EX-13.2 5 clpannualreport2002.txt CL&P 2002 ANNUAL REPORT EXHIBIT 13.2 2002 Annual Report The Connecticut Light and Power Company and Subsidiaries Index Contents Page -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 1 Independent Auditors' Report and Report of Independent Public Accountants.............................................. 9 Consolidated Balance Sheets....................................... 10-11 Consolidated Statements of Income................................. 12 Consolidated Statements of Comprehensive Income................... 12 Consolidated Statements of Common Stockholder's Equity............ 13 Consolidated Statements of Cash Flows............................. 14 Notes to Consolidated Financial Statements........................ 15 Selected Consolidated Financial Data.............................. 25 Consolidated Quarterly Financial Data (Unaudited)................. 25 Consolidated Statistics (Unaudited)............................... 26 Preferred Stockholder and Bondholder Information.................. Back Cover Management's Discussion and Analysis Financial Condition ------------------- Overview The Connecticut Light and Power Company (CL&P or the company), the largest operating subsidiary of Northeast Utilities (NU), earned $85.6 million in 2002 compared with $109.8 million in 2001. The lower 2002 net income was largely attributable to an after-tax gain of $17.7 million CL&P recorded in 2001 associated with the sale of the Millstone nuclear units (Millstone). NU's other subsidiaries include Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), Yankee Energy System, Inc., North Atlantic Energy Corporation (NAEC), Select Energy, Inc. (Select Energy), Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc. CL&P's revenues for 2002 decreased to $2.5 billion from revenues of $2.6 billion for 2001. The decrease in revenues was primarily due to lower wholesale revenues, partially offset by higher retail revenues. Wholesale revenues decreased due to the sale of the Millstone units in the first quarter of 2001, lower revenues from sales of energy and capacity resulting from the buyout of cogenerator purchase contracts and lower wholesale market prices, and lower revenue from expiring market based contracts. Retail revenues were higher due to the recovery of previously deferred fuel costs and higher sales. Future Outlook CL&P is expected to have reduced earnings in 2003 as compared to 2002. The primary reason for the earnings decrease at CL&P in 2003 is a significant reduction in the projected level of pension income in 2003 and forward. CL&P recorded $50.6 million in pre-tax pension income in 2002, approximately 40 percent of which was capitalized and reflected as a reduction to the cost of capital expenditures with the remainder being recognized in the consolidated statements of income as reductions to operating expenses. In 2003, as a result of continued poor performance in the equity markets, CL&P is projecting the total level of pre-tax pension income to decline to approximately $27 million, with a similar percentage being reflected as a reduction to the cost of capital expenditures. Pension income is annually adjusted during the second quarter based upon updated actuarial valuations, at which time the 2003 estimate may be modified. Liquidity The year 2002 represented the final year of a four-year process of selling all of the regulated generation assets owned by CL&P. On November 1, 2002, CL&P consummated the sale of its 4.06 percent ownership interest in Seabrook. CL&P received approximately $36 million of total cash proceeds from the sale of Seabrook. In November 2002, CL&P, along with NU's other regulated utilities, renewed their $300 million credit line under terms similar to the arrangement that expired in November 2002. A previous credit line had provided up to $350 million for the regulated companies. CL&P had no borrowings on this credit line at December 31, 2002. In addition to its revolving credit arrangement, CL&P can access up to $100 million by selling certain of its accounts receivable. At December 31, 2002, CL&P had $40 million sold under this arrangement. This accounts receivable arrangement is expected to be renewed in July 2003. Rate reduction bonds are included on the consolidated balance sheets of CL&P, even though the debt is nonrecourse to CL&P. At December 31, 2002, CL&P had $1.2 billion in rate reduction bonds outstanding, compared with $1.4 billion outstanding at December 31, 2001. All outstanding rate reduction bonds of CL&P are scheduled to be amortized by December 30, 2010. Interest on the rate reduction bonds totaled $75.7 million in 2002, compared with $60.6 million in 2001. Amortization of the rate reduction bonds totaled $112.9 million in 2002, compared with $79.7 million in 2001. CL&P fully recovered the amortization and interest payments from customers in 2002, and the bonds had no impact on net income. Moreover, because the debt is nonrecourse to CL&P, the three rating agencies that rate CL&P's debt and preferred stock securities do not include the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of CL&P. CL&P is also considering refinancing