EXHIBIT 13.2
2002 Annual Report
The Connecticut Light and Power Company and Subsidiaries
Index
Contents Page
- -------- ----
Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 1
Independent Auditors' Report and Report of Independent
Public Accountants.............................................. 9
Consolidated Balance Sheets....................................... 10-11
Consolidated Statements of Income................................. 12
Consolidated Statements of Comprehensive Income................... 12
Consolidated Statements of Common Stockholder's Equity............ 13
Consolidated Statements of Cash Flows............................. 14
Notes to Consolidated Financial Statements........................ 15
Selected Consolidated Financial Data.............................. 25
Consolidated Quarterly Financial Data (Unaudited)................. 25
Consolidated Statistics (Unaudited)............................... 26
Preferred Stockholder and Bondholder Information.................. Back Cover
Management's Discussion and Analysis
Financial Condition
- -------------------
Overview
The Connecticut Light and Power Company (CL&P or the company), the largest
operating subsidiary of Northeast Utilities (NU), earned $85.6 million in
2002 compared with $109.8 million in 2001. The lower 2002 net income was
largely attributable to an after-tax gain of $17.7 million CL&P recorded in
2001 associated with the sale of the Millstone nuclear units (Millstone).
NU's other subsidiaries include Public Service Company of New Hampshire
(PSNH), Western Massachusetts Electric Company (WMECO), Yankee Energy
System, Inc., North Atlantic Energy Corporation (NAEC), Select Energy, Inc.
(Select Energy), Northeast Generation Company, Northeast Generation
Services Company, and Select Energy Services, Inc.
CL&P's revenues for 2002 decreased to $2.5 billion from revenues of $2.6
billion for 2001. The decrease in revenues was primarily due to lower
wholesale revenues, partially offset by higher retail revenues. Wholesale
revenues decreased due to the sale of the Millstone units in the first
quarter of 2001, lower revenues from sales of energy and capacity resulting
from the buyout of cogenerator purchase contracts and lower wholesale
market prices, and lower revenue from expiring market based contracts.
Retail revenues were higher due to the recovery of previously deferred fuel
costs and higher sales.
Future Outlook
CL&P is expected to have reduced earnings in 2003 as compared to 2002. The
primary reason for the earnings decrease at CL&P in 2003 is a significant
reduction in the projected level of pension income in 2003 and forward.
CL&P recorded $50.6 million in pre-tax pension income in 2002,
approximately 40 percent of which was capitalized and reflected as a
reduction to the cost of capital expenditures with the remainder being
recognized in the consolidated statements of income as reductions to
operating expenses. In 2003, as a result of continued poor performance in
the equity markets, CL&P is projecting the total level of pre-tax pension
income to decline to approximately $27 million, with a similar percentage
being reflected as a reduction to the cost of capital expenditures.
Pension income is annually adjusted during the second quarter based upon
updated actuarial valuations, at which time the 2003 estimate may be
modified.
Liquidity
The year 2002 represented the final year of a four-year process of selling
all of the regulated generation assets owned by CL&P.
On November 1, 2002, CL&P consummated the sale of its 4.06 percent
ownership interest in Seabrook. CL&P received approximately $36 million of
total cash proceeds from the sale of Seabrook.
In November 2002, CL&P, along with NU's other regulated utilities, renewed
their $300 million credit line under terms similar to the arrangement that
expired in November 2002. A previous credit line had provided up to $350
million for the regulated companies. CL&P had no borrowings on this credit
line at December 31, 2002.
In addition to its revolving credit arrangement, CL&P can access up to $100
million by selling certain of its accounts receivable. At December 31,
2002, CL&P had $40 million sold under this arrangement. This accounts
receivable arrangement is expected to be renewed in July 2003.
Rate reduction bonds are included on the consolidated balance sheets of
CL&P, even though the debt is nonrecourse to CL&P. At December 31, 2002,
CL&P had $1.2 billion in rate reduction bonds outstanding, compared with
$1.4 billion outstanding at December 31, 2001. All outstanding rate
reduction bonds of CL&P are scheduled to be amortized by December 30, 2010.
Interest on the rate reduction bonds totaled $75.7 million in 2002,
compared with $60.6 million in 2001. Amortization of the rate reduction
bonds totaled $112.9 million in 2002, compared with $79.7 million in 2001.
CL&P fully recovered the amortization and interest payments from customers
in 2002, and the bonds had no impact on net income. Moreover, because the
debt is nonrecourse to CL&P, the three rating agencies that rate CL&P's
debt and preferred stock securities do not include the revenues, expenses,
or outstanding securities related to the rate reduction bonds in
establishing the credit ratings of CL&P.
CL&P is also considering refinancing approximately $200 million of spent
nuclear fuel obligations in 2003. These obligations are included in long-
term debt.
CL&P's net cash flows provided by operating activities increased to $387.4
million in 2002, compared with $12.2 million in 2001. Cash flows provided
by operating activities increased primarily due to changes in working
capital, primarily receivables and unbilled revenues and accounts payable,
partially offset by the decrease in net income in 2002.
There was a lower level of investing and financing activities in 2002 as
compared to 2001, primarily due to the issuance of rate reduction
certificates and the buyout and buydown of independent power producer
contracts in 2001. The level of common dividends totaled $60.1 million in
2002 and 2001.
CL&P has embarked upon a significant upgrade program within its service
territory. Over the past five years, CL&P has increased its annual
investment in electric utility plant by approximately 50 percent. Much of
the additional investment has been devoted to improving the reliability of
CL&P's electric distribution system. Over the next several years, CL&P has
proposed a significant expansion of its 345,000 volt electric transmission
system into southwestern Connecticut at a cost that is likely to exceed
$500 million. If Connecticut regulators approve the expansion, CL&P's
construction expenditures are projected to exceed $350 million annually
from 2004 through 2007. Such a program would significantly exceed CL&P's
projections for internally generated operating cash flows and would require
CL&P to access the capital markets for financing. In 2003, CL&P is
expected to generate enough cash internally to fund most, if not all, of
its capital needs.
Implementation of Standard Market Design
On March 1, 2003, the New England independent system operator (ISO)
implemented a new Standard Market Design (SMD). As part of this effort,
locational marginal pricing (LMP) will be utilized to assign value and
causation to transmission congestion. Transmission congestion costs will
be assigned to the load zone in which the congestion occurs. Those costs
are now spread across virtually all New England electric customers. In
addition, the implementation of SMD will impact wholesale energy contracts
with respect to the energy delivery points contained in those contracts.
Connecticut has been designated a single load zone. Due to the
transmission constraints and inadequate generation, Connecticut could
experience significant additional congestion costs under SMD. The New
England ISO estimates that the costs of transmission congestion for 2003 in
New England will range between $50 million and $300 million. The New
England ISO estimates that the majority of this congestion and its costs
will be in Connecticut, where approximately 80 percent are expected to be
paid by CL&P beginning on March 1, 2003. CL&P believes that under the
terms of its contracts with its standard offer suppliers, these costs are
its responsibility. The contracts with the standard offer suppliers expire
on December 31, 2003. In addition, the determination of the energy
delivery points associated with the standard offer service contracts under
SMD could also produce significant costs for CL&P that management cannot
determine at this time.
Another factor affecting the level of congestion costs is the designation
of certain generating units by the New England ISO as units needed for
system reliability. Some of the companies owning these units have applied
to the Federal Energy Regulatory Commission (FERC) for "reliability must
run" (RMR) treatment. RMR treatment allows these units to receive cost of
service - based payments that recognize their reliability value. Prior to
March 1, 2003, all RMR costs were spread across New England with all
utilities being billed by the New England ISO based upon their share of New
England's load. NU's regulated electric utilities were responsible for
approximately 25 percent of these costs. Effective with the March 1, 2003
implementation of SMD by the New England ISO, RMR costs will be allocated
to the load zone in which the RMR unit is located. At present, the only
load zone that will experience a cost increase in which a NU regulated
electric company operates is Connecticut. With respect to the Connecticut
load zone, there are two generating units operating under a RMR contract
with an additional contract pending before FERC. These contracts are for
one year terms, and one contract contains an extension option. On a
combined basis, these two RMR contracts will result in an annual cost of
approximately $45 million to the Connecticut load zone. CL&P accounts for
approximately 80 percent of the Connecticut load zone, and would be
responsible for approximately $36 million of this cost. In the near
future, it is probable that there will be significant new requests for RMR
treatment in Connecticut which, if approved by FERC, would add significant
additional costs to the total cost of energy in Connecticut. However,
generating units operating under RMR contracts could potentially mitigate
the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of
providing regulated electric service in Connecticut. A Connecticut
Department of Public Utility Control (DPUC) regulatory proceeding is
expected to be initiated soon to determine the appropriate recovery
mechanism for these costs. If these costs are incurred before the final
recovery mechanism is established by the DPUC, CL&P expects to record a
regulatory asset for those costs incurred. See Critical Accounting
Policies and Estimates - Regulatory Accounting and Assets included in
management's discussion and analysis for further information.
Business Development and Capital Expenditures
CL&P's capital expenditures, excluding nuclear fuel, totaled $242.3 million
in 2002, compared with $237.4 million in 2001 and $208.2 million in 2000.
CL&P expects capital expenditures to increase to $326.9 million in 2003.
CL&P spent $141.2 million related to its overhead and underground electric
distribution system in 2002 and expects to spend a similar amount in 2003.
CL&P spent $35.6 million to upgrade its transmission system in 2002, and
expects its transmission capital expenditures to increase to $95 million in
2003, if its current construction plans receive regulatory approval. CL&P
also spent $20 million on new meters and customer services, and $17 million
on substations in 2002.
In 2001, CL&P announced plans for three transmission projects. In
September 2002, the Connecticut Siting Council (CSC) approved the first
project, a plan to replace an undersea electric transmission line between
Norwalk, Connecticut and Northport - Long Island, New York, at an estimated
cost of $80 million. CL&P owns 50 percent of the line with the Long Island
Power Authority also owning 50 percent. The project still requires federal
and New York state approvals. Given the approval process and the
uncertainty created by the recent damage to the existing transmission line,
the expected in-service date is currently under evaluation. At
December 31, 2002, CL&P has capitalized approximately $4.8 million related
to this project.
In early 2003, the CSC completed hearings on the second project, a $135
million proposal to build a new 345,000 volt transmission line between
Norwalk, Connecticut and Bethel, Connecticut. A decision is expected in
April 2003. The current cost estimate is based on building the entire
transmission line aboveground. Alternative proposals have been made to
build all or part of the line underground, which likely would result in
significantly higher construction costs. CL&P hopes to have the new
transmission line operational by the summer of 2005. At December 31, 2002,
CL&P has capitalized approximately $8.8 million related to this project.
By mid-2003, CL&P expects to apply to the CSC for approval of a third
project, the installation of another 345,000 volt transmission line between
Norwalk, Connecticut and Middletown, Connecticut. Estimated construction
costs of this overhead line are approximately $500 million. CL&P will
jointly construct this project with United Illuminating with CL&P owning 80
percent or approximately $400 million of the project. At December 31,
2002, CL&P has capitalized approximately $2.4 million related to this
project.
Construction of these three projects would significantly enhance CL&P's
ability to provide reliable electric service to the rapidly growing energy
market in southwestern Connecticut. Despite the need for such facilities,
significant opposition has been raised. As a result, management cannot be
certain as to the expected in-service dates or the ultimate cost of these
projects. Should the plans proceed, applicable law provides that CL&P will
be able to recover its operating cost and carrying costs through federally
approved transmission tariffs.
Regional Transmission Organization
The FERC has required all transmission owning utilities, including CL&P, to
voluntarily start forming regional transmission organizations (RTO) or to
state why this process has not begun.
CL&P has been discussing with the other transmission owners in New England
the potential to form an Independent Transmission Company (ITC). If
formed, the ITC would be a for-profit entity and would perform certain
transmission functions required by the FERC, including tariff control,
system planning and system operations. The remaining functions required by
the FERC would be performed by the ISO regarding the energy market and
short-term reliability. Together, the ITC, if formed, and ISO would form
the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their
intention to form an RTO. On November 22, 2002, the two ISOs withdrew
their joint petition to FERC. The New England ISO intends to make an RTO
filing with the transmission owners in New England in 2003. The agreements
needed to create the RTO and to define the working relationships among the
ISO and the transmission owners should be created in 2003, and will allow
the RTO to begin operation shortly thereafter. The agreements are expected
to include provisions for the future creation of one or more ITCs within
the RTO. The creation of the RTO will require a FERC rate case, and the
impact on CL&P's return on equity as a result of this rate case cannot be
estimated at this time. At December 31, 2002, CL&P capitalized $0.8
million related to RTO formation activities.
Merchant Energy Company Counterparty Exposures
CL&P has entered into various transactions with subsidiaries of NRG Energy,
Inc. (NRG). NRG's credit rating has been downgraded to below investment
grade by all three major rating agencies, and NRG is presently in default
on debt service payments. Management does not expect that the resolution
of the transactions with NRG will have a material adverse effect on CL&P's
consolidated financial condition or results of operations. Additionally,
CL&P does not have a significant level of exposure to other merchant energy
companies. For further information regarding these transactions, see NU's
2002 report on Form 10-K, Item 1, "Business."
Restructuring and Rate Matters
Since retail competition began in Connecticut in 2000, an extremely small
number of customers have opted to choose an alternate supplier. At
December 31, 2002, virtually all of CL&P's customers were procuring their
electricity through CL&P's standard offer service. In 2003, Select Energy
will continue to supply 50 percent of CL&P's standard offer supply service
with NRG Power Marketing, Inc. (NRG-PM), a subsidiary of NRG, contracted to
supply 45 percent and a subsidiary of Duke Energy, Inc. contracted to
supply the remaining 5 percent of service. On November 18, 2001, at NRG-
PM's request, CL&P filed an application with the DPUC to raise the standard
offer rate from an average of $0.0495 per kilowatt-hour (kWh) to $0.0595
per kWh to help promote competition in advance of the January 1, 2004
termination of the standard offer period and to provide financial relief to
standard offer suppliers. In December 2001, the DPUC rejected CL&P's
request, but opened two new dockets to examine the absence of effective
retail competition in Connecticut and the financial condition of the
suppliers. The first docket culminated in a joint study report issued in a
DPUC decision on February 15, 2002, which provided the DPUC's and the
Office of Consumer Counsel's findings on how to best structure default
service and other issues related to electric industry restructuring. In
the second docket, the DPUC concluded on June 17, 2002, that it would not
commence further proceedings.
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed
a new proposal with the DPUC to maintain current total rates, but to shift
$0.007 per kWh from being used to recover stranded costs to instead provide
additional payments to NRG-PM and Select Energy to ensure electric
reliability in southwestern Connecticut. On July 26, 2002, the DPUC denied
the proposal. CL&P continues to evaluate NRG-PM's ability to meet its
obligations under the standard offer service contract. If CL&P is required
to seek an alternate source of supply, CL&P would pursue recovery of any
additional costs associated with obtaining such supply from NRG-PM pursuant
to the contract and may be required to seek DPUC approval to flow through any
such costs to customers. Management believes that recovery of these costs,
should they be incurred, would be permitted under the provisions of
Connecticut's electric utility restructuring legislation and with the
DPUC's prior decisions. On February 21, 2003, Fitch Ratings lowered its
rating outlook on CL&P to negative as a result of its concern over timely
recovery of purchased-power costs if NRG-PM were to default on its CL&P
standard offer obligations and CL&P needs to acquire replacement supply
service at significantly higher prices.
On September 27, 2001, CL&P filed its application with the DPUC for
approval of the disposition of the proceeds in the amount of approximately
$1.2 billion from the sale of the Millstone units. This application
described and requested DPUC approval for CL&P's treatment of its share of
the proceeds from the sale. In accordance with Connecticut's electric
utility industry restructuring legislation, CL&P was required to utilize
any gains from the Millstone sale to offset stranded costs. The DPUC's
final decision regarding this application was issued on February 27, 2003,
and increased the amount of net proceeds used to reduce stranded costs by
$26.9 million. The earnings impact of the final decision will be reflected
in 2003 earnings and will result in an increase in first quarter net income
of $2.6 million.
On November 1, 2002, CL&P sold its interest in Seabrook to a subsidiary of
FPL Group, Inc. The gain on the sale was used to reduce stranded costs.
CL&P continues to be subject to the earnings sharing mechanism implemented
by the DPUC, under which CL&P's earnings in excess of a 10.3 percent return
on equity will be shared equally by shareholders and ratepayers.
CL&P expects to file a distribution rate case with the DPUC in mid-2003
that would be effective January 1, 2004. Also in the second half of 2003,
CL&P will need to secure bids for power supply contracts for 2004 to meet
the needs of its customers. Management has not yet identified what level
of rates it will request in 2004, but believes that several factors could
combine to result in a significant increase in supply costs in 2004. The
first is the expiration of current standard offer supply contracts.
Another factor is the likely impact of LMP in New England with the
implementation of SMD. Implementation of such pricing, which occurred on
March 1, 2003, will force Connecticut electric customers to bear the
significant additional costs of serving southwestern Connecticut with less
efficient local generation because of insufficient transmission capacity to
bring cheaper energy into the region. CL&P's completed and planned
reliability improvements and transmission construction program will also
impact the level of rates management will request in 2004.
For further information regarding commitments and contingencies related to
restructuring, see Note 6A, "Commitments and Contingencies - Restructuring
and Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interest in Seabrook.
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC)
consummated the sale of its nuclear generating unit. CL&P owns 10.1
percent of VYNPC.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of
Millstone 1 and 2, and CL&P, PSNH, and WMECO sold their ownership interests
in Millstone 3.
Under the terms of these asset divestitures, the purchasers agreed to
assume responsibility for decommissioning their respective units. For
further information regarding these divestitures and nuclear
decommissioning, see Note 5, "Nuclear Generation Asset Divestitures," and
Note 6F, "Nuclear Decommissioning and Plant Closure Costs," to the
consolidated financial statements. For further information regarding spent
nuclear fuel disposal costs, see Note 6C, "Commitments and Contingencies -
Spent Nuclear Fuel Disposal Costs," to the consolidated financial
statements.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult,
subjective or complex judgments. Changes in these estimates, assumptions
and judgments, in and of themselves, could materially impact the financial
condition of CL&P. The following describes accounting policies and
estimates that management believes are the most critical in nature:
Presentation: In accordance with current accounting pronouncements, CL&P's
consolidated financial statements include all subsidiaries upon which
significant control is maintained and all intercompany transactions between
these subsidiaries are eliminated as part of the consolidation process.
CL&P has less than 50 percent ownership interests in the Connecticut Yankee
Atomic Power Company, Yankee Atomic Electric Company, Maine Yankee Atomic
Power Company, VYNPC, and two companies that transmit electricity imported
from the Hydro-Quebec system, which are classified as variable interest
entities under Financial Accounting Standards Board Interpretation No. 46,
"Consolidation of Variable Interest Entities," and for which CL&P is not
the primary beneficiary. As a result, management does not expect the
adoption of Interpretation No. 46 to result in the consolidation of any
currently unconsolidated entities or to have any other material impacts on
CL&P's consolidated financial statements.
Revenue Recognition: Revenues are based on rates approved by the DPUC.
These regulated rates are applied to customers' accounts based on their use
of energy. In general, rates can only be changed through formal
proceedings with the DPUC.
The determination of the energy sales to individual customers is based on
the reading of their meters, which occurs on a systematic basis throughout
the month. At the end of each month, amounts of energy delivered to
customers since the date of the last meter reading are estimated and the
corresponding unbilled revenue is estimated. This unbilled revenue is
estimated each month based on generation volumes, estimated customer usage
by class, line losses, and applicable customer rates.
Regulatory Accounting and Assets: The accounting policies of CL&P
historically reflect the effects of the rate-making process in accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting
for the Effects of Certain Types of Regulation." CL&P's transmission and
distribution businesses continue to be cost-of-service rate regulated, and
management believes the application of SFAS No. 71 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 this business no longer meets the criteria of
regulatory accounting under SFAS No. 71, that portion of the company will
have to discontinue regulatory accounting and write off regulatory assets.
Such a write-off could have a material impact on CL&P's consolidated
financial statements.
The application of SFAS No. 71 results in the deferral of costs as
regulatory assets that, in some cases, have not yet been approved for
recovery by the applicable regulatory commission. Management must conclude
that any costs deferred as regulatory assets are probable of future
recovery in rates. However, the regulatory commission can reach different
conclusions about the recovery of costs, which can have a material impact
on CL&P's consolidated financial statements. Management believes it is
probable that CL&P will recover its investments in long-lived assets,
including regulatory assets.
Pension and Postretirement Benefit Obligations: CL&P participates in a
uniform noncontributory defined benefit retirement plan (Plan) covering
substantially all regular NU employees and also provides certain health
care benefits, primarily medical and dental, and life insurance benefits
through a benefit plan to retired employees. For each of these plans, the
development of the benefit obligation, fair value of plan assets, funded
status and net periodic benefit credit or cost is based on several
significant assumptions. If these assumptions were changed, the resultant
change in benefit obligations, fair values of plan assets, funded status
and net periodic benefit credits or costs could have a material impact on
CL&P's consolidated financial statements.
CL&P's pre-tax periodic pension income for the Plan, excluding settlements,
curtailments, and special termination benefits, totaled $50.6 million and
$61.4 million for the years ended December 31, 2002 and 2001, respectively.
Pension income is calculated based upon a number of actuarial assumptions,
including an expected long-term rate of return on Plan assets of 9.25
percent for 2002 and 9.5 percent for 2001. CL&P expects to use a long-term
rate of return assumption of 8.75 percent for 2003. The pension income
amounts exclude one-time items recorded under SFAS No. 88, "Employers'
Accounting for Settlements and Curtailments of Defined Benefit Pension
Plans and for Termination Benefits," associated with early termination
programs and the sale of the Millstone and Seabrook nuclear units. Net
SFAS No. 88 expenses totaled $8.1 million and $1.2 million for the years
ended December 31, 2002 and 2001, respectively. Approximately 40 percent
of net pension income is capitalized as a reduction to capital additions to
utility plant.
