EX-13.2 5 clpedgar.txt CL&P 2003 ANNUAL REPORT EXHIBIT 13.2 2003 Annual Report The Connecticut Light and Power Company Index Contents Page -------- ---- 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 ------------------------------------------------------------------------------- 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.