approximately $200 million of spent nuclear fuel obligations in 2003. These obligations are included in long- term debt. CL&P's net cash flows provided by operating activities increased to $387.4 million in 2002, compared with $12.2 million in 2001. Cash flows provided by operating activities increased primarily due to changes in working capital, primarily receivables and unbilled revenues and accounts payable, partially offset by the decrease in net income in 2002. There was a lower level of investing and financing activities in 2002 as compared to 2001, primarily due to the issuance of rate reduction certificates and the buyout and buydown of independent power producer contracts in 2001. The level of common dividends totaled $60.1 million in 2002 and 2001. CL&P has embarked upon a significant upgrade program within its service territory. Over the past five years, CL&P has increased its annual investment in electric utility plant by approximately 50 percent. Much of the additional investment has been devoted to improving the reliability of CL&P's electric distribution system. Over the next several years, CL&P has proposed a significant expansion of its 345,000 volt electric transmission system into southwestern Connecticut at a cost that is likely to exceed $500 million. If Connecticut regulators approve the expansion, CL&P's construction expenditures are projected to exceed $350 million annually from 2004 through 2007. Such a program would significantly exceed CL&P's projections for internally generated operating cash flows and would require CL&P to access the capital markets for financing. In 2003, CL&P is expected to generate enough cash internally to fund most, if not all, of its capital needs. Implementation of Standard Market Design On March 1, 2003, the New England independent system operator (ISO) implemented a new Standard Market Design (SMD). As part of this effort, locational marginal pricing (LMP) will be utilized to assign value and causation to transmission congestion. Transmission congestion costs will be assigned to the load zone in which the congestion occurs. Those costs are now spread across virtually all New England electric customers. In addition, the implementation of SMD will impact wholesale energy contracts with respect to the energy delivery points contained in those contracts. Connecticut has been designated a single load zone. Due to the transmission constraints and inadequate generation, Connecticut could experience significant additional congestion costs under SMD. The New England ISO estimates that the costs of transmission congestion for 2003 in New England will range between $50 million and $300 million. The New England ISO estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent are expected to be paid by CL&P beginning on March 1, 2003. CL&P believes that under the terms of its contracts with its standard offer suppliers, these costs are its responsibility. The contracts with the standard offer suppliers expire on December 31, 2003. In addition, the determination of the energy delivery points associated with the standard offer service contracts under SMD could also produce significant costs for CL&P that management cannot determine at this time. Another factor affecting the level of congestion costs is the designation of certain generating units by the New England ISO as units needed for system reliability. Some of the companies owning these units have applied to the Federal Energy Regulatory Commission (FERC) for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service - based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by the New England ISO based upon their share of New England's load. NU's regulated electric utilities were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD by the New England ISO, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience a cost increase in which a NU regulated electric company operates is Connecticut. With respect to the Connecticut load zone, there are two generating units operating under a RMR contract with an additional contract pending before FERC. These contracts are for one year terms, and one contract contains an extension option. On a combined basis, these two RMR contracts will result in an annual cost of approximately $45 million to the Connecticut load zone. CL&P accounts for approximately 80 percent of the Connecticut load zone, and would be responsible for approximately $36 million of this cost. In the near future, it is probable that there will be significant new requests for RMR treatment in Connecticut which, if approved by FERC, would add significant additional costs to the total cost of energy in Connecticut. However, generating units operating under RMR contracts could potentially mitigate the overall level of congestion costs. These unavoidable congestion and RMR costs are part of the prudent cost of providing regulated electric service in Connecticut. A Connecticut Department of Public Utility Control (DPUC) regulatory proceeding is expected to be initiated soon to determine the appropriate recovery mechanism for these costs. If these costs are incurred before the final recovery mechanism