In developing the expected long-term rate of return assumption, CL&P
evaluated input from actuaries, consultants and economists as well as long-
term inflation assumptions and NU's historical 20-year compounded return of
10.7 percent. NU's expected long-term rate of return on Plan assets is
based on target asset allocation assumptions of 45 percent in United States
equities and 14 percent in non-United States equities, both with
expected long-term rates of return of 9.25 percent, 3 percent in emerging
market equities with an expected long-term return of 10.25 percent, 20
percent in fixed income securities with an expected long-term rate of
return of 5.5 percent, 5 percent in high yield fixed income securities with
expected long-term rates of return of 7.5 percent, 8 percent in private
equities with expected long-term rates of return of 14.25 percent, and 5
percent in real estate with expected long-term rates of return of 7.5
percent. The combination of these target allocations and expected returns
results in the overall assumed long-term rate of return of 8.75 percent for
2003. The actual asset allocation at December 31, 2002, was close to these
target asset allocations, and NU regularly reviews the actual asset
allocations and periodically rebalances the investments to the targeted
allocation when appropriate. NU reduced the long-term rate of return
assumption by 0.5 percent and 0.25 percent, respectively, each of the last
two years due to lower rate of return assumptions for most asset classes.
CL&P believes that 8.75 percent is a reasonable long-term rate of return on
Plan assets for 2003. CL&P will continue to evaluate the actuarial
assumptions, including the expected rate of return, at least annually, and
will adjust the appropriate assumptions as necessary.
CL&P bases the actuarial determination of Plan pension income/expense on a
market-related valuation of assets, which reduces year-to-year volatility.
This market-related valuation recognizes investment gains or losses over a
four-year period from the year in which they occur. Investment gains or
losses for this purpose are the difference between the expected return
calculated using the market-related value of assets and the actual return
based on the fair value of assets. Since the market-related value of
assets recognizes gains or losses over a four-year period, the future value
of the market-related assets will be impacted as previously deferred gains
or losses are recognized. There will be no impact on the fair value of
Plan assets. At December 31, 2002, CL&P's portion of the Plan had
cumulative unrecognized investment losses of $234.2 million, which will
increase Plan expense over the next four years by reducing the expected
return on Plan assets. At December 31, 2002, CL&P's portion of the Plan
also had cumulative unrecognized actuarial gains of $57.6 million, which
will reduce Plan expenses over the expected future working lifetime of
active Plan participants, or approximately 13 years. The combined total of
unrecognized investment losses and actuarial gains at December 31, 2002 is
$176.6 million. This amount impacts the actuarially determined prepaid
pension amount recorded on the consolidated balance sheet but has no impact
on expected Plan funding.
The discount rate that is utilized in determining future pension
obligations is based on a basket of long-term bonds that receive one of the
two highest ratings given by a recognized rating agency. To compensate for
the Plan's longer duration 0.25 percent was added to this rating. The
discount rate determined on this basis has decreased from 7.25 percent at
December 31, 2001 to 6.75 percent at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an
expected rate of return on Plan assets of 8.75 percent, a discount rate of
6.75 percent and various other assumptions, CL&P estimates that pension
income/expense for the Plan will be approximately $27 million in income,
approximately $10 million in income and approximately $4 million in expense
in 2003, 2004 and 2005, respectively. Future actual pension income/expense
will depend on future investment performance, changes in future discount
rates and various other factors related to the populations participating in
the plan.
The value of CL&P's portion of the Plan assets has decreased from $910.4
million at December 31, 2001 to $752.7 million at December 31, 2002. The
investment performance returns and declining discount rates have reduced
the funded status of CL&P's portion of the Plan, on a projected benefit
obligation (PBO) basis, from an overfunded position of $284.4 million at
December 31, 2001 to $72.3 million at December 31, 2002. The PBO includes
expectations of future employee service and compensation increases. The
significant deterioration in the funded position of the Plan will likely
result in Plan contributions sooner than previously expected. CL&P has not
made contributions since 1991. This deterioration could also lead to the
requirement under defined benefit plan accounting to record an additional
minimum liability. The total accumulated benefit obligation (ABO) of the
entire Plan was $78 million less than Plan assets at December 31, 2002.
The ABO is the obligation for employee service provided through
December 31, 2002. If the ABO exceeds Plan assets, CL&P may need to record
an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated for each period for which a
statement of income is presented. This process involves estimating CL&P's
actual current tax exposures as well as assessing temporary differences
resulting from differing treatment of items, such as timing of the
deduction of expenses for tax and book accounting purposes. These
differences result in deferred tax assets and liabilities, which are
included in the consolidated balance sheets. CL&P must also assess the
likelihood that the deferred tax assets will be recovered from future
taxable income, and to the extent that recovery is not likely, a valuation
allowance must be established. Significant management judgment is required
in determining income tax expense, deferred tax assets and liabilities and
valuation allowances. CL&P 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,
CL&P has established a regulatory asset. This asset amounted to $170.5
million and $154.2 million at December 31, 2002 and 2001, respectively.
Depreciation: Depreciation expense is calculated based on an asset's
useful life, and judgment is involved when estimating the useful lives of
certain assets. A change in the estimated useful lives of these assets
could have a material impact on CL&P's consolidated financial statements.
Environmental Matters: At December 31, 2002, CL&P has recorded a reserve
for various environmental liabilities. CL&P's environmental liabilities
are based on the best estimate of the amounts to be incurred for the
investigation, remediation and monitoring of the remediation sites. It is
possible that future cost estimates will either increase or decrease as
additional information becomes known.
Special Purpose Entities: CL&P has two special purpose entities (SPE),
which are currently consolidated in the financial statements. During 2001,
to facilitate the issuance of rate reduction certificates intended to
finance certain stranded costs, CL&P established one SPE, CL&P Funding LLC.
The funding company was created as part of state sponsored securitization
programs. CL&P Funding LLC is restricted from engaging in non-related
activities and is required to operate in a manner intended to reduce the
likelihood that it would be included in CL&P's bankruptcy estate if it ever
becomes involved in such bankruptcy proceedings.
The CL&P Receivables Corporation (CRC) is an SPE that was incorporated on
September 5, 1997, and is a wholly owned subsidiary of CL&P. The CRC was
established for the sole purpose of selling CL&P's accounts receivable and
is included in the consolidation of CL&P's financial statements. On July 10,
2002 the CRC renewed its Receivables Purchase and Sale Agreement with
CL&P and a subsidiary of Citigroup, Inc. (Citigroup). The agreement gives
the CRC the right to sell and Citigroup the right to purchase up to $100
million in receivables through July 9, 2003. At December 31, 2002 there
was $40 million outstanding under this facility. Sales of receivables to
Citigroup under this arrangement meet the accounting criteria for
derecognition from the consolidated balance sheet. Accordingly, the $40
million outstanding under this facility is not reflected as debt or
included in the consolidated financial statements.
For further information regarding these types of activities, see Note 1,
"Summary of Significant Accounting Policies," Note 3, "Pension Benefits and
Postretirement Benefits Other Than Pensions," Note 4, "Sale of Customer
Receivables," Note 6B, "Commitments and Contingencies - Environmental
Matters," and Note 12, "Income Tax Expense," to the consolidated financial
statements.
Other Matters
Other Commitments and Contingencies: For further information regarding
other commitments and contingencies, see Note 6, "Commitments and
Contingencies," to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding
CL&P's contractual obligations and commercial commitments at December 31,
2002, is summarized through 2007 as follows:
- ---------------------------------------------------------------------
(Millions of
Dollars) 2003 2004 2005 2006 2007
- ---------------------------------------------------------------------
Capital leases $ 2.6 $ 2.5 $ 2.4 $ 2.4 $ 2.4
Operating leases 12.0 11.0 10.2 9.1 6.1
Long-term contractual
arrangements 230.3 231.9 233.7 236.7 240.4
- ---------------------------------------------------------------------
Totals $244.9 $245.4 $246.3 $248.2 $248.9
- ---------------------------------------------------------------------
Rate reduction bond amounts are not included in this table. For further
information regarding CL&P's contractual obligations and commercial
commitments, see Note 8, "Leases," and Note 6E, "Long-Term Contractual
Arrangements," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward
looking statements, which are statements of future expectations and not
facts including, but not limited to, statements regarding future earnings,
refinancings, the use of proceeds from restructuring, and the recovery of
operating costs. Words such as estimates, expects, anticipates, intends,
plans, and similar expressions identify forward looking statements. Actual
results or outcomes could differ materially as a result of further actions
by state and federal regulatory bodies, competition and industry
restructuring, changes in economic conditions, changes in weather patterns,
changes in laws, developments in legal or public policy doctrines,
technological developments, volatility in electric and natural gas
commodity markets, and other presently unknown or unforeseen factors.
Results of Operations
The components of significant income statement variances for the past two
years are provided in the table below.
<Table>
<Caption>
- --------------------------------------------------------------------------------
2002 over/(under)2001 2001 over/(under) 2000
Income Statement Variances --------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
- --------------------------------------------------------------------------------
Operating Revenues $(139) (5)% $(290) (10)%
Operating Expenses:
Fuel, purchased and net
interchange power (37) (2) (151) (9)
Other operation (10) (3) (102) (25)
Maintenance (26) (25) (30) (22)
Depreciation 2 2 (21) (18)
Amortization of regulatory
assets, net (568) (76) 649 (a)
Taxes other than income taxes 7 5 (7) (5)
Gain on sale of utility plant 505 97 (522) (100)
- --------------------------------------------------------------------------------
Total operating expenses (127) (5) (184) (7)
- --------------------------------------------------------------------------------
Operating income (12) (4) (106) (29)
Interest expense, net - - 22 23
Other income/(loss), net (30) (58) 75 (a)
- --------------------------------------------------------------------------------
Income before income tax expense (42) (22) (53) (22)
Income tax expense (18) (21) (15) (15)
- --------------------------------------------------------------------------------
Net income/(loss) $ (24) (22)% $ (38) (26)%
================================================================================
</Table>
(a) Percent greater than 100.
Operating Revenues
Operating revenues decreased $139 million or 5 percent in 2002, primarily
due to lower wholesale and other revenues ($184 million), partially offset
by higher retail revenues ($45 million). Wholesale revenues were lower due
to the inclusion in 2001 of revenue from the output of the Millstone
nuclear units ($62 million), lower revenues from sales of energy and
capacity ($63 million) resulting from the buyout of cogenerator purchase
contracts and lower wholesale market prices, and lower revenue from
expiring market based contracts ($24 million). Retail revenues were higher
due to the collection of deferred fuel costs ($25 million) and higher
retail sales. Retail sales increased 1.8 percent compared to 2001.
Total revenues decreased $290 million or 10 percent in 2001, primarily due
to lower wholesale revenues ($325 million) and lower transmission revenues
($19 million), partially offset by higher retail revenues ($57 million).
Wholesale revenues were lower primarily as a result of the sale of the
Millstone units at the end of the first quarter of 2001 and lower sales of
capacity and energy. The lower transmission revenues were partially offset
by lower transmission expenses. Retail revenues increased primarily due to
higher retail sales ($43 million) and the recovery of previously deferred
fuel costs ($19 million), partially offset by a rate decrease ($5 million).
Retail sales increased 2.4 percent compared to 2000.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $37 million in
2002 primarily due to lower purchased-power costs resulting from the
buydown and buyout of various cogeneration contracts ($50 million), lower
market-based contracts ($23 million) and lower nuclear fuel expense ($8
million), partially offset by the 2002 amortization of deferred fuel
expenses which are being recovered ($25 million) and the higher expenses
related to the standard offer supply and associated deferrals ($17
million).
Fuel, purchased and net interchange power expense decreased in 2001,
primarily due to lower purchased power costs resulting from the buydown and
buyout of various cogeneration contracts and lower nuclear fuel expense.
Other Operation and Maintenance
Other operation and maintenance (O&M) expenses decreased $36 million in
2002, primarily due to lower nuclear expense as a result of the sale of the
Millstone units at the end of the first quarter of 2001 ($52 million),
lower distribution expenses ($8 million), partially offset by higher
transmission expenses ($16 million) and higher administrative and general
expenses ($10 million).
Other O&M expenses decreased $132 million in 2001, primarily due to lower
nuclear expenses ($95 million) as a result of the sale of the Millstone
units at the end of the first quarter of 2001, lower administrative and
general expenses ($22 million), lower transmission expenses ($16 million),
and lower fossil/hydro expenses ($3 million), partially offset by higher
distribution expenses ($4 million).
Depreciation
Depreciation expense increased $2 million in 2002, primarily due to higher
utility plant balances.
Depreciation expense decreased in 2001, primarily due to the elimination of
decommissioning expenses as a result of the sale of the Millstone units at
the end of the first quarter of 2001.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $568 million in 2002,
primarily due to lower amortizations related to the sale of the Millstone
units ($524 million) and lower amortizations of the nuclear investment ($42
million).
Amortization of regulatory assets, net increased in 2001, primarily due to
the amortization related to the gain on the sale of the Millstone units
($524 million) and higher amortization related to securitized assets ($68
million), stranded costs ($30 million), and other amortizations related to
restructuring ($27 million).
Taxes Other Than Income Taxes
Taxes other than income taxes increased $7 million in 2002, primarily due
to payments to the Town of Waterford for its loss of property tax resulting
from electric utility restructuring ($15 million), partially offset by the
recognition of a Connecticut sales and use tax audit settlement for the
years 1993 through 2001 ($7 million). CL&P is recovering through rates the
additional property tax payments to the Town of Waterford.
Taxes other than income taxes decreased in 2001, primarily due to
settlement of a property tax appeal with the City of Meriden in 2001 ($5
million) and the reduction in property tax due to the sale of the Millstone
units ($12 million), partially offset by higher gross earnings tax paid on
higher revenues ($8 million).
Gain on Sale of Utility Plant
CL&P recorded a gain on the sale of its ownership share in Seabrook in 2002
($16 million) as compared to the 2001 gain on the sale of the Millstone
units ($522 million). A corresponding amount of amortization expenses was
recorded.
CL&P recorded a gain on the sale of its ownership share in the Millstone
units. A corresponding amount of amortization expense was recorded in
2001.
Interest Expense, Net
Interest expense, net increased in 2001, primarily due to interest
associated with the issuance of rate reduction certificates in 2001,
partially offset by lower interest on other long-term debt resulting from
reacquisitions and retirements of long-term debt in 2001.
Other Income/(Loss), Net
Other income, net decreased $30 million in 2002, primarily due to the gain
recognized in 2001 on the sale of the Millstone units ($29 million).
Other income/(loss), net increased in 2001, primarily due to the gain on
the sale of CL&P's ownership share in the Millstone units ($29 million),
the settlement, in 2000, of Millstone-related litigation, net of insurance
proceeds ($9 million), a write-off associated with the former CMEEC nuclear
entitlement ($6 million) in 2000 and higher interest income in 2001,
including the allowed return on deferred fuel balances ($10 million),
interest on an Internal Revenue Service tax settlement ($10 million), and
interest income related to the City of Meriden property tax refund ($2
million).
Income Tax Expense
Income tax expense decreased in 2002 primarily due to lower book taxable
income.
Independent Auditors' Report
- ----------------------------
To the Board of Directors of
The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company and subsidiaries (a Connecticut
corporation and a wholly owned subsidiary of Northeast Utilities) (the
"Company") as of December 31, 2002 and 2001, and the related consolidated
statements of income, comprehensive income, common stockholder's equity,
and cash flows for the years then ended. The consolidated financial
statements of the Company as of December 31, 2000, and for the year then
ended, were audited by other auditors who have ceased operations. Those
auditors expressed an unqualified opinion on those financial statements in
their report dated January 22, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 2002 and 2001 consolidated financial statements present
fairly, in all material respects, the financial position of The Connecticut
Light and Power Company and subsidiaries as of December 31, 2002 and 2001,
and the results of their operations and their cash flows for the years then
ended in conformity with accounting principles generally accepted in the
United States of America.
/s/ DELOITTE & TOUCHE LLP
---------------------
DELOITTE & TOUCHE LLP
Hartford, Connecticut
January 28, 2003
(February 27, 2003 as to Note 6A)
Report of Independent Public Accountants
- ----------------------------------------
To the Board of Directors of
The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company (a Connecticut corporation and a
wholly owned subsidiary of Northeast Utilities) and subsidiaries as of
December 31, 2001 and 2000, and the related consolidated statements of
income, comprehensive income, common stockholder's equity and cash flows
for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of The
Connecticut Light and Power Company and subsidiaries as of December 31,
2001 and 2000, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United
States.
/s/ ARTHUR ANDERSEN LLP
-------------------
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 22, 2002
Readers of these consolidated financial statements should be aware
that this report is a copy of a previously issued Arthur Andersen LLP
report and that this report has not been reissued by Arthur Andersen
LLP. Furthermore, this report has not been updated since January 22,
2002, and Arthur Andersen LLP completed its last post-audit review of
December 31, 2001, consolidated financial information on May 13, 2002.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
- ----------------------------------------------------------------------------------------------
At December 31, 2002 2001
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash and cash equivalents.................................. $ 159 $ 773
Investments in securitizable assets........................ 178,908 206,367
Receivables, less provision for uncollectible
accounts of $525 in 2002 and 2001 ........................ 88,001 77,801
Accounts receivable from affiliated companies.............. 51,060 22,134
Unbilled revenues.......................................... 5,801 7,492
Notes receivable from affiliated companies................. 1,900 77,200
Fuel, materials and supplies, at average cost.............. 32,379 33,085
Prepayments and other...................................... 19,407 17,873
---------- ----------
377,615 442,725
---------- ----------
Property, Plant and Equipment:
Electric utility........................................... 3,139,128 3,127,548
Less: Accumulated depreciation.......................... 1,113,991 1,236,638
---------- ----------
2,025,137 1,890,910
Construction work in progress.............................. 153,556 134,964
Nuclear fuel, net.......................................... - 3,299
---------- ----------
2,178,693 2,029,173
---------- ----------
Deferred Debits and Other Assets:
Regulatory assets.......................................... 1,702,677 1,877,191
Prepaid pension............................................ 276,173 233,692
Nuclear decommissioning trusts, at market.................. - 6,231
Other...................................................... 96,925 138,715
---------- ----------
2,075,775 2,255,829
---------- ----------
Total Assets................................................. $4,632,083 $4,727,727
========== ==========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
- ----------------------------------------------------------------------------------------------
At December 31, 2002 2001
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Accounts payable....................................... $ 174,890 $ 132,593
Accounts payable to affiliated companies............... 117,904 85,057
Accrued taxes.......................................... 34,350 34,993
Accrued interest....................................... 10,077 10,369
Other.................................................. 48,495 47,342
---------- ----------
385,716 310,354
---------- ----------
Rate Reduction Bonds..................................... 1,245,728 1,358,653
---------- ----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes...................... 756,461 820,444
Accumulated deferred investment tax credits............ 93,408 95,996
Deferred contractual obligations....................... 234,537 141,497
Other.................................................. 276,325 283,399
---------- ----------
1,360,731 1,341,336
---------- ----------
Capitalization:
Long-Term Debt......................................... 827,866 824,349
---------- ----------
Preferred Stock - Nonredeemable........................ 116,200 116,200
---------- ----------
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2002 and 7,584,884 shares outstanding in 2001.... 60,352 75,849
Capital surplus, paid in............................. 327,299 414,018
Retained earnings.................................... 308,554 286,901
Accumulated other comprehensive (loss)/income........ (363) 67
---------- ----------
Common Stockholder's Equity............................ 695,842 776,835
---------- ----------
Total Capitalization..................................... 1,639,908 1,717,384
---------- ----------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization..................... $4,632,083 $4,727,727
========== ==========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<Table>
<Caption>
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2002 2001 2000
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.......................................... $2,507,036 $2,646,123 $2,935,922
---------- ---------- ----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power.............. 1,477,347 1,514,418 1,665,806
Other.................................................. 300,439 310,477 412,230
Maintenance............................................... 80,132 106,228 136,141
Depreciation.............................................. 98,360 96,212 117,305
Amortization of regulatory assets, net.................... 178,274 746,693 97,315
Taxes other than income taxes............................. 137,299 130,656 137,846
Gain on sale of utility plant............................. (16,143) (521,590) -
---------- ---------- ----------
Total operating expenses................................ 2,255,708 2,383,094 2,566,643
---------- ---------- ----------
Operating Income............................................ 251,328 263,029 369,279
Interest Expense:
Interest on long-term debt................................ 41,332 56,527 85,980
Interest on rate reduction bonds.......................... 75,705 60,644 -
Other interest............................................ 3,925 3,958 12,886
---------- ---------- ----------
Interest expense, net................................... 120,962 121,129 98,866
---------- ---------- ----------
Other Income/(Loss), Net.................................... 22,112 52,804 (22,224)
---------- ---------- ----------
Income Before Income Tax Expense............................ 152,478 194,704 248,189
Income Tax Expense.......................................... 66,866 84,901 100,054
---------- ---------- ----------
Net Income.................................................. $ 85,612 $ 109,803 $ 148,135
========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income................................................. $ 85,612 $ 109,803 $ 148,135
---------- ---------- ----------
Other comprehensive (loss)/income, net of tax:
Unrealized (losses)/gains on securities.................. (452) (439) 90
Minimum pension liability adjustments.................... (22) - -
---------- ---------- ----------
Other comprehensive (loss)/income, net of tax......... (474) (439) 90
---------- ---------- ----------
Comprehensive Income....................................... $ 85,138 $ 109,364 $ 148,225
========== ========== ==========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
Accumulated
Capital Other
Common Surplus, Retained Comprehensive Total
Stock Paid In Earnings Income/(Loss) (a)
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 2000........................ $122,229 $665,598 $153,254 $ 416 $941,497
Net income for 2000........................... 148,135 148,135
Cash dividends on preferred stock............. (7,402) (7,402)
Cash dividends on common stock................ (72,014) (72,014)
Redemption of preferred stock................. (749) (749)
Repurchase of common stock.................... (46,380) (253,620) (300,000)
Capital stock expenses, net................... 1,963 1,963
Allocation of benefits - ESOP (b)............. 21,224 21,224
Other comprehensive income.................... 90 90
-------- -------- -------- ----- --------
Balance at December 31, 2000...................... 75,849 413,192 243,197 506 732,744
Net income for 2001........................... 109,803 109,803
Cash dividends on preferred stock............. (5,559) (5,559)
Cash dividends on common stock................ (60,072) (60,072)
Capital stock expenses, net................... 826 826
Allocation of benefits - ESOP................. (468) (468)
Other comprehensive loss...................... (439) (439)
-------- -------- -------- ----- --------
Balance at December 31, 2001...................... 75,849 414,018 286,901 67 776,835
Net income for 2002........................... 85,612 85,612
Cash dividends on preferred stock............. (5,559) (5,559)
Cash dividends on common stock................ (60,145) (60,145)
Repurchase of common stock.................... (15,497) (84,493) (99,990)
Capital stock expenses, net................... 232 232
Allocation of benefits - ESOP................. (2,458) 1,745 (713)
Other comprehensive loss...................... (430) (430)
-------- -------- -------- ----- --------
Balance at December 31, 2002...................... $ 60,352 $327,299 $308,554 $(363) $695,842
======== ======== ======== ===== ========
</Table>
(a) The company has a dividend restriction as well as two tests it must meet
before it can pay out any dividends. The most restrictive of which limits
the company's ability to pay out approximately $275.4 million of equity at
December 31, 2002.
(b) In June 1999, CL&P paid NU parent $30.5 million for NU shares issued from
1992 through 1998 on behalf of its employees in accordance with NU's 401(k)
plan. This transaction resulted in a reduction of the NU parent loss and
a tax benefit to CL&P. The amount in 2000 represents the remaining
previously unallocated 1993 through 1999 NU parent losses.
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income....................................................... $ 85,612 $ 109,803 $ 148,135
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation................................................... 98,360 96,212 117,305
Deferred income taxes and investment tax credits, net.......... (71,880) (144,559) 5,672
Net amortization of recoverable energy costs................... 30,787 5,162 4,155
Amortization of regulatory assets, net......................... 178,274 746,693 97,315
Tax benefit for 1993-1999 from
reduction in NU parent losses................................ - - 21,461
Gain on sale of utility plant.................................. (16,143) (521,590) -
Prepaid pension................................................ (42,481) (63,020) (170,672)
Net other sources/(uses) of cash............................... 62,868 (107,024) 111,594
Changes in working capital:
Receivables and unbilled revenues, net......................... (37,435) (144,419) (109,938)
Fuel, materials and supplies................................... (1,017) 3,247 1,271
Accounts payable............................................... 74,831 (58,400) 171,729
Accrued taxes.................................................. (643) 1,922 (136,313)
Investments in securitizable assets............................ 27,459 61,779 9,474
Other working capital (excludes cash).......................... (1,184) 26,440 3,204
-------- ---------- ---------
Net cash flows provided by operating activities.................... 387,408 12,246 274,392
-------- ---------- ---------
Investing Activities:
Investments in plant:
Electric utility plant......................................... (242,301) (237,423) (208,249)
Nuclear fuel................................................... (57) (1,992) (35,709)
--------- ---------- ---------
Cash flows used for investments in plant......................... (242,358) (239,415) (243,958)
NU system Money Pool borrowing/(lending)......................... 75,300 (39,200) (49,700)
Investments in nuclear decommissioning trusts.................... (1,086) (74,866) (25,133)
Net proceeds from the sale of utility plant...................... 35,887 827,681 686,807
Buyout/buydown of IPP contracts.................................. - (1,029,008) -
Other investment activities, net................................. 23,395 (10,164) 10,246
--------- ---------- ---------
Net cash flows (used in)/provided by investing activities.......... (108,862) (564,972) 378,262
-------- ----------- ---------
Financing Activities:
Repurchase of common stock....................................... (99,990) - (300,000)
Issuance of rate reduction bonds................................. - 1,438,400 -
Retirement of rate reduction bonds............................... (112,924) (79,747) -
Net(decrease)/increase in short-term debt........................ - (115,000) 25,000
Reacquisitions and retirements of long-term debt................. - (416,155) (179,071)
Reacquisitions and retirements of preferred stock................ - - (99,539)
Retirement of monthly income preferred securities................ - (100,000) -
Retirement of capital lease obligation........................... - (145,800) -
Cash dividends on preferred stock................................ (5,559) (5,559) (7,402)
Cash dividends on common stock................................... (60,145) (60,072) (72,014)
Other financing activities, net.................................. (542) 31,971 (14,531)
--------- ---------- ---------
Net cash flows (used in)/provided by financing activities.......... (279,160) 548,038 (647,557)
--------- ---------- ---------
Net (decrease)/increase in cash and cash equivalents............... (614) (4,688) 5,097
Cash and cash equivalents - beginning of year...................... 773 5,461 364
--------- ---------- ---------
Cash and cash equivalents - end of year............................ $ 159 $ 773 $ 5,461
========= ========== =========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized............................. $ 117,718 $ 120,645 $ 96,735
========= ========== =========
Income taxes..................................................... $ 141,724 $ 230,144 $ 226,380
========= ========== =========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. About The Connecticut Light and Power Power Company
The Connecticut Light and Power Company (CL&P or the company) along with
the Public Service Company of New Hampshire (PSNH), Western Massachusetts
Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), Holyoke
Water Power Company (HWP), and Yankee Energy System, Inc. (Yankee) are the
operating companies comprising the Northeast Utilities system and are
wholly owned by Northeast Utilities (NU). CL&P furnishes franchised retail
electric service in Connecticut, while PSNH and WMECO furnish franchised
retail electric service in New Hampshire and western Massachusetts. NAEC
previously sold all of its entitlement to the capacity and output of the
Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two
life-of-unit, full cost recovery contracts (Seabrook Power Contracts).
Seabrook was sold on November 1, 2002. NU's other subsidiaries include
HWP, a company engaged in the production of electric power, Yankee, the
parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's
largest natural gas distribution system, and several competitive
subsidiaries including Select Energy, Inc., Northeast Generation Company,
Northeast Generation Services Company, and Select Energy Services, Inc.
CL&P is registered with the Securities and Exchange Commission (SEC) under
the Securities Exchange Act of 1934. NU is registered with the SEC as a
holding company under the Public Utility Holding Company Act of 1935 (1935
Act), and NU, including CL&P, is subject to the provisions of the 1935 Act.
Arrangements among CL&P, 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. CL&P is subject to further
regulation for rates, accounting and other matters by the FERC and the
Connecticut Department of Public Utility Control (DPUC).
Several wholly owned subsidiaries of NU provide support services for NU's
companies, including CL&P, and in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, engineering, financial, information
resources, legal, operational, planning, purchasing, and other services to
NU's companies. Until the sale of Seabrook on November 1, 2002, North
Atlantic Energy Service Corporation had operational responsibility for
Seabrook. Three other subsidiaries construct, acquire or lease some of the
property and facilities used by NU's companies.
B. Presentation
The consolidated financial statements of CL&P include the accounts of all
subsidiaries. Intercompany transactions have been eliminated in
consolidation.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent liabilities
at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from those estimates.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
C. New Accounting Standards
Asset Retirement Obligations: In June 2001, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards
(SFAS) No. 143, "Accounting for Asset Retirement Obligations." This
statement requires that legal obligations associated with the retirement of
property, plant and equipment be recognized as a liability at fair value
when incurred and when a reasonable estimate of the fair value of the
liability can be made. SFAS No. 143 is effective on January 1, 2003, for
CL&P. Management has completed its review process for potential asset
retirement obligations (AROs) and has not identified any material AROs
which have been incurred. However, management has identified certain
removal obligations which arise in the ordinary course of business that
either have a low probability of occurring or are not material in nature.
These types of obligations primarily relate to transmission and
distribution lines and poles, telecommunication towers, transmission cables
and certain FERC or state regulatory agency re-licensing issues.
A portion of CL&P's regulated rates is intended to recover the cost of
removal of certain utility assets. The amounts recovered do not represent
AROs. At December 31, 2002, CL&P maintained approximately $154.5 million
in cost of removal regulatory liabilities, which are included in its
accumulated provision for depreciation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others." Interpretation
No. 45 requires that disclosures be made by a guarantor in its interim and
annual financial statements about its obligations under certain guarantees
that it has issued and clarifies that a guarantor is required to recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. Interpretation No. 45 does
not apply to certain guarantee contracts, such as residual value guarantees
provided by lessees in capital leases, guarantees that are accounted for as
derivatives, guarantees that represent contingent consideration in a
business combination, guarantees issued between either parents and their
subsidiaries or corporations under common control, a parent's guarantee of
a subsidiary's debt to a third party, and a subsidiary's guarantee of the
debt owed to a third party by either its parent or another subsidiary of
that parent. The initial recognition and initial measurement provisions of
Interpretation No. 45 are applicable to CL&P on a prospective basis to
guarantees issued or modified after January 1, 2003. Currently, management
does not expect the adoption of the initial recognition and initial
measurement provisions of Interpretation No. 45 to have a material impact
on CL&P's consolidated financial statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB
issued Interpretation No. 46, "Consolidation of Variable Interest
Entities." Interpretation No. 46 addresses the consolidation and
disclosure requirements for companies that hold an equity interest in a
variable interest entity (VIE), regardless of the date on which the VIE was
created. Interpretation No. 46 requires consolidation of a VIE's assets,
liabilities and noncontrolling interests at fair value when a company is
the primary beneficiary, which is defined as a company that absorbs a
majority of the expected losses, risks and revenues from the VIE as a
result of holding a contractual or other financial interest in the VIE.
Consolidation is not required under Interpretation No. 46 for those
companies that hold a significant equity interest in a VIE but are not the
primary beneficiary. Interpretation No. 46 is effective for CL&P beginning
in the third quarter of 2003. At December 31, 2002, CL&P held equity
interests in various VIEs, for which CL&P was not the primary beneficiary,
as CL&P does not absorb a majority of the expected losses, risks and
revenues from the VIEs or provide a substantial portion of financial
support. As a result, management does not expect the adoption of
Interpretation No. 46 to have a material impact on CL&P's consolidated
financial statements. For further information regarding CL&P's investments
in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric
Utility Plant" to the consolidated financial statements.
D. Equity Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P owns common stock in four
regional nuclear companies (Yankee Companies). CL&P's ownership interests
in the Yankee Companies at December 31, 2002 and 2001, which are accounted
for on the equity method, are 34.5 percent of the Connecticut Yankee Atomic
Power Company (CYAPC), 24.5 percent of the Yankee Atomic Electric Company
(YAEC), 12 percent of the Maine Yankee Atomic Power Company (MYAPC), and
10.1 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC).
CL&P's total equity investment in the Yankee Companies and its exposure to
loss as a result of these investments at December 31, 2002 and 2001, is
$32.2 million and $34.7 million, respectively. These investments are VIE's
under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear
generating plant, each Yankee Company owns a single decommissioned nuclear
generating plant. On July 31, 2002, VYNPC consummated the sale of its
nuclear generating plant to a subsidiary of Entergy Corporation for
approximately $180 million.
Seabrook: CL&P had a 4.06 percent joint ownership interest in Seabrook, a
1,148 megawatt nuclear generating unit. On November 1, 2002, CL&P
consummated the sale of its ownership interest in Seabrook to a subsidiary
of FPL Group, Inc. (FPL). At December 31, 2001, plant-in-service and the
accumulated provision for depreciation for CL&P's share of Seabrook totaled
$174.7 million and $164.8 million, respectively.
E. Depreciation
The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable utility plant-
in-service, which range primarily from 3 years to 50 years, adjusted for
salvage value and removal costs, as approved by the appropriate regulatory
agency where applicable. Depreciation rates are applied to plant-in-
service from the time they are placed in service. When plant is retired
from service, the original cost of the plant, including costs of removal
less salvage, is charged to the accumulated provision for depreciation.
The depreciation rates for the several classes of electric utility plant-in-
service are equivalent to a composite rate of 3.2 percent in 2002 and 3.1
percent in 2001 and 3 percent in 2000.
F. Revenues
Revenues are based on rates approved by the DPUC. These regulated rates
are applied to customer's accounts based on their use of energy. In
general, rates can only be changed through formal proceedings with the
DPUC.
The determination of the energy sales to individual customers is based on
the reading of their meters, which occurs on a systematic basis throughout
the month. At the end of each month, amounts of energy delivered to
customers since the date of the last meter reading are estimated and the
corresponding unbilled revenue is estimated. This unbilled revenue is
estimated each month based on generation volumes, estimated customer usage
by class, line losses, and applicable customer rates.
G. Regulatory Accounting and Assets
The accounting policies of CL&P 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."
CL&P's transmission and distribution businesses continue to be cost-of-
service rate regulated, and management believes the application of SFAS No.
71 to that portion of those businesses continues to be appropriate.
Management also believes it is probable that CL&P will recover its
investments in long-lived assets, including regulatory assets. In
addition, all material regulatory assets are earning a return, except for
securitized regulatory assets. The components of CL&P's regulatory assets
are as follows:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
- ---------------------------------------------------------------------
Recoverable nuclear costs $ 10.6 $ 158.1
Securitized regulatory assets 1,244.5 1,356.3
Income taxes, net 170.5 154.2
Unrecovered contractual obligations 116.8 2.1
Recoverable energy costs, net 49.3 80.1
Other 111.0 126.4
- ---------------------------------------------------------------------
Totals $1,702.7 $1,877.2
- ---------------------------------------------------------------------
In March 2001, CL&P sold its ownership interests in the Millstone units.
The gain on this sale of approximately $521.6 million was used to offset
recoverable nuclear costs, resulting in an unamortized balance of $6
million and $148.9 million at December 31, 2002 and 2001, respectively.
Also included in recoverable nuclear costs is $4.6 million and $9.2 million
at December 31, 2002 and 2001, respectively, associated with Millstone 1
recoverable nuclear costs relating to the recoverable portion of the
undepreciated plant and related assets.
In March 2001, CL&P issued $1.4 billion in rate reduction certificates and
used $1.1 billion of those proceeds to buyout or buydown certain contracts
with independent power producers. The majority of the payments to buyout
or buydown these contracts were recorded as securitized regulatory assets.
CL&P also securitized a portion of its SFAS No. 109 regulatory asset.
CL&P, under the terms of contracts with the Yankee Companies, is
responsible for its proportionate share of the remaining costs of the
units, including decommissioning. These amounts are recorded as
unrecovered contractual obligations. A portion of these obligations was
securitized in 2001 and is included in securitized regulatory assets.
During 2002, CL&P was notified by the Yankee Companies that the estimated
cost of decommissioning their units had increased over prior estimates due
to higher anticipated costs for spent fuel storage, security and liability
and property insurance. In December 2002, CL&P recorded an additional
$115.6 million in deferred contractual obligations and a corresponding
increase in the unrecovered contractual obligations regulatory asset as a
result of these increased costs.
CL&P, under the Energy Policy Act of 1992 (Energy Act), was assessed for
its proportionate share of the costs of decontaminating and decommissioning
uranium enrichment plants owned by the United States Department of Energy
(DOE) (D&D Assessment) when they owned nuclear generating plants. The
Energy Act requires that regulators treat D&D Assessments as a reasonable
and necessary current cost of fuel, to be fully recovered in rates like any
other fuel cost. CL&P is currently recovering these costs through rates.
At December 31, 2002 and 2001, CL&P's total D&D Assessment deferrals were
$17.6 million and $21.1 million, respectively, and have been recorded as
recoverable energy costs, net.
Through December 31, 1999, CL&P had an energy adjustment clause under which
fuel prices above or below base-rate levels were charged to or credited to
customers. CL&P's energy costs deferred and not yet collected under the
energy adjustment clause amounted to $31.7 million and $59 million at
December 31, 2002 and 2001, respectively, which have been recorded as
recoverable energy costs, net. On July 26, 2001, the DPUC authorized CL&P
to assess a charge of approximately $0.002 per kilowatt-hour (kWh) from
August 2001 through December 2003 to collect these costs.
H. Income Taxes
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the
periods in which they affect the determination of taxable income) is
accounted for in accordance with the rate-making treatment of the
applicable regulatory commissions and SFAS No. 109, "Accounting for Income
Taxes."
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give rise to
the accumulated deferred tax obligation is as follows:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
- ---------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $239.6 $279.1
Regulatory assets:
Nuclear stranded investment and
other asset divestitures 213.5 276.1
Securitized contract termination
costs and other 57.5 63.4
Income tax gross-up 134.4 134.4
Other 111.5 67.4
- ---------------------------------------------------------------------
Totals $756.5 $820.4
- ---------------------------------------------------------------------
I. Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand and short-term cash
investments which are highly liquid in nature and have original maturities
of three months or less.
J. Other Income/(Loss), Net
The pre-tax components of CL&P's other income/(loss), net items are as
follows:
- ---------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
- ---------------------------------------------------------------------
Seabrook-related gains $ 2.1 $ - $ -
Gain related to Millstone sale - 29.5 -
Nuclear related costs - - (14.1)
Investment income 10.2 12.9 6.5
Other, net 9.8 10.4 (14.6)
- ---------------------------------------------------------------------
Totals $22.1 $52.8 $(22.2)
- ---------------------------------------------------------------------
2. Short-Term Debt
Limits: The amount of short-term borrowings that may be incurred by CL&P
is subject to periodic approval by either the SEC under the 1935 Act or by
the DPUC. Currently, SEC authorization allows CL&P to incur total short-
term borrowings up to a maximum of $375 million. In addition, the charter
of CL&P contains preferred stock provisions restricting the amount of
unsecured debt that CL&P may incur. At December 31, 2002, CL&P's charter
permits CL&P to incur $480 million of additional unsecured debt.
Credit Agreement: On November 12, 2002, CL&P, PSNH, WMECO, and Yankee Gas
entered into a 364-day unsecured revolving credit facility for $300
million. This facility replaced a $350 million facility for CL&P, PSNH,
WMECO and Yankee Gas, which expired on November 15, 2002 and CL&P may draw
up to $150 million under the facility. Unless extended, the credit
facility will expire on November 11, 2003. At December 31, 2002 and 2001,
there were no borrowings under these facilities.
Under the aforementioned credit agreement, CL&P 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.
This credit agreement provides that CL&P must comply with certain financial
and nonfinancial covenants as are customarily included in such agreements,
including, but not limited to, consolidated debt ratios and interest
coverage ratios. CL&P currently is and expects to remain in compliance
with these covenants.
Money Pool: CL&P is a member of the Northeast Utilities System Money Pool
(Pool). The Pool provides a more efficient use of the cash resources of NU
and reduces outside short-term borrowings. NUSCO administers the Pool as
agent for the member companies. Short-term borrowing needs of the member
companies are first met with available funds of other member companies,
including funds borrowed by NU parent. NU parent may lend to the Pool but
may not borrow. Funds may be withdrawn from or repaid to the Pool at any
time without prior notice. Investing and borrowing subsidiaries receive or
pay interest based on the average daily federal funds rate. Borrowings
based on loans from NU parent, however, bear interest at NU parent's cost
and must be repaid based upon the terms of NU parent's original borrowing.
At December 31, 2002 and 2001, CL&P had $1.9 million and $77.2 million of
lendings to the Pool, respectively. The interest rate on lendings to the
Pool at December 31, 2002 and 2001 was 1.2 percent and 1.5 percent,
respectively.
3. Pension Benefits and Postretirement Benefits Other Than Pensions
Pension Benefits: CL&P participates in a uniform noncontributory defined
benefit retirement plan (Plan) covering substantially all regular NU
employees. Benefits are based on years of service and the employees'
highest eligible compensation during 60 consecutive months of employment.
Pre-tax pension income, approximately 40 percent of which was credited to
utility plant, was $50.6 million in 2002, $61.4 million in 2001, and $57.2
million in 2000. These amounts exclude pension settlements, curtailments
and net special termination expenses of $8.1 million and $1.2 million in
2002 and 2001, respectively. There were no pension settlements,
curtailments, or net special termination expenses recognized in 2000.
Pension income attributable to earnings is as follows:
- --------------------------------------------------------------------------
For Years Ended December 31,
- --------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(50.6) $(61.4) $(57.2)
Net pension income
capitalized as utility plant (a) 20.2 24.6 22.9
- --------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (30.4) (36.8) (34.3)
Settlements, curtailments and
special termnination benefits
reflected in earnings - 3.3 -
- --------------------------------------------------------------------------
Total pension income
included in earnings $(30.4) $(33.5) $(34.3)
- --------------------------------------------------------------------------
(a) Net pension income capitalized as utility plant was calculated
utilizing an average of 40 percent.
Effective February 1, 2002, certain CL&P employees who were displaced were
eligible for a Voluntary Retirement Program (VRP). The VRP supplements
NU's Plan and provides special provisions. Eligible employees include non-
bargaining unit employees or employees belonging to a collective bargaining
unit that has agreed to accept the VRP who are active participants in NU's
Plan at January 1, 2002, and that have been displaced as part of the
reorganization between January 22, 2002 and March 3, 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, CL&P recorded an expense of $8.1 million associated
with special pension termination benefits related to the VRP. CL&P
believes that the cost of the VRP is probable of recovery through regulated
utility rates, and accordingly, the $8.1 million was recorded as a
regulatory asset with no impact on 2002 earnings.
In conjunction with the Voluntary Separation Program (VSP) that was
announced in December 2000, CL&P recorded $1.6 million in settlement income
and $0.8 million in curtailment income in 2001. The VSP was intended to
reduce the generation-related support staff between March 1, 2001 and
February 28, 2002, and was available to non-bargaining unit employees who,
by February 1, 2002, were at least age 50, with a minimum of five years of
credited service, and at December 15, 2000, were assigned to certain groups
and in eligible job classifications.
One component of the VSP included special pension termination benefits
equal to the greater of five years added to both age and credited service
of eligible participants or two weeks of pay for each year of service
subject to a minimum level of 12 weeks and a maximum of 52 weeks for
eligible participants. The special pension termination benefits expense
associated with the VSP totaled $3.6 million in 2001. The net total of the
settlement and curtailment income and the special termination benefits
expense was $1.2 million, of which $3.3 million of costs were included in
operating expenses and $2.1 million was deferred as a regulatory liability
and has been returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries,
including CL&P, also provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees. These benefits are available for employees retiring
from NU who have met specified service requirements. For current employees
and certain retirees, the total benefit is limited to two times the 1993
per retiree health care cost. These costs are charged to expense over the
estimated work life of the employee. CL&P annually funds postretirement
costs through external trusts with amounts that have been rate-recovered
and which also are tax deductible.
In 2001, CL&P recorded PBOP special termination benefits expense of $0.7
million in connection with the VSP. This amount was recorded as a
regulatory asset and collected through regulated utility rates in 2002.
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 $13.5
million decrease in CL&P's benefit obligation under the PBOP plan at
December 31, 2002.
The following table represents information on the plans' benefit
obligation, fair value of plan assets, and the respective plans' funded
status:
<Table>
<Caption>
- -------------------------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(626.0) $(587.3) $(165.7) $(136.3)
Service cost (11.7) (10.0) (2.0) (1.9)
Interest cost (44.8) (43.7) (13.4) (11.1)
Plan amendment (4.5) - 13.5 -
Transfers (2.2) (2.4) (20.4) -
Actuarial loss (45.3) (24.9) (17.7) (32.2)
Benefits paid - excluding lump sum payments 41.5 40.2 18.3 16.0
Benefits paid - lump sum payments 20.7 4.9 - -
Curtailments and settlements - 0.8 - (0.2)
Special termination benefits (8.1) (3.6) - -
- -------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(680.4) $(626.0) $(187.4) $(165.7)
- -------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 910.4 $ 998.8 $ 55.7 $ 62.4
Actual return on plan assets (97.7) (45.7) (5.9) (5.8)
Employer contribution - - 18.3 14.5
Benefits paid - excluding lump sum payments (41.5) (40.2) (18.3) (16.0)
Benefits paid - lump sum payments (20.7) (4.9) - -
Transfers 2.2 2.4 9.5 0.6
- -------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 752.7 $ 910.4 $ 59.3 $ 55.7
- -------------------------------------------------------------------------------------------------
Funded status at December 31 $ 72.3 $ 284.4 $(128.1) $(110.0)
Unrecognized transition (asset)/obligation (1.8) (2.7) 62.7 80.3
Unrecognized prior service cost 29.1 27.6 (2.9) -
Unrecognized net loss/(gain) 176.6 (75.6) 60.9 29.1
- -------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 276.2 $ 233.7 $ (7.4) $ (0.6)
- -------------------------------------------------------------------------------------------------
</Table>
The following actuarial assumptions were used in calculating the plans'
year end funded status:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
- -------------------------------------------------------------------------------
(a) The annual per capita cost of covered health care benefits was assumed
to decrease to 5.00 percent by 2007.
The components of net periodic benefit (income)/expense are as follows:
<Table>
<Caption>
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ---------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
- ---------------------------------------------------------------------------------------------------
Service cost $ 11.7 $ 10.0 $ 9.7 $ 2.0 $ 1.9 $ 1.9
Interest cost 44.8 43.7 42.3 13.4 11.1 10.1
Expected return on plan assets (94.2) (95.3) (88.4) (6.3) (5.5) (4.9)
Amortization of unrecognized net
transition (asset)/obligation (0.9) (0.9) (0.9) 6.9 7.3 7.3
Amortization of prior service cost 3.0 2.6 2.7 - - -
Amortization of actuarial gain (15.0) (21.5) (22.6) - - -
Other amortization, net - - - 2.0 (0.5) (1.9)
- ---------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (50.6) (61.4) (57.2) 18.0 14.3 12.5
- ---------------------------------------------------------------------------------------------------
Settlement income - (1.6) - - - -
Curtailment income - (0.8) - - - -
Special termination benefits expense 8.1 3.6 - - 0.7 -
- ---------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits 8.1 1.2 - - 0.7 -
- ---------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $(42.5) $(60.2) $(57.2) $18.0 $15.0 $12.5
- ---------------------------------------------------------------------------------------------------
</Table>
For calculating pension and postretirement benefit income and expense
amounts, the following assumptions were used:
<Table>
<Caption>
- -----------------------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 9.50% 9.50%
- -----------------------------------------------------------------------------------------
</Table>
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 $0.4 $(0.4)
Effect on postretirement
benefit obligation $5.7 $(5.1)
- --------------------------------------------------------------------------
Currently, CL&P's policy is to annually fund an amount at least equal to
that which will satisfy the requirements of the Employee Retirement Income
Security Act and Internal Revenue Code.
Pension and trust assets are invested primarily in domestic and
international equity securities and bonds.
The trust holding the postretirement benefit health plan assets is subject
to federal income taxes.
4. Sale of Customer Receivables
At December 31, 2002, CL&P had sold accounts receivable of $40 million to a
subsidiary of Citigroup, Inc. with limited recourse through the CL&P
Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.
Additionally, at December 31, 2002, $3.8 million of assets were designated
as collateral and restricted under the agreement with the CRC and included
in the consolidated balance sheets as cash and cash equivalents.
Concentrations of credit risk to the purchaser under this agreement with
respect to the receivables are limited due to CL&P's diverse customer base
within its service territory. At December 31, 2002, amounts sold to CRC
from CL&P, but not sold to the Citgroup, Inc. subsidiary, totaling $178.9
million are included in investments in securitizable assets on the
consolidated balance sheets. No amounts were sold in 2001.
5. Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P consummated the sale of its 4.06
percent 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. CL&P received approximately $36 million of total cash
proceeds from the sale of Seabrook. As part of the sale, FPL assumed
responsibility for decommissioning Seabrook. In connection with the sale,
CL&P recorded a gain in the amount of approximately $16 million, which was
primarily used to offset stranded costs. In the third quarter of 2002,
CL&P received regulatory approvals for the sale of Seabrook from the DPUC.
As a result of these approvals, CL&P eliminated $0.6 million, on a pre-tax
basis, of reserves related to its ownership shares of certain Seabrook
assets.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear
generating plant to a subsidiary of Entergy Corporation (Entergy) for
approximately $180 million. As part of the sale, Entergy assumed
responsibility for decommissioning VYNPC's nuclear generating unit. Under
the terms of the sale, CL&P will continue to buy 9.5 percent of the plant's
output through March 2012 at a range of fixed prices.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of
Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc. (Dominion).
CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to
Dominion along with all of the unaffiliated joint ownership interests in
Millstone 3. CL&P received approximately $828 million of cash proceeds
from the sale and applied the proceeds to taxes and reductions of debt and
equity. As part of the sale, Dominion assumed responsibility for
decommissioning the three Millstone units. In connection with the sale,
CL&P recorded a gain in the amount of $521.6 million, which was used to
offset stranded costs.
6. Commitments and Contingencies
A. Restructuring and Rate Matters
On September 27, 2001, CL&P filed its application with the DPUC for
approval of the disposition of the proceeds in the amount of approximately
$1.2 billion from the sale of the Millstone units to a subsidiary of
Dominion. This application described and requested DPUC approval for
CL&P's treatment of its share of the proceeds from the sale. In accordance
with Connecticut's electric utility industry restructuring legislation,
CL&P was required to utilize any gains from the Millstone sale to offset
stranded costs. The DPUC's final decision regarding this application was
received on February 27, 2003, and did not have a material impact on NU's
2002 results of operations.
B. Environmental Matters
CL&P is subject to environmental laws and regulations intended to mitigate
or remove the effect of past operations and improve or maintain the quality
of the environment. As such, CL&P has active environmental auditing and
training programs and believes it is substantially in compliance with the
current laws and regulations.
However, the normal course of operations may involve activities and
substances that expose CL&P to potential liabilities of which management
cannot determine the outcome. Additionally, management cannot determine
the outcome for liabilities that may be imposed for past acts, even though
such past acts may have been lawful at the time they occurred. Management
does not believe, however, that this will have a material impact on CL&P's
consolidated financial statements.
Based upon currently available information for the estimated remediation
costs at December 31, 2002 and 2001, the liability recorded by CL&P for its
estimated environmental remediation costs amounted to $7.3 million and $2.5
million, respectively.
C. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE for the
disposal of spent nuclear fuel and high-level radioactive waste. The DOE
is responsible for the selection and development of repositories for, and
the disposal of, spent nuclear fuel and high-level radioactive waste. For
nuclear fuel used to generate electricity prior to April 7, 1983 (Prior
Period Fuel), an accrual has been recorded for the full liability and
payment must be made prior to the first delivery of spent fuel to the DOE.
Until such payment is made, the outstanding balance will continue to accrue
interest at the 3-month treasury bill yield rate. At December 31, 2002 and
2001, fees due to the DOE for the disposal of Prior Period Fuel were $205.5
million and $201.9 million, respectively, including interest costs of
$138.9 million and $135.4 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed
currently to customers and paid to the DOE on a quarterly basis. At
December 31, 2002, as CL&P's ownership shares of Millstone and Seabrook
have been sold, CL&P is no longer responsible for fees relating to current
fuel burned at these facilities.
D. Nuclear Insurance Contingencies
In conjunction with the divestiture of Millstone in 2001 and Seabrook in
2002, NU and CL&P terminated their nuclear insurance related to these
plants, and CL&P has no further exposure for potential assessments related
to Millstone and Seabrook. However, through its continuing association
with Nuclear Electric Insurance Limited (NEIL) and CYAPC and VYNPC, NU is
subject to potential retrospective assessments totaling $0.8 million under
its respective NEIL insurance policies.
E. Long-Term Contractual Arrangements
VYNPC: Previously, under the terms of its agreements, CL&P paid its
ownership (or entitlement) shares of costs, which included depreciation,
operation and maintenance (O&M) expenses, taxes, the estimated cost of
decommissioning, and a return on invested capital to VYNPC and recorded
these costs as purchased-power expenses. On July 31, 2002, VYNPC
consummated the sale of its nuclear generating unit to a subsidiary of
Entergy for approximately $180 million. Under the terms of the sale, CL&P
will continue to buy 9.5 percent of the plant's output through March 2012
at a range of fixed prices. CL&P's cost of purchases under contracts with
VYNPC amounted to $16.4 million in 2002, $14.7 million in 2001, and $14.5
million in 2000.
Electricity Procurement Contracts: CL&P has entered into various
arrangements for the purchase of electricity. The total cost of purchases
under these arrangements amounted to $154.6 million in 2002, $205 million
in 2001, and $308.6 million in 2000. These amounts are for independent
power producer contracts and do not include contractual commitments related
to CL&P's standard offer.
Hydro-Quebec: Along with other New England utilities, CL&P has entered
into an agreement to support transmission and terminal facilities to import
electricity from the Hydro-Quebec system in Canada. CL&P is obligated to
pay, over a 30-year period ending in 2020, its proportionate share of the
annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Costs: The estimated future annual costs of CL&P's
significant long-term contractual arrangements are as follows:
- -------------------------------------------------------------------------------
(Millions of Dollars) 2003 2004 2005 2006 2007
- -------------------------------------------------------------------------------
VYNPC $ 18.3 $ 17.4 $ 16.1 $ 16.8 $ 16.3
Electricity Procurement Contracts 197.0 200.0 203.4 206.9 211.7
Hydro-Quebec 15.0 14.5 14.2 13.0 12.4
- -------------------------------------------------------------------------------
Totals $230.3 $231.9 $233.7 $236.7 $240.4
- -------------------------------------------------------------------------------
F. Nuclear Decommissioning and Plant Closure Costs
In conjunction with the Millstone, Seabrook and VYNPC nuclear generation
asset divestitures, the applicable liabilities and nuclear decommissioning
trusts were transferred to the purchasers and the purchasers agreed to
assume responsibility for decommissioning their respective units.
During 2002, NU, along with the other joint owners, were notified by the
Yankee Companies that the estimated cost of decommissioning the units owned
by CYAPC, YAEC and MYAPC increased in total by approximately $380 million
over prior estimates due to higher anticipated costs for spent fuel
storage, security and liability and property insurance. CL&P's share of
this increase would total $115.6 million. Following rate cases to be filed
by the Yankee Companies with the FERC, NU will seek recovery of the higher
decommissioning costs from retail customers through the appropriate state
regulatory agency. At December 31, 2002 and 2001, CL&P's remaining
estimated obligations, for decommissioning for the units owned by CYAPC,
YAEC and MYAPC, which have been shut down, were $234.5 million and $141.5
million, respectively.
7. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and Cash Equivalents: The carrying amounts approximate fair value due
to the short-term nature of cash and cash equivalents.
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value
of CL&P'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
CL&P's financial instruments and the estimated fair values are as follows:
- --------------------------------------------------------------------------
At December 31, 2002
- --------------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- --------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 84.0
Long-term debt -
First mortgage bonds 198.8 242.0
Other long-term debt 629.3 643.0
Rate reduction bonds 1,245.7 1,356.1
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
At December 31, 2001
- --------------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- --------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 62.4
Long-term debt -
First mortgage bonds 198.8 212.8
Other long-term debt 625.8 615.1
Rate reduction bonds 1,358.7 1,388.3
- --------------------------------------------------------------------------
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.
8. Leases
CL&P 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 million
in 2002, $9.2 million in 2001, and $36.3 million in 2000. Interest
included in capital lease rental payments was $2 million in 2002, $3.4
million in 2001, and $7.9 million in 2000. Operating lease rental payments
charged to expense were $6.9 million in 2002, $7.1 million in 2001, and
$9.8 million in 2000.
Future minimum rental payments excluding executory costs, such as property
taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, at December 31, 2002 are as follows:
- --------------------------------------------------------------------------
(Millions of Dollars) Capital Operating
Year Leases Leases
- --------------------------------------------------------------------------
2003 $ 2.6 $12.0
2004 2.5 11.0
2005 2.4 10.2
2006 2.4 9.1
2007 2.4 6.1
After 2007 22.2 15.2
- --------------------------------------------------------------------------
Future minimum lease payments $34.5 $63.6
Less amount representing interest 19.0
- --------------------------------------------------------------------------
Present value of future
minimum lease payments $15.5
- --------------------------------------------------------------------------
9. Accumulated Other Comprehensive Income/(Loss)
The accumulated balance for each other comprehensive income/(loss) item is
as follows:
- --------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars 2001 Change 2002
- --------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.4 $(0.5) $(0.1)
Minimum pension
liability adjustments (0.3) - (0.3)
- --------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.1 $(0.5) $(0.4)
- --------------------------------------------------------------------------
- --------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars 2000 Change 2001
- --------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.8 $(0.4) $ 0.4
Minimum pension
liability adjustments (0.3) - (0.3)
- --------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.5 $(0.4) $ 0.1
- --------------------------------------------------------------------------
The changes in the components of other comprehensive income/(loss) are
reported net of the following income tax effects:
- --------------------------------------------------------------------------
(Millions of Dollars 2002 2001 2000
- --------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $0.3 $0.3 $(0.1)
Minimum pension
liability adjustments - - -
- --------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $0.3 $0.3 $(0.1)
- --------------------------------------------------------------------------
10. Preferred Stock Not Subject to Mandatory Redemption
Details of preferred stock not subject to mandatory redemption are as
follows:
- ------------------------------------------------------------------------------
Shares
December 31, Outstanding
2002 at December 31,
Redemption December 31, ------------
Description Price 2002 2002 2001
- ------------------------------------------------------------------------------
(Millions of Dollars)
$1.90 Series
of 1947 $52.50 163,912 $ 8.2 $ 8.2
$2.00 Series
of 1947 54.00 336,088 16.8 16.8
$2.04 Series
of 1949 52.00 100,000 5.0 5.0
$2.20 Series
of 1949 52.50 200,000 10.0 10.0
3.90% Series
of 1949 50.50 160,000 8.0 8.0
$2.06 Series E
of 1954 51.00 200,000 10.0 10.0
$2.09 Series F
of 1955 51.00 100,000 5.0 5.0
4.50% Series
of 1956 50.75 104,000 5.2 5.2
4.96% Series
of 1958 50.50 100,000 5.0 5.0
4.50% Series
of 1963 50.50 160,000 8.0 8.0
5.28% Series
of 1967 51.43 200,000 10.0 10.0
$3.24 Series G
of 1968 51.84 300,000 15.0 15.0
6.56% Series
of 1968 51.44 200,000 10.0 10.0
- -------------------------------------------------------------------------------
Totals $116.2 $116.2
- -------------------------------------------------------------------------------
11. Long-Term Debt
Details of long-term debt outstanding are as follows:
- -------------------------------------------------------------------------------
At December 31, 2002 2001
- -------------------------------------------------------------------------------
(Millions of Dollars)
First Mortgage Bonds:
8 1/2% Series C due 2024 $ 59.0 $ 59.0
7 7/8% Series D due 2024 139.8 139.8
------ ------
198.8 198.8
Pollution Control Notes:
Fixed rate, due 2016-2022 46.4 46.4
Fixed rate, tax exempt, due 2028 315.5 315.5
Variable rate, tax exempt, due 2031 62.0 62.0
Fees and interest due for spent
nuclear fuel disposal costs 205.5 201.9
------ ------
629.4 625.8
Less amounts due within one year - -
Unamortized premium and
discount, net (0.3) (0.3)
- -------------------------------------------------------------------------------
Long-term debt $827.9 $824.3
- -------------------------------------------------------------------------------
Essentially, all utility plant of CL&P is subject to the liens of the
company's first mortgage bond indenture.
CL&P has secured $315.5 million of pollution control notes secured by
second mortgage liens on transmission assets, junior to the liens of their
first mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by the first mortgage bonds and a liquidity
facility. For financial reporting purposes, these first mortgage bonds
would not be considered outstanding unless CL&P failed to meet its
obligations under the PCRBs.
The average effective interest rates on the variable-rate pollution control
notes ranged from 1.2 percent to 1.7 percent for 2002 and from 1.3 percent
to 3.6 percent for 2001.
12. Income Tax Expense
The components of the federal and state income tax provisions were
charged/(credited) to operations as follows:
- -------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $114.4 $190.7 $ 77.2
State 24.3 38.8 17.2
------ ------ ------
Total current 138.7 229.5 94.4
------ ------ ------
Deferred income taxes, net:
Federal (53.3) (117.0) 10.6
State (15.2) (23.8) 2.4
------ ------ ------
Total deferred (68.5) (140.8) 13.0
------ ------ ------
Investment tax credits, net (3.3) (3.8) (7.3)
- -------------------------------------------------------------------------------
Total income tax expense $ 66.9 $ 84.9 $100.1
- -------------------------------------------------------------------------------
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
- -------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------
(Millions of Dollars
Depreciation, leased nuclear
fuel, settlement credits and
disposal costs $ 34.4 $ (9.2) $ 13.8
Regulatory deferral (68.3) (33.1) (14.1)
State net operating
loss carryforward - - -
Regulatory disallowance 0.3 - -
Sale of generation assets (18.4) (197.6) -
Pension (deferral)/accrual (6.3) 19.9 13.6
Securitized contract
termination
costs and other (5.9) 63.4 -
Other (4.3) 15.8 (0.3)
- -------------------------------------------------------------------------------
Deferred income taxes, net $(68.5) $(140.8) $ 13.0
- -------------------------------------------------------------------------------
A reconciliation between income tax expense and the expected tax expense at
the statutory rate is as follows:
- -------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------
(Millions of Dollars
Expected federal income tax $53.4 $68.1 $ 86.9
Tax effect of differences:
Depreciation 3.8 4.0 5.8
Amortization of
regulatory assets 13.7 (0.6) 3.6
Investment tax credit
amortization (3.3) (3.8) (7.3)
State income taxes,
net of federal benefit 5.9 9.8 12.7
Other, net (6.6) 7.4 (1.6)
- -------------------------------------------------------------------------------
Total income tax expense $66.9 $84.9 $100.1
- -------------------------------------------------------------------------------
13. Segment Information
NU is organized between regulated utilities (electric and gas since the
March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries.
CL&P is included in the regulated utilities segment of NU and has no other
reportable segments.
<Table>
<Caption>
- --------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data
- --------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2002 2001 2000 1999 1998
- --------------------------------------------------------------------------------------------------------
Operating Revenues $2,507,036 $2,646,123 $2,935,922 $2,452,855 $2,386,864
Net Income/(Loss) 85,612 109,803 148,135 (13,568) (195,725)
Cash Dividends on Common Stock 60,145 60,072 72,014 - -
Total Assets 4,632,083 4,727,727 4,764,198 5,298,284 6,050,198
Rate Reduction Bonds 1,245,728 1,358,653 - - -
Long-Term Debt (a) 827,866 824,349 1,232,688 1,400,056 2,007,957
Preferred Stock Not Subject to
Mandatory Redemption 116,200 116,200 116,200 116,200 116,200
Preferred Stock Subject to
Mandatory Redemption (a) - - - 99,539 119,289
Obligations Under Capital Leases (a) 15,499 16,040 129,869 144,400 162,884
- --------------------------------------------------------------------------------------------------------
</Table>
- -------------------------------------------------------------------------------
Consolidated Quarterly Financial Data (Unaudited)
- -------------------------------------------------------------------------------
(Thousands of Dollars) Quarter Ended
- -------------------------------------------------------------------------------
2002 March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------
Operating Revenues $604,420 $581,731 $687,938 $632,947
Operating Income $ 64,111 $ 45,528 $ 72,946 $ 68,743
Net Income $ 21,684 $ 11,407 $ 29,297 $ 23,224
- -------------------------------------------------------------------------------
2001
- -------------------------------------------------------------------------------
Operating Revenues $733,905 $610,275 $675,578 $626,365
Operating Income $ 65,096 $ 68,114 $ 63,103 $ 66,716
Net Income $ 38,300 $ 18,812 $ 18,824 $ 33,867
- -------------------------------------------------------------------------------
(a) Includes portions due within one year.
- -------------------------------------------------------------------------------
Consolidated Statistics (Unaudited)
- -------------------------------------------------------------------------------
Gross Electric
Utility Plant Average Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (a) (Millions) Customer (kWh) (Average) December 31,
- -------------------------------------------------------------------------------
2002 $3,292,685 29,623 9,244 1,158,307 2,130
2001 3,265,811 32,645 8,884 1,153,234 2,160
2000 5,964,605 42,120 8,976 1,121,551 2,057
1999 6,007,421 29,235 8,969 1,120,846 2,377
1998 6,345,215 27,300 8,476 1,111,370 2,379
(a) Amount includes construction work in progress.