EXHIBIT 13.2
2003 Annual Report
The Connecticut Light and Power Company
Index
Contents Page
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Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 1
Independent Auditors' Report..................................... 15
Consolidated Balance Sheets...................................... 16-17
Consolidated Statements of Income................................ 18
Consolidated Statements of Comprehensive Income.................. 18
Consolidated Statements of Common Stockholder's Equity........... 19
Consolidated Statements of Cash Flows............................ 20
Notes to Consolidated Financial Statements....................... 21
Consolidated Quarterly Financial Data (Unaudited)................ 36
Selected Consolidated Financial Data (Unaudited)................. 36
Consolidated Statistics (Unaudited).............................. 36
Bondholder Information........................................... Back Cover
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION AND BUSINESS ANALYSIS
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OVERVIEW
The Connecticut Light and Power Company (CL&P), a wholly owned subsidiary
of Northeast Utilities (NU), earned, before preferred dividends, $68.9
million in 2003, compared with $85.6 million in 2002 and $109.8 million in
2001. The lower 2003 income was primarily attributable to lower pension
income, after-tax write-offs of approximately $5 million related to a
distribution rate case that was decided in December 2003, and a loss
recorded for the settlement of a wholesale power contract dispute between
CL&P and its three 2003 standard offer power suppliers, including an NU
subsidiary, Select Energy, Inc., offset by an adjustment to estimated
unbilled revenues. For more information about this dispute and the
settlement, see the "Impacts of Standard Market Design" section of this
Management's Discussion and Analysis. The lower 2002 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, Select Energy, Inc.
(Select Energy), Northeast Generation Company, Northeast Generation
Services Company, and Select Energy Services, Inc.
During 2003, pre-tax pension income for CL&P declined $21.5 million, from a
credit of $50.6 million in 2002 to a credit of $29.1 million in 2003. Of
the $29.1 million and $50.6 million of pension credits recorded during 2003
and 2002, $14 million and $29.8 million, respectively, were recognized in
the consolidated statements of income as reductions to operating expenses.
The remaining $15.1 million in 2003 and $20.8 million in 2002 relate to
employees working on capital projects and were reflected as reductions to
capital expenditures. The pre-tax $15.8 million decrease in pension income
that reduces operating expenses was reflected evenly throughout 2003,
resulting in a decline of $2.4 million in net income per quarter during
2003.
CL&P's revenues for 2003 increased to $2.7 billion from $2.5 billion in
2002 due to both an increase in electric sales and the collection of
incremental locational marginal pricing (LMP) costs.
As a result of an adjustment to estimated unbilled revenues resulting from
a process to validate and update the assumptions used to estimate unbilled
revenues, 2003 CL&P retail sales increased 3.3 percent compared to 2002.
Absent that adjustment, CL&P retail sales increased 1.5 percent. The
adjustment to CL&P's estimated unbilled revenues increased CL&P's net
income by $7.2 million for 2003. For further information regarding the
estimate of unbilled revenues, see "Critical Accounting Policies and
Estimates - Unbilled Revenues," included in this Management's Discussion
and Analysis.
FUTURE OUTLOOK
Management projects CL&P earnings to increase in 2004, compared with 2003.
CL&P is expected to benefit from higher overall transmission and
distribution rates, the implementation of a 0.50 mill per kilowatt-hour
(kWh) procurement fee on transitional standard offer (TSO) purchases made
by CL&P on behalf of retail customers, and higher plant balances on which
CL&P can earn a return. Those factors will be partially offset by a lower
authorized return on equity (ROE) on CL&P's distribution assets, higher
levels of depreciation, and lower pension income. In 2004, CL&P is
projecting to record pre-tax pension income of $13.5 million as compared to
pension income of $29.1 million in 2003. Pension income is annually
adjusted during the second quarter based on updated actuarial valuations,
and the 2004 estimate may change. CL&P's transmission earnings will be
affected by the outcome of a transmission rate case that was filed at the
Federal Energy Regulatory Commission (FERC) in 2003 and is expected to be
decided in late 2004. A $23.7 million annual increase, most of which
affects CL&P, went into effect October 28, 2003, subject to refund.
LIQUIDITY
CL&P's net cash flows provided by operating activities totaled $409 million
in 2003 as compared to $384.7 million in 2002 and $9 million in 2001. Cash
flows provided by operating activities in 2003 increased due to increase in
regulatory overrecoveries in 2003 as compared to 2002, primarily associated
with CL&P's Competitive Transition Assessment (CTA), Generation Service
Charge (GSC) and System Benefits Charge (SBC). The increases were offset
by restricted cash deposited into an escrow account related to the
collection of LMP costs as well as decreases in working capital items,
primarily accounts payable. Accounts payable decreased due to the timing
of payments on amounts outstanding. For a description of the costs
recovered through the CTA, GSC and SBC, see Note 1G, "Summary of
Significant Accounting Policies - Regulatory Accounting," to the
consolidated financial statements.
Cash flows provided by operating activities increased in 2002 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 comparable level of investing and financing activity in 2003 as
compared to 2002, except for $100 million for the repurchase of common
shares and $35.9 million from the sale of utility plant, both in 2002. The
level of common dividends totaled $60.1 million in 2003, 2002 and 2001.
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.
Aside from the rate reduction bonds outstanding, no CL&P debt issues mature
during the eight-year period of 2004 through 2011.
By the end of 2003, CL&P had completed the first stage of a comprehensive
restructuring of its business profile. For CL&P that marked the sale of
all electric generation in the period of 1999 through 2002 and the recovery
of almost all of its unsecuritized stranded costs. The sale of assets and
recovery of stranded costs have provided CL&P with extremely strong cash
flows over the past five years. Those proceeds allowed CL&P to repay more
than half of its debt and preferred securities and to return hundreds of
millions of dollars of equity capital to NU. Aided by relatively low cost
power supply contracts from 2000 through 2003, CL&P was able to maintain
retail rates that were relatively low for New England and generally 10
percent below those charged by CL&P in 1996.
The year 2004, however, will show a significant change in CL&P's financial
statements, even if net income remains relatively stable. The settlement
of the dispute between CL&P and its standard offer service suppliers over a
portion of the incremental costs incurred following the implementation of
standard market design (SMD) on March 1, 2003, will have a significant
negative impact on CL&P's cash flows in 2004 as compared to 2003. In 2003,
CL&P was withholding payment of a portion of the incremental SMD costs from
suppliers pending resolution but was recovering the costs from ratepayers
at the same time. Through January 31, 2004, CL&P collected approximately
$155 million from customers. Of this amount, $31.1 million was used in
CL&P's operating cash flows and is secured by a surety bond. The remaining
$124 million was deposited into an escrow account, and escrow account
deposits through December 31, 2003 were $93.6 million and are included in
restricted cash - LMP costs on the accompanying consolidated balance
sheets. As a result of the settlement, CL&P will pay approximately $83
million to suppliers and return the remainder to its customers.
Another significant negative impact to CL&P's cash flows will be the refund
of previously overcollected stranded costs to CL&P's customers. The
Connecticut Department of Public Utility Control (DPUC) stated in CL&P's
TSO docket that CL&P should either refund $262 million of overcollections
back to customers or use these overcollections to pay for cash expenses
over the next four years, beginning in 2004.
These refunds or applications of past cash collections to future expenses,
combined with CL&P's capital expansion program, will require CL&P to issue
debt securities and receive equity infusions from NU parent over the next
several years. CL&P is expected to issue up to $250 million of first
mortgage bonds in 2004.
CL&P will continue to increase its distribution and transmission
construction program to meet Connecticut's electric service reliability
needs. CL&P projects capital spending of approximately $440 million in
2004, compared with $314.6 million in 2003, $239.6 million in 2002 and
$236.2 million in 2001. Over time, the capital program will add to CL&P's
asset base and net income.
Under FERC policy, transmission owners cannot bill customers for new plant
until it enters service. However, transmission owners may capitalize debt
and equity costs during the construction period through an allowance for
funds used during construction (AFUDC). Debt costs capitalized offset
interest expense with no impact on net income, while equity costs
capitalized increase net income. CL&P expects to fund its construction
expenditures with approximately 45 percent equity and 55 percent debt. As
a result of the size of the projects and the duration of the construction,
a growing level of CL&P's earnings over the next four years is expected to
be in the form of equity-related AFUDC. While the return on and recovery
of the capitalized debt and equity AFUDC benefits earnings and cash flows
after the projects enter service, AFUDC has no positive effect on cash
flows until the projects are reflected in rates.
In November 2003, CL&P renewed a $300 million credit line under terms
similar to the previous arrangement that expired in November 2003. CL&P
can borrow up to $150 million under this credit line. There were no
borrowings outstanding on this credit line at December 31, 2003.
In addition to its revolving credit line, CL&P has an arrangement with a
financial institution under which CL&P can sell up to $100 million of
accounts receivable. At December 31, 2003 and 2002, CL&P had sold accounts
receivable of $80 million and $40 million, respectively, to that financial
institution. For more information on the sale of receivables, see "Off-
Balance Sheet Arrangements" in this Management's Discussion and Analysis
and Note 1N, "Summary of Significant Accounting Policies - Sale of Customer
Receivables," to the consolidated financial statements.
In November 2003, CL&P received approval from its preferred shareholders
for an extension of a 10-year waiver that allows CL&P's unsecured debt to
rise to 20 percent of total capitalization. CL&P preferred shareholders
approved a similar waiver in 1993 that will expire in March 2004. The
approval waives a requirement that unsecured debt represent no more than 10
percent of total capitalization.
Rate reduction bonds are included on the consolidated balance sheets of
CL&P, even though the debt is non-recourse to CL&P. At December 31, 2003,
CL&P had a total of $1.1 billion in rate reduction bonds outstanding,
compared with $1.2 billion outstanding at December 31, 2002. All
outstanding rate reduction bonds of CL&P are scheduled to amortize by
December 30, 2010. Interest on the bonds totaled $70.3 million in 2003,
compared with $75.7 million in 2002 and $60.6 million in 2001, the year of
issuance. Cash flows from the amortization of rate reduction bonds totaled
$103.3 million in 2003, compared with $96.5 million in 2002 and $68 million
in 2001. Over the next several years, retirement of rate reduction bonds
will increase, and interest payments will steadily decrease, resulting in
no material changes to debt service costs on the existing issues. CL&P
fully recovers the amortization and interest payments from customers
through stranded cost revenues each year, and the bonds have no impact on
net income. Moreover, as the rate reduction bonds are non-recourse, the
three rating agencies that rate the debt of CL&P do not reflect the
revenues, expenses, or outstanding securities related to the rate reduction
bonds in establishing the credit ratings of CL&P.
The retirement of rate reduction bonds does not equal the amortization of
rate reduction bonds because the retirement represents principal payments,
while the amortization represents amounts recovered from customers for
future principal payments. The timing of recovery does not exactly match
the expected principal payments.
IMPACTS OF STANDARD MARKET DESIGN
On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented SMD. As part of SMD, LMP is utilized to assign value and
causation to transmission congestion and line losses. Transmission
congestion costs represent the additional costs incurred due to the need to
run uneconomic generating units in certain areas that have transmission
constraints, which prevent these areas from obtaining alternative lower-
cost generation. Line losses represent losses of electricity as it is sent
over transmission lines. The costs associated with transmission congestion
and line losses are now assigned to the pricing zone in which they occur,
and the calculation of line losses is now based on an economic formula.
Prior to March 1, 2003, those costs were spread across virtually all New
England electric customers based on engineering data of actual line losses
experienced. As part of the implementation of SMD, ISO-NE established
eight separate pricing zones in New England: three in Massachusetts and one
in each of the five other New England states. The three components of the
LMP for each zone are 1) an energy cost, 2) congestion costs and 3) line
loss charges assigned to the zone. LMP is increasing costs in zones that
have inadequate or less cost-efficient generation and/or transmission
constraints, such as Connecticut, and decreasing costs in zones that have
sufficient or excess generation, such as Maine.
CL&P was billed $186 million of incremental LMP costs by its standard offer
service suppliers or by ISO-NE. CL&P recovered a portion of these costs
through an additional charge on customer bills beginning on May 1, 2003.
Billings were on a two-month lag and were recorded as operating revenues
when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the
responsibility for the $186 million of incremental LMP costs incurred.
CL&P recorded an after-tax loss in 2003 of $1.3 million related to the
settlement of this dispute. A settlement agreement was reached among all
parties involved. This settlement agreement was filed with the FERC on
March 3, 2004 and will not be final until the FERC approves it. Management
expects to receive FERC approval in the first half of 2004.
NRG ENERGY, INC. EXPOSURES
CL&P entered into various transactions with subsidiaries of NRG Energy,
Inc. (NRG). On May 14, 2003, NRG and certain of its subsidiaries filed
voluntary bankruptcy petitions in the United States Bankruptcy Court for
the Southern District of New York. On December 5, 2003, NRG emerged from
bankruptcy. NRG-related exposures to CL&P as a result of these
transactions are as follows:
Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PMI)
contracted with CL&P to supply 45 percent of CL&P's standard offer service
load through December 31, 2003. In May 2003, NRG-PMI attempted to
terminate the contract with CL&P, but the FERC ordered NRG-PMI to continue
serving CL&P under its standard offer service contract. Subsequently, NRG-
PMI received a temporary restraining order from the United States District
Court for the Southern District of New York (District Court) and stopped
serving CL&P with standard offer supply on June 12, 2003. NRG-PMI was
ultimately ordered by the FERC and the District Court to resume serving
CL&P's standard offer service load and did so on July 2, 2003. During the
period NRG-PMI did not serve CL&P under its standard offer service
contract, CL&P's net replacement power cost amounted to $8.5 million, which
was collected by CL&P from its customers and withheld from standard offer
service contract payments to NRG-PMI.
On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the
Office of Consumer Counsel, and the attorney general of Connecticut entered
into a comprehensive settlement agreement. Under the settlement agreement,
approved by the bankruptcy court and the FERC on November 21, 2003 and
December 18, 2003, respectively, NRG was required to continue to deliver
power to CL&P under the terms and conditions of the standard offer service
contract through the end of its term, which was December 31, 2003, in
exchange for a commitment by CL&P to make payments to NRG on a revised
weekly schedule. The settlement agreement also allowed CL&P to retain the
aforementioned $8.5 million withheld from NRG for replacement power
purchased by CL&P during the period June 12, 2003 through July 2, 2003.
CL&P will seek to refund this amount to its customers in 2004 pending DPUC
approval. On January 19, 2004, CL&P paid NRG-PMI its last weekly payment.
Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit
against NRG in Connecticut Superior Court seeking judgment for unpaid pre-
March 1, 2003 congestion charges under its standard offer supply contract.
On August 5, 2002, CL&P withheld the then unpaid congestion charges from
payments due to NRG for standard offer service and continued to withhold
those amounts through December 31, 2003, the end of the contract term. The
total amount of congestion costs withheld from NRG was $28.4 million. If
it is ultimately concluded that CL&P is responsible for pre-March 1, 2003
congestion costs, then management believes that CL&P would be allowed to
recover these costs from its customers. This litigation is ongoing.
Station Service: Since December 1999, CL&P has provided NRG's Connecticut
generating plants with station service, which includes energy and/or
delivery services provided when a generator is off-line or unable to
satisfy its station service energy requirements. Pursuant to the parties'
interconnection agreement dated July 1, 1999, CL&P provides this service at
DPUC-approved retail rates. In October 2002, CL&P filed a complaint with
the FERC seeking interpretation of a FERC-filed interconnection agreement
in which NRG agreed to pay CL&P's applicable retail rates for station
service and delivery services. The FERC issued a decision on December 20,
2002 that agreed that station service from CL&P would be subject to CL&P's
applicable retail rates and that states have jurisdiction over the
delivery of power to end users even where, as with station service, power
is not delivered by distribution facilities. NRG disputed its obligation
and refused to pay CL&P.
In September 2003, the bankruptcy court approved a stipulation between CL&P
and NRG to submit the station service dispute to arbitration, and
arbitration proceedings have been initiated by the parties. No hearing
dates have been scheduled. On December 17, 2003, the DPUC determined that
CL&P had appropriately administered its station service rates in providing
NRG station service. In unrelated proceedings, the FERC has issued
decisions with conflicting policy direction. In January 2004, CL&P filed a
request with the FERC for further clarification of this issue.
Management will continue to pursue recovery from NRG of the station service
balance, including approximately $4 million NRG placed in an escrow account
related to this matter. In 2003, as a result of NRG's bankruptcy, the
amount due from NRG in excess of the escrow amount was reserved.
Management believes that amounts not collected from NRG are ultimately
recoverable from CL&P's customers. Therefore, a regulatory asset of $11.4
million was recorded. At December 31, 2003, NRG owed CL&P $16 million for
station service. The $16 million owed to CL&P includes $0.6 million billed
to NRG subsequent to its emergence from bankruptcy on December 5, 2003.
Legal Costs: Through December 31, 2003, legal costs incurred by CL&P
related to NRG's bankruptcy and the SMD dispute amounted to $2.3 million.
This amount has been recorded as a regulatory asset, and CL&P received
approval to recover $1.6 million in its recent rate case. CL&P will
continue to defer these legal costs as they are incurred, and management
believes that amounts in excess of $1.6 million will also be recovered from
customers.
Meriden Gas Turbines, LLC: CL&P is involved in ongoing litigation with
Meriden Gas Turbines, LLC (MGT), an NRG subsidiary that was not included in
NRG's voluntary bankruptcy proceeding, related to the construction of a
generating plant which MGT stated it was abandoning.
MGT currently owes CL&P $0.5 million for work on the South Kensington
switching station, which was to be the interconnection point for the MGT
generating plant. CL&P has joined pending foreclosure proceedings in
an effort to recover the outstanding balance.
Management does not expect that the resolution of the aforementioned NRG
exposures will have a material adverse effect on the financial condition or
results of operations of CL&P.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
Over the next several years, CL&P's capital spending will be significant.
CL&P is seeking to upgrade and expand an aging and, in some locations,
stressed distribution and transmission system. CL&P's capital
expenditures totaled $314.6 million in 2003, compared with $239.6 million
in 2002 and $236.2 million in 2001. CL&P expects capital expenditures to
increase to $440 million in 2004. CL&P spent $246 million on distribution
in 2003 and anticipates spending $228 million on distribution in 2004.
In its final 2003 CL&P rate decision, the DPUC authorized rate recovery of
distribution capital expenditures totaling $236 million in 2004, $220
million in 2005, $216 million in 2006, and $225 million in 2007.
On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000
volt transmission line project from Bethel, Connecticut to Norwalk,
Connecticut, proposed in October 2001 by CL&P. The configuration of the
new transmission line, enhancements to an existing 115,000 volt
transmission line, and work in related substations are estimated to cost
approximately $200 million. The line will alleviate identified reliability
issues in southwest Connecticut and help reduce congestion costs for all of
Connecticut. An appeal of the CSC decision by the City of Norwalk is
pending, but management does not expect the appeal to be successful. CL&P
anticipates placing the new transmission line in service by the end of
2005. This project is exempt from the State of Connecticut's moratorium on
the approval of new electric and natural gas transmission projects. At
December 31, 2003, CL&P has capitalized $12.4 million associated with this
project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of
a separate 345,000 volt transmission line from Norwalk, Connecticut to
Middletown, Connecticut. Estimated construction costs of this project are
approximately $620 million. CL&P will jointly site this project with UI,
and CL&P will own 80 percent, or approximately $496 million, of the
project. This project is also exempt from the State of Connecticut's
moratorium on the approval of new electric and natural gas transmission
projects. CL&P expects the CSC to rule on the application in 2004 and for
construction to occur from 2005 through 2007. At December 31, 2003, CL&P
has capitalized $9.2 million related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric
transmission line between Norwalk, Connecticut and Northport - Long Island,
New York, at an estimated cost of $90 million. CL&P and the Long Island
Power Authority each own approximately 50 percent of the line. The project
still requires federal and New York state approvals. Given the approval
process, changing pricing and operational rules in the New England and New
York energy markets and pending business issues between the parties, the
expected in-service date remains under evaluation. This project is also
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. At December 31, 2003, CL&P
has capitalized $5.2 million associated with this project.
Construction of these three projects would significantly enhance CL&P's
ability to provide reliable electric service to the rapidly growing energy
market in southwestern Connecticut. Despite the need for such facilities,
significant opposition has been raised. As a result, management cannot be
certain as to the expected in-service dates or the ultimate cost of these
projects. Should the plans proceed, applicable law provides that CL&P will
be able to recover its operating cost and carrying costs through federally-
approved transmission tariffs.
Management believes that construction of the 345,000 volt projects is
critical to maintaining service reliability in southwest Connecticut. The
345,000 volt projects, in addition to additional transmission spending
planned between 2004 and 2007, also represent a significant source of
potential earnings growth for NU. Management believes that if the projects
now being considered are all built over the next four years, CL&P's net
transmission plant investment would triple. Revenues and earnings for
CL&P's transmission system are established by the FERC.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities, including CL&P, to
voluntarily form regional transmission organizations (RTOs) or to state why
this process has not begun.
On October 31, 2003, ISO-NE, along with NU (including CL&P), and six other
New England transmission companies filed a proposal with the FERC to create
a RTO for New England. The RTO is intended to strengthen the independent
and efficient management of the region's power system while ensuring that
customers in New England continue to have the most reliable system possible
to realize the benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and
will also become the transmission provider for New England by exercising
operational control over New England's transmission facilities pursuant to
a detailed contractual arrangement with the New England transmission
owners. Under this contractual arrangement, the RTO will have clear
authority to direct the transmission owners to operate their facilities in
a manner that preserves system reliability, including requiring
transmission owners to expand existing transmission lines or build new ones
when needed for reliability. Transmission owners will retain their rights
over revenue requirements, rates and rate designs. The filing requests
that the FERC approve the RTO arrangements for an effective date of March 1,
2004.
In a separate filing made on November 4, 2003, NU including CL&P, along
with six other New England transmission owners requested, consistent with
the FERC's pricing policy for RTOs and Order-2000-compliant independent
system operators, that the FERC approve a single ROE for regional and local
rates that would consist of a base ROE as well as incentive adders of 50
basis points for joining a RTO and 100 basis points for constructing new
transmission facilities approved by the RTO. If the FERC approves the
request, then the transmission owners would receive a 13.3 percent ROE for
existing transmission facilities and a 14.3 percent ROE for new
transmission facilities. The outcome of this request and its impact on
CL&P cannot be determined at this time.
RESTRUCTURING AND RATE MATTERS
On August 26, 2003, NU's electric operating companies, including CL&P,
filed their first transmission rate case at the FERC since 1995. In the
filing, NU requested implementation of a formula rate that would allow
recovery of increasing transmission expenditures on a timelier basis and
that the changes, including a $23.7 million annual rate increase through
2004, take effect on October 27, 2003. NU requested that the FERC maintain
NU's existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this
filing implementing the proposed rates subject to refund effective on
October 28, 2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution
companies through FERC-approved transmission rates. Electric distribution
companies pass through higher transmission rates to retail customers as
approved by the DPUC. In its 2003 rate case, CL&P sought a tracking
mechanism to allow it to recover changes in transmission expenses on a
timely basis. While the DPUC approved a $28.4 million increase in
transmission rates for CL&P's retail customers effective January 1, 2004,
it did not grant a tracking mechanism in rates. As a result, CL&P will
need to reapply to the DPUC to adjust transmission rates when its revenues
are not adequate to recover transmission costs.
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor
of Connecticut signed into law Public Act No. 03-135 (Act) that amended
Connecticut's 1998 electric utility industry legislation. Among key
features, the Act created a TSO period from 2004 through 2006 that allowed
the base rate cap to return to 1996 levels, which represented a potential
increase of up to 11.1 percent. Additional costs related to Federally
Mandated Congestion Charges (FMCC) are not included in the cap.
Additionally, if energy supply costs were to exceed levels established in
the TSO rate, these costs could be recovered through an energy adjustment
clause or through the FMCC. The Act also allowed CL&P to collect a
procurement fee of at least 0.50 mills per kWh from customers who continue
to purchase TSO service. That fee can increase to 0.75 mills if CL&P beats
certain regional benchmarks. Management expects that the procurement fee
will be between $11 million and $12 million annually, which will add $6
million to $7 million to CL&P's net income. One mill is equal to one-tenth
of a cent.
ISO-NE and the New England Power Pool are currently debating the
implementation of locational installed capacity (LICAP). LICAP is the
requirement that CL&P support enough generation to meet peak demand (plus a
reserve to protect against higher demand than expected or generating plant
outages) in its service territory. Connecticut, because of its lack of
sufficient generation and transmission, is expected to have high LICAP
costs. LICAP rules are subject to the jurisdiction of the FERC. ISO-NE
filed a proposal with the FERC on March 1, 2004 for implementation in June
2004. Until the exact proposal is approved by the FERC, the financial
impact on CL&P's customers cannot be determined. CL&P expects to recover
LICAP from its customers as a FMCC.
On July 1, 2003, CL&P filed with the DPUC to establish TSO service and to
set the TSO rates equal to December 31, 1996 total rate levels. On
December 19, 2003, the DPUC issued a final decision setting the average TSO
rate at $0.1076 per kWh for 2004, which the DPUC found to be within the
statutory cap. That rate incorporated nine key elements, which combined
produced the average TSO rate. The most significant element was an average
GSC of $0.05744 per kWh. That charge will allow CL&P to fully recover from
customers the amounts to be paid in 2004 to its five TSO suppliers. These
suppliers include Select Energy, which was awarded 37.5 percent of CL&P's
TSO load through a request for proposal process overseen by the DPUC, and
four other suppliers, all of which are investment grade rated by major
rating agencies.
The Act also required CL&P to file a four-year transmission and
distribution plan with the DPUC. Accordingly, on August 1, 2003, CL&P
filed a rate case that amended rate schedules and proposed changes to
increase distribution rates. On December 19, 2003, the DPUC issued its
final decision in the rate case. In that decision, the DPUC chose to apply
$120 million of overcollections from CL&P's customers in prior years
against higher distribution rates in the form of credits of $30 million per
year. Net of those overcollections, the DPUC ordered that distribution
rates be lowered by $1.9 million in 2004 and be raised by $25.1 million in
2005, $11.9 million in 2006, and $7 million in 2007. The decision approved
a transmission rate increase of $28.4 million in 2004, but did not allow
the tracking mechanism and did not set transmission rates beyond 2004. The
DPUC also approved rate recovery of approximately $900 million of CL&P's
proposed $1 billion distribution capital budget over the four-year period.
The decision set CL&P's authorized ROE at 9.85 percent. Earnings above
9.85 percent will be shared equally by shareholders and ratepayers. The
sharing mechanism is not affected by earnings from the procurement fee.
CL&P filed a petition for reconsideration of certain items in the rate case
on December 31, 2003. Other parties also filed petitions for
reconsideration. On January 21, 2004, the DPUC agreed to reconsider CL&P's
items; however, CL&P also filed an appeal with the Connecticut Superior
Court on January 30, 2004, which was within the time frame required by law.
The appeal was filed in the event that the DPUC's reconsideration is still
not acceptable to CL&P.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook
nuclear unit on November 1, 2002. The net proceeds in excess of the book
value of Seabrook of $16 million were recorded as a regulatory liability
and, after being offset by accelerated decommissioning funding and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September
2003, and a draft decision was received on February 3, 2004. The final
decision, which was received on March 3, 2004 did not have a material
effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual
CTA and SBC reconciliation with the DPUC. For the year ended December 31,
2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue
requirement by $93.5 million. This amount was recorded as a regulatory
liability. For the same period, SBC revenues exceeded the SBC revenue
requirement by $22.4 million. In compliance with a prior decision of the
DPUC, a portion of the SBC overcollection reduced regulatory assets, and
the remaining overcollection of $18.6 million was applied to the CTA. The
DPUC's December 19, 2003 TSO decision addressed $41 million of SBC
overcollections and $64 million of CTA overcollections that had been
estimated as of December 31, 2003. In its decision, the DPUC ordered that
$80 million of the overcollections be used to reduce CTA costs during the
2004 through 2006 TSO period. The DPUC also ordered that $25 million of
the overcollections be used to offset SBC costs during the TSO period. The
DPUC also ordered that $37 million of GSC overcollections be used to pay
CL&P's 0.50 mill per kWh procurement fee during the TSO period.
NUCLEAR GENERATION ASSET DIVESTITURES
Millstone: On March 31, 2001, CL&P sold its ownership interest in
Millstone.
Seabrook: On November 1, 2002, CL&P sold its ownership interest in
Seabrook.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation
(VYNPC) consummated the sale of its nuclear generating unit. In November
2003, CL&P sold back to VYNPC its shares of stock for approximately $0.9
million. CL&P continues to purchase approximately 9.5 percent of the
plant's output under a new contract.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers
of CL&P's ownership shares of the Millstone, Seabrook and Vermont Yankee
plants assumed the obligation of decommissioning those plants, CL&P still
has significant decommissioning and plant closure cost obligations to the
companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine
Yankee plants (collectively Yankee Companies). Each plant has been shut
down and is undergoing decommissioning. The Yankee Companies collect
decommissioning and closure costs through wholesale FERC-approved rates
charged under a power purchase agreement with CL&P. CL&P in turn passes
these costs on to its customers through state regulatory commission-
approved retail rates. A portion of the decommissioning and closure costs
have already been collected, but a substantial portion related to the
decommissioning of CY has not yet been filed at and approved for collection
by the FERC. The cost estimate for CY that has not yet been approved for
recovery by FERC at December 31, 2003 is $181.9 million.
CL&P cannot at this time predict the timing or outcome of the FERC
proceeding required for the collection of these remaining decommissioning
and closure costs or the Bechtel Power Corporation litigation referred to
in Note 6G, "Commitments and Contingencies - Nuclear Decommissioning and
Plant Closure Costs," to the consolidated financial statements. Although
management believes that these costs will ultimately be recovered from
CL&P's customers, there is a risk that the FERC may not allow these costs,
the estimates of which have increased significantly in 2003 and 2002, to be
recovered in wholesale rates. If FERC does not allow these costs to be
recovered in wholesale rates, CL&P would expect the state regulatory
commissions to disallow these costs in retail rates as well.
OFF-BALANCE SHEET ARRANGEMENTS
The CL&P Receivables Corporation (CRC) was incorporated on September 5,
1997, and is a wholly owned subsidiary of CL&P. CRC has an arrangement
with a highly rated financial institution under which CRC can sell up to
$100 million of accounts receivable. At December 31, 2003 and 2002, CRC
had sold accounts receivable of $80 million and $40 million, respectively,
to that financial institution with limited recourse.
CRC was established for the sole purpose of selling CL&P's accounts
receivable and unbilled revenues and is included in the consolidation of
NU's financial statements. On July 9, 2003, CRC renewed its Receivables
Purchase and Sale Agreement with CL&P and the financial institution. The
agreement expires on July 7, 2004. Management plans to renew this
agreement prior to its expiration.
The transfer of receivables to the financial institution under this
arrangement qualifies for sale treatment under Statement of Financial
Accounting Standards (SFAS) No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - A
Replacement of SFAS No. 125." Accordingly, the $80 million and $40 million
outstanding under this facility are not reflected as debt or included in the
consolidated financial statements at December 31, 2003 and 2002,
respectively.
This off-balance sheet arrangement is not significant to CL&P's liquidity
or other benefits. There are no known events, demands, commitments,
trends, or uncertainties that will, or are reasonably likely to, result in
the termination, or material reduction in the amount available to the
company under this off-balance sheet arrangement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult,
subjective or complex judgments. Changes in these estimates, assumptions
and judgments, in and of themselves, could materially impact the financial
statements of CL&P. Management communicates to and discusses with NU's
Audit Committee of the Board of Trustees all critical accounting policies
and estimates. The following are the accounting policies and estimates
that management believes are the most critical in nature.
Presentation: In accordance with current accounting pronouncements, CL&P's
consolidated financial statements include all subsidiaries upon which
control is maintained and all variable interest entities for which CL&P is
the primary beneficiary, as defined. 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 and Maine Yankee
Atomic Power Company. CL&P does not control these companies and does not
consolidate them in its financial statements. CL&P accounts for the
investments in these companies using the equity method. Under the equity
method, CL&P records its ownership share of the earnings or losses at these
companies. Determining whether or not CL&P should apply the equity method
of accounting for an investee company requires management judgment.
The required adoption date of Financial Accounting Standards Board (FASB)
Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities"
was delayed from July 1, 2003 to December 31, 2003 for CL&P. However, CL&P
elected to adopt FIN 46 at the original adoption date. The adoption of FIN
46 had no impact on CL&P. In December 2003, the FASB issued a revised
version of FIN 46 (FIN 46R). FIN 46R is effective for CL&P for the first
quarter of 2004, but is not expected to have an impact on CL&P's
consolidated financial statements.
Revenue Recognition: CL&P retail revenues are based on rates approved by
the DPUC. These regulated rates are applied to customers' use of energy to
calculate a bill. In general, rates can only be changed through formal
proceedings with the DPUC.
CL&P utilizes regulatory commission-approved tracking mechanisms to track
the recovery of certain incurred costs. The tracking mechanisms allow for
rates to be changed periodically, with overcollections refunded to
customers or underrecollections collected from customers in future periods.
The determination of the energy sales to individual customers is based on
the reading of meters, which occurs on a systematic basis throughout the
month. Billed revenues are based on these meter readings. At the end of
each month, amounts of energy delivered to customers since the date of the
last meter reading are estimated, and an estimated amount of unbilled
revenues is recorded.
Wholesale transmission revenues are based on rates and formulas that are
approved by the FERC. Most of CL&P's wholesale transmission revenues are
collected through a combination of the New England Regional Network Service
(RNS) tariff and CL&P's Local Network Service (LNS) tariff. The RNS
tariff, which is administered by ISO-NE, recovers the revenue requirements
associated with transmission facilities that are deemed by the FERC to be
Pool Transmission Facilities. The LNS tariff which was accepted by the
FERC on October 22, 2003, provides for the recovery of CL&P's total
transmission revenue requirements, net of revenue credits received from
various rate components, including revenues received under the RNS rates.
Unbilled Revenues: Unbilled revenues represent an estimate of electricity
delivered to customers that has not been billed. Unbilled revenues
represent assets on the balance sheet that become accounts receivable in
the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can
significantly impact the amount of revenues recorded. Estimating the
impact of these factors is complex and requires management's judgment. The
estimate of unbilled revenues is important to CL&P's consolidated financial
statements as adjustments to that estimate could significantly impact
operating revenues and earnings. Two potential methods for estimating
unbilled revenues are the requirements and the cycle method.
CL&P estimates unbilled revenues monthly using the requirements method.
The requirements method utilizes the total monthly volume of electricity
delivered to the system and applies a delivery efficiency (DE) factor to
reduce the total monthly volume by an estimate of delivery losses in order
to calculate total estimated monthly sales to customers. The total
estimated monthly sales amount less total monthly billed sales amount
results in a monthly estimate of unbilled sales. Unbilled revenues are
estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can
have a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for CL&P were tested using the cycle
method. The cycle method uses the billed sales from each meter reading
cycle and an estimate of unbilled days in each month based on the meter
reading schedule. The cycle method is historically more accurate than the
requirements method when used in a mostly weather-neutral month. The cycle
method resulted in adjustments to the estimate of unbilled revenues that
had a positive after-tax earnings impact on CL&P of $7.2 million in 2003.
The testing of the requirements method with the cycle method will be done
on at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, CL&P adopted SFAS No.
133, as amended.
Many CL&P contracts for the purchase or sale of energy or energy-related
products are derivatives. The application of derivative accounting under
SFAS No. 133, as amended, is complex and requires management judgment in
the following respects: identification of derivatives and embedded
derivatives, election, and designation of the normal purchases and sales
exception, and determining the fair value of derivatives. All of these
judgments, depending upon their timing and effect, can have a significant
impact on CL&P's consolidated balance sheets.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amended existing
derivative accounting guidance. This new statement incorporates
interpretations that were included in previous Derivative Implementation
Group (DIG) guidance, clarifies certain conditions, and amends other
existing pronouncements. It was effective for contracts entered into or
modified after June 30, 2003. Management has determined that the adoption
of SFAS No. 149 had no impact on the accounting for CL&P contracts.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the
meaning of "not clearly and closely related regarding contracts with a
price adjustment feature" as it relates to the election of the normal
purchase and sales exception to derivative accounting. The implementation
of this guidance was required for the fourth quarter of 2003 for CL&P. The
implementation of Issue No. C-20 resulted in CL&P recording the fair value
of two existing power purchase contracts as derivatives, one as a
derivative asset, and one as a derivative liability. An offsetting
regulatory liability and an offsetting regulatory asset were recorded, as
these contracts are part of stranded costs, and management believes that
these costs will continue to be recovered or refunded in rates. The fair
values of these long-term power purchase contracts include a derivative
asset with a fair value of $112.4 million and a derivative liability with a
fair value of $54.6 million at December 31, 2003.
CL&P holds financial transmission rights (FTR) contracts to mitigate the
risk associated with the congestion price differences associated with LMP
in New England. FTR contracts held by CL&P were recorded at a fair value
of $3 million. Management believes the amount to be paid for the FTR
contracts best represents their fair value. If new markets for these
contracts develop, then there may be an impact on CL&P's consolidated
financial statements in future periods.
Regulatory Accounting: The accounting policies of CL&P historically
reflect the effects of the rate-making process in accordance with SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." The
transmission and distribution businesses of CL&P continue to be cost-of-
service rate regulated, and management believes the application of SFAS No.
71 to that portion of those businesses continues to be appropriate.
Management must reaffirm this conclusion at each balance sheet date. If,
as a result of a change in circumstances, it is determined that any portion
of CL&P 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 their regulatory assets and liabilities. Such a
write-off could have a material impact on CL&P's consolidated financial
statements.
The application of SFAS No. 71 results in recording regulatory assets and
liabilities. Regulatory assets represent the deferral of incurred costs
that are probable of future recovery in customer rates. In some cases,
CL&P records regulatory assets before approval for recovery has been
received from the applicable regulatory commission. Management must use
judgment to conclude that costs deferred as regulatory assets are probable
of future recovery. Management bases its conclusion on certain factors,
including changes in the regulatory environment, recent rate orders issued
by the DPUC and the status of any potential new legislation. Regulatory
liabilities represent revenues received from customers to fund expected
costs that have not yet been incurred or probable future refunds to
customers.
Management uses its best judgment when recording regulatory assets and
liabilities; however, the DPUC can reach different conclusions about the
recovery of costs, and those conclusions could have a material impact on
CL&P's consolidated financial statements. Management believes it is
probable that CL&P will recover the regulatory assets that have been
recorded.
Pension and Postretirement Benefits Other Than Pensions (PBOP): CL&P
participates in a uniform noncontributory defined benefit retirement plan
(Pension Plan) covering substantially all regular CL&P employees. CL&P
also participates in a postretirement benefit plan (PBOP Plan) to provide
certain health care benefits, primarily medical and dental, and life
insurance benefits through a benefit plan to retired employees. For each
of these plans, the development of the benefit obligation, fair value of
plan assets, funded status and net periodic benefit credit or cost is based
on several significant assumptions. If these assumptions were changed, the
resulting change in benefit obligations, fair values of plan assets, funded
status and net periodic benefit credits or costs could have a material
impact on CL&P's consolidated financial statements.
Results: Pre-tax periodic pension income for the Pension Plan, excluding
settlements, curtailments and special termination benefits, totaled $29.1
million, $50.6 million and $61.4 million for the years ended December 31,
2003, 2002 and 2001, respectively. The pension income amounts exclude one-
time items recorded under SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," associated with early termination programs and the
sale of the Millstone and Seabrook nuclear units. Net SFAS No. 88 items
totaled $8.1 million in expense for the year ended December 31, 2002. This
amount was recorded as a liability for refund to customers.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and
special termination benefits, totaled $16.6 million, $17.4 million and
$14.3 million for the years ended December 31, 2003, 2002 and 2001,
respectively.
Long-Term Rate of Return Assumptions: In developing the expected long-term
rate of return assumptions, CL&P evaluated input from actuaries,
consultants and economists, as well as long-term inflation assumptions and
CL&P's historical 20-year compounded return of approximately 11 percent.
CL&P's expected long-term rates of return on assets is based on certain
target asset allocation assumptions and expected long-term rate of return.
The Pension Plan's and PBOP Plan's target asset allocation assumptions and
expected long-term rates of return assumptions by asset category are as
follows:
- -----------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
- -----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
- -----------------------------------------------------------------------------------------------------------------
The actual asset allocations at December 31, 2003 and 2002 approximated
these target asset allocations. CL&P regularly reviews the actual asset
allocations and periodically rebalances the investments to the targeted
asset allocations when appropriate. For information regarding actual asset
allocations, see Note 4, "Pension Benefits and Postretirement Benefits
Other Than Pensions," to the consolidated financial statements.
CL&P reduced the long-term rate of return assumption 50 basis points from
9.25 percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due
to lower expected market returns. CL&P believes that 8.75 percent is a
reasonable long-term rate of return on Pension Plan and PBOP Plan assets
for 2003, and CL&P expects to use 8.75 percent in 2004. 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.
Actuarial Determination of Income and Expense: CL&P bases the actuarial
determination of Pension Plan and PBOP Plan income/expense on a market-
related valuation of assets, which reduces year-to-year volatility. This
market-related valuation calculation recognizes investment gains or losses
over a four-year period from the year in which they occur. Investment
gains or losses for this purpose are the difference between the expected
return calculated using the market-related value of assets and the actual
return based on the fair value of assets. Since the market-related
valuation calculation recognizes gains or losses over a four-year period,
the future value of the market-related assets will be impacted as
previously deferred gains or losses are recognized. There will be no
impact on the fair value of Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized
investment losses of $49 million, which will increase pension expense over
the next four years by reducing the expected return on Pension Plan assets.
At December 31, 2003, the Pension Plan also had cumulative unrecognized
actuarial losses of $63.1 million, which will increase pension expense over
the expected future working lifetime of active Pension Plan participants,
or approximately 13 years. The combined total of unrecognized investment
and actuarial losses at December 31, 2003 is $112.1 million. These losses
impact the determination of pension expense and the actuarially determined
prepaid pension amount recorded on the consolidated balance sheets but have
no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment
losses of $3.2 million, which will increase PBOP Plan cost over the next
four years by reducing the expected return on plan assets. At December 31,
2003, the PBOP Plan also had cumulative unrecognized actuarial losses of
$45.3 million, which will increase PBOP Plan expense over the expected
future working lifetime of active PBOP Plan participants, or approximately
13 years. The combined total of unrecognized investment and actuarial
losses at December 31, 2003 is $48.5 million. These losses impact the
determination of PBOP Plan cost and the actuarially determined accrued PBOP
Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future
pension and PBOP obligations is based on a basket of long-term bonds that
receive one of the two highest ratings given by a recognized rating agency.
To compensate for the Pension Plan's longer duration 25 basis points were
added to the benchmark. The discount rate determined on this basis has
decreased from 6.75 percent at December 31, 2002 to 6.25 percent at
December 31, 2003.
Expected Pension Income: Due to the effect of the unrecognized actuarial
losses and based on an expected rate of return on Pension Plan assets of
8.75 percent, a discount rate of 6.25 percent and various other
assumptions, CL&P estimates that expected contributions to and pension
income for the Pension Plan will be as follows (millions):
- -------------------------------------------------------
Expected
Year Contributions Pension Income
- -------------------------------------------------------
2004 $ - $13.5
2005 $ - $ 3.3
2006 $ - $ 0.1
- -------------------------------------------------------
Future actual pension income/expense will depend on future investment
performance, changes in future discount rates and various other factors
related to the populations participating in the Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to
the Pension Plan's reported cost and to the PBOP Plan's reported cost as a
result of the change in the following assumptions by 50 basis points (in
millions):
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
Pension Plan Postretirement Plan
- ---------------------------------------------------------------------
Assumption Change 2003 2002 2003 2002
- ---------------------------------------------------------------------
Lower long-term
rate of return $ 4.9 $ 4.9 $0.3 $0.4
Lower discount
rate $ 4.9 $ 4.4 $0.4 $0.5
Lower compensation
increase $(2.0) $(1.8) N/A N/A
- ---------------------------------------------------------------------
Plan Assets: The value of the Pension Plan assets has increased from
$752.7 million at December 31, 2002 to $899.3 million at December 31, 2003.
The investment performance returns, despite declining discount rates, have
increased the overfunded status of the Pension Plan on a projected benefit
obligation (PBO) basis from $72.3 million at December 31, 2002 to $168
million at December 31, 2003. The PBO includes expectations of future
employee compensation increases. The accumulated benefit obligation (ABO)
of the Pension Plan was approximately $253 million less than Pension Plan
assets at December 31, 2003 and approximately $158 million less than
Pension Plan assets at December 31, 2002. The ABO is the obligation for
employee service and compensation provided through December 31, 2003. If
the ABO for the entire Pension Plan exceeds all Pension Plan assets at a
future plan measurement date, NU will record an additional minimum
liability of which CL&P will be allocated its proportionate share. CL&P
has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $50.3 million at December 31,
2002 to $64.3 million at December 31, 2003. The investment performance
returns, despite declining discount rates, have decreased the underfunded
status of the PBOP Plan on an accumulated projected benefit obligation
basis from $116.7 million at December 31, 2002 to $105 million at December 31,
2003. CL&P has made a contribution each year equal to the PBOP Plan's
postretirement benefit cost, excluding curtailments, settlements and
special termination benefits.
Health Care Cost: The health care cost trend assumption used to project
increases in medical costs is 9 percent for 2003, decreasing one percentage
point per year to an ultimate rate of 5 percent in 2007. The effect of
increasing the health care cost trend by one percentage point would have
increased 2003 service and interest cost components of the PBOP Plan cost
by $0.3 million in 2003 and $0.4 million in 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8,
2003, the President signed into law a bill that expands Medicare, primarily
by adding a prescription drug benefit and by adding a federal subsidy to
qualifying plan sponsors of retiree health care benefit plans. Management
believes that CL&P currently qualifies.
Specific authoritative accounting guidance on how to account for the effect
the Medicare federal subsidy has on CL&P's PBOP Plan has not been issued by
the FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003," required CL&P to make an
election for 2003 financial reporting. The election was to either defer
the impact of the subsidy until the FASB issues guidance or to reflect the
impact of the subsidy on December 31, 2003 reported amounts. CL&P chose to
reflect the impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit
obligation by approximately $9.4 million and increased actuarial gains by
approximately $9.4 million with no impact on 2003 expenses, assets, or
liabilities. The $9.4 million actuarial gain will be amortized as a
reduction to PBOP expense over 13 years beginning in 2004. PBOP expense in
2004 will also reflect a lower interest cost due to the reduction in the
December 31, 2003 benefit obligation. Management estimates that the
reduction in PBOP expense in 2004 will be approximately $0.7 million.
When accounting guidance is issued by the FASB, it may require CL&P to
change the accounting described above and change the information included
in this annual report.
Income Taxes: Income tax expense is calculated each year in each of the
jurisdictions in which CL&P operates. 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 and expenses for tax and book accounting purposes. These
differences result in deferred tax assets and liabilities, which are
included in CL&P's consolidated balance sheets. Adjustments made to income
taxes could significantly affect CL&P's consolidated financial statements.
Management must also assess the likelihood that deferred tax assets will be
recovered from future taxable income, and to the extent that recovery is
not likely, a valuation allowance must be established. Significant
management judgment is required in determining income tax expense and
deferred tax assets and liabilities.
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. The regulatory asset amounted to $140.9 million and $165
million at December 31, 2003 and 2002, respectively. Regulatory agencies
in certain jurisdictions in which CL&P operates require the tax effect of
specific temporary differences to be "flowed through" to utility customers.
Flow through treatment means that deferred tax expense is not recorded in
the consolidated statements of income. Instead, the tax effect of the
temporary difference impacts both amounts for income tax expense currently
included in customers' rates and the company's net income. Flow through
treatment can result in effective income tax rates that are significantly
different than expected income tax rates. Recording deferred taxes on flow
through items is required by SFAS No. 109, and the offset to the deferred
tax amounts is the regulatory asset referred to above. A reconciliation
from expected tax expense at the statutory federal income tax rate to
actual tax expense recorded is included in Note 12, "Income Tax Expense,"
to the consolidated financial statements.
The estimates that are made by management in order to record income tax
expense, accrued taxes and deferred taxes are compared each year to the
actual tax amounts filed on CL&P's income tax returns. The income tax
returns were filed in the fall of 2003 for the 2002 tax year. In the
fourth quarter, CL&P recorded differences between income tax expense,
accrued taxes and deferred taxes on its consolidated financial statements
and the amounts that were on its income tax returns. Recording these
differences in income tax expense resulted in a positive impact of
approximately $2.7 million on CL&P's 2003 earnings.
Depreciation: Depreciation expense is calculated based on an asset's
useful life, and judgment is involved when estimating the useful lives of
certain assets. A change in the estimated useful lives of these assets
could have a material impact on CL&P's consolidated financial statements
absent timely rate relief for CL&P's assets.
Accounting for Environmental Reserves: Environmental reserves are accrued
using a probabilistic model approach when assessments indicate that it is
probable that a liability has been incurred and an amount can be reasonably
estimated. Adjustments made to environmental liabilities could have a
significant effect on earnings. The probabilistic model approach estimates
the liability based on the most likely action plan from a variety of
available remediation options, ranging from no action to remedies ranging
from establishing institutional controls to full site remediation and long-
term monitoring. The probabilistic model approach estimates the
liabilities associated with each possible action plan based on findings
through various phases of site assessments. These estimates are based on
currently available information from presently enacted state and federal
environmental laws and regulations and several cost estimates from outside
engineering and remediation contractors. These amounts also take into
consideration prior experience in remediating contaminated sites and data
released by the United States Environmental Protection Agency and other
organizations.
These estimates are subjective in nature partly because there are usually
several different remediation options from which to choose when working on
a specific site. These estimates are subject to revisions in future
periods based on actual costs or new information concerning either the
level of contamination at the site or newly enacted laws and regulations.
The amounts recorded as environmental liabilities on the consolidated
balance sheets represent management's best estimate of the liability for
environmental costs based on current site information from site assessments
and remediation estimates. These liabilities are estimated on an
undiscounted basis.
CL&P recovers a certain level of environmental costs currently in rates but
does not have an environmental cost recovery tracking mechanism.
Accordingly, changes in CL&P's environmental reserves impact CL&P's
earnings.
Asset Retirement Obligations: CL&P adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations" on January 1, 2003. SFAS No. 143 requires
that legal obligations associated with the retirement of property, plant
and equipment be recorded as a liability on the balance sheet at fair value
when incurred and when a reasonable estimate of the fair value can be made.
SFAS No. 143 defines an asset retirement obligation (ARO) as a legal
obligation that is required to be settled due to an existing or enacted
law, statute, ordinance or a written or oral promise to remove an asset.
AROs may stem from environmental laws, state laws and regulations, easement
agreements, building codes, contracts, franchise grants and agreements,
oral promises made upon which third parties have relied, or the
dismantlement, restoration, or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified
that management believes are AROs but either have not been incurred or are
not material. These removal obligations arise in the ordinary course of
business or have a low probability of occurring. The types of obligations
primarily relate to transmission and distribution lines and poles,
telecommunication towers, transmission cables and certain FERC or state
regulatory agency re-licensing issues. There was no impact to CL&P's
earnings upon adoption of SFAS No. 143; however, if there are changes in
certain laws and regulations, orders, interpretations or contracts entered
into by CL&P there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including CL&P, currently recover
amounts in rates for future costs of removal of plant assets. Future
removals of assets do not represent legal obligations and are not AROs.
Historically, these amounts were included as a component of accumulated
depreciation until spent. At December 31, 2003 and 2002, these amounts
totaling $150 million and $154 million, respectively, were reclassified to
regulatory liabilities on the accompanying consolidated balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No.
143, 'Accounting for Asset Retirement Obligations', to Legislative
Requirements on Property Owners to Remove and Dispose of Asbestos or
Asbestos-Containing Materials." In the FSP, the FASB staff concludes that
current legislation creates a legal obligation for the owner of a building
to remove and dispose of asbestos-containing materials. In the FSP, the
FASB staff also concludes that this legal obligation constitutes an ARO
that should be recognized as a liability under SFAS No. 143. This FSP
changes a FASB staff interpretation of SFAS No. 143 that an obligating
event did not occur until a building containing asbestos was demolished.
In November 2003, the FASB indicated that, based on the diverse views it
received in comment letters on the proposed FSP, it was considering a
proposal for a FASB agenda project to address this issue. If this FSP is
adopted in its current form, then CL&P would be required to record an ARO.
Management has not estimated this potential ARO at December 31, 2003.
Special Purpose Entities: In addition to the special purpose entity that
is described in the "Off-Balance Sheet Arrangements" section of this
Management's Discussion and Analysis, during 2001, to facilitate the
issuance of rate reduction certificates intended to finance certain
stranded costs, CL&P established CL&P Funding LLC. CL&P Funding LLC was
created as part of a state-sponsored securitization program. 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 became involved in a
bankruptcy proceeding. CL&P Funding LLC and the securitization amounts are
consolidated in the accompanying consolidated financial statements.
For further information regarding the matters in this "Critical Accounting
Policies and Estimates" section see Note 1, "Summary of Significant
Accounting Policies," Note 3, "Derivative Instruments and Risk Management
Activities," Note 4, "Pension Benefits and Postretirement Benefits Other
Than Pensions," Note 12, "Income Tax Expense," and Note 6C, "Commitments
and Contingencies - Environmental Matters," to the consolidated financial
statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 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,
2003 is summarized through 2008 and thereafter as follows:
- ------------------------------------------------------------------------------------------------------
(Millions of
Dollars) 2004 2005 2006 2007 2008 Thereafter
- ------------------------------------------------------------------------------------------------------
Long-term debt (a) $ - $ - $ - $ - $ - $ 622.7
Capital
leases (b) (c) 2.6 2.6 2.5 2.4 2.1 20.1
Operating
leases (c) 11.8 11.2 10.1 9.0 8.3 16.4
Long-term
contractual
arrangements (c) (d) 222.9 222.1 223.6 225.3 215.5 1,252.1
- ------------------------------------------------------------------------------------------------------
Totals $237.3 $235.9 $236.2 $236.7 $225.9 $1,911.3
- ------------------------------------------------------------------------------------------------------
(a) Included in CL&P's debt agreements are usual and customary positive,
negative and financial covenants. Non-compliance with certain covenants,
for example the timely payment of principal and interest, may constitute an
event of default, which could cause an acceleration of principal in the
absence of receipt by the company of a waiver or amendment. Such
acceleration would change the obligations outlined in the table of
contractual obligations and commercial commitments. Long-term debt
excludes fees and interest for spent nuclear fuel disposal costs and
amortized premium and discount, net.
(b) The capital lease obligations include imputed interest of $17.4 million.
(c) CL&P has no provisions in its capital or operating lease agreements or
agreements related to its long-term contractual arrangements that could
trigger a change in terms and conditions, such as acceleration of payment
obligations.
(d) Amounts are not included on CL&P's consolidated balance sheets.
Rate reduction bond amounts are non-recourse to CL&P, have no required
payments over the next five years and are not included in this table.
Additionally, this table does not include notes payable to affiliated
companies totaling $91.1 million at December 31, 2003 and CL&P's expected
contribution to the PBOP Plan in 2004 of $19.9 million. CL&P's standard
offer service contracts and default service contracts are also not included
in this table. For further information regarding CL&P's contractual
obligations and commercial commitments, see Note 8, "Leases," Note 6F,
"Commitments and Contingencies - Long-Term Contractual Arrangements," and
Note 11, "Long-Term Debt," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward
looking statements, which are statements of future expectations and not
facts including, but not limited to, statements regarding future earnings,
refinancings, regulatory proceedings, the use of proceeds from
restructuring, and the recovery of operating costs. Words such as
estimates, expects, anticipates, intends, plans, and similar expressions
identify forward looking statements. Actual results or outcomes could
differ materially as a result of further actions by state and federal
regulatory bodies, competition and industry restructuring, changes in
economic conditions, changes in weather patterns, changes in laws,
developments in legal or public policy doctrines, technological
developments, volatility in electric commodity markets, and other presently
unknown or unforeseen factors.
Website: Additional financial information is available through NU's website
at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items
for the consolidated statements of income included in this annual report
for the past two years.
- ---------------------------------------------------------------------------------------------------
2003 over/(under) 2002 2002 over/(under) 2001
Income Statement Variances ---------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
- ---------------------------------------------------------------------------------------------------
Operating Revenues $197 8% $(139) (5)%
Operating Expenses:
Fuel, purchased and net interchange power 125 8 (37) (2)
Other operation 79 26 (10) (3)
Maintenance (7) (9) (26) (25)
Depreciation 6 6 2 2
Amortization 17 21 (597) (88)
Amortization of rate reduction bonds 7 7 29 42
Taxes other than income taxes 5 4 7 5
Gain on sale of utility plant 16 100 505 97
- ---------------------------------------------------------------------------------------------------
Total operating expenses 248 11 (127) (5)
- ---------------------------------------------------------------------------------------------------
Operating income (51) (20) (12) (4)
Interest expense, net (10) (9) - -
Other income, net (17) (79) (30) (58)
- ---------------------------------------------------------------------------------------------------
Income before income tax expense (58) (38) (42) (22)
Income tax expense (41) (62) (18) (21)
- ---------------------------------------------------------------------------------------------------
Net income $(17) (20)% $ (24) (22)%
===================================================================================================
OPERATING REVENUES
Operating revenues increased by $197 million in 2003, primarily due to
higher retail revenues ($144 million), and higher wholesale revenues ($51
million). Retail revenues were higher primarily due to the collection of
incremental LMP costs beginning in May 2003 ($72 million) net of amounts to
be returned to customers and higher retail sales volumes ($72 million)
which includes a positive adjustment in estimated unbilled revenue of
approximately $39 million. Retail kWh sales increased by 3.3 percent in
2003 with the adjustment to unbilled sales. Wholesale revenues were higher
primarily due to higher market prices in 2003.
Operating revenues decreased $139 million 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.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $125 million in
2003, primarily due to incremental LMP costs that were recovered from
customers ($72 million) and higher standard offer purchases as a result of
higher retail sales ($47 million).
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).
OTHER OPERATION
Other operation expenses increased $79 million in 2003, primarily due to
higher administrative costs ($37 million) resulting from lower pension
income, higher reliability must run related transmission costs ($30
million), higher C&LM expenses ($8 million) and higher distribution
expenses ($5 million), partially offset by lower related nuclear expenses
($4 million) as a result of the final DPUC order regarding the CL&P
Millstone use of proceeds docket in the first quarter of 2003.
Other operation expenses decreased $10 million in 2002, primarily due to
lower nuclear expense as a result of the sale of Millstone at the end of
the first quarter of 2001 ($24 million), lower distribution expenses ($8
million), partially offset by higher transmission expenses ($16 million)
and higher administrative and general expenses ($10 million).
MAINTENANCE
Maintenance expenses decreased $7 million in 2003, primarily due to lower
nuclear related expenses ($6 million) as a result of the final DPUC order
regarding the CL&P Millstone use of proceeds docket in the first quarter of
2003.
Maintenance expenses decreased $26 million in 2002, primarily due to lower
nuclear expense as a result of the sale of Millstone at the end of the
first quarter of 2001 ($28 million), partially offset by higher
transmission expenses ($3 million).
DEPRECIATION
Depreciation expense increased $6 million in 2003, primarily due to higher
utility plant balances in 2003 resulting from plant additions.
Depreciation expense increased $2 million in 2002, primarily due to higher
utility plant balances.
AMORTIZATION
Amortization increased $17 million in 2003, primarily due to higher
amortization related to the recovery of stranded costs ($73 million),
partially offset by lower amortization of recoverable nuclear costs ($38
million), and amortization expense recorded in 2002 related to gain on the
sale of CL&P's ownership share in Seabrook ($16 million).
Amortization decreased $597 million in 2002, primarily due to lower
amortizations related to the sale of Millstone ($522 million) and lower
amortizations of the nuclear investment ($42 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $7 million in 2003 due to
the repayment of principal.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5 million in 2003, primarily due
to higher gross earnings taxes ($2 million), the recognition in 2002 of a
Connecticut sales and use tax audit settlement ($7 million), partially
offset by lower tax payments to the Town of Waterford in 2003 as compared
to 2002 ($4 million).
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.
GAIN ON SALE OF UTILITY PLANT
Gain on sale of utility plant decreased due to the $16 million gain
recorded in 2002 on the sale of CL&P's ownership share in Seabrook versus
no gain recorded in 2003.
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 Millstone ($522
million). A corresponding amount of amortization expenses was recorded.
INTEREST EXPENSE, NET
Interest expense, net decreased $10 million in 2003 primarily due to lower
interest on rate reduction bonds ($5 million) and other interest ($3
million).
OTHER INCOME, NET
Other income, net decreased $17 million in 2003, primarily due to lower
interest and dividend income ($4 million), lower equity in earnings from
the nuclear entitlements ($4 million), lower conservation and load management
incentive income ($2 million), and higher charitable donations ($2 million).
Other income, net decreased $30 million in 2002, primarily due to the gain
recognized in 2001 on the sale of Millstone ($29 million).
INCOME TAX EXPENSE
Income tax expense decreased in 2003 and in 2002 primarily due to lower
book taxable income. For further information regarding income tax expense,
see Note 12, "Income Tax Expense," to the consolidated financial
statements.
COMPANY REPORT
- -------------------------------------------------------------------------------
Management is responsible for the preparation, integrity, and fair
presentation of the accompanying consolidated financial statements of The
Connecticut Light and Power Company and subsidiaries and other sections of
this annual report. These financial statements, which were audited by
Deloitte & Touche LLP, have been prepared in conformity with accounting
principles generally accepted in the United States of America using
estimates and judgments, where required, and giving consideration to
materiality.
The company has endeavored to establish a control environment that
encourages the maintenance of high standards of conduct in all of its
business activities. Management is responsible for maintaining a system of
internal control over financial reporting that is designed to provide
reasonable assurance, at an appropriate cost-benefit relationship, to the
company's management and Board of Trustees of Northeast Utilities regarding
the preparation of reliable, published financial statements. The system is
supported by an organization of trained management personnel, policies and
procedures, and a comprehensive program of internal audits. Through
established programs, the company regularly communicates to its management
employees their internal control responsibilities and obtains information
regarding compliance with policies prohibiting conflicts of interest and
policies segregating information between regulated and unregulated
subsidiary companies. The company has standards of business conduct for
all employees, as well as a code of ethics for senior financial officers.
The Audit Committee of the Board of Trustees of Northeast Utilities is
composed entirely of independent trustees and includes two members that the
Board of Trustees considers "audit committee financial experts." The Audit
Committee meets regularly with management, the internal auditors and the
independent auditors to review the activities of each and to discuss audit
matters, financial reporting matters, and the system of internal controls
over financial reporting. The Audit Committee also meets periodically with
the internal auditors and the independent auditors without management
present.
Because of inherent limitations in any system of internal controls, errors
or irregularities may occur and not be detected. The company believes,
however, that its system of internal controls over financial reporting and
control environment provide reasonable assurance that its assets are
safeguarded from loss or unauthorized use and that its financial records,
which are the basis for the preparation of all financial statements, are
reliable. Additionally, management believes that its disclosure controls
and procedures are in place and operating effectively. Disclosure controls
and procedures are designed to ensure that information included in reports
such as this annual report is recorded, processed, summarized, and reported
within the time periods required and that the information disclosed is
accumulated and reviewed by management for discussion and approval.
INDEPENDENT AUDITORS' REPORT
- -------------------------------------------------------------------------------
To the Board of 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, 2003 and 2002, 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,
2003. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audits to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of The Connecticut Light and
Power Company and subsidiaries as of December 31, 2003 and 2002, and the
results of their operations and their cash flows for the each of the three
years in the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------------
At December 31, 2003 2002
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 5,814 $ 159
Restricted cash - LMP costs 93,630 -
Investments in securitizable assets 166,465 178,908
Receivables, less provision for uncollectible
accounts of $21,790 in 2003 and $525 in 2002 60,759 88,001
Accounts receivable from affiliated companies 73,986 51,060
Unbilled revenues 6,961 5,801
Notes receivable from affiliated companies - 1,900
Materials and supplies, at average cost 31,583 32,379
Derivative assets 115,370 -
Prepayments and other 12,521 19,407
---------------- ----------------
567,089 377,615
---------------- ----------------
Property, Plant and Equipment:
Electric utility 3,355,794 3,139,128
Less: Accumulated depreciation 1,018,173 959,991
---------------- ----------------
2,337,621 2,179,137
Construction work in progress 224,277 153,556
---------------- ----------------
2,561,898 2,332,693
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 1,673,010 1,702,677
Prepaid pension 305,320 276,173
Other 99,577 96,925
---------------- ----------------
2,077,907 2,075,775
---------------- ----------------
Total Assets $ 5,206,894 $ 4,786,083
================ ================
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------------
At December 31, 2003 2002
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to affiliated companies $ 91,125 $ -
Accounts payable 138,155 174,890
Accounts payable to affiliated companies 176,948 117,904
Accrued taxes 65,587 34,350
Accrued interest 10,361 10,077
Derivative liabilities 54,566 -
Other 49,674 48,495
---------------- ----------------
586,416 385,716
---------------- ----------------
Rate Reduction Bonds 1,124,779 1,245,728
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 609,068 756,461
Accumulated deferred investment tax credits 90,885 93,408
Deferred contractual obligations 318,043 234,537
Regulatory liabilities 752,992 343,754
Other 79,935 86,571
---------------- ----------------
1,850,923 1,514,731
---------------- ----------------
Capitalization:
Long-Term Debt 830,149 827,866
---------------- ----------------
Preferred Stock - Non-redeemable 116,200 116,200
---------------- ----------------
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2003 and 2002 60,352 60,352
Capital surplus, paid in 326,629 327,299
Retained earnings 311,793 308,554
Accumulated other comprehensive loss (347) (363)
---------------- ----------------
Common Stockholder's Equity 698,427 695,842
---------------- ----------------
Total Capitalization 1,644,776 1,639,908
---------------- ----------------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization $ 5,206,894 $ 4,786,083
================ ================
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
- ----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 2,704,524 $ 2,507,036 $ 2,646,123
-------------- -------------- -------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 1,602,240 1,477,347 1,514,418
Other 380,039 300,439 310,477
Maintenance 73,066 80,132 106,228
Depreciation 104,513 98,360 96,212
Amortization of regulatory assets, net 98,670 81,785 678,651
Amortization of rate reduction bonds 103,285 96,489 68,042
Taxes other than income taxes 142,339 137,299 130,656
Gain on sale of utility plant - (16,143) (521,590)
-------------- -------------- -------------
Total operating expenses 2,504,152 2,255,708 2,383,094
-------------- -------------- -------------
Operating Income 200,372 251,328 263,029
Interest Expense:
Interest on long-term debt 39,815 41,332 56,527
Interest on rate reduction bonds 70,284 75,705 60,644
Other interest 508 3,925 3,958
-------------- -------------- -------------
Interest expense, net 110,607 120,962 121,129
-------------- -------------- -------------
Other Income, Net 4,564 22,112 52,804
-------------- -------------- -------------
Income Before Income Tax Expense 94,329 152,478 194,704
Income Tax Expense 25,421 66,866 84,901
-------------- -------------- -------------
Net Income $ 68,908 $ 85,612 $ 109,803
============== ============== =============
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income $ 68,908 $ 85,612 $ 109,803
-------------- -------------- -------------
Other comprehensive income/(loss), net of tax:
Unrealized gains/(losses) on securities 152 (408) (439)
Minimum supplemental executive retirement
pension liability adjustments (136) (22) -
-------------- -------------- -------------
Other comprehensive income/(loss), net of tax 16 (430) (439)
-------------- -------------- -------------
Comprehensive Income $ 68,924 85,182 $ 109,364
============== ============== =============
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
- --------------------------------------------------------------------------------------------------------------------------------
Accumulated
Common Stock Capital Other
---------------------- Surplus, Retained Comprehensive Total
Shares Amount Paid In Earnings Income/(Loss) (a)
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance at January 1, 2001 7,584,884 $ 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 7,584,884 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 (1,549,679) (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 6,035,205 60,352 327,299 308,554 (363) 695,842
Net income for 2003 68,908 68,908
Cash dividends on preferred stock (5,559) (5,559)
Cash dividends on common stock (60,110) (60,110)
Capital stock expenses, net 186 186
Allocation of benefits - ESOP (856) (856)
Other comprehensive income 16 16
---------- -------- -------- -------- ----- --------
Balance at December 31, 2003 6,035,205 $ 60,352 $326,629 $311,793 $(347) $698,427
========== ======== ======== ======== ===== ========
(a) The Federal Power Act and the Public Utility Holding Act of 1935 (the 1935
Act)limit the payment of dividends by the company to its retained earnings
balance.
The company also has dividend restrictions imposed by its long-term debt
agreements. These restrictions limit the amount of retained earnings
available for common dividends.
The Utility Group credit agreement also limits dividend payments subject to
the requirements that the company's total debt to total capitalization
ratio does not exceed 65 percent.
At December 31, 2003, retained earnings available for payment of dividends
is restricted to $275.0 million.
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
- -------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 68,908 $ 85,612 $ 109,803
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 104,513 98,360 96,212
Deferred income taxes and investment tax credits, net (118,425) (71,880) (144,559)
Amortization of regulatory assets, net 98,670 81,785 678,651
Amortization of rate reduction bonds 103,285 96,489 68,042
Amortization of recoverable energy costs 19,191 30,787 5,162
Gain on sale of utility plant - (16,143) (521,590)
Increase in prepaid pension (29,147) (42,481) (63,020)
Regulatory overrecoveries/(refunds) 275,015 92,743 (49,443)
Other sources of cash 2,283 11,646 26,465
Other uses of cash (99,827) (44,245) (86,635)
Changes in current assets and liabilities:
Restricted cash - LMP costs (93,630) - -
Receivables and unbilled revenues, net 3,156 (37,435) (144,419)
Materials and supplies 796 (1,017) 3,247
Investments in securitizable assets 12,443 27,459 61,779
Other current assets (excludes cash) 6,886 (1,535) 14,418
Accounts payable 22,309 74,831 (58,400)
Accrued taxes 31,237 (643) 1,922
Other current liabilities 1,385 351 11,414
----------- ---------- ----------
Net cash flows provided by operating activities 409,048 384,684 9,049
----------- ---------- ----------
Investing Activities:
Investments in plant (314,628) (239,634) (236,218)
NU system Money Pool borrowing/(lending) 93,025 75,300 (39,200)
Investments in nuclear decommissioning trusts - (1,086) (74,866)
Net proceeds from the sale of utility plant - 35,887 827,681
Buyout/buydown of IPP contracts - - (1,029,008)
Other investment activities 5,448 23,395 (10,164)
----------- ---------- ----------
Net cash flows used in investing activities (216,155) (106,138) (561,775)
----------- ---------- ----------
Financing Activities:
Repurchase of common shares - (99,990) -
Issuance of rate reduction bonds - - 1,438,400
Retirement of rate reduction bonds (120,949) (112,924) (79,747)
Decrease in short-term debt - - (115,000)
Reacquistions and retirements of long-term debt - - (416,155)
Retirement of monthly income preferred securities - - (100,000)
Retirement of capital lease obligation - - (145,800)
Cash dividends on preferred stock (5,559) (5,559) (5,559)
Cash dividends on common stock (60,110) (60,145) (60,072)
Other financing activities (620) (542) 31,971
----------- ---------- ----------
Net cash flows (used in)/provided by financing activities (187,238) (279,160) 548,038
----------- ---------- ----------
Net increase/(decrease) in cash 5,655 (614) (4,688)
Cash - beginning of year 159 773 5,461
----------- ---------- ----------
Cash - end of year $ 5,814 $ 159 $ 773
=========== ========== ==========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 112,258 $ 117,718 $ 120,645
=========== ========== ==========
Income taxes $ 105,167 $ 141,724 $ 230,144
=========== ========== ==========
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 COMPANY
The Connecticut Light and Power Company (CL&P or the company) is a wholly
owned subsidiary of Northeast Utilities (NU). 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). CL&P, Public Service Company
of New Hampshire (PSNH), and Western Massachusetts Electric Company
(WMECO), furnish franchised retail electric service in Connecticut, New
Hampshire and Massachusetts, respectively.
Several wholly owned subsidiaries of NU provide support services for NU's
companies, including CL&P. Northeast Utilities Service Company (NUSCO)
provides centralized accounting, administrative, engineering, financial,
information technology, legal, operational, planning, purchasing, and other
services to NU's companies.
On January 1, 2000, Select Energy, Inc. (Select Energy), another NU
subsidiary, began serving one half of CL&P's standard offer load for a four-
year period ending on December 31, 2003, at fixed prices. Total CL&P
purchases from Select Energy for CL&P's standard offer load and for other
transactions with Select Energy represented approximately $688 million,
approximately $631 million and approximately $648 million, for the years
ended December 31, 2003, 2002, and 2001, respectively.
B. PRESENTATION
The consolidated financial statements of CL&P and of its subsidiaries, as
applicable, include the accounts of all their respective subsidiaries.
Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingencies at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from
those estimates.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation. Reclassifications were made to cost
of removal and regulatory asset and liability amounts on the accompanying
consolidated balance sheets. Reclassifications have also been made to the
accompanying consolidated statements of cash flows.
C. NEW ACCOUNTING STANDARDS
Derivative Accounting: Effective January 1, 2001, CL&P adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. In April 2003, the
Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment
of Statement 133 on Derivative Instruments and Hedging Activities," which
amends SFAS No. 133. This new statement incorporates interpretations that
were included in previous Derivative Implementation Group (DIG) guidance,
clarifies certain conditions, and amends other existing pronouncements. It
is effective for contracts entered into or modified after June 30, 2003.
Management has determined that the adoption of SFAS No. 149 did not change
CL&P's accounting for contracts, or the ability of CL&P to elect the normal
purchases and sales exception.
In August of 2003, the FASB ratified the consensus reached by its Emerging
Issues Task Force (EITF) in July 2003 on EITF Issue No. 03-11, "Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to
FASB Statement No. 133 and Not `Held for Trading Purposes' as Defined in
Issue No. 02-3." Prior to Issue No. 03-11, no specific guidance existed to
address the classification in the income statement of derivative contracts
that are not held for trading purposes. The consensus states that
determining whether realized gains and losses on contracts that physically
deliver and are not held for trading purposes should be reported on a net
or gross basis is a matter of judgment that depends on the relevant facts
and circumstances. EITF Issue No. 03-11 did not have an impact on CL&P's
consolidated financial statements.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the
meaning of "not clearly and closely related regarding contracts with a
price adjustment feature" as it relates to the election of the normal
purchase and sales exception to derivative accounting. The implementation
of this guidance was required to be adopted in the fourth quarter of 2003
for CL&P. Issue No. C-20 resulted in CL&P recording the fair value of two
existing power purchase contracts as derivatives, one as a derivative
asset and one as a derivative liability with offsetting regulatory
liabilities and assets, as these contracts are part of stranded costs and
as management believes that these costs will continue to be recovered or
refunded in rates. The fair values of these long-term power purchase contracts
include a derivative asset with a fair value of $112.4 million and a derivative
liability with a fair value of $54.6 million at December 31, 2003.
Employers' Disclosures about Pensions and Other Postretirement Benefits:
In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," (SFAS No.
132R). This statement revises employers' disclosures about pension plans
and other postretirement benefit plans, requires additional disclosures
about the assets, obligations, cash flows, and the net periodic benefit
cost of defined benefit pension plans and other defined benefit
postretirement plans and requires companies to disclose various elements of
pension and postretirement benefit costs in interim period financial
statements. The revisions in SFAS No. 132R are effective for 2003, and
CL&P included the disclosures required by SFAS No. 132R in this annual
report. For the required disclosures, see Note 4, "Pension Benefits and
Postretirement Benefits Other Than Pensions," to the consolidated financial
statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity." SFAS No. 150 establishes standards on how to
classify and measure certain financial instruments with characteristics of
both liabilities and equity. SFAS No. 150 is effective for financial
instruments entered into or modified after May 31, 2003, and was otherwise
effective for CL&P for the third quarter of 2003. The adoption of SFAS No.
150 did not have an impact on CL&P's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB
issued a revised version of FASB Interpretation No. (FIN) 46 "Consolidation
of Variable Interest Entities," (FIN 46R). FIN 46R is effective for CL&P
for the first quarter of 2004 but is not expected to have an impact on
CL&P's consolidated financial statements.
D. GUARANTEES
CL&P has obtained surety bonds in the amount of $31.1 million related to
the collection of March 2003 and April 2003 incremental locational marginal
pricing (LMP) costs in compliance with a DPUC order. These surety bonds
are guaranteed by NU.
E. REVENUES
CL&P retail revenues are based on rates approved by the DPUC. These
regulated rates are applied to customers' use of energy to calculate a
bill. In general, rates can only be changed through formal proceedings
with the DPUC.
CL&P utilizes regulatory commission-approved tracking mechanisms to track
the recovery of certain incurred costs. The tracking mechanisms allow for
rates to be changed periodically, with overcollections refunded to
customers or underrecollections collected from customers in future periods.
Unbilled revenues represent an estimate of electricity delivered to
customers that has not been billed. Unbilled revenues represent assets on
the balance sheet that become accounts receivable in the following month as
customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The
requirements method utilizes the total monthly volume of electricity or gas
delivered to the system and applies a delivery efficiency factor to reduce
the total monthly volume by an estimate of delivery losses in order to
calculate total estimated monthly sales to customers. The total estimated
monthly sales amount less total monthly billed sales amount results in a
monthly estimate of unbilled sales. Unbilled revenues are estimated by
applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for CL&P were tested using the cycle
method. The cycle method uses the billed sales from each meter reading
cycle and an estimate of unbilled days in each month based on the meter
reading schedule. The cycle method is historically more accurate than the
requirements method when used in a mostly weather-neutral month. The cycle
method resulted in adjustments to the estimate of unbilled revenues that
had a positive after-tax earnings impact on CL&P of $7.2 million in 2003.
Wholesale transmission revenues are based on rates and formulas that are
approved by the FERC. Most of CL&P's wholesale transmission revenues are
collected through a combination of the New England Regional Network Service
(RNS) tariff and CL&P's Local Network Service (LNS) tariff. The RNS
tariff, which is administered by the New England Independent System
Operator (ISO-NE), recovers the revenue requirements associated with
transmission facilities that are deemed by the FERC to be Pool Transmission
Facilities. The LNS tariff which was accepted by the FERC on October 22,
2003, provides for the recovery of CL&P's total transmission revenue
requirements, net of revenue credits received from various rate components,
including revenues received under the RNS rates.
F. ACCOUNTING FOR ENERGY CONTRACTS
The accounting treatment for energy contracts entered into varies between
contracts and depends on the intended use of the particular contract and on
whether or not the contracts are derivatives.
Non-derivative contracts that are entered into for the normal purchase or
sale of energy to customers that will result in physical delivery are
recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for the normal purchase and sale
of energy and meet the normal purchase and sale exception to derivative
accounting, as defined in SFAS No. 133 and amended by SFAS No. 149
(normal), are also recorded at the point of delivery under accrual
accounting.
Both non-derivative contracts and derivative contracts that are normal are
recorded in revenues when these contracts represent sales, and recorded in
fuel, purchased and net interchange power when these contracts represent
purchases, except for sales contracts that relate to procurement
activities. These contracts are recorded in fuel, purchased and net
interchange power when settled.
Derivative contracts that are not held for trading purposes and that do not
qualify as normal purchases and sales or hedges are non-trading derivative
contracts. These contracts are recorded on the consolidated balance sheets
at fair value, and since management believes that these costs will continue
to be recovered or refunded in rates, the changes in fair value are offset
by regulatory assets and liabilities.
For further information regarding these contracts and their accounting, see
Note 3, "Derivative Instruments and Risk Management Activities," to the
consolidated financial statements.
G. REGULATORY ACCOUNTING
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."
The transmission and distribution businesses of CL&P continue to be cost-of-
service rate regulated. 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 their
investments in long-lived assets, including regulatory assets. In
addition, all material net regulatory assets are earning an equity return,
except for securitized regulatory assets, which are not supported by
equity.
The components of CL&P's regulatory assets are as follows:
- --------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
- --------------------------------------------------------------------------
Recoverable nuclear costs $ 16.4 $ 10.6
Securitized assets 1,123.7 1,244.5
Income taxes, net 140.9 165.0
Unrecovered contractual obligations 221.8 116.8
Recoverable energy costs 30.1 49.3
Other 140.1 116.5
- --------------------------------------------------------------------------
Totals $1,673.0 $1,702.7
- --------------------------------------------------------------------------
Additionally, CL&P had $12.2 million and $6.1 million of regulatory assets
at December 31, 2003 and 2002, respectively, that are included in deferred
debits and other assets - other on the accompanying consolidated balance
sheets. These amounts represent regulatory assets that have not yet been
approved by the applicable regulatory agency. Management believes these
assets are recoverable in future rates.
Recoverable Nuclear Costs: In March 2001, CL&P sold its ownership interest
in the Millstone nuclear units (Millstone). The gain on the sale of $521.6
million was used to offset recoverable nuclear costs, resulting in unamortized
balances of $16.4 million and $6 million at December 31, 2003 and 2002,
respectively. Also included in recoverable nuclear costs for 2002 are $4.6
million related to Millstone 1 recoverable nuclear costs associated with the
undepreciated plant and related assets at the time Millstone 1 was shut down.
Securitized Assets: In March 2001, CL&P issued $1.4 billion in rate
reduction certificates. CL&P used $1.1 billion of those proceeds to buy out
or buy down certain contracts with independent power producers (IPP). The
remaining balance is $960 million and $1.1 billion at December 31, 2003 and
2002, respectively. CL&P also securitized a portion of its SFAS No. 109,
"Accounting for Income Taxes," regulatory asset which had a balance of $164
million and $180 million at December 31, 2003 and 2002, respectively.
Securitized assets are being recovered over the amortization period of
their associated rate reduction bonds. All outstanding rate reduction
bonds of CL&P are scheduled to amortize by December 30, 2010.
Income Taxes, Net: The tax effect of temporary differences (differences
between the periods in which transactions affect income in the financial
statements and the periods in which they affect the determination of
taxable income) is accounted for in accordance with the rate-making
treatment of the DPUC and SFAS No. 109. Differences in income taxes
between SFAS No. 109 and the rate-making treatment of the DPUC are recorded
as regulatory assets. For further information regarding income taxes, see
Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and
Note 12, "Income Tax Expense," to the consolidated financial statements.
Unrecovered Contractual Obligations: 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.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC)
prepared an updated estimate of the cost of decommissioning its nuclear
unit. CL&P's aggregate share of the estimated increased cost is $118.1
million. CL&P recorded an additional $118.1 million in deferred
contractual obligations and a corresponding increase in the unrecovered
contractual obligations regulatory asset as a result of these increased
costs.
Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy
Act), CL&P was assessed for its proportionate shares of the costs of
decontaminating and decommissioning uranium enrichment plants owned by the
United States Department of Energy (DOE) (D&D Assessment). The Energy Act
requires that regulators treat D&D Assessments as a reasonable and
necessary current cost of fuel, to be fully recovered in rates like any
other fuel cost. CL&P no longer owns nuclear generation but continues to
recover these costs through rates. At December 31, 2003 and 2002, CL&P's
total D&D Assessment deferrals were $14.3 million and $17.6 million,
respectively, and have been recorded as recoverable energy costs.
Through December 31, 1999, CL&P had an energy adjustment clause under which
fuel prices above or below base-rate levels were charged to or credited to
customers. CL&P's energy costs deferred and not yet collected under the
energy adjustment clause amounted to $31.7 million at December 31, 2002,
which were recorded as recoverable energy costs. On July 26, 2001, the
DPUC authorized CL&P to assess a charge of approximately $0.002 per
kilowatt-hour (kWh) to collect these costs from August 2001 through
December 31, 2003, at which time no unrecovered costs remained. During
2003, CL&P paid for a temporary generation resource in southwest
Connecticut to help maintain reliability. Costs for this resource of $15.8
million were recorded as recoverable energy costs at December 31, 2003.
The DPUC has authorized recovery of these costs in 2004 through a non-
bypassable Federally Mandated Congestion Charge.
The majority of the recoverable energy costs are recovered in rates
currently from CL&P's customers.
Regulatory Liabilities: CL&P maintained $753 million and $343.8 million of
regulatory liabilities at December 31, 2003 and 2002, respectively. These
amounts are comprised of the following:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
- ---------------------------------------------------------------------
Cost of removal $150.0 $154.0
CL&P CTA, GSC, and SBC overcollections 333.7 133.6
Regulatory liabilities offsetting
derivative assets 115.4 -
CL&P LMP overcollections 83.6 -
Other regulatory liabilities 70.3 56.2
- ---------------------------------------------------------------------
Totals $753.0 $343.8
- ---------------------------------------------------------------------
Under SFAS No. 71, CL&P currently recovers amounts in rates for future
costs of removal of plant assets. Historically, these amounts were
included as a component of accumulated depreciation until spent. These
amounts were reclassified to regulatory liabilities on the accompanying
consolidated balance sheets.
The Competitive Transition Assessment (CTA) allows CL&P to recover stranded
costs, such as securitization costs associated with the rate reduction
bonds, amortization of regulatory assets, and IPP over market costs while
the Generation Service Charge (GSC) allows CL&P to recover the costs of the
procurement of energy for standard offer service. The System Benefits
Charge (SBC) allows CL&P to recover certain regulatory and energy public
policy costs, such as public education outreach costs, hardship protection
costs, transition period property taxes, and displaced workers protection
costs.
The regulatory liabilities offsetting derivative assets relate to the fair
value of IPP contracts that will benefit ratepayers in the future. CL&P
also has financial transmission rights (FTR) contracts which are derivative
assets offset by a regulatory liability.
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.
The tax effects of temporary differences that give rise to the net
accumulated deferred tax obligation are as follows:
- ---------------------------------------------------------------------
At December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
- ---------------------------------------------------------------------
Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $533.8 $514.8
Regulatory amounts:
Securitized contract termination
costs and other 51.0 57.5
Income tax gross-up 136.5 156.7
Employee benefits 121.1 115.5
Other 46.2 86.3
- ---------------------------------------------------------------------
Total deferred tax liabilities 888.6 930.8
- ---------------------------------------------------------------------
Deferred tax assets:
Regulatory deferrals 199.3 101.5
Employee benefits 7.0 6.8
Income tax gross-up 20.9 22.3
Other 52.3 43.7
- ---------------------------------------------------------------------
Total deferred tax assets 279.5 174.3
- ---------------------------------------------------------------------
Totals $609.1 $756.5
- ---------------------------------------------------------------------
NU and its subsidiaries, including CL&P, file a consolidated federal income
tax return. Likewise NU and its subsidiaries, including CL&P, file state
income tax returns, with some filing in more than one state. NU and its
subsidiaries, including CL&P, are parties to a tax allocation agreement
under which each taxable subsidiary pays a quarterly estimate (or
settlement) of no more than it would have otherwise paid had it filed a
stand-alone tax return. Generally these quarterly estimated payments are
settled to actual payments within three months after filing the associated
return. Subsidiaries generating tax losses are similarly paid for their
losses when utilized.
In 2000, NU requested from the Internal Revenue Service (IRS) a Private
Letter Ruling (PLR) regarding the treatment of unamortized investment tax
credits (ITC) and excess deferred income taxes (EDIT) related to generation
assets that have been sold. EDIT are temporary differences between book
and taxable income that were recorded when the federal statutory tax rate
was higher than it is now or when those differences were expected to be
resolved. The PLR addresses whether or not EDIT and ITC can be returned to
customers, which without a PLR management believes would represent a
violation of current tax law. The IRS declared a moratorium on issuing
PLRs until final regulations on the return of EDIT and ITC to regulated
customers are issued by the Treasury Department. Proposed regulations were
issued in March 2003, and a hearing took place in June 2003. The proposed
new regulations would allow the return of EDIT and ITC to regulated
customers without violating the tax law. Also, under the proposed
regulations, a company could elect to apply the regulation retroactively.
The Treasury Department is currently deliberating the comments received at
the hearing. If final regulations consistent with the proposed regulations
are issued, then there could be an impact on CL&P's financial statements.
I. DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable plant-in-
service, which range primarily from 3 years to 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 it is placed in service. When plant is retired from
service, the original cost of the plant, including costs of removal less
salvage, is charged to the accumulated provision for depreciation. Cost of
removal is now classified as a regulatory liability. The depreciation
rates for the several classes of electric utility plant-in-service are
equivalent to a composite rate of 3.3 percent in 2003, 3.2 percent in 2002
and 3.1 percent in 2001.
J. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Companies: At December 31, 2003, CL&P owns common stock in
three regional nuclear companies (Yankee Companies). CL&P's ownership
interest in the Yankee Companies at December 31, 2003, which are accounted
for on the equity method are 34.5 percent of the CYAPC, 24.5 percent of the
Yankee Atomic Electric Company (YAEC) and 12 percent of the Maine Yankee
Atomic Power Company (MYAPC). Effective November 7, 2003, CL&P sold its
10.1 percent ownership interest in Vermont Yankee Nuclear Power Corporation
(VYNPC). CL&P's total equity investment in the Yankee Companies at
December 31, 2003 and 2002, is $21.8 million and $32.2 million,
respectively. Each of the remaining Yankee Companies owns a single nuclear
generating plant which is being decommissioned.
K. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) is a non-cash item
that is included in the cost of utility plant and represents the cost of
borrowed and equity funds used to finance construction. The portion of AFUDC
attributable to borrowed funds is recorded as a reduction of other interest
expense, and the cost of equity funds is recorded as other income on the
consolidated statements of income:
- ----------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------
(Millions of Dollars,
except percentages) 2003 2002 2001
- ----------------------------------------------------------------
Borrowed funds $3.0 $2.7 $3.2
Equity funds 5.8 5.1 2.0
- ----------------------------------------------------------------
Totals $8.8 $7.8 $5.2
- ----------------------------------------------------------------
Average AFUDC rates 7.9% 8.2% 8.5%
- ----------------------------------------------------------------
L. ASSET RETIREMENT OBLIGATIONS
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires that legal obligations
associated with the retirement of property, plant and equipment be
recognized as a liability at fair value when incurred and when a reasonable
estimate of the fair value of the liability can be made. SFAS No. 143 was
effective on January 1, 2003, for CL&P. Management has completed its
review process for potential asset retirement obligations (ARO) and has not
identified any material AROs that have been incurred. However, management
has identified certain removal obligations that arise in the ordinary
course of business or have a low probability of occurring. These types of
obligations primarily relate to transmission and distribution lines and
poles, telecommunication towers, transmission cables and certain FERC or
state regulatory agency re-licensing issues. These obligations are AROs
that have not been incurred or are not material in nature.
A portion of CL&P's rates are intended to recover the cost of removal of
certain utility assets. The amounts recovered do not represent AROs. At
December 31, 2003 and 2002, cost of removal was approximately $150 million
and $154 million, respectively.
M. MATERIALS AND SUPPLIES
Materials and supplies include materials purchased primarily for
construction, operation and maintenance (O&M) purposes. Materials and
supplies are valued at the lower of average cost or market.
N. SALE OF CUSTOMER RECEIVABLES
CL&P has an arrangement with a financial institution under which CL&P can
sell up to $100 million of accounts receivable and unbilled revenues. At
December 31, 2003 and 2002, CL&P had sold accounts receivable of $80
million and $40 million, respectively, to the financial institution with
limited recourse through CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. At December 31, 2003 and 2002, the reserve
requirements calculated in accordance with the Receivables Purchase and
Sale Agreement were $29.3 million and $3.8 million, respectively. These
reserve amounts are deducted from the amount of receivables eligible for
sale at the time. Concentrations of credit risk to the purchaser under
this agreement with respect to the receivables are limited due to CL&P's
diverse customer base within its service territory. At December 31, 2003
and 2002, amounts sold to CRC by CL&P but not sold to the financial
institution totaling $166.5 million and $178.9 million, respectively, are
included in investments in securitizable assets on the accompanying
consolidated balance sheets. These amounts would be excluded from CL&P's
assets in the event of CL&P's bankruptcy. On July 9, 2003, CL&P renewed
this arrangement.
The transfer of receivables to the financial institution under this arrangement
qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement
of SFAS No. 125." This agreement expires on July 7, 2004. Management plans to
renew this agreement prior to its expiration.
O. RESTRICTED CASH - LMP COSTS
Restricted cash - LMP costs represents incremental LMP cost amounts that
have been collected by CL&P and deposited into an escrow account.
P. EXCISE TAXES
Certain excise taxes levied by state or local governments are collected by
CL&P from its customers. These excise taxes are accounted for on a gross
basis with collections in revenues and payments in expenses. For the years
ended December 31, 2003, 2002 and 2001, gross receipts taxes, franchise
taxes and other excise taxes of approximately $76.3 million, $74.4 million
and $74.8 million, respectively, are included in operating revenues and
taxes other than income taxes on the accompanying consolidated statements
of income.
Q. OTHER INCOME
The pre-tax components of CL&P's other income/(loss) items are as follows:
- ---------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------
Seabrook-related gains $ - $ 2.1 $ -
Gain related to Millstone sale - - 29.5
Investment income 2.7 10.2 12.9
Charitable donations (4.6) (2.8) (3.5)
Other 6.5 12.6 13.9
- ---------------------------------------------------------------------
Totals $4.6 $22.1 $52.8
- ---------------------------------------------------------------------
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. On June 30, 2003, the SEC granted authorization allowing CL&P to
incur total short-term borrowings up to a maximum of $375 million through
June 30, 2006, with authorization for borrowings from the NU Money Pool
(Pool) granted through June 30, 2004.
The charter of CL&P contains preferred stock provisions restricting the
amount of unsecured debt that CL&P may incur. At meetings in November
2003, CL&P obtained authorization from its stockholders to issue unsecured
indebtedness with a maturity of less than 10 years in excess of the 10
percent of total capitalization limitation in CL&P's charter, provided that
all unsecured indebtedness would not exceed 20 percent of total
capitalization for a ten-year period expiring March 2014. As of
December 31, 2003, CL&P is permitted to incur $366 million of additional
unsecured debt.
Credit Agreement: On November 10, 2003, CL&P, PSNH, WMECO and Yankee Gas
entered into a 364-day unsecured revolving credit facility for $300
million. This facility replaces a similar credit facility that expired on
November 11, 2003 and CL&P may draw up to $150 million. Unless extended,
the credit facility will expire on November 8, 2004. At December 31, 2003
and 2002, there were no CL&P borrowings under these credit 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.
Under the credit agreement, CL&P must comply with certain financial and non-
financial covenants as are customarily included in such agreements,
including but not limited to, consolidated debt ratios and interest
coverage ratios. The most restrictive financial covenant is the interest
coverage ratio. CL&P currently is and expects to remain in compliance with
these covenants.
Pool: CL&P is a member of the 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, 2003 and 2002, CL&P had
borrowings of $91.1 million and lendings of $1.9 million to the Pool,
respectively. The interest rate on borrowings from and lendings to the
Pool at December 31, 2003 and 2002 was 5 percent and 1.2 percent,
respectively.
3. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT ACTIVITIES
- -------------------------------------------------------------------------------
A. DERIVATIVE INSTRUMENTS
Effective January 1, 2001, CL&P adopted SFAS No. 133, as amended.
Derivatives that do not meet the definition of a cash flow hedge and cannot
be designated as being used for normal purchases or normal sales are also
recorded at fair value with changes in fair value included in earnings
unless recorded as a regulatory asset or liability. Derivative contracts
that are entered into as a normal purchase or sale and will result in
physical delivery, and are documented as such, are recorded under accrual
accounting. For information regarding accounting changes related to
derivative instruments, see Note 1C, "Summary of Significant Accounting
Policies - New Accounting Standards," to the consolidated financial
statements.
In 2003, there were changes to the interpretations of as well as an
amendment to SFAS No. 133, and the FASB continues to consider changes that
could affect the way CL&P records and discloses derivative and hedging
activities.
CL&P has two IPP contracts to purchase power that contain pricing
provisions that are not clearly and closely related to the price of power.
Because of a clarification in the definition of "clearly and closely
related" in Issue No. C-20, these contracts no longer qualify for the
normal purchases and sales exception to SFAS No. 133, as amended. The fair
values of these IPP non-trading derivatives at December 31, 2003 include a
derivative asset with a fair value of $112.4 million and a derivative
liability with a fair value of $54.6 million with offsetting regulatory
liabilities and regulatory assets, respectively. These fair values were
determined by comparing the IPP contract prices to projected market prices
and discounting the estimated over or under-market portions back to
December 31, 2003. To mitigate the risk associated with certain supply
contracts, CL&P purchased FTRs. FTRs are derivatives that cannot qualify
for the normal purchases and sales exception. The fair value of these FTR
non-trading derivatives at December 31, 2003 was an asset of $3 million.
CL&P had no non-trading derivatives at December 31, 2002 that were required
to be recorded at fair value.
B. RISK MANAGEMENT ACTIVITIES
CL&P is subject to credit risk from certain long-term or high-volume supply
contracts with energy marketing companies. Credit risks and market risks
at CL&P are monitored regularly by a Risk Oversight Council operating
outside of the business units that create or actively manage these risk
exposures to ensure compliance with NU's stated risk management policies.
4. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
- -------------------------------------------------------------------------------
Pension Benefits: CL&P participates in a uniform noncontributory defined
benefit retirement plan (Pension Plan) covering substantially all regular
NU employees. Benefits are based on years of service and the employees'
highest eligible compensation during 60 consecutive months of employment.
Pre-tax pension income was $29.1 million in 2003, $50.6 million in 2002,
and $61.4 million in 2001. These amounts exclude pension settlements,
curtailments and net special termination expenses of $8.1 million in 2002
and $1.2 million in 2001. CL&P uses a December 31 measurement date for the
Pension Plan. Pension income attributable to earnings is as follows:
- --------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- --------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(29.1) $(50.6) $(61.4)
Net pension income
capitalized as utility plant 15.1 20.8 24.8
- ---------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (14.0) (29.8) (36.6)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 3.3
- ---------------------------------------------------------------------
Total pension income
included in earnings $(14.0) $(29.8) $(33.3)
- ---------------------------------------------------------------------
Pension Settlements, Curtailments and Special Termination Benefits: There
were no settlements, curtailments or special termination benefits in 2003.
Effective February 1, 2002, certain CL&P employees who were displaced were
eligible for a Voluntary Retirement Program (VRP). The VRP supplements the
Pension Plan and provides special provisions. Eligible employees include
non-bargaining unit employees or employees belonging to a collective
bargaining unit that agreed to accept the VRP who were active participants
in the Pension Plan at January 1, 2002, and that were displaced as part of the
reorganization between January 22, 2002 and March 2003. Eligible employees
received a special retirement benefit under the VRP whose value was roughly
equivalent to a multiple of base pay based on years of credited service.
During 2002, CL&P recorded an expense of $8.1 million associated with special
pension termination benefits related to the VRP. The cost of the VRP was
recovered through regulated utility rates and the $8.1 million was recorded as
a regulatory asset with no impact on 2002 earnings.
In conjunction with the Voluntary Separation Program (VSP) that was
announced in December 2000, 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 5 years added to both age and credited service of
eligible participants or two weeks of pay for each year of service subject
to a minimum level of 12 weeks and a maximum of 52 weeks for eligible
participants. The special pension termination benefits expense associated
with the VSP totaled $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, $2.1 million was deferred as a regulatory liability and has been
returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): CL&P also provides
certain health care benefits, primarily medical and dental, and life
insurance benefits through a benefit plan to retired employees (PBOP Plan).
These benefits are available for employees retiring from CL&P 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 uses a December 31 measurement date for
the PBOP Plan. CL&P annually funds postretirement costs through external
trusts with amounts that have been rate-recovered and which also are tax
deductible.
In 2002, the PBOP Plan was amended to change the claims experience basis,
to increase minimum retiree contributions and to reduce the cap on the
company's subsidy to the dental plan. These amendments resulted in a $10.6
million decrease in CL&P's benefit obligation under the PBOP Plan at
December 31, 2002.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President
signed into law a bill that expands Medicare, primarily by adding a
prescription drug benefit starting in 2006 for Medicare-eligible retirees
as well as a federal subsidy to plan sponsors of retiree health care benefit
plans who provide a prescription drug benefit at least actuarially equivalent
to the new Medicare benefit.
Based on the current PBOP Plan provisions, CL&P's actuaries believe that
CL&P will qualify for this federal subsidy because the actuarial value of
CL&P's PBOP Plan is estimated to be 60 percent greater than that of the
standard Medicare benefit. CL&P will directly benefit from the federal
subsidy for retirees who retired before 1991. For other retirees,
management does not believe that CL&P will benefit from the subsidy because
CL&P's cost support for these retirees is capped at a fixed dollar
commitment.
The aggregate effect of recognizing the Medicare change is a decrease to
the PBOP benefit obligation of $9.4 million. This amount includes the
present value of the future government subsidy, which was estimated by
discounting the expected payments using the actuarial assumptions used to
determine the PBOP liability at December 31, 2003. Also included in the
$9.4 million estimate is a decrease in the assumed participation in NU's
retiree health plan from 95 percent to 85 percent for future retirees,
which reflects the expectation that the Medicare prescription benefit will
produce insurer-sponsored health plans that are more financially attractive
to future retirees. The per capita claims cost estimate was not changed.
Management reduced the PBOP benefit obligation as of December 31, 2003 by
$9.4 million and recorded this amount as an actuarial gain within
unrecognized net loss/(gain) in the tables that follow. The $9.4 million
actuarial gain will be amortized beginning in 2004 as a reduction to PBOP
expense over the future working lifetime of employees covered under the
plan (approximately 13 years). PBOP expense in 2004 will also reflect a
lower interest cost due to the reduction in the December 31, 2003 benefit
obligation.
Specific authoritative guidance on accounting for the effect of the
Medicare federal subsidy on PBOP plans and amounts is pending from the
FASB. When issued, that guidance could require CL&P to change the
accounting described above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There
were no settlements, curtailments or special termination benefits in 2002
or 2003. 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 rates in 2002.
The following table represents information on the plans' benefit
obligation, fair value of plan assets, and the respective plans' funded
status:
- ----------------------------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(680.3) $(626.0) $(167.0) $(165.7)
Service cost (12.8) (11.7) (2.0) (2.0)
Interest cost (44.4) (44.8) (11.3) (12.0)
Medicare impact - - 9.4 -
Plan amendment - (4.5) - 10.6
Transfers 1.4 (2.2) - -
Actuarial loss (39.1) (45.2) (14.2) (16.2)
Benefits paid - excluding lump sum payments 41.7 41.5 15.8 18.3
Benefits paid - lump sum payments 2.2 20.7 - -
Special termination benefits - (8.1) - -
- ----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(731.3) $(680.3) $(169.3) $(167.0)
- ----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 752.7 $ 910.4 $ 50.3 $ 55.7
Actual return on plan assets 191.9 (97.7) 13.2 (4.9)
Employer contribution - - 16.6 17.6
Transfers (1.4) 2.2 - 0.2
Benefits paid - excluding lump sum payments (41.7) (41.5) (15.8) (18.3)
Benefits paid - lump sum payments (2.2) (20.7) - -
- ----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 899.3 $ 752.7 $ 64.3 $ 50.3
- ----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 168.0 $ 72.3 $(105.0) $(116.7)
Unrecognized transition (asset)/obligation (0.9) (1.8) 56.5 62.7
Unrecognized prior service cost 26.1 29.1 - -
Unrecognized net loss 112.1 176.6 48.5 53.6
- ----------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 305.3 $ 276.2 $ - $ (0.4)
- ----------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for the Pension Plan was $645.9 million
and $594.6 million at December 31, 2003 and 2002, respectively.
The following actuarial assumptions were used in calculating the plans'
year end funded status:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend N/A N/A 9.00% 10.00%
- -------------------------------------------------------------------------------
The components of net periodic (income)/expense are as follows:
- ------------------------------------------------------------------------------------------------------------
For the Year Ended December 31,
- ------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- ------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------
Service cost $ 12.8 $ 11.7 $ 10.0 $ 2.0 $ 2.0 $ 1.9
Interest cost 44.4 44.8 43.7 11.3 12.0 11.1
Expected return on plan assets (84.1) (94.2) (95.3) (5.1) (5.4) (5.5)
Amortization of unrecognized net
transition (asset)/obligation (0.9) (0.9) (0.9) 6.3 6.9 7.3
Amortization of prior service cost 3.0 3.0 2.6 - - -
Amortization of actuarial gain (4.3) (15.0) (21.5) - - -
Other amortization, net - - - 2.1 1.9 (0.5)
- ------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (29.1) (50.6) (61.4) 16.6 17.4 14.3
- ------------------------------------------------------------------------------------------------------------
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 $(29.1) $(42.5) $(60.2) $16.6 $17.4 $15.0
- ------------------------------------------------------------------------------------------------------------
For calculating pension and postretirement benefit income and expense
amounts, the following assumptions were used:
- -----------------------------------------------------------------------------------------
For the Years Ended December 31,
- -----------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
- -----------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
- -----------------------------------------------------------------------------------------
The following table represents the PBOP assumed health care cost trend rate
for the next year and the assumed ultimate trend rate:
- ---------------------------------------------------------------------
Year Following December 31,
- ---------------------------------------------------------------------
2003 2002
- ---------------------------------------------------------------------
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
- ---------------------------------------------------------------------
The annual per capita cost of covered health care benefits was assumed to
decrease by one percentage point each year through 2007. Assumed health
care cost trend rates have a significant effect on the amounts reported for
the health care plans. The effect of changing the assumed health care cost
trend rate by one percentage point in each year would have the following
effects:
- ---------------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
- ---------------------------------------------------------------------
Effect on total service and
interest cost components $0.3 $(0.3)
Effect on postretirement
benefit obligation $5.3 $(4.8)
- ---------------------------------------------------------------------
CL&P's investment strategy for its Pension Plan and PBOP Plan is to
maximize the long-term rate of return on those plans' assets within an
acceptable level of risk. The investment strategy establishes target
allocations, which are regularly reviewed and periodically rebalanced.
CL&P's expected long-term rates of return on Pension Plan assets and PBOP
Plan assets are based on these target asset allocation assumptions and
related expected long-term rates of return. In developing its expected
long-term rate of return assumptions for the Pension Plan and the PBOP
Plan, CL&P also evaluated input from actuaries, consultants and economists
as well as long-term inflation assumptions and CL&P's historical 20-year
compounded return of approximately 11 percent. The Pension Plan's and PBOP
Plan's target asset allocation assumptions and expected long-term rate of
return assumptions by asset category are as follows:
- -----------------------------------------------------------------------------------------------------------------
At December 31,
- -----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
- -----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
- -----------------------------------------------------------------------------------------------------------------
The actual asset allocations at December 31, 2003 and 2002, approximated
these target asset allocations. The plans' actual weighted-average asset
allocations by asset category are as follows:
- --------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
- --------------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
- --------------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
- -------------------------------------------------------------------------
Total 100.00% 100.00% 100.00% 100.00%
- --------------------------------------------------------------------------
Currently, 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.
CL&P does not expect to make any contributions to the Pension Plan in 2004
and expects to make $19.9 million in contributions to the PBOP Plan in
2004.
Postretirement health plan assets for non-union employees are subject to
federal income taxes.
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 Group, Inc.
(FPL). CL&P, North Atlantic Energy Corporation 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. CL&P recorded a gain on the sale 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 this approval, CL&P
eliminated $0.6 million, on an after-tax basis, of reserves related to its
ownership share 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. On
November 7, 2003, CL&P sold its 10.1 percent ownership interest in VYNPC.
CL&P will continue to buy approximately 9.5 percent of the plant's output
through March 2012 at a range of fixed prices.
6. COMMITMENTS AND CONTINGENCIES
- -------------------------------------------------------------------------------
A. RESTRUCTURING AND RATE MATTERS
Impacts of Standard Market Design: On March 1, 2003, ISO-NE implemented
standard market design (SMD). As part of SMD, LMP is utilized to assign
value and causation to transmission congestion and line losses.
CL&P was billed $186 million of incremental LMP costs by its standard offer
service suppliers or by ISO-NE. CL&P recovered a portion of these costs
through an additional charge on customer bills beginning on May 1, 2003.
Billings were on a two-month lag and were recorded as operating revenues
when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the
responsibility for the $186 million in 2003 of incremental LMP costs
incurred. CL&P recorded after-tax loss in 2003 of $1.3 million related to
an agreement in principle to settle this dispute. On February 23, 2004,
CL&P, its suppliers, and other parties reached an agreement in principle to
settle the dispute. A settlement agreement is subject to approval by the
FERC.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook
nuclear unit on November 1, 2002. The net proceeds in excess of the book
value of Seabrook of $16 million were recorded as a regulatory liability
and, after being offset by accelerated decommissioning funding and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September
2003, and a draft decision was received on February 3, 2004. Management
does not believe that the final decision, which is expected in March 2004,
will have a material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual
CTA and SBC reconciliation with the DPUC. For the year ended December 31,
2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue
requirement by $93.5 million. This amount was recorded as a regulatory
liability. For the same period, SBC revenues exceeded the SBC revenue
requirement by $22.4 million. In compliance with a prior decision of the
DPUC, a portion of the SBC overcollection reduced regulatory assets, and
the remaining overcollection of $18.6 million was applied to the CTA. The
DPUC's December 19, 2003 transitional standard offer (TSO) decision
addressed $41 million of SBC overcollections and $64 million of CTA
overcollections that had been estimated as of December 31, 2003. In its
decision, the DPUC ordered that $80 million of the overcollections be used
to reduce CTA costs during the 2004 through 2006 TSO period. The DPUC also
ordered that $25 million of the overcollections be used to offset SBC costs
during the TSO period. The DPUC also ordered that $37 million of GSC
overcollections be used to pay CL&P's 0.50 mill/kWh procurement fee during
the TSO period.
B. NRG ENERGY, INC. EXPOSURES
Certain subsidiaries of NU, including CL&P have entered into transactions
with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14,
2003, NRG and certain of its subsidiaries filed voluntary bankruptcy
petitions. On December 5, 2003, NRG emerged from bankruptcy. CL&P's NRG-
related exposures as a result of these transactions relate to 1) the
recovery of congestion charges incurred by NRG prior to the implementation
of SMD on March 1, 2003, 2) the recovery of CL&P's station service billings
to NRG, and 3) the recovery of CL&P's expenditures that were incurred
related to an NRG subsidiary's generating plant construction project that
is now abandoned. While it is unable to determine the ultimate outcome of
these issues, management does not expect their resolution will have a
material adverse effect on CL&P's consolidated financial condition or
results of operations.
C. ENVIRONMENTAL MATTERS
General: 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. These laws and regulations require the
removal or the remedy of the effect on the environment of the disposal or
release of certain specified hazardous substances at current and former
operating sites. As such, CL&P has an active environmental auditing and
training program and believes that it is substantially in compliance with
all enacted laws and regulations.
Environmental reserves are accrued using a probabilistic model approach
when assessments indicate that it is probable that a liability has been
incurred and an amount can be reasonably estimated. The probabilistic
model approach estimates the liability based on the most likely action plan
from a variety of available remediation options, ranging from no action to
several different remedies ranging from establishing institutional controls
to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration
several different remediation options at each specific site. The
reliability and precision of these estimates can be affected by several
factors including new information concerning either the level of
contamination at the site, recently enacted laws and regulations or a
change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities on the consolidated
balance sheets represent management's best estimate of the liability for
environmental costs and takes into consideration site assessment and
remediation costs. Based on currently available information for estimated
site assessment and remediation costs at December 31, 2003 and 2002, CL&P
had $7.9 million and $7.3 million, respectively, recorded as environmental
reserves. A reconciliation of the total amount reserved at December 31,
2003 and 2002 is as follows:
- ---------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
- ---------------------------------------------------------------------
2003 2002
- ---------------------------------------------------------------------
Balance at beginning of year $ 7.3 $ 1.8
Additions and adjustments 0.7 5.8
Payments (0.1) (0.3)
- ---------------------------------------------------------------------
Balance at end of year $ 7.9 $ 7.3
- ---------------------------------------------------------------------
These liabilities are estimated on an undiscounted basis and do not assume
that any amounts are recoverable from insurance companies or other third
parties. The environmental reserve includes sites at different stages of
discovery and remediation and does not include any unasserted claims. At
December 31, 2003, there are three sites for which there are unasserted
claims; however, any related remediation costs are not probable or
estimable at this time. CL&P's environmental liability also takes into
account recurring costs of managing hazardous substances and pollutants,
mandated expenditures to remediate previously contaminated sites and any
other infrequent and non-recurring clean up costs.
CL&P currently has 11 sites included in the environmental reserve. Of
those 11 sites, two sites are in the remediation or long-term monitoring
phase, seven sites have had site assessments completed and the remaining
two sites are in the preliminary stages of site assessment.
In addition, capital expenditures related to environmental matters are
expected to total approximately $8 million in aggregate for the years 2004
through 2008. These expenditures relate to CL&P's PCB removal program.
MGP Sites: Manufactured gas plant (MGP) sites comprise the largest portion
of CL&P's environmental liability. MGPs are sites that manufactured gas
from coal and produced certain byproducts that may pose risk to human health
and the environment. At December 31, 2003 and 2002, $6.5 million and $6.1
million, respectively, represent amounts for the site assessment and
remediation of MGPs. CL&P currently has five MGP sites included in its
environmental liability and one contingent MGP site of which management is
aware and for which costs are not probable or estimable at this time. All
of the five MGP sites are currently in the site assessment stage.
At December 31, 2003, CL&P has one site that is held for sale. The site, a
former MGP site, is currently held for sale under a pending purchase and
sale agreement. CL&P is currently remediating the property and has been
deferring the costs associated with those remediation efforts as allowed by
a regulatory order. At December 31, 2003, CL&P had $7.8 million related to
remediation efforts at the property and other sale costs recorded in other
deferred debits on the accompanying consolidated balance sheets.
The pending purchase and sale agreement releases CL&P from all
environmental claims arising out of or in connection with the property.
The purchase price in the pending purchase and sale agreement exceeds the
book value of the land including the aforementioned deferred environmental
remediation costs.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (CERCLA) and its' amendments or state equivalents
impose joint and several strict liabilities, regardless of fault, upon
generators of hazardous substances resulting in removal and remediation
costs and environmental damages. Liabilities under these laws can be
material and in some instances may be imposed without regard to fault or
for past acts that may have been lawful at the time they occurred. CL&P
has two superfund sites under CERCLA for which it has been notified that it
is a potentially responsible party (PRP). For sites where there are other
PRPs and CL&P is not managing the site assessment and remediation, the
liability accrued represents CL&P's estimate of what it will need to pay to
settle its obligations with respect to the site.
It is possible that new information or future developments could require a
reassessment of the potential exposure to related environmental matters.
As this information becomes available management will continue to assess
the potential exposure and adjust the reserves as necessary.
CL&P recovers a certain level of environmental costs currently in rates but
does not have an environmental cost recovery tracking mechanism.
Accordingly, changes in CL&P's environmental reserves impact CL&P's
earnings.
D. 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, 2003 and
2002, fees due to the DOE for the disposal of Prior Period Fuel were $207.7
million and $205.5 million, respectively, including interest costs of
$141.2 million and $138.9 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed
currently to customers and were paid to the DOE on a quarterly basis. At
December 31, 2003, CL&P's ownership shares of Millstone and Seabrook have
been sold, and CL&P is no longer responsible for fees relating to fuel
burned at these facilities since their sale.
E. NUCLEAR INSURANCE CONTINGENCIES
In conjunction with the divestiture of Millstone in 2001 and Seabrook in
2002, CL&P terminated its 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, NU is subject to potential
retrospective assessments totaling $0.8 million under its respective NEIL
insurance policies.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
VYNPC: Previously, under the terms of its agreement, CL&P paid its
ownership (or entitlement) shares of costs, which included depreciation,
O&M expenses, taxes, the estimated cost of decommissioning, and a return on
invested capital to VYNPC and recorded these costs as purchased-power
expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear
generating unit to a subsidiary of Entergy for approximately $180 million.
Under the terms of the sale, CL&P will continue to buy approximately 9.5
percent of the plant's output through March 2012 at a range of fixed
prices. The total cost of purchases under contracts with VYNPC amounted to
$17.8 million in 2003, $16.4 million in 2002 and $14.7 million in 2001.
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 $157.8 million in 2003, $154.6 million
in 2002 and $205 million in 2001. These amounts relate to IPP 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 agreements 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, their proportionate shares of
the annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Utility Group Costs: The estimated future annual
costs of CL&P's significant long-term contractual arrangements are as
follows:
- ----------------------------------------------------------------------
(Millions of
Dollars) 2004 2005 2006 2007 2008 Thereafter
- ----------------------------------------------------------------------
VYNPC $ 17.5 $ 16.2 $16.9 $ 16.3 $ 16.6 $ 57.7
Electricity
Procurement
Contracts 190.9 192.1 193.7 197.2 187.5 1,057.6
Hydro-Quebec 14.5 13.8 13.0 11.8 11.4 136.8
- ----------------------------------------------------------------------
Totals $222.9 $222.1 $223.6 $225.3 $215.5 $1,252.1
- ----------------------------------------------------------------------
G. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
In conjunction with the Millstone, Seabrook and VYNPC nuclear generation
asset divestitures, the applicable liabilities and nuclear decommissioning
trusts were transferred to the purchasers, and the purchasers agreed to
assume responsibility for decommissioning their respective units.
CL&P still has significant decommissioning and plant closure cost
obligations to the Yankee Companies that own the Yankee Atomic, Connecticut
Yankee (CY) and Maine Yankee nuclear power plants. Each plant has been
shut down and is undergoing decommissioning. The Yankee Companies collect
decommissioning and closure costs through wholesale FERC-approved rates
charged under power purchase agreements to CL&P. CL&P in turn passes these
costs on to its customers through state regulatory commission-approved
retail rates. A portion of the decommissioning and closure costs have
already been collected, but a substantial portion related to the
decommissioning of CY has not yet been filed at and approved for collection
by the FERC.
During 2002, CL&P was notified by CYAPC and YAEC that the estimated cost of
decommissioning these units and other closure costs increased over prior
estimates due to higher anticipated costs for spent fuel storage, security
and liability and property insurance. CL&P's share of this increase is
$118.9 million. Following FERC rate cases by the Yankee Companies, CL&P
expects to recover the higher decommissioning costs from its retail
customers.
In June 2003, CYAPC notified NU that it had terminated its contract with
Bechtel Power Corporation (Bechtel) for the decommissioning of the CY
nuclear power plant. CYAPC terminated the contract based on its
determination that Bechtel's decommissioning work has been incomplete and
untimely and that Bechtel refused to perform the remaining decommissioning
work. Bechtel has filed a counterclaim against CYAPC asserting a number of
claims and seeking a variety of remedies, including monetary and punitive
damages and the rescission of the contract. Bechtel has amended its
complaint to add claims for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of
decommissioning its nuclear unit. CL&P's aggregate share of the estimated
increased cost, primarily related to the termination of
Bechtel, is $118.1 million.
CYAPC is seeking recovery of additional decommissioning costs and other
damages from Bechtel and, if necessary, its surety. In pursuing this
recovery through pending litigation, CYAPC is also exploring options to
structure an appropriate rate application to be filed with the FERC, with
any resulting adjustments being charged to the owners of the nuclear unit,
including CL&P. The timing, amount and outcome of these filings cannot be
predicted at this time.
CL&P cannot at this time predict the timing or outcome of the FERC
proceeding required for the collection of these remaining decommissioning
and closure costs. Although management believes that these costs will
ultimately be recovered from CL&P's customers, there is a risk that the
FERC may not allow these costs, the estimates of which have increased
significantly in 2003 and 2002, to be recovered in wholesale rates. If
FERC does not allow these costs to be recovered in wholesale rates, CL&P
would expect the state regulatory commissions to disallow these costs in
retail rates as well.
At December 31, 2003 and 2002, CL&P's remaining estimated obligations for
decommissioning and closure costs for the shut down units owned by CYAPC,
YAEC and MYAPC were $318 million and $234.5 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:
Restricted Cash - LMP: The carrying amounts approximate fair value due to
the short-term nature of this cash item.
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, 2003
- ---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
- ---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 87.5
Long-term debt -
First mortgage bonds 198.8 244.9
Other long-term debt 631.6 650.1
Rate reduction bonds 1,124.8 1,197.5
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
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 629.4 643.0
Rate reduction bonds 1,245.7 1,356.1
- ---------------------------------------------------------------------
Other long-term debt includes $207.7 million and $205.5 million of fees and
interest due for spent nuclear fuel disposal costs at December 31, 2003 and
2002, respectively.
Other Financial Instruments: The carrying value of financial instruments
included in current assets and current liabilities, including investments
in securitizable assets, approximates their fair value.
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 $3.1
million in 2003, $3 million in 2002, and $9.2 million in 2001. Interest
included in capital lease rental payments was $2 million in 2003 and 2002,
and $3.4 million in 2001. Operating lease rental payments charged to
expense were $7.3 million in 2003, $6.9 million in 2002, and $7.1 million
in 2001.
Future minimum rental payments excluding executory costs, such as property
taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, at December 31, 2003 are as follows:
- ---------------------------------------------------------------------
(Millions of Dollars) Capital Operating
Year Leases Leases
- ---------------------------------------------------------------------
2004 $ 2.6 $ 11.8
2005 2.6 11.2
2006 2.5 10.1
2007 2.4 9.0
2008 2.1 8.3
Thereafter 20.1 16.4
- ---------------------------------------------------------------------
Future minimum lease payments $32.3 $66.8
Less amount representing interest 17.4
- ---------------------------------------------------------------------
Present value of future
minimum lease payments $14.9
- ---------------------------------------------------------------------
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) 2002 Change 2003
- -----------------------------------------------------------------------
Unrealized
(losses)/gains
on securities $(0.1) $ 0.2 $ 0.1
Minimum supplemental
executive retirement
pension liability
adjustments (0.3) (0.1) (0.4)
- -----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(0.4) $ 0.1 $(0.3)
- -----------------------------------------------------------------------
- -----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
- -----------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.4 $(0.5) $(0.1)
Minimum supplemental
executive retirement
pension liability
adjustments (0.3) - (0.3)
- -----------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.1 $(0.5) $(0.4)
- -----------------------------------------------------------------------
The changes in the components of other comprehensive income/(loss) are
reported net of the following income tax effects:
- -----------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
- -----------------------------------------------------------------------
Unrealized
(losses)/gains
on securities $(0.1) $0.3 $0.3
Minimum supplemental
executive retirement
pension liability
adjustments - - -
- -----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(0.1) $0.3 $0.3
- -----------------------------------------------------------------------
10. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
- -------------------------------------------------------------------------------
Details of preferred stock not subject to mandatory redemption are as
follows:
- -------------------------------------------------------------------------------
Shares
December 31, Outstanding
2003 at December 31,
Redemption December 31, ----------------
Description Price 2003 2003 2002
- -------------------------------------------------------------------------------
(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, 2003 2002
- -------------------------------------------------------------------------------
(Millions of Dollars)
First Mortgage Bonds:
8.50% Series C due 2024 $ 59.0 $ 59.0
7.875% Series D due 2024 139.8 139.8
- -------------------------------------------------------------------------------
Total First Mortgage Bonds 198.8 198.8
- -------------------------------------------------------------------------------
Pollution Control Notes:
5.85%-5.90%, fixed rate,
due 2016-2022 46.4 46.4
5.85%-5.95%, fixed rate
tax exempt, due 2028 315.5 315.5
Variable rate, tax exempt, due 2031 62.0 62.0
- -------------------------------------------------------------------------------
Total Pollution Control Notes 423.9 423.9
- -------------------------------------------------------------------------------
Total First Mortgage Bonds and
Pollution Control Notes 622.7 622.7
- -------------------------------------------------------------------------------
Fees and interest due for spent
nuclear fuel disposal costs 207.7 205.5
- -------------------------------------------------------------------------------
Less amounts due within one year - -
Unamortized premium and
discount, net (0.3) (0.3)
- -------------------------------------------------------------------------------
Long-term debt $830.1 $827.9
- -------------------------------------------------------------------------------
Essentially, all utility plant of CL&P is subject to the liens of the
company's first mortgage bond indenture.
CL&P has $315.5 million of pollution control notes secured by second
mortgage liens on transmission assets, junior to the liens of their first
mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by the first mortgage bonds. For financial
reporting purposes, these first mortgage bonds would not be considered
outstanding unless CL&P failed to meet its obligations under the PCRBs. On
October 1, 2003, CL&P fixed the interest rate on $62 million of variable-
rate, tax-exempt notes for five years at 3.35 percent. These notes mature
in 2031.
The average effective interest rates on the variable-rate PCRBs, which were
fixed in 2003, ranged from 1 percent to 1.9 percent for 2002.
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, 2003 2002 2001
- -------------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $ 115.0 $114.4 $190.7
State 28.8 24.3 38.8
- -------------------------------------------------------------------------------
Total current 143.8 138.7 229.5
- -------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (82.7) (53.3) (117.0)
State (33.2) (15.2) (23.8)
- -------------------------------------------------------------------------------
Total deferred (115.9) (68.5) (140.8)
- -------------------------------------------------------------------------------
Investment tax credits, net (2.5) (3.3) (3.8)
- -------------------------------------------------------------------------------
Total income tax expense $ 25.4 $ 66.9 $ 84.9
- -------------------------------------------------------------------------------
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
- -------------------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------
(Millions of Dollars)
Depreciation $ 23.5 $ 34.4 $ (9.2)
Net regulatory deferral (128.9) (68.3) (33.1)
Regulatory disallowance 0.4 0.3 -
Sale of generation assets - (18.4) (197.6)
Pension (deferral)/accrual (1.4) (6.3) 19.9
Contract termination
costs, net of amortization (6.5) (5.9) 63.4
Other (3.0) (4.3) 15.8
- -------------------------------------------------------------------------------
Deferred income taxes, net $(115.9) $(68.5) $(140.8)
- -------------------------------------------------------------------------------
A reconciliation between income tax expense and the expected tax expense at
the statutory rate is as follows:
- -------------------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $33.0 $53.4 $68.1
Tax effect of differences:
Depreciation (0.3) 3.8 10.7
Amortization of
regulatory assets 3.7 13.7 1.6
Investment tax credit
amortization (2.5) (3.3) (3.8)
State income taxes,
net of federal benefit (2.9) 5.9 9.8
Tax reserve adjustments (5.5) (1.3) (9.1)
Other, net (0.1) (5.3) 7.6
- -------------------------------------------------------------------------------
Total income tax expense $25.4 $66.9 $84.9
- -------------------------------------------------------------------------------
13. SEGMENT INFORMATION
- -------------------------------------------------------------------------------
NU is organized between the Utility Group and NU Enterprises based on each
segments' regulatory environment or lack thereof. CL&P is included in the
Utility Group segment of NU and has no other reportable segments.
- -------------------------------------------------------------------------------
Consolidated Quarterly Financial Data (Unaudited)
- -------------------------------------------------------------------------------
(Thousands of Dollars) Quarter Ended (a)
- -------------------------------------------------------------------------------
2003 March 31, June 30, September 30, December 31,
- -------------------------------------------------------------------------------
Operating Revenues $705,916 $615,268 $797,896 $585,445
Operating Income $ 69,087 $ 38,299 $ 73,151 $ 19,835
Net Income $ 26,722 $ 6,064 $ 30,431 $ 5,691
- -------------------------------------------------------------------------------
2002
- -------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data (Unaudited)
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2003 2002 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $2,704,525 $2,507,036 $2,646,123 $2,935,922 $2,452,855
Net Income/(Loss) 68,908 85,612 109,803 148,135 (13,568)
Cash Dividends on Common Stock 60,110 60,145 60,072 72,014 -
Gross Property, Plant and Equipment (b) 3,580,071 3,292,684 3,265,811 5,964,605 6,007,421
Total Assets (c) 5,206,894 4,786,083 4,727,727 4,764,198 5,298,284
Rate Reduction Bonds 1,124,779 1,245,728 1,358,653 - -
Long-Term Debt (d) 830,149 827,866 824,349 1,232,688 1,400,056
Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 116,200 116,200 116,200
Preferred Stock Subject to Mandatory Redemption (d) - - - - 99,539
Obligations Under Capital Leases (d) 14,879 15,499 16,040 129,869 144,400
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
Consolidated Statistics (Unaudited)
- --------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $1,151,707 $1,028,425 $ 991,946 $ 965,528 $1,014,215
Commercial 960,678 874,713 855,348 823,130 850,729
Industrial 290,526 274,228 285,479 285,877 291,062
Other Utilities 322,955 271,484 420,664 745,399 235,688
Streetlighting and Railroads 35,359 33,788 33,356 34,967 34,807
Non-franchised Sales - - - 1,390 4,125
Miscellaneous (56,700) 24,398 59,330 79,631 22,229
- --------------------------------------------------------------------------------------------------------------------------------
Total $2,704,525 $2,507,036 $2,646,123 $2,935,922 $2,452,855
- --------------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 10,359 9,699 9,340 9,084 9,071
Commercial 9,829 9,644 9,460 9,037 8,973
Industrial 3,630 3,707 3,850 4,000 4,004
Other Utilities 5,885 6,281 9,709 19,713 6,919
Streetlighting and Railroads 298 292 286 286 267
Non-franchised Sales - - - 59 83
- --------------------------------------------------------------------------------------------------------------------------------
Total 30,001 29,623 32,645 42,179 29,317
- --------------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 1,058,247 1,048,096 1,050,633 1,022,466 1,022,005
Commercial 104,750 103,408 95,782 92,303 92,046
Industrial 3,989 4,035 4,028 3,983 3,987
Other 2,643 2,768 2,791 2,799 2,808
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,169,629 1,158,307 1,153,234 1,121,551 1,120,846
- --------------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 9,790 9,244 8,884 8,976 8,969
- --------------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $1,089.63 $979.86 $943.48 $954.15 $1,002.73
- --------------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 11.13 cents 10.60 cents 10.62 cents 10.63 cents 11.18 cents
Commercial 9.77 9.07 9.04 9.11 9.48
Industrial 8.00 7.40 7.42 7.15 7.27
- --------------------------------------------------------------------------------------------------------------------------------
Employees 2,141 2,130 2,160 2,057 2,377
- --------------------------------------------------------------------------------------------------------------------------------
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
(b) Amount includes construction work in progress.
(c) Total assets were not adjusted for cost of removal prior to 2002.
(d) Includes portions due within one year.