is established by the DPUC, CL&P expects to record a regulatory asset for those costs incurred. See Critical Accounting Policies and Estimates - Regulatory Accounting and Assets included in management's discussion and analysis for further information. Business Development and Capital Expenditures CL&P's capital expenditures, excluding nuclear fuel, totaled $242.3 million in 2002, compared with $237.4 million in 2001 and $208.2 million in 2000. CL&P expects capital expenditures to increase to $326.9 million in 2003. CL&P spent $141.2 million related to its overhead and underground electric distribution system in 2002 and expects to spend a similar amount in 2003. CL&P spent $35.6 million to upgrade its transmission system in 2002, and expects its transmission capital expenditures to increase to $95 million in 2003, if its current construction plans receive regulatory approval. CL&P also spent $20 million on new meters and customer services, and $17 million on substations in 2002. In 2001, CL&P announced plans for three transmission projects. In September 2002, the Connecticut Siting Council (CSC) approved the first project, a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $80 million. CL&P owns 50 percent of the line with the Long Island Power Authority also owning 50 percent. The project still requires federal and New York state approvals. Given the approval process and the uncertainty created by the recent damage to the existing transmission line, the expected in-service date is currently under evaluation. At December 31, 2002, CL&P has capitalized approximately $4.8 million related to this project. In early 2003, the CSC completed hearings on the second project, a $135 million proposal to build a new 345,000 volt transmission line between Norwalk, Connecticut and Bethel, Connecticut. A decision is expected in April 2003. The current cost estimate is based on building the entire transmission line aboveground. Alternative proposals have been made to build all or part of the line underground, which likely would result in significantly higher construction costs. CL&P hopes to have the new transmission line operational by the summer of 2005. At December 31, 2002, CL&P has capitalized approximately $8.8 million related to this project. By mid-2003, CL&P expects to apply to the CSC for approval of a third project, the installation of another 345,000 volt transmission line between Norwalk, Connecticut and Middletown, Connecticut. Estimated construction costs of this overhead line are approximately $500 million. CL&P will jointly construct this project with United Illuminating with CL&P owning 80 percent or approximately $400 million of the project. At December 31, 2002, CL&P has capitalized approximately $2.4 million related to this project. Construction of these three projects would significantly enhance CL&P's ability to provide reliable electric service to the rapidly growing energy market in southwestern Connecticut. Despite the need for such facilities, significant opposition has been raised. As a result, management cannot be certain as to the expected in-service dates or the ultimate cost of these projects. Should the plans proceed, applicable law provides that CL&P will be able to recover its operating cost and carrying costs through federally approved transmission tariffs. Regional Transmission Organization The FERC has required all transmission owning utilities, including CL&P, to voluntarily start forming regional transmission organizations (RTO) or to state why this process has not begun. CL&P has been discussing with the other transmission owners in New England the potential to form an Independent Transmission Company (ITC). If formed, the ITC would be a for-profit entity and would perform certain transmission functions required by the FERC, including tariff control, system planning and system operations. The remaining functions required by the FERC would be performed by the ISO regarding the energy market and short-term reliability. Together, the ITC, if formed, and ISO would form the FERC-desired RTO. In January 2002, the New York and New England ISOs announced their intention to form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to FERC. The New England ISO intends to make an RTO filing with the transmission owners in New England in 2003. The agreements needed to create the RTO and to define the working relationships among the ISO and the transmission owners should be created in 2003, and will allow the RTO to begin operation shortly thereafter. The agreements are expected to include provisions for the future creation of one or more ITCs within the RTO. The creation of the RTO will require a FERC rate case, and the impact on CL&P's return on equity as a result of this rate case cannot be estimated at this time. At December 31, 2002, CL&P capitalized $0.8 million related to RTO formation activities. Merchant Energy Company Counterparty Exposures CL&P has entered into various transactions with subsidiaries of NRG Energy, Inc. (NRG). NRG's credit rating has been downgraded to below investment grade by all three major rating agencies, and NRG is presently in default on debt service payments. Management does not expect that the resolution of the transactions with NRG will have a material adverse effect on CL&P's consolidated financial condition or results of operations. Additionally, CL&P does not have a significant level of exposure to other merchant energy companies. For further information regarding these transactions, see NU's 2002 report on Form 10-K, Item 1, "Business." Restructuring and Rate Matters Since retail competition began in Connecticut in 2000, an extremely small number of customers have opted to choose an alternate supplier. At December 31, 2002, virtually all of CL&P's customers were procuring their electricity through CL&P's standard offer service. In 2003, Select Energy will continue to supply 50 percent of CL&P's standard offer supply service with NRG Power Marketing, Inc. (NRG-PM), a subsidiary of NRG, contracted to supply 45 percent and a subsidiary of Duke Energy, Inc. contracted to supply the remaining 5 percent of service. On November 18, 2001, at NRG- PM's request, CL&P filed an application with the DPUC to raise the standard offer rate from an average of $0.0495 per kilowatt-hour (kWh) to $0.0595 per kWh to help promote competition in advance of the January 1, 2004 termination of the standard offer period and to provide financial relief to standard offer suppliers. In December 2001, the DPUC rejected CL&P's request, but opened two new dockets to examine the absence of effective retail competition in Connecticut and the financial condition of the suppliers. The first docket culminated in a joint study report issued in a DPUC decision on February 15, 2002, which provided the DPUC's and the Office of Consumer Counsel's findings on how to best structure default service and other issues related to electric industry restructuring. In the second docket, the DPUC concluded on June 17, 2002, that it would not commence further proceedings. On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to recover stranded costs to instead provide additional payments to NRG-PM and Select Energy to ensure electric reliability in southwestern Connecticut. On July 26, 2002, the DPUC denied the proposal. CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs associated with obtaining such supply from NRG-PM pursuant to the contract and may be required to seek DPUC approval to flow through any such costs to customers. Management believes that recovery of these costs, should they be incurred, would be permitted under the provisions of Connecticut's electric utility restructuring legislation and with the DPUC's prior decisions. On February 21, 2003, Fitch Ratings lowered its rating outlook on CL&P to negative as a result of its concern over timely recovery of purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations and CL&P needs to acquire replacement supply service at significantly higher prices. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. The DPUC's final decision regarding this application was issued on February 27, 2003, and increased the amount of net proceeds used to reduce stranded costs by $26.9 million. The earnings impact of the final decision will be reflected in 2003 earnings and will result in an increase in first quarter net income of $2.6 million. On November 1, 2002, CL&P sold its interest in Seabrook to a subsidiary of FPL Group, Inc. The gain on the sale was used to reduce stranded costs. CL&P continues to be subject to the earnings sharing mechanism implemented by the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on equity will be shared equally by shareholders and ratepayers. CL&P expects to file a distribution rate case with the DPUC in mid-2003 that would be effective January 1, 2004. Also in the second half of 2003, CL&P will need to secure bids for power supply contracts for 2004 to meet the needs of its customers. Management has not yet identified what level of rates it will request in 2004, but believes that several factors could combine to result in a significant increase in supply costs in 2004. The first is the expiration of current standard offer supply contracts. Another factor is the likely impact of LMP in New England with the implementation of SMD. Implementation of such pricing, which occurred on March 1, 2003, will force Connecticut electric customers to bear the significant additional costs of serving southwestern Connecticut with less efficient local generation because of insufficient transmission capacity to bring cheaper energy into the region. CL&P's completed and planned reliability improvements and transmission construction program will also impact the level of rates management will request in 2004. For further information regarding commitments and contingencies related to restructuring, see Note 6A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. Nuclear Generation Asset Divestitures Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners consummated the sale of their ownership interest in Seabrook. VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. CL&P owns 10.1 percent of VYNPC. Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2, and CL&P, PSNH, and WMECO sold their ownership interests in Millstone 3. