net: 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. Differences in income
taxes between SFAS No. 109 and the rate-making treatment of the applicable
regulatory commissions are recorded as regulatory assets. For further
information regarding income taxes, see Note 1I, "Summary of Significant
Accounting Policies - Income Taxes," to the consolidated financial
statements.
Unrecovered Contractual Obligations: 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. The
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 by approximately $380 million 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.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC)
prepared an updated estimate of the cost of decommissioning its nuclear unit.
NU's aggregate share of the estimated increased cost is approximately $167.7
million. NU subsidiaries' respective shares of the estimated increased costs
are as follows: CL&P, $118.1 million; PSNH, $17.1 million; and WMECO, $32.5
million. NU recorded an additional $167.7 million in deferred contractual
obligations and a corresponding increase in the unrecovered contractual
obligations regulatory asset as a result of these increased costs.
Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act),
CL&P, PSNH, WMECO, and NAEC 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). 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 no longer own nuclear generation but
continue to recover these costs through rates. At December 31, 2003 and
2002, NU's total D&D Assessment deferrals were $18 million and $21.9 million,
respectively, and have been recorded as recoverable energy 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, 2003 and 2002,
PSNH had $162.2 million and $179.6 million, respectively, of recoverable
energy costs deferred under the FPPAC, including previous deferrals of
purchases from IPPs. 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 IPPs that had previously
been included in the FPPAC. These costs are treated as Part 3 stranded costs
and amounted to $56.1 million and $62.1 million at December 31, 2003 and
2002, 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 or refunded in
future periods. These amounts are recorded as recoverable energy costs of
$2.9 million and $3.3 million at December 31, 2003 and 2002, respectively.
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 at December 31, 2002,
which were recorded as recoverable energy costs. On July 26, 2001, the DPUC
authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour
(kWh) to collect these costs from August 2001 through December 31, 2003, at
which time no unrecovered costs remained.
The majority of the recoverable energy costs are recovered in rates currently
from the customers of CL&P, PSNH, WMECO, and Yankee Gas. PSNH's recoverable
energy costs are Part 3 stranded costs which are nonsecuritized regulatory
assets which must be recovered by a recovery end date to be determined in
accordance with the Restructuring Settlement or which will be written off.
Based on current projections, PSNH expects to fully recover all of its Part 3
stranded costs by the recovery end date.
Regulatory Liabilities: The Utility Group maintained $1.2 billion and $740.2
million of regulatory liabilities at December 31, 2003 and 2002,
respectively. These amounts are comprised of the following:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
- ---------------------------------------------------------------------
Cost of removal $334.0 $321.0
CL&P CTA, GSC, and SBC overcollections 333.7 133.6
PSNH SCRC overcollections 160.4 166.2
Regulatory liabilities offsetting
Utility Group derivative assets 117.0 -
CL&P LMP overcollections 79.8 -
Yankee Gas IERM overcollections 5.3 2.9
Other regulatory liabilities 134.1 116.5
- ---------------------------------------------------------------------
Totals $1,164.3 $740.2
- ---------------------------------------------------------------------
Under SFAS No. 71, regulated utilities, including NU's Utility Group
companies, currently recover amounts in rates for future costs of removal of
plant assets. Historically, these amounts were included as a component of
accumulated depreciation until spent. These amounts were reclassified to
regulatory liabilities on the accompanying consolidated balance sheets.
The Competitive Transition Assessment (CTA) allows CL&P to recover stranded
costs, such as securitization costs associated with the rate reduction bonds,
amortization of regulatory assets, and IPP over market costs while the
Generation Service Charge (GSC) allows CL&P to recover the costs of the
procurement of energy for standard offer service. The System Benefits Charge
(SBC) allows CL&P to recover certain regulatory and energy public policy
costs, such as public education outreach costs, hardship protection costs,
transition period property taxes, and displaced workers protection costs.
The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded
costs. CL&P LMP overcollections represent amounts that are refundable to
ratepayers related to the implementation of standard market design (SMD) on
March 1, 2003. Yankee Gas' Infrastructure Expansion Rate Mechanism (IERM)
tracks the revenues and expenses associated with its system expansion
program.
The regulatory liabilities offsetting derivative assets relate to the fair
value of CL&P IPP contracts and PSNH purchase and sales contracts used for
market discovery of future procurement activities that will benefit
ratepayers in the future. CL&P and PSNH also have financial transmission
rights (FTR) contracts which are derivative assets offset by a regulatory
liability.
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods
in which they affect the determination of taxable income) is accounted for in
accordance with the rate-making treatment of the applicable regulatory
commissions and SFAS No. 109.
The tax effects of temporary differences that give rise to the net
accumulated deferred tax obligation are as follows:
- -----------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------
(Millions of Dollars) 2003 2002
- -----------------------------------------------------------------
Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $ 904.4 $ 893.0
Regulatory amounts:
Securitized contract termination
costs and other 247.0 267.5
Income tax gross-up 178.6 220.2
Employee benefits 151.4 142.8
Other 332.2 306.6
- ----------------------------------------------------------------
Total deferred tax liabilities 1,813.6 1,830.1
- ----------------------------------------------------------------
Deferred tax assets:
Regulatory deferrals 341.6 238.3
Employee benefits 72.1 64.3
Income tax gross-up 20.8 25.6
Other 91.7 65.4
- ----------------------------------------------------------------
Total deferred tax assets 526.2 393.6
- ----------------------------------------------------------------
Totals $1,287.4 $1,436.5
- ----------------------------------------------------------------
In 2000, NU requested from the Internal Revenue Service (IRS) a Private
Letter Ruling (PLR) regarding the treatment of unamortized investment tax
credits (ITC) and excess deferred income taxes (EDIT) related to generation
assets that have been sold. EDIT are temporary differences between book and
taxable income that were recorded when the federal statutory tax rate was
higher than it is now or when those differences were expected to be resolved.
The PLR addresses whether or not EDIT and ITC can be returned to customers,
which without a PLR management believes would represent a violation of
current tax law. The IRS declared a moratorium on issuing PLRs until final
regulations on the return of EDIT and ITC to regulated customers are issued
by the Treasury Department. Proposed regulations were issued in March 2003,
and a hearing took place in June 2003. The proposed new regulations would
allow the return of EDIT and ITC to regulated customers without violating the
tax law. Also, under the proposed regulations, a company could elect to
apply the regulation retroactively. The Treasury Department is currently
deliberating the comments received at the hearing. If final regulations
consistent with the proposed regulations are issued, then there could be an
impact on NU's financial statements.
J. DEPRECIATION
The provision for depreciation on utility assets is calculated using the
straight-line method based on the estimated remaining useful lives of
depreciable 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 it is 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. Cost of
removal is now classified as a regulatory liability. The depreciation rates
for the several classes of electric utility plant-in-service are equivalent
to a composite rate of 3.4 percent in 2003, 3.2 percent in 2002 and 3.1
percent in 2001.
NU also maintains other non-utility plant which is being depreciated using
the straight-line method based on estimated remaining useful lives, which
range primarily from 15 years to 120 years.
In 2002, NU Enterprises 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 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
Enterprises' operating expenses decreased by $8.6 million in 2003 and $5.1
million in 2002 as compared to 2001.
K. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Companies: At December 31, 2003, CL&P, PSNH and WMECO own
common stock in three regional nuclear companies (Yankee Companies). NU's
ownership interests in the Yankee Companies at December 31, 2003, which are
accounted for on the equity method are 49 percent of the CYAPC, 38.5 percent
of the Yankee Atomic Electric Company (YAEC) and 20 percent of the Maine
Yankee Atomic Power Company (MYAPC). Effective November 7, 2003, CL&P, PSNH
and WMECO sold their collective 17 percent ownership interest in Vermont
Yankee Nuclear Power Corporation (VYNPC). NU's total equity investment in
the Yankee Companies at December 31, 2003 and 2002, is $32.2 million and
$48.9 million, respectively. Each of the remaining Yankee Companies owns a
single nuclear generating plant which is being decommissioned.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest in two
companies that transmit electricity imported from the Hydro-Quebec system in
Canada. NU's investment and exposure to loss is $10.1 million and $12
million at December 31, 2003 and 2002, respectively.
Other Investments: At December 31, 2003 and 2002, NU maintains certain cost
method and other investments. The cost method investments are comprised of
NEON Communications, Inc. (NEON), a provider of high-bandwidth fiber optic
telecommunications services and 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 automobile industry. These cost method
investments have a combined total carrying value of $17.4 million and $12.5
million at December 31, 2003 and 2002, respectively.
Other investments also include a long-term note receivable from BMC Energy
LLC, (BMC), an operator of renewable energy projects. NU's remaining note
receivable from BMC totaled $4 million and $4.7 million at December 31, 2003
and 2002, respectively.
During 2002, after-tax impairment write-offs totaling $10.3 million were
recorded to reduce the carrying values of NEON and Acumentrics to their net
realizable values. Excluding BMC, these investments are VIEs under FIN 46
for which NU is not the primary beneficiary, and NU's exposure to loss as a
result of these investments totaled $17.4 million and $12.5 million at
December 31, 2003 and 2002, respectively.
L. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) is a non-cash item
that is included in the cost of Utility Group utility plant and represents
the cost of borrowed and equity funds used to finance construction. The
portion of AFUDC attributable to borrowed funds is recorded as a reduction
of other interest expense, and the cost of equity funds is recorded as other
income on the consolidated statements of income:
- ----------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------
(Millions of Dollars,
except percentages) 2003 2002 2001
- ----------------------------------------------------------------
Borrowed funds $ 5.0 $ 7.5 $ 6.6
Equity funds 6.5 5.8 3.8
- ----------------------------------------------------------------
Totals $11.5 $13.3 $10.4
- ----------------------------------------------------------------
Average AFUDC rates 4.0% 4.9% 7.2%
- ----------------------------------------------------------------
M. EQUITY-BASED COMPENSATION
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." This statement amended 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 equity-based employee compensation. This statement also
requires prominent disclosures in both annual and interim financial
statements about the method of accounting for equity-based employee
compensation and the effect of the method used on reported results. At this
time, NU has not elected to transition to the fair value-based method of
accounting for equity-based employee compensation. At December 31, 2003,
NU maintains an Employee Share Purchase Plan (ESPP) and other long-term
incentive plans, which are described in Note 4D, "Employee Benefits -
Equity-Based Compensation," to the consolidated financial statements. NU
accounts for these plans under the recognition and measurement principles of
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued
to Employees," and related interpretations. No equity-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. No stock options were
granted during 2003. 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 equity-based employee compensation.
- --------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------
(Millions of Dollars, except per
share amounts) 2003 2002 2001
- --------------------------------------------------------------------------
Net income as reported $116.4 $152.1 $243.5
Total equity-based employee
compensation expense
determined under the
fair value-based method for
all awards, net of related tax
effects (1.9) (3.2) (2.6)
- --------------------------------------------------------------------------
Pro forma net income $114.5 $148.9 $240.9
- --------------------------------------------------------------------------
EPS:
Basic - as reported $0.91 $1.18 $1.80
Basic - pro forma $0.90 $1.15 $1.78
Diluted - as reported $0.91 $1.18 $1.79
Diluted - pro forma $0.90 $1.15 $1.77
- --------------------------------------------------------------------------
Net income as reported includes $2 million, $1 million and $1.2 million
expensed for restricted stock in 2003, 2002 and 2001, respectively. NU
accounts for restricted stock in accordance with APB No. 25 and amortizes the
intrinsic value of the award over the service period.
NU assumes an income tax rate of 40 percent to estimate the tax effect on
total equity-based employee compensation expense determined under the fair
value-based method for all awards.
N. 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 was effective on January 1, 2003
for NU. Management completed its review process for potential asset
retirement obligations (ARO) and has not identified any material AROs that
have been incurred. However, management has identified certain removal
obligations that arise in the ordinary course of business or have a low
probability of occurring. 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. These obligations are AROs that have not been incurred or are not
material in nature.
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, 2003 and 2002, cost of removal was approximately $334
million and $321 million, respectively.
O. MATERIALS AND SUPPLIES
Materials and supplies include materials purchased primarily for
construction, operation and maintenance (O&M) purposes. Materials and
supplies are valued at the lower of average cost or market.
P. SALE OF CUSTOMER RECEIVABLES
CL&P has an arrangement with a financial institution under which CL&P can
sell up to $100 million of accounts receivable and unbilled revenues. At
December 31, 2003 and 2002, CL&P had sold accounts receivable of $80 million
and $40 million, respectively, to the financial institution with limited
recourse through CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. At December 31, 2003 and 2002, the reserve requirements
calculated in accordance with the Receivables Purchase and Sale Agreement
were $29.3 million and $3.8 million, respectively. These reserve amounts are
deducted from the amount of receivables eligible for sale at the time.
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, 2003 and 2002, amounts sold to
CRC by CL&P but not sold to the financial institution totaling $166.5 million
and $178.9 million, respectively, are included in investments in
securitizable assets on the accompanying consolidated balance sheets. These
amounts would be excluded from CL&P's assets in the event of CL&P's
bankruptcy. On July 9, 2003, CL&P renewed this arrangement.
The transfer of receivables to the financial institution under this arrangement
qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement
of SFAS No. 125." This agreement expires on July 7, 2004. Management plans to
renew this agreement prior to its expiration.
Q. CASH AND CASH EQUIVALENTS
Cash and cash equivalents includes cash on hand and short-term cash
investments that are highly liquid in nature and have original maturities of
three months or less.
R. RESTRICTED CASH - LMP COSTS AND UNRESTRICTED CASH FROM COUNTERPARTIES
Restricted cash - LMP costs represents incremental LMP cost amounts that have
been collected by CL&P and deposited into an escrow account.
Unrestricted cash on deposit from counterparties represents balances
collected from counterparties resulting from Select Energy's credit
management activities. An offsetting liability has been recorded in other
current liabilities for the amounts collected.
S. SPECIAL DEPOSITS
Special deposits represents amounts Select Energy has on deposit with
brokerage firms in the amount of $17 million, amounts included in escrow for
SESI which have not been spent on its construction projects of $32 million,
and $30.1 million in escrow that PSNH funded to acquire CVEC on January 1,
2004.
T. EXCISE TAXES
Certain excise taxes levied by state or local governments are collected by NU
from its customers. These excise taxes are accounted for on a gross basis
with collections in revenues and payments in expenses. For the years ended
December 31, 2003, 2002 and 2001, gross receipts taxes, franchise taxes and
other excise taxes of $94.5 million, $86.7 million and $90.5 million,
respectively, are included in operating revenues and taxes other than income
taxes on the accompanying consolidated statements of income.
U. SUPPLEMENTAL CASH FLOW INFORMATION
- ---------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------
Cash paid during the
year for:
Interest, net of
amounts capitalized $241.3 $259.9 $275.3
Income taxes $248.3 $114.4 $321.0
- ---------------------------------------------------------------------
V. OTHER INCOME/(LOSS)
The pre-tax components of NU's other income/(loss) items are as follows:
- ---------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------
Seabrook-related gains $ - $ 38.7 $ -
Investment write-downs (1.4) (18.4) -
Gain related to Millstone sale - - 201.9
Loss on share
repurchase contracts - - (35.4)
Investment income 17.1 25.4 19.3
Charitable donations (8.4) (3.7) (5.8)
Other (7.7) 1.8 7.6
- ---------------------------------------------------------------------
Totals $(0.4) $ 43.8 $187.6
- ---------------------------------------------------------------------
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. On June 30, 2003,
the SEC granted authorization allowing NU, CL&P, PSNH, WMECO, and Yankee Gas
to incur total short-term borrowings up to a maximum of $400 million, $375
million, $100 million, $200 million, and $100 million, respectively, through
June 30, 2006, with authorization for borrowings from the NU Money Pool
(Pool) granted through June 30, 2004.
The charter of CL&P contains preferred stock provisions restricting the
amount of unsecured debt that CL&P may incur. At meetings in November 2003,
CL&P obtained authorization from its stockholders to issue unsecured
indebtedness with a maturity of less than 10 years in excess of the 10
percent of total capitalization limitation in CL&P's charter, provided that
all unsecured indebtedness would not exceed 20 percent of total capitalization
for a ten-year period expiring March 2014. As of December 31, 2003, CL&P is
permitted to incur $366 million of additional unsecured debt.
PSNH is authorized by the NHPUC to incur short-term borrowings up to a
maximum of $100 million.
SEC authorization was also given on June 30, 2003, permitting NAEC to incur
short-term borrowings from the Pool up to a maximum of $10 million through
June 30, 2004. NAEC currently has a short-term debt limit set by the NHPUC
equal to 10 percent of net fixed plant and has no plans at this time to incur
any future short-term borrowings.
Utility Group Credit Agreement: On November 10, 2003, CL&P, PSNH, WMECO, and
Yankee Gas entered into a 364-day unsecured revolving credit facility for
$300 million. This facility replaces a similar credit facility that expired
on November 11, 2003. CL&P may draw up to $150 million with PSNH, WMECO and
Yankee Gas able to draw up to $100 million, subject to the $300 million
maximum borrowing limit. Unless extended, the credit facility will expire on
November 8, 2004. At December 31, 2003 and 2002, there were $40 million and
$7 million, respectively, in borrowings under these credit facilities.
NU Parent Credit Agreement: On November 10, 2003, NU entered into a 364-day
unsecured revolving credit and letter of credit (LOC) facility for $350
million. This facility replaces a similar facility that expired on November
11, 2003. This facility provides a total commitment of $350 million, subject
to two overlapping sub-limits. First, subject to the notional amount of any
outstanding LOCs, amounts up to $350 million are available for advances.
Second, subject to the advances outstanding, LOCs may be issued in notional
amounts up to $250 million for periods up to 364 days. The agreement
provides for LOCs to be issued in the name of NU or any of its subsidiaries.
Unless extended, the credit facility will expire on November 8, 2004. At
December 31, 2003 and 2002, there were $65 million and $49 million,
respectively, in borrowings under these credit facilities. In addition, there
were $106.9 million and $6.7 million in LOCs outstanding at December 31, 2003
and 2002, respectively.
Under the Utility Group and NU parent 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, 2003 and 2002 were 2.07
percent and 4.25 percent, respectively.
Under the Utility Group and NU parent credit agreements, NU and its
subsidiaries must comply with certain financial and non-financial covenants
as are customarily included in such agreements, including but not limited to,
consolidated debt ratios and interest coverage ratios. The most restrictive
financial covenant is the interest coverage ratio. The parties to the credit
agreements currently are and expect to remain in compliance with these
covenants.
Other Credit Facility: On December 29, 2003, E.S. Boulos Company (Boulos), a
subsidiary of NGS, entered into a line of credit for $6 million. This
facility replaces a similar credit facility that expired on December 31,
2003, and unless extended, this credit facility will expire on June 30, 2004.
This credit facility limits Boulos' ability to pay dividends if borrowings
are outstanding and limits access to the Pool for additional borrowings. At
December 31, 2003 and 2002, there were no borrowings under this credit
facility.
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 designated as fair
value hedges and the item they are hedging are both recorded at fair value on
the consolidated balance sheets. 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 derivative instruments, see Note 1C,
"Summary of Significant Accounting Policies - New Accounting Standards," to
the consolidated financial statements.
During 2003, a negative $5.3 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 $0.3 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 2003, new cash flow hedge transactions were entered into
that hedge cash flows through 2006. As a result of these new transactions
and market value changes since January 1, 2003, accumulated other
comprehensive income increased by $9.3 million, net of tax. Accumulated
other comprehensive income at December 31, 2003 was a positive $24.8
million, net of tax (increase to equity), relating to hedged transactions,
and it is estimated that $27.3 million of this net of tax balance will be
reclassified as an increase to earnings within the next twelve months. Cash
flows from hedge contracts are reported in the same category as cash flows
from the underlying hedged transaction.
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. During 2002, new cash flow hedge transactions were entered into that
hedge cash flows through 2005. As a result of these new transactions and
market value changes during 2002, accumulated 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.
In 2003, there were changes to interpretations of as well as an amendment to
SFAS No. 133, and the FASB continues to consider changes that could affect
the way NU records and discloses derivative and hedging activities.
The tables below summarize the derivative assets and liabilities at
December 31, 2003 and 2002. These amounts do not include option premiums paid,
which are recorded as prepayments and amounted to $16.7 million and $26.6
million at December 31, 2003 and 2002, respectively. These amounts also do not
include option premiums received, which are recorded as other current
liabilities and amounted to $12.2 million and $33.9 million at December 31,
2003 and 2002, respectively. The premium amounts relate primarily to energy
trading activities.
- ---------------------------------------------------------------------
At December 31, 2003
- ---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
- ---------------------------------------------------------------------
NU Enterprises:
Trading $123.9 $ (91.4) $ 32.5
Non-trading 1.6 (0.8) 0.8
Hedging 55.8 (12.7) 43.1
Utility Group - Gas:
Non-trading 0.2 (0.2) -
Hedging 2.8 - 2.8
Utility Group - Electric:
Non-trading 116.9 (56.0) 60.9
NU Parent:
Hedging - (3.6) (3.6)
- ---------------------------------------------------------------------
Total $301.2 $(164.7) $136.5
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
At December 31, 2002
- ---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
- ---------------------------------------------------------------------
NU Enterprises:
Trading $102.9 $(61.9) $41.0
Non-trading 2.9 - 2.9
Hedging 22.8 (2.0) 20.8
Utility Group - Gas:
Hedging 2.3 - 2.3
- ---------------------------------------------------------------------
Total $130.9 $(63.9) $67.0
- ---------------------------------------------------------------------
NU Enterprises - Trading: To gather market intelligence and utilize this
information in risk management activities for the wholesale marketing
activities, Select Energy conducts limited 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 exposures. 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, 2003 and 2002 were assets of $32.5 million and $41 million,
respectively.
Select Energy's 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 market prices; and bilateral
contracts for the purchase or sale of electricity or natural gas, the fair
value of which is determined using available information from external
sources. Select Energy's trading portfolio also includes transmission
congestion contracts (TCC). The fair value of certain TCCs is based on
published market data.
NU Enterprises - Non-trading: Non-trading derivative contracts are used for
delivery of energy related to Select Energy's wholesale and retail marketing
activities. These contracts are subject to fair value accounting because
these contracts are derivatives that cannot be designated as normal purchases
or sales, as defined. 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 management did not elect the
normal purchase and sale designation. Changes in fair value of a negative
$2.1 million of non-trading derivative contracts were recorded in revenues in
2003. Market information for certain TCCs is not available, and those
contracts cannot be reliably valued. Management believes the amounts paid for
these contracts, which total $4.3 million and are included in premiums paid,
are equal to their fair value.
NU Enterprises - 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 supply and
delivery 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 accumulated other comprehensive income. Hedges impact net
income 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 2006. Select
Energy has hedged its gas supply risk under these agreements through NYMEX
futures contracts. Under these contracts, which also extend through 2006,
the purchase price of a specified quantity of gas is effectively fixed over
the term of the gas service agreements. At December 31, 2003 and 2002, the
NYMEX futures contracts had notional values of $104.5 million and $30.9
million, respectively, and were recorded at fair value as derivative assets
of $11.6 million and $12.2 million at December 31, 2003 and 2002,
respectively.
Select Energy maintains power swaps to hedge purchases in New England as well
as financial gas contracts and gas futures to hedge electricity purchase
contracts that are indexed to gas prices. These hedging contracts, which are
valued at the mid-point of bid and ask market prices, were recorded as
derivative assets of $27.3 million and derivative liabilities of $5.1 million
at December 31, 2003. To hedge the congestion price differences associated
with LMP in the New England and the Pennsylvania, New Jersey, Maryland and
Delaware (PJM) regions, Select Energy holds FTR contracts recorded as a
derivative asset at a fair value of $3.8 million at December 31, 2003.
Other hedging derivative liabilities, which are valued at the mid-point of
bid and ask market prices, include forwards, options and swaps to hedge
Select Energy's basic generation service contracts in the PJM region and were
recorded at fair value as derivative liabilities of $5.8 million at December
31, 2003 and derivative assets of $1.1 million at December 31, 2002.
Select Energy New York, Inc. maintains financial power swaps to hedge its
retail sales portfolio through 2004, which were also valued at the mid-point
of bid and ask market prices. These contracts were recorded at fair value as
derivative assets of $6.9 million and $5.6 million at December 31, 2003 and
2002, respectively.
Utility Group - Gas - Non-trading: Yankee Gas' non-trading derivatives
consist of peaking supply arrangements to serve winter load obligations and
firm sales contracts with options to curtail delivery. These contracts are
subject to fair value accounting because these contracts are derivatives that
cannot be designated as normal purchases or sales, as defined, because of the
optionality in their contract terms. The net fair values of non-trading
derivatives at December 31, 2003 were liabilities of $24 thousand. Yankee
Gas held no contracts accounted for as non-trading derivatives at December 31,
2002.
Utility Group - Gas - 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
an unaffiliated customer is effectively fixed over the term of the gas
service agreements with those customers for a period not extending beyond
2005. At December 31, 2003 and 2002, the commodity swap agreement had
notional values of $6.3 million and $10.7 million, respectively, and was
recorded at fair value as derivative assets at December 31, 2003 and 2002 of
$2.8 million and $2.3 million, respectively.
Utility Group - Electric - Non-trading: CL&P has two IPP contracts to
purchase power that contain pricing provisions that are not clearly and
closely related to the price of power. Because of a clarification in the
definition of "clearly and closely related" in Issue No. C-20, these
contracts no longer qualify for the normal purchases and sales exception to
SFAS No. 133, as amended. The fair values of these IPP non-trading
derivatives at December 31, 2003 include a derivative asset with a fair
value of $112.4 million and a derivative liability with a fair value of $54.6
million. To mitigate the risk associated with certain supply contracts, CL&P
purchased FTRs. FTRs are derivatives that cannot qualify for the normal
purchases and sales exception. The fair value of these FTR non-trading
derivatives at December 31, 2003 was an asset of $3 million. CL&P had no non-
trading derivatives at December 31, 2002 that were required to be recorded at
fair value.
NU Parent - Hedging: In March of 2003, NU parent entered into a fixed to
floating interest rate swap on its $263 million, 7.25 percent fixed-rate note
that matures on April 1, 2012. As a matched-terms fair value hedge, the
changes in fair value of the swap and the hedged debt instrument are recorded
on the consolidated balance sheets but are equal and offsetting in the
consolidated statements of income. The cumulative change in the fair value
of the hedged debt of $3.6 million is included as long-term debt on the
consolidated balance sheets. The resulting changes in interest payments made
are recorded as adjustments to interest expense.
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.
NU Enterprises - Wholesale and Retail Marketing Portfolio: When conducting
sensitivity analyses of the change in the fair value of Select Energy's
electricity, natural gas and oil on the wholesale and retail marketing
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 consideration 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
wholesale and retail marketing portfolio, which includes cash flow hedges and
electricity, natural gas and oil contracts, assuming a 10 percent change in
forward market prices. At December 31, 2003, a 10 percent change in market
price would have resulted in an increase or decrease in fair value of $3.7
million.
The impact of a change in electricity, natural gas and oil prices on Select
Energy's wholesale and retail marketing portfolio at December 31, 2003, is
not necessarily representative of the results that will be realized when
these contracts are physically delivered.
NU Enterprises - Trading Contracts: At December 31, 2003, Select Energy has
calculated the market price resulting from a 10 percent change in forward
market prices. That 10 percent change would result in a $0.4 million
increase or decrease in the fair value of the Select Energy trading
portfolio. In the normal course of business, Select Energy also faces risks
that are either non-financial or non-quantifiable. These risks principally
include credit risk, which is not reflected in this sensitivity analysis.
C. OTHER RISK MANAGEMENT ACTIVITIES
Interest Rate Risk Management: NU manages its interest rate risk exposure in
accordance with written policies and procedures by maintaining a mix of fixed
and variable rate debt. At December 31, 2003, approximately 82 percent (72
percent including the debt subject to the fixed-to-floating interest rate
swap in variable rate debt) of NU's long-term debt, including fees and
interest due for spent nuclear fuel disposal costs, is at a fixed interest
rate. 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, including the rate
on debt subject to the fixed-to-floating interest rate swap, annual interest
expense would have increased by $4.3 million. At December 31, 2003, NU
parent maintained a fixed to floating interest rate swap to manage the interest
rate risk associated with its $263 million of fixed-rate debt.
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 IPPs, 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.
The Utility Group has a lower level of credit risk related to providing
electric and gas distribution service than NU Enterprises. However, Utility
Group companies are subject to credit risk from certain long-term or high-
volume supply contracts with energy marketing companies.
Credit risks and market risks at NU Enterprises are monitored regularly by a
Risk Oversight Council operating outside of the business lines 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 condition (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 energy contracts. 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, 2003 and 2002, Select Energy maintained collateral balances
from counterparties of $46.5 million and $16.9 million, respectively. These
amounts are included in both unrestricted cash from counterparties and other
current liabilities on the accompanying consolidated balance sheets.
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 (Pension 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 was $31.8 million in 2003, $73.4 million
in 2002, and $101 million in 2001. These amounts exclude pension
settlements, curtailments and net special termination income of $22.2 million
in 2002 and expense of $2.6 million in 2001. NU uses a December 31
measurement date for the Pension Plan. Pension income attributable to
earnings is as follows:
- ------------------------------------------------------------------------
For the Years Ended December 31,
- ------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- ------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(31.8) $(73.4) $(101.0)
Net pension income
capitalized as utility plant 15.4 26.2 36.8
- ------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (16.4) (47.2) (64.2)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 7.5
- ------------------------------------------------------------------------
Total pension income
included in earnings $(16.4) $(47.2) $ (56.7)
- ------------------------------------------------------------------------
Pension Settlements, Curtailments and Special Termination Benefits: There
were no settlements, curtailments or special termination benefits in 2003.
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), and North Atlantic Energy Service Corporation (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 Pension 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, all of which was
recorded as a regulatory liability and did not impact earnings.
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 the Pension Plan and provides special provisions. Eligible
employees include non-bargaining unit employees or employees belonging to a
collective bargaining unit that agreed to accept the VRP who were active
participants in the Pension Plan at January 1, 2002, and that were 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. The cost of the VRP
was recovered through regulated utility rates, and 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 5 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 (PBOP Plan).
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 uses a December 31 measurement date for the PBOP Plan. NU
annually funds postretirement costs through external trusts with amounts that
have been rate-recovered and which also are tax deductible.
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.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President
signed into law a bill that expands Medicare, primarily by adding a
prescription drug benefit starting in 2006 for Medicare-eligible retirees as
well as a federal subsidy to plan sponsors of retiree health care benefit
plans who provide a prescription drug benefit at least actuarially equivalent
to the new Medicare benefit.
Based on the current PBOP Plan provisions, NU's actuaries believe that NU
will qualify for this federal subsidy because the actuarial value of NU's
PBOP Plan is estimated to be 60 percent greater than that of the standard
Medicare benefit. NU will directly benefit from the federal subsidy for
retirees of PSNH and NAESCO who retired before 1993, and other NU-company
retirees who retired before 1991. For other retirees, management does not
believe that NU will benefit from the subsidy because NU's cost support for
these retirees is capped at a fixed dollar commitment.
The aggregate effect of recognizing the Medicare change is a decrease to the
PBOP benefit obligation of $19.5 million. This amount includes the present
value of the future government subsidy, which was estimated by discounting
the expected payments using the actuarial assumptions used to determine the
PBOP liability at December 31, 2003. Also included in the $19.5 million
estimate is a decrease in the assumed participation in NU's retiree health
plan from 95 percent to 85 percent for future retirees, which reflects the
expectation that the Medicare prescription benefit will produce insurer-
sponsored health plans that are more financially attractive to future
retirees. The per capita claims cost estimate was not changed. Management
reduced the PBOP benefit obligation as of December 31, 2003 by $19.5 million
and recorded this amount as an actuarial gain within unrecognized net
loss/(gain) in the tables that follow. The $19.5 million actuarial gain will
be amortized beginning in 2004 as a reduction to PBOP expense over the future
working lifetime of employees covered under the plan (approximately 13
years). PBOP expense in 2004 will also reflect a lower interest cost due to
the reduction in the December 31, 2003 benefit obligation.
Specific authoritative guidance on accounting for the effect of the Medicare
federal subsidy on PBOP plans and amounts is pending from the FASB. When
issued, that guidance could require NU to change the accounting described
above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There were
no settlements, curtailments or special termination benefits in 2003. 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 totaling $3.3 million and special termination benefits
expense totaling $8.6 million in connection with the VSP. This amount was
recorded as a regulatory asset and collected through regulated utility rates
in 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) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(1,789.8) $(1,687.6) $(397.8) $(400.0)
Service cost (35.1) (37.2) (5.3) (6.2)
Interest cost (117.0) (119.8) (26.8) (29.2)
Medicare impact - - 19.5 -
Plan amendment - (11.4) - 34.2
Actuarial loss (102.9) (117.7) (34.8) (44.0)
Benefits paid - excluding lump sum payments 99.6 97.3 40.2 44.0
Benefits paid - lump sum payments 3.9 50.2 - -
Curtailments and settlements - 44.5 - 3.4
Special termination benefits - (8.1) - -
- ----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(1,941.3) $(1,789.8) $(405.0) $(397.8)
- ----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 1,632.3 $ 1,990.4 $ 147.7 $ 171.0
Actual return on plan assets 416.3 (213.1) 35.4 (14.4)
Employer contribution - - 35.1 35.1
Plan asset transfer in - 2.5 - -
Benefits paid - excluding lump sum payments (99.6) (97.3) (40.2) (44.0)
Benefits paid - lump sum payments (3.9) (50.2) - -
- ----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 1,945.1 $ 1,632.3 $ 178.0 $ 147.7
- ----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 3.8 $ (157.5) $(227.0) $(250.1)
Unrecognized transition (asset)/obligation (1.1) (2.6) 106.6 118.5
Unrecognized prior service cost 63.5 70.1 (5.5) (5.9)
Unrecognized net loss/(gain) 294.5 418.9 113.6 124.8
- ----------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 360.7 $ 328.9 $ (12.3) $ (12.7)
- ----------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for the Plan was $1.7 billion and $1.6
billion at December 31, 2003 and 2002, respectively.
The following actuarial assumptions were used in calculating the plans' year
end funded status:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend rate N/A N/A 9.00% 10.00%
- -------------------------------------------------------------------------------
The components of net periodic (income)/expense are as follows:
- ----------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
Service cost $ 35.1 $ 37.2 $ 35.7 $ 5.3 $ 6.2 $ 6.2
Interest cost 117.0 119.8 119.7 26.8 29.2 27.2
Expected return on plan assets (182.5) (204.9) (214.1) (14.9) (16.6) (17.0)
Amortization of unrecognized net
transition (asset)/obligation (1.5) (1.4) (1.5) 11.9 13.6 14.5
Amortization of prior service cost 7.2 7.7 6.9 (0.4) (0.1) -
Amortization of actuarial gain (7.1) (31.8) (47.7) - - -
Other amortization, net - - - 6.4 2.2 (2.6)
- ----------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (31.8) (73.4) (101.0) 35.1 34.5 28.3
- ----------------------------------------------------------------------------------------------------------
Settlement income - - (26.0) - - -
Curtailment (income)/expense - (30.3) (64.7) - - 3.3
Special termination benefits expense/(income) - 8.1 93.3 - (1.2) 8.6
- ----------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits - (22.2) 2.6 - (1.2) 11.9
- ----------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $(31.8) $(95.6) $ (98.4) $ 35.1 $ 33.3 $ 40.2
- ----------------------------------------------------------------------------------------------------------
For calculating pension and postretirement benefit income and expense
amounts, the following assumptions were used:
- ----------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
- ----------------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
- ----------------------------------------------------------------------------------------------
The following table represents the PBOP assumed health care cost trend rate
for the next year and the assumed ultimate trend rate:
- ---------------------------------------------------------------
Year Following December 31,
- ---------------------------------------------------------------
2003 2002
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
- ----------------------------------------------------------------
The annual per capita cost of covered health care benefits was assumed to
decrease by one percentage point each year through 2007. Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plans. The effect of changing the assumed health care cost trend
rate by one percentage point in each year would have the following effects:
- ----------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
- ----------------------------------------------------------------
Effect on total service and
interest cost components $ 0.8 $ (0.7)
Effect on postretirement
benefit obligation $12.5 $(11.3)
- ----------------------------------------------------------------
NU's investment strategy for its Pension Plan and PBOP Plan is to maximize
the long-term rate of return on those plans' assets within an acceptable
level of risk. The investment strategy establishes target allocations, which
are regularly reviewed and periodically rebalanced. NU's expected long-term
rates of return on Pension Plan assets and PBOP Plan assets are based on
these target asset allocation assumptions and related expected long-term
rates of return. In developing its expected long-term rate of return
assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input
from actuaries, consultants and economists as well as long-term inflation
assumptions and NU's historical 20-year compounded return of approximately 11
percent. The Pension Plan's and PBOP Plan's target asset allocation
assumptions and expected long-term rate of return assumptions by asset
category are as follows:
- -----------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
- -----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
- -----------------------------------------------------------------------------------------------------------------
The actual asset allocations at December 31, 2003 and 2002, approximated
these target asset allocations. The plans' actual weighted-average asset
allocations by asset category are as follows:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
- ---------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
- ---------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
- ---------------------------------------------------------------------
Total 100.00% 100.00% 100.00% 100.00%
- ---------------------------------------------------------------------
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.
NU does not expect to make any contributions to the Pension Plan in 2004 and
expects to make $41.3 million in contributions to the PBOP Plan in 2004.
Postretirement health plan assets for non-union employees are 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 $9.9 million in 2003, $11.1 million in 2002 and $11.7 million in 2001.
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 2002, NU declared a $0.125 per share quarterly dividend. During
the third quarter of 2002 through the second quarter of 2003, NU declared a
$0.1375 per share quarterly dividend. NU declared a $0.15 per share dividend
during the third and fourth quarters of 2003.
In 2003 and 2002, the ESOP trust issued 607,020 and 607,475 of NU common
shares, respectively, to satisfy 401(k) Savings Plan obligations to
employees. At December 31, 2003 and 2002, total allocated ESOP shares were
7,615,804 and 7,008,784, respectively, and total unallocated ESOP shares were
3,184,381 and 3,791,401, respectively. The fair market value of the
unallocated ESOP shares at December 31, 2003 and 2002, was $64.2 million and
$57.5 million, respectively.
D. EQUITY-BASED COMPENSATION
ESPP: Since July 1998, NU has maintained an ESPP for all eligible employees.
Under the ESPP, NU common shares are purchased at six-month intervals at 85
percent of the lower of the price on the first or last day of each six-month
period. Employees may purchase shares having a value not exceeding 25 percent
of their compensation as of the beginning of the purchase period. During 2003
and 2002, employees purchased 225,985 and 188,774 shares, respectively, at
discounted prices of $12.20 in 2003 and $14.15 and $15.39 in 2002. At
December 31, 2003 and 2002, 1,585,241 shares and 1,811,226 shares remained
registered for future issuance under the ESPP, respectively.
Incentive Plans: Under the Northeast Utilities Incentive Plan (Incentive
Plan), NU is authorized to grant various types of awards, including
restricted stock, performance units, restricted stock units, and stock
options to eligible employees and board members. The number of shares that
may be utilized for grants and awards 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, 2003 and 2002, NU had
1,649,268 and 2,440,339 shares of common stock, respectively, registered for
issuance under the Incentive Plan.
Restricted Stock: During 2003, NU granted 417,222 shares of restricted stock
under the Incentive Plan. The shares granted in 2003 had a fair value of
$6.1 million when granted and were recorded as an offset to shareholders'
equity. NU also made several grants of restricted stock during 2002 and 2001
under the Incentive Plan. During 2003, 2002 and 2001, $2 million, $1 million
and $1.2 million, respectively, was expensed related to restricted stock.
Performance Units and Restricted Stock Units: Under the Incentive Plan, NU
also granted 35,303 and 38,847 performance units during 2003 and 2002,
respectively. There were no performance units granted in 2001. The
performance units vest ratably over three years and will be paid in cash at
the end of the vesting period. NU records a liability for the performance
units based on the achievement of the performance unit goals. A liability of
$1.5 million and $1.3 million was recorded at December 31, 2003 and 2002,
respectively, for these performance units. During 2003 and 2002, $0.2
million and $1.3 million, respectively, was expensed related to these
performance units.
During 2003, 75,000 restricted stock units were granted, all of which were
forfeited effective January 1, 2004.
Stock Options: Prior to 2003, NU granted stock options to certain employees.
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 equity-
based compensation cost is reflected in net income. No stock options were
granted during 2003, and stock option transactions for 2002 and 2001 are as
follows:
- -----------------------------------------------------------------------------------------------------
Exercise Price Per Share
-------------------------------------------
Options Range Weighted Average
- -----------------------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------------------
Exercised (562,982) $ 9.6250 - $19.5000 $14.6223
Forfeited and cancelled (151,005) $14.9375 - $21.0300 $19.0227
- -----------------------------------------------------------------------------------------------------
Outstanding - December 31, 2003 3,123,322 $ 9.6250 - $22.2500 $17.1270
- -----------------------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------------------
Exercisable - December 31, 2003 2,027,413 $ 9.6250 - $22.2500 $16.6969
- -----------------------------------------------------------------------------------------------------
In 1997, 500,000 options with a weighted average exercise price of $9.625
were granted. These options, of which 350,000 are outstanding and
exercisable at December 31, 2003, have a remaining contractual life of 3.63
years. Excluding these options from those outstanding at December 31, 2003,
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.
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. No stock options were granted during 2003.
- ------------------------------------------------------
2002 2001
- ------------------------------------------------------
Risk-free interest rate 4.86% 5.34%
Expected life 10 years 10 years
Expected volatility 23.71% 25.47%
Expected dividend yield 2.11% 2.11%
- ------------------------------------------------------
The weighted average grant date fair values of options granted during 2002
and 2001 were $5.64 and $6.94, respectively. The weighted average remaining
contractual lives for the options outstanding at December 31, 2003 is 6.79
years.
For further information regarding equity-based compensation, see Note 1M,
"Summary of Significant Accounting Policies - Equity-Based Compensation."
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 $22.1 million and $20.1 million at December 31, 2003 and 2002,
respectively, represents NU's actuarially-determined obligation under the
SERP. During 2003, 2002, and 2001, $3.9 million, $3.8 million, and $4
million, respectively, was expensed related to the SERP. The SERP is the
only NU retirement plan for which a minimum pension liability has been
recorded. Recording this minimum pension liability resulted in a reduction
of $0.8 million to accumulated other comprehensive income at December 31, 2003.
For information regarding the SERP investments, see Note 8, "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 $35.5 million and $32.2 million at December 31, 2003 and 2002,
respectively. During 2003, 2002, and 2001, $6.3 million, $7.8 million, and
$3.2 million, respectively, was expensed related to this plan.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
- -------------------------------------------------------------------------------
Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which ended the 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 at least annually by applying a fair value-based
test. NU selected October 1 as the annual goodwill impairment testing date.
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. Excluding adjustments to the purchase price allocation
related to the acquisition of Woods Electrical Co., Inc. (Woods Electrical)
and Woods Network, there were no impairments or adjustments to the goodwill
balances during 2003. The adjustments primarily related to the
reclassification between goodwill and intangible assets. In July 2002, NU
Enterprises acquired certain assets and assumed certain liabilities of Woods
Electrical, an electrical services company, and Woods Network, a network
products and service company.
NU's reporting units that maintain goodwill are generally consistent with the
operating segments underlying the reportable segments identified in Note 12,
"Segment Information," to the consolidated financial statements. Consistent
with the way management reviews the operating results of its reporting units,
NU's reporting units under the NU Enterprises reportable segment include: 1)
the merchant energy business line reporting unit, and 2) the energy services
business line reporting unit. The merchant energy business line reporting
unit is comprised of the operations of Select Energy, NGC and the generation
operations of HWP, while the energy services business line reporting unit is
comprised of the operations of SESI, NGS and Woods Network. As a result,
NU's reporting units that maintain goodwill are as follows: Yankee Gas,
which is classified under the Utility Group - gas reportable segment; the
merchant energy business line reporting unit; and the energy services
business line reporting unit, both of which are classified under the NU
Enterprises reportable segment. The goodwill balances of these reporting
units are included in the table herein.
NU has completed its impairment analyses as of October 1, 2003, for all
reporting units that maintain goodwill and 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.
At December 31, 2003, NU maintained $319.9 million of goodwill that is no
longer being amortized, $14.4 million of identifiable intangible assets subject
to amortization and $8.5 million of intangible assets not subject to
amortization. At December 31, 2002, NU maintained $321 million of goodwill
that is no longer being amortized, $18.1 million of identifiable intangible
assets subject to amortization and $6.8 million of intangible assets not
subject to amortization. A summary of NU's goodwill balances at December 31,
2003 and 2002, by reportable segment and reporting unit is as follows:
- ------------------------------------------------------
At December 31,
- ------------------------------------------------------
(Millions of Dollars) 2003 2002
- ------------------------------------------------------
Utility Group - Gas:
Yankee Gas $287.6 $287.6
NU Enterprises:
Energy Services Business Line 29.1 30.2
Merchant Energy Business Line 3.2 3.2
- ------------------------------------------------------
Totals $319.9 $321.0
- ------------------------------------------------------
The goodwill recorded related to the acquisition of Yankee Gas is not being
recovered from the customers of Yankee Gas.
At December 31, 2003 and December 31, 2002, NU's intangible assets and
related accumulated amortization consisted of the following:
- --------------------------------------------------------------------------
At December 31, 2003
- --------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
- --------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $ 7.2 $10.5
Customer list 6.6 2.7 3.9
Customer backlog,
employment related
agreements and other 0.1 0.1 -
- --------------------------------------------------------------------------
Totals $24.4 $10.0 $14.4
- --------------------------------------------------------------------------
Intangible assets not
subject to amortization:
Customer relationships $ 5.2
Tradenames 3.3
- ---------------------------------------------------
Totals $ 8.5
- ---------------------------------------------------
- --------------------------------------------------------------------------
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,
employment related
agreements and other 0.1 - 0.1
- --------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
- --------------------------------------------------------------------------
Intangible assets not
subject to amortization:
Customer relationships $ 3.8
Tradenames 3.0
- ---------------------------------------------------
Totals $ 6.8
- ---------------------------------------------------
NU recorded amortization expense of $3.7 million and $2.1 million for the
years ended December 31, 2003 and 2002, respectively, related to these
intangible assets. Substantially all of the intangible assets subject to
amortization are being amortized over a period of 8.5 years. Based on the
current amount of intangible assets subject to amortization, the estimated
annual amortization expense for each of the succeeding 5 years is $3.6
million in 2004 through 2007 and no amortization expense in 2008. These
amounts may vary as acquisitions and dispositions occur in the future.
The results for the year ended December 31, 2001, on a historical basis, do
not reflect the provisions of SFAS No. 142. Had NU adopted SFAS No. 142 on
January 1, 2001, historical income before the cumulative effect of an
accounting change, net income and basic and fully diluted EPS amounts would
have been adjusted as follows:
- --------------------------------------------------------------------------
(Millions of Dollars, except Net Basic Fully
share information) Income EPS Diluted EPS
- --------------------------------------------------------------------------
Year Ended December 31, 2003:
- --------------------------------------------------------------------------
Reported income before cumulative
effect of accounting change $121.1 $0.95 $0.95
- --------------------------------------------------------------------------
Reported net income $116.4 $0.91 $0.91
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
Year Ended December 31, 2002:
- --------------------------------------------------------------------------
Reported income before cumulative
effect of accounting change $152.1 $1.18 $1.18
- --------------------------------------------------------------------------
Reported net income $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
==========================================================================
6. 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
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 was used to pay approximately $93 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. NAEC and CL&P recorded a gain
on the sale 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 for Baycorp's 15 percent ownership
interest. The agreement also limited any accelerated decommissioning funding
required to be funded by Baycorp as part of the sale process. NU received
approximately $17 million in 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. On
November 7, 2003, CL&P, PSNH and WMECO sold their collective 17 percent
ownership interest in VYNPC. 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.
7. COMMITMENTS AND CONTINGENCIES
- -------------------------------------------------------------------------------
A. RESTRUCTURING AND RATE MATTERS
Connecticut:
Impacts of Standard Market Design: On March 1, 2003, ISO-NE implemented SMD.
As part of SMD, LMP is utilized to assign value and causation to transmission
congestion and line losses.
CL&P was billed $186 million of incremental LMP costs by its standard offer
service suppliers or by ISO-NE. CL&P recovered a portion of these costs
through an additional charge on customer bills beginning on May 1, 2003.
Billings were on a two-month lag and were recorded as operating revenues when
billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the
responsibility for the $186 million of incremental LMP costs incurred. NU
recorded a pre-tax loss in 2003 of approximately $60 million ($36.9 million
after-tax) related to an agreement in principle to settle this dispute. On
February 23, 2004, CL&P, its suppliers, and other parties reached an
agreement in principle to settle the dispute. A settlement agreement is
subject to approval by the FERC.
The pre-tax loss of approximately $60 million was reflected in two line items
on the consolidated statements of income. Approximately $58 million was
recorded as a reduction to operating revenues, and approximately $2 million
was recorded in operating expenses.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook
nuclear unit on November 1, 2002. The net proceeds in excess of the book
value of Seabrook of $16 million were recorded as a regulatory liability and,
after being offset by accelerated decommissioning funding and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September 2003,
and a draft decision was received on February 3, 2004. Management does not
believe that the final decision, which is expected in March 2004, will have a
material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual
CTA and SBC reconciliation with the DPUC. For the year ended December 31,
2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue
requirement by $93.5 million. This amount was recorded as a regulatory
liability. For the same period, SBC revenues exceeded the SBC revenue
requirement by $22.4 million. In compliance with a prior decision of the DPUC,
a portion of the SBC overcollection reduced regulatory assets, and the
remaining overcollection of $18.6 million was applied to the CTA. The DPUC's
December 19, 2003 transitional standard offer (TSO) decision addressed $41
million of SBC overcollections and $64 million of CTA overcollections that had
been estimated as of December 31, 2003. In its decision, the DPUC ordered that
$80 million of the overcollections be used to reduce CTA costs during the 2004
through 2006 TSO period. The DPUC also ordered that $25 million of the
overcollections be used to offset SBC costs during the TSO period. The DPUC
also ordered that $37 million of GSC overcollections be used to pay CL&P's 0.50
mill/kWh procurement fee during the TSO period.
New Hampshire:
SCRC Reconciliation Filing: On an annual basis, PSNH files with the NHPUC an
SCRC reconciliation filing for the preceding calendar year. This filing
includes the reconciliation of stranded cost revenues with stranded costs,
and transition energy service (TS) revenues with TS costs. The NHPUC reviews
the filing, including a prudence review of PSNH's generation operations.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does
not expect the review of the 2003 SCRC filing to have a material effect on
PSNH's net income or financial position.
Massachusetts:
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002
transition cost reconciliation with the Massachusetts Department of
Telecommunications and Energy (DTE). This filing reconciled the recovery of
generation-related stranded costs for calendar year 2002 and included the
renegotiated purchased power contract related to the Vermont Yankee nuclear
unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition
cost reconciliation, which addressed WMECO's cost tracking mechanisms. As
part of that order, the DTE directed WMECO to revise its 2002 annual
transition cost reconciliation filing. The revised filing was submitted to
the DTE on September 22, 2003. Hearings have been held, and the timing of a
final decision from the DTE is uncertain. Management does not expect the
outcome of this docket to have a material adverse impact on WMECO's net
income or financial position.
B. NRG ENERGY, INC. EXPOSURES
Certain subsidiaries of NU, including CL&P and Yankee Gas, have entered into
transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On
May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy
petitions. On December 5, 2003, NRG emerged from bankruptcy. NU's NRG-
related exposures as a result of these transactions relate to 1) the recovery
of congestion charges incurred by NRG prior to the implementation of SMD on
March 1, 2003, 2) the recovery of CL&P's station service billings to NRG,
and 3) the recovery of Yankee Gas' and CL&P's expenditures that were incurred
related to an NRG subsidiary's generating plant construction project that is
now abandoned. While it is unable to determine the ultimate outcome of these
issues, management does not expect their resolution will have a material
adverse effect on NU's consolidated financial condition or results of
operations.
C. ENVIRONMENTAL MATTERS
General: 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. These laws and regulations require the removal
or the remedy of the effect on the environment of the disposal or release of
certain specified hazardous substances at current and former operating sites.
As such, NU has an active environmental auditing and training program and
believes that it is substantially in compliance with all enacted laws and
regulations.
Environmental reserves are accrued using a probabilistic model approach when
assessments indicate that it is probable that a liability has been incurred
and an amount can be reasonably estimated. The probabilistic model approach
estimates the liability based on the most likely action plan from a variety
of available remediation options, ranging from no action to several different
remedies ranging from establishing institutional controls to full site
remediation and monitoring.
These estimates are subjective in nature as they take into consideration
several different remediation options at each specific site. The reliability
and precision of these estimates can be affected by several factors including
new information concerning either the level of contamination at the site,
recently enacted laws and regulations or a change in cost estimates due to
certain economic factors.
The amounts recorded as environmental liabilities on the consolidated balance
sheets represent management's best estimate of the liability for
environmental costs and takes into consideration site assessment and
remediation costs. Based on currently available information for estimated
site assessment and remediation costs at December 31, 2003 and 2002, NU had
$40.8 million and $41.9 million, respectively, recorded as environmental
reserves. A reconciliation of the total amount reserved at December 31, 2003
and 2002 is as follows:
- -------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
- -------------------------------------------------------------------
2003 2002
- -------------------------------------------------------------------
Balance at beginning of year $ 41.9 $ 46.2
Additions and adjustments 4.1 5.4
Payments (5.2) (9.7)
- -------------------------------------------------------------------
Balance at end of year $ 40.8 $ 41.9
- -------------------------------------------------------------------
These liabilities are estimated on an undiscounted basis and do not assume
that any amounts are recoverable from insurance companies or other third
parties. The environmental reserve includes sites at different stages of
discovery and remediation and does not include any unasserted claims. At
December 31, 2003, there are nine sites for which there are unasserted
claims; however, any related remediation costs are not probable or estimable
at this time. NU's environmental liability also takes into account recurring
costs of managing hazardous substances and pollutants, mandated expenditures
to remediate previously contaminated sites and any other infrequent and non-
recurring clean up costs.
NU currently has 50 sites included in the environmental reserve. Of those 50
sites, 20 sites are in the remediation or long-term monitoring phase, 24
sites have had site assessments completed and the remaining six sites are in
the preliminary stages of site assessment.
In addition, capital expenditures related to environmental matters are
expected to total approximately $106 million in aggregate for the years 2004
through 2008. Of the $106 million, $70 million relates to the proposed
conversion of a 50 megawatt oil and coal burning unit at Schiller Station to
a wood burning unit. The remainder primarily relates to other environmental
remediation programs including programs associated with NU's hydroelectric
generation assets.
MGP Sites: Manufactured gas plant (MGP) sites comprise the largest portion
of NU's environmental liability. MGPs are sites that manufactured gas from
coal and produced certain byproducts that may pose risk to human health and the
environment. At December 31, 2003 and 2002, $36.3 million and $38.3 million,
respectively, represent amounts for the site assessment and remediation of
MGPs. At December 31, 2003 and 2002, the five largest MGP sites comprise
approximately 57 percent and 55 percent, respectively, of the total MGP
environmental liability. NU currently has 29 MGP sites included in its
environmental liability and five contingent MGP sites of which management is
aware and for which costs are not probable or estimable at this time. Of the
29 MGP sites, seven are currently undergoing remediation efforts with the
remainder in the site assessment stage.
At December 31, 2003, NU has one site that is held for sale. The site, a
former MGP site, is currently held for sale under a pending purchase and sale
agreement. NU is currently remediating the property and has been deferring
the costs associated with those remediation efforts as allowed by a
regulatory order. At December 31, 2003, NU had $7.8 million related to
remediation efforts at the property and other sale costs recorded in other
deferred debits on the accompanying consolidated balance sheets.
The pending purchase and sale agreement releases NU from all environmental
claims arising out of or in connection with the property. The purchase price
in the pending purchase and sale agreement exceeds the book value of the land
including the aforementioned deferred environmental remediation costs.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (CERCLA) and its' amendments or state equivalents
impose joint and several strict liabilities, regardless of fault, upon
generators of hazardous substances resulting in removal and remediation costs
and environmental damages. Liabilities under these laws can be material and
in some instances may be imposed without regard to fault or for past acts
that may have been lawful at the time they occurred. NU has five superfund
sites under CERCLA for which it has been notified that it is a potentially
responsible party (PRP). For sites where there are other PRPs and NU's
subsidiaries are not managing the site assessment and remediation, the
liability accrued represents NU's estimate of what it will need to pay to
settle its obligations with respect to the site.
It is possible that new information or future developments could require a
reassessment of the potential exposure to related environmental matters. As
this information becomes available management will continue to assess the
potential exposure and adjust the reserves as necessary.
Rate Recovery: PSNH and Yankee Gas have rate recovery mechanisms for
environmental costs. CL&P recovers a certain level of environmental costs
currently in rates but does not have an environmental cost recovery tracking
mechanism. Accordingly, changes in CL&P's environmental reserves impact
CL&P's earnings. WMECO does not have a regulatory mechanism to recover
environmental costs from its customers, and changes in WMECO's environmental
reserves impact WMECO's earnings.
D. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must
pay the DOE for the disposal of spent nuclear fuel and high-level radioactive
waste. The DOE is responsible for the selection and development of
repositories for, and the disposal of, spent nuclear fuel and high-level
radioactive waste. 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, 2003 and 2002, fees due to the DOE for the disposal of Prior
Period Fuel were $256.4 million and $253.6 million, respectively, including
interest costs of $174.3 million and $171.5 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed currently
to customers and were paid to the DOE on a quarterly basis. At December 31,
2003, NU's ownership shares of Millstone and Seabrook have been sold, and NU
is no longer responsible for fees relating to fuel burned at these facilities
since their sale.
E. 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, NU is subject to potential retrospective
assessments totaling $0.8 million under its respective NEIL insurance
policies.
F. 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, 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 $29.9 million in 2003, $27.6 million in 2002 and $25.3 million in
2001.
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 $283.4 million in 2003, $278.3
million in 2002 and $363.9 million in 2001. These amounts relate to IPP
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 $218.6 million
in 2003, $158 million in 2002 and $195.8 million in 2001.
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 Utility Group Costs: The estimated future annual
costs of NU's significant long-term contractual arrangements are as follows:
- --------------------------------------------------------------------------
(Millions of
Dollars) 2004 2005 2006 2007 2008 Thereafter
- --------------------------------------------------------------------------
VYNPC $ 29.5 $ 27.3 $ 28.5 $ 27.5 $ 28.0 $ 97.2
Electricity
Procurement
Contracts 314.6 318.1 320.9 253.2 217.5 1,302.6
Gas
Procurement
Contracts 176.8 158.6 150.2 128.7 36.4 122.3
Hydro-Quebec 25.4 24.3 22.8 20.6 19.8 237.6
- --------------------------------------------------------------------------
Totals $546.3 $528.3 $522.4 $430.0 $301.7 $1,759.7
- --------------------------------------------------------------------------
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 $5.8 billion at December 31, 2003 as follows:
- ----------------------------------
(Millions of Dollars)
- ----------------------------------
Year
2004 $4,471.0
2005 761.5
2006 142.9
2007 84.3
2008 84.7
Thereafter 275.4
- ----------------------------------
Total $5,819.8
- ----------------------------------
Select Energy's purchase contract amounts can exceed the amount expected to
be reported in fuel, purchased and net interchange power because energy
trading transactions are classified in revenues.
G. 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.
NU still has significant decommissioning and plant closure cost obligations
to the Yankee Companies that own the Yankee Atomic, Connecticut Yankee (CY)
and Maine Yankee nuclear power plants. Each plant has been shut down and is
undergoing decommissioning. The Yankee Companies collect decommissioning and
closure costs through wholesale FERC-approved rates charged under power
purchase agreements to NU electric utility companies CL&P, PSNH and WMECO.
These companies in turn pass these costs on to their customers through state
regulatory commission-approved retail rates. A portion of the decommissioning
and closure costs have already been collected, but a substantial portion
related to the decommissioning of CY has not yet been filed at and approved
for collection by the FERC.
During 2002, NU was notified by CYAPC and YAEC that the estimated cost of
decommissioning these units and other closure costs increased over prior
estimates due to higher anticipated costs for spent fuel storage, security
and liability and property insurance. NU's share of this increase is $177.1
million. Following FERC rate cases by the Yankee Companies, NU expects to
recover the higher decommissioning costs from the retail customers of CL&P,
PSNH and WMECO.
In June 2003, CYAPC notified NU that it had terminated its contract with
Bechtel Power Corporation (Bechtel) for the decommissioning of the CY nuclear
power plant. CYAPC terminated the contract based on its determination that
Bechtel's decommissioning work has been incomplete and untimely and that
Bechtel refused to perform the remaining decommissioning work. Bechtel has
filed a counterclaim against CYAPC asserting a number of claims and seeking a
variety of remedies, including monetary and punitive damages and the
rescission of the contract. Bechtel has amended its complaint to add claims
for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of
decommissioning its nuclear unit. NU's aggregate share of the estimated
increased cost primarily related to the termination of Bechtel is approximately
$167.7 million. The respective shares of the estimated increased costs
recorded in 2003 are as follows: CL&P, $118.1 million; PSNH, $17.1 million;
and WMECO, $32.5 million.
CYAPC is seeking recovery of additional decommissioning costs and other
damages from Bechtel and, if necessary, its surety. In pursuing this
recovery through pending litigation, CYAPC is also exploring options to
structure an appropriate rate application to be filed with the FERC, with any
resulting adjustments being charged to the owners of the nuclear unit,
including CL&P, PSNH and WMECO. The timing, amount and outcome of these
filings cannot be predicted at this time.
NU cannot at this time predict the timing or outcome of the FERC proceeding
required for the collection of these remaining decommissioning and closure
costs. Although management believes that these costs will ultimately be
recovered from the customers of CL&P, PSNH and WMECO, there is a risk that
the FERC may not allow these costs, the estimates of which have increased
significantly in 2003 and 2002, to be recovered in wholesale rates. If FERC
does not allow these costs to be recovered in wholesale rates, NU would
expect the state regulatory commissions to disallow these costs in retail
rates as well.
At December 31, 2003 and 2002, NU's remaining estimated obligations for
decommissioning and closure costs for the shut down units owned by CYAPC,
YAEC and MYAPC were $469.2 million and $354.5 million, respectively.
H. CONSOLIDATED EDISON, INC. MERGER LITIGATION
Certain gain and loss contingencies exist with regard to the litigation
related to the 1999 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' merger agreement. On
March 12, 2001, NU filed suit against Con Edison seeking damages in excess of
$1 billion.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for
breach of contract, fraudulent inducement and negligent misrepresentation.
Con Edison claimed that it is entitled to recover a portion of the merger
synergy savings estimated to have a net present value 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 completed discovery in the litigation and both submitted
motions for summary judgment. The court denied Con Edison's motion in its
entirety, leaving NU's claim for breach of the merger agreement and partially
granted NU's motion for summary judgment by eliminating Con Edison's claims
against NU for fraud and negligent misrepresentation.
Various other motions in the case are now pending. 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.
8. 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, Unrestricted Cash from Counterparties, Restricted
Cash - LMP, and Special Deposits: The carrying amounts approximate fair
value due to the short-term nature of these cash items.
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 $33.8 million and $17.9 million held for benefit of the SERP
were recorded at their fair market values at December 31, 2003 and 2002, of
$36.9 million and $17.8 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, 2003
- ---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- ---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 87.5
Long-term debt -
First mortgage bonds 743.0 833.3
Other long-term debt 1,810.7 1,896.5
Rate reduction bonds 1,730.0 1,860.7
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
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
- ---------------------------------------------------------------------
Other long-term debt includes $256.4 million and $253.6 million of fees and
interest due for spent nuclear fuel disposal costs at December 31, 2003
and 2002, respectively.
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.
9. 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 $3.7 million
in 2003, $1.7 million in 2002, and $13.1 million in 2001. Interest included
in capital lease rental payments was $2.3 million in 2003, $0.6 million in
2002, and $4.7 million in 2001. Operating lease rental payments charged to
expense were $7.6 million in 2003, $7.8 million in 2002, and $7 million in
2001.
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, 2003 are as follows:
- ------------------------------------------------------------------
(Millions of Dollars) Capital Operating
Year Leases Leases
- ------------------------------------------------------------------
2004 $ 3.1 $ 21.9
2005 3.1 19.6
2006 2.9 17.6
2007 2.6 14.2
2008 2.3 12.0
Thereafter 20.1 27.4
- ------------------------------------------------------------------
Future minimum lease payments $34.1 $112.7
Less amount representing interest 18.2
- ------------------------------------------------------------------
Present value of future
minimum lease payments $15.9
- ------------------------------------------------------------------
10. 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) 2002 Change 2003
- ----------------------------------------------------------------------
Qualified cash flow
hedging instruments $15.5 $9.3 $24.8
Unrealized
(losses)/gains
on securities (0.1) 2.1 2.0
Minimum supplemental
executive retirement
pension liability
adjustments (0.5) (0.3) (0.8)
- ----------------------------------------------------------------------
Accumulated other
comprehensive
income $14.9 $11.1 $26.0
- ----------------------------------------------------------------------
- ----------------------------------------------------------------------
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 supplemental
executive retirement
pension liability
adjustments (0.6) 0.1 (0.5)
- ----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(32.5) $47.4 $14.9
- ----------------------------------------------------------------------
The changes in the components of other comprehensive income/(loss) are
reported net of the following income tax effects:
- ----------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- ----------------------------------------------------------------------
Qualified cash flow
hedging instruments $(6.4) $(33.1) $24.3
Unrealized
(losses)/gains
on securities (1.4) 3.3 (1.9)
Minimum supplemental
executive retirement
pension liability
adjustments - - -
- ----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(7.8) $(29.8) $22.4
- ----------------------------------------------------------------------
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) 2003 2002
- ----------------------------------------------------------------------
Balance at beginning of year $15.5 $(36.9)
- ----------------------------------------------------------------------
Hedged transactions
recognized into earnings (5.3) 17.0
Change in fair value 5.0 29.2
Cash flow transactions entered
into for the period 9.6 6.2
- ----------------------------------------------------------------------
Net change associated with the
current period hedging
transactions 9.3 52.4
- ----------------------------------------------------------------------
Total fair value adjustments
included in accumulated other
comprehensive income $24.8 $ 15.5
- ----------------------------------------------------------------------
11. 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. In
2003, 2002 and 2001, 355,153 options, 2,968,933 options and 1,268,887
options, respectively, were excluded from the following table as these
options were antidilutive. The following table sets forth the components of
basic and diluted EPS.
- --------------------------------------------------------------------------------------------------------
(Millions of Dollars,
except share information) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------
Income before preferred dividends of subsidiaries $126.7 $157.7 $273.2
Preferred dividends of subsidiaries 5.6 5.6 7.3
- --------------------------------------------------------------------------------------------------------
Income before cumulative effect of accounting change 121.1 152.1 265.9
Cumulative effect of accounting change, net of tax benefit (4.7) - (22.4)
- --------------------------------------------------------------------------------------------------------
Net income $116.4 $152.1 $243.5
- --------------------------------------------------------------------------------------------------------
Basic EPS common shares outstanding (average) 127,114,743 129,150,549 135,632,126
Dilutive effect of employee stock options 125,981 190,811 285,297
- --------------------------------------------------------------------------------------------------------
Fully diluted EPS common shares outstanding (average) 127,240,724 129,341,360 135,917,423
- --------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Income before cumulative effect of accounting change $0.95 $1.18 $1.97
Cumulative effect of accounting change, net of tax benefit (0.04) - (0.17)
- --------------------------------------------------------------------------------------------------------
Net income $0.91 $1.18 $1.80
- --------------------------------------------------------------------------------------------------------
Fully diluted earnings per common share:
Income before cumulative effect of accounting change $0.95 $1.18 $1.96
Cumulative effect of accounting change, net of tax benefit (0.04) - (0.17)
- --------------------------------------------------------------------------------------------------------
Net income $0.91 $1.18 $1.79
- --------------------------------------------------------------------------------------------------------
12. SEGMENT INFORMATION
- -------------------------------------------------------------------------------
NU is organized between the Utility Group and NU Enterprises based on each
segments' regulatory environment or lack thereof. The Utility Group segment,
including both electric and gas utilities, represents approximately 71
percent, 78 percent and 77 percent of NU's total revenues for the years ended
December 31, 2003, 2002 and 2001, respectively, and primarily includes the
operations of the electric utilities, CL&P, PSNH and WMECO, whose complete
financial statements are included in NU's combined report on Form 10-K. The
Utility Group - gas segment also includes the operations of Yankee Gas.
Utility Group 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.
The NU Enterprises segment includes Select Energy, NGC, SESI, NGS, and their
respective subsidiaries. The generation operations of HWP and Woods Network
are also included in the NU Enterprises segment.
On January 1, 2000, Select Energy began serving one half of CL&P's standard
offer load for a four-year period ending on 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 $688
million or 27 percent for the year ended December 31, 2003, approximately
$631 million or 35 percent for the year ended December 31, 2002, and
approximately $648 million or 31 percent for the year ended December 31,
2001, of total NU Enterprises' revenues. Total CL&P purchases from NU
Enterprises are eliminated in consolidation. Select Energy revenues from
NSTAR represented approximately $273.3 million or 13 percent of total NU
Enterprises revenues for the year ended December 31, 2001. Beginning in
2002, Select Energy also provides basic generation service in the New Jersey
market. Select Energy revenues related to these contracts represented
approximately $380.4 million or 15 percent of total NU Enterprises' revenues
for the year ended December 31, 2003 and approximately $207.4 million or 12
percent for the year ended December 31, 2002. Additionally, WMECO's purchases
from Select Energy for standard offer and default service and for other
transactions with Select Energy represented approximately $143 million,
$14 million and $4 million of total NU Enterprises' revenues for the years
ended December 31, 2003, 2002 and 2001, respectively. No other individual
customer represented in excess of 10 percent of NU Enterprises' revenues for
the years ended December 31, 2003, 2002 or 2001.
Eliminations and other in the following table includes the results for Mode 1
Communications, Inc., an investor in a fiber-optic communications network,
the results of the nonenergy-related subsidiaries of Yankee Energy System,
Inc., (Yankee Energy Services Company, RMS, Yankee Energy Financial Services,
and NorConn Properties, Inc.) the companies' parent and service companies,
and the company's investment in Acumentrics. Interest expense included in
eliminations and other primarily relates to the debt of NU parent. Inter-
segment eliminations of revenues and expenses are also included in
eliminations and other. Eliminations and other includes NU's investment in
RMS, which was consolidated with NU effective July 1, 2003, resulting in a
negative $4.7 million net of tax cumulative effect of an accounting change.
- -------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2003
- -------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
- -------------------------------------------------------------------------------------------------------------
Operating revenues $3,975.1 $ 361.5 $2,574.8 $(842.2) $ 6,069.2
Depreciation and amortization (494.9) (23.4) (19.6) (2.3) (540.2)
Other operating expenses (3,115.6) (311.7) (2,508.7) 840.4 (5,095.6)
- -------------------------------------------------------------------------------------------------------------
Operating income/(loss) 364.6 26.4 46.5 (4.1) 433.4
Interest expense, net (169.6) (13.1) (49.6) (14.0) (246.3)
Other income/(loss), net 2.1 (2.4) 2.4 (2.5) (0.4)
Income tax (expense)/benefit (66.5) (3.6) (2.8) 12.9 (60.0)
Preferred dividends (5.6) - - - (5.6)
- -------------------------------------------------------------------------------------------------------------
Income/(loss) before cumulative
effect of accounting change 125.0 7.3 (3.5) (7.7) 121.1
Cumulative effect of accounting
change, net of tax benefit - - - (4.7) (4.7)
- -------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 125.0 $ 7.3 $ (3.5) $ (12.4) $ 116.4
- -------------------------------------------------------------------------------------------------------------
Total assets $8,218.0 $1,068.6 $2,125.5 $(103.2) $11,308.9
- -------------------------------------------------------------------------------------------------------------
Total investments in plant $ 450.6 $ 55.2 $ 17.7 $ 26.4 $ 549.9
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2002
- -------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
- -------------------------------------------------------------------------------------------------------------
Operating revenues $3,815.0 $ 282.0 $1,800.8 $(660.8) $ 5,237.0
Depreciation and amortization (618.9) (24.0) (21.6) (2.6) (667.1)
Other operating expenses (2,716.7) (218.1) (1,818.5) 650.1 (4,103.2)
- -------------------------------------------------------------------------------------------------------------
Operating income/(loss) 479.4 39.9 (39.3) (13.3) 466.7
Interest expense, net (187.2) (14.2) (43.9) (25.2) (270.5)
Other income/(loss), net 42.1 (0.8) 0.6 1.9 43.8
Income tax (expense)/benefit (121.7) (7.3) 29.4 17.3 (82.3)
Preferred dividends (5.6) - - - (5.6)
- -------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 207.0 $ 17.6 $ (53.2) $ (19.3) $ 152.1
- -------------------------------------------------------------------------------------------------------------
Total assets $ 7,815.1 $1,042.7 $1,978.2 $ (71.1) $ 10,764.9
- -------------------------------------------------------------------------------------------------------------
Total investments in plant $ 376.1 $ 69.8 $ 21.0 $ 18.1 $ 485.0
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2001
- -------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
- -------------------------------------------------------------------------------------------------------------
Operating revenues $4,075.5 $ 378.0 $2,074.9 $(767.4) $ 5,761.0
Depreciation and amortization (1,619.3) (33.3) (10.3) 478.8 (1,184.1)
Other operating expenses (1,964.7) (294.6) (2,017.4) 239.0 (4,037.7)
- -------------------------------------------------------------------------------------------------------------
Operating income/(loss) 491.5 50.1 47.2 (49.6) 539.2
Interest expense, net (199.3) (14.0) (42.5) (23.9) (279.7)
Other income/(loss), net 72.8 4.1 5.8 104.9 187.6
Income tax (expense)/benefit (154.3) (14.3) (4.4) (0.9) (173.9)
Preferred dividends (7.3) - - - (7.3)
- -------------------------------------------------------------------------------------------------------------
Income/(loss) before cumulative
effect of accounting change 203.4 25.9 6.1 30.5 265.9
Cumulative effect of accounting
change, net of tax benefit - - (22.0) (0.4) (22.4)
- -------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 203.4 $ 25.9 $ (15.9) $ 30.1 $ 243.5
- -------------------------------------------------------------------------------------------------------------
Total investments in plant $ 375.3 $ 47.3 $ 14.6 $ 14.2 $ 451.4
- -------------------------------------------------------------------------------------------------------------
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,
- --------------------------------------------------------------------------------------------------------------------
2003
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,584,183 $1,330,038 $1,640,117 $1,514,818
Operating Income 164,032 105,096 129,727 34,511
Income/(Loss) Before Cumulative Effect of
Accounting Change 60,204 26,869 43,979 (9,900)
Cumulative Effect of Accounting Change,
Net of Tax Benefit - - (4,741) -
- --------------------------------------------------------------------------------------------------------------------
Net Income $ 60,204 $ 26,869 $ 39,238 $ (9,900)
- --------------------------------------------------------------------------------------------------------------------
Basic and Fully Diluted Earnings Per Common Share:
- --------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change $ 0.47 $ 0.21 $ 0.35 $ (0.08)
Cumulative Effect of Accounting Change,
Net of Tax Benefit - - (0.04) -
- --------------------------------------------------------------------------------------------------------------------
Net Income $ 0.47 $ 0.21 $ 0.31 $ (0.08)
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
2002
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,279,229 $1,164,205 $1,389,366 $1,404,200
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
- --------------------------------------------------------------------------------------------------------------------
(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 2002 and from those reported in the
first three quarters of 2003 on the reports on Form 10-Q because of the
adoption of EITF Issue No. 03-11. Quarterly operating revenues as
previously reported for 2003 and 2002 are as follows (thousands of
dollars):
-------------------------------------------------------
Operating Revenues
-------------------------------------------------------
Quarter Ended 2003 2002
-------------------------------------------------------
March 31 $1,688,437 $1,284,461
June 30 1,457,541 1,141,928
September 30 2,054,274 1,414,304
December 31 1,525,104 1,375,628
-------------------------------------------------------
Selected Consolidated Financial Data (Unaudited)
- ------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except
percentages and share information) 2003 2002 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Property, Plant and Equipment, Net $ 5,429,916 $ 5,049,369 $ 4,472,977 $ 3,547,215 $ 3,947,434
Total Assets (a) 11,308,884 10,764,880 10,331,923 10,217,149 9,688,052
Total Capitalization (b) 4,926,587 4,670,771 4,576,858 4,739,417 5,216,456
Obligations Under Capital Leases (b) 15,938 16,803 17,539 159,879 181,293
- ------------------------------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues (c) $ 6,069,156 $ 5,237,000 $ 5,760,949 $ 5,876,620 $ 4,471,251
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits 121,152 152,109 265,942 205,295 34,216
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (4,741) - (22,432) - -
Extraordinary Loss, Net of Tax Benefit - - - (233,881) -
- ------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 116,411 $ 152,109 $ 243,510 $ (28,586) $ 34,216
- ------------------------------------------------------------------------------------------------------------------------------
Common Share Data:
Basic Earnings/(Loss) Per Common Share:
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits $0.95 $1.18 $1.97 $ 1.45 $ 0.26
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (0.04) - (0.17) - -
Extraordinary Loss, Net of Tax Benefit - - - (1.65) -
- ------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $0.91 $1.18 $1.80 $(0.20) $ 0.26
- ------------------------------------------------------------------------------------------------------------------------------
Fully Diluted Earnings/(Loss) Per Common Share:
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits $0.95 $1.18 $1.96 $ 1.45 $ 0.26
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (0.04) - (0.17) - -
Extraordinary Loss, Net of Tax Benefit - - - (1.65) -
- ------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $0.91 $1.18 $1.79 $(0.20) $ 0.26
- ------------------------------------------------------------------------------------------------------------------------------
Basic Common Shares Outstanding (Average) 127,114,743 129,150,549 135,632,126 141,549,860 131,415,126
Fully Diluted Common Shares
Outstanding (Average) 127,240,724 129,341,360 135,917,423 141,967,216 132,031,573
Dividends Per Share $ 0.58 $ 0.53 $ 0.45 $ 0.40 $ 0.10
Market Price - Closing (high) (d) $20.17 $20.57 $23.75 $24.25 $22.00
Market Price - Closing (low) (d) $13.38 $13.20 $16.80 $18.25 $13.56
Market Price - Closing (end of year) (d) $20.17 $15.17 $17.63 $24.25 $20.56
Book Value Per Share (end of year) $17.73 $17.33 $16.27 $15.43 $15.80
Tangible Book Value Per Share (end of year) $15.27 $14.62 $13.71 $13.09 $15.53
Rate of Return Earned on Average
Common Equity (%) 5.2 7.0 11.2 (1.3) 1.6
Market-to-Book Ratio (end of year) 1.1 0.9 1.1 1.6 1.3
- ------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity 46% 47% 46% 47% 40%
Preferred Stock (b) (e) 2 3 3 4 5
Long-Term Debt (b) 52 50 51 49 55
- ------------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100%
- ------------------------------------------------------------------------------------------------------------------------------
(a) Total assets were not adjusted for cost of removal prior to 2002.
(b) Includes portions due within one year.
(c) Operating revenue amounts have been reclassified from those reported in
2002 and 2001 related to the adoption of EITF Issue No. 03-11.
(d) Market price information reflects closing prices as presented in the
Wall Street Journal.
(e) Excludes $100 million of Monthly Income Preferred Securities.
Consolidated Sales Statistics (Unaudited)
- -------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
Revenues: (Thousands)
Residential $1,669,199 $1,512,397 $1,490,487 $1,469,439 $1,517,913
Commercial 1,409,445 1,294,943 1,303,351 1,256,126 1,272,969
Industrial 514,076 485,592 549,808 566,625 560,801
Other Utilities 1,678,397 1,247,029 1,554,053 1,884,082 926,056
Streetlighting and Railroads 44,977 43,679 43,889 45,998 45,564
Non-franchised Sales - - - 16,932 24,659
Miscellaneous (50,586) 41,357 64,371 96,666 52,357
- -------------------------------------------------------------------------------------------------------------------------------
Total Electric 5,265,508 4,624,997 5,005,959 5,335,868 4,400,319
Gas 573,660 430,642 566,814 461,716 -
Other 229,988 181,361 188,176 79,036 70,932
- -------------------------------------------------------------------------------------------------------------------------------
Total $6,069,156 $5,237,000 $5,760,949 $5,876,620 $4,471,251
- -------------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 14,824 13,923 13,322 12,940 12,912
Commercial 14,471 14,103 13,751 13,023 12,850
Industrial 6,223 6,265 6,790 7,130 7,050
Other Utilities 18,791 82,538 48,336 42,127 33,575
Streetlighting and Railroads 348 344 332 333 314
Non-franchised Sales - - - 107 147
- -------------------------------------------------------------------------------------------------------------------------------
Total 54,657 117,173 82,531 75,660 66,848
- -------------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 1,631,582 1,614,239 1,610,154 1,576,068 1,569,932
Commercial 186,792 183,577 171,218 166,114 164,932
Industrial 7,644 7,763 7,730 7,701 7,721
Other 3,858 3,949 3,969 3,917 3,908
- -------------------------------------------------------------------------------------------------------------------------------
Total Electric 1,829,876 1,809,528 1,793,071 1,753,800 1,746,493
Gas 192,816 190,855 190,998 185,328 -
- -------------------------------------------------------------------------------------------------------------------------------
Total 2,022,692 2,000,383 1,984,069 1,939,128 1,746,493
- -------------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 9,087 8,611 8,251 8,233 8,243
- -------------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $1,024.20 $ 934.90 $ 923.70 $ 934.94 $ 969.38
- -------------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 11.27 cents 10.86 cents 11.20 cents 11.36 cents 11.76 cents
Commercial 9.74 9.18 9.48 9.65 9.91
Industrial 8.26 7.75 8.10 7.95 7.95
- -------------------------------------------------------------------------------------------------------------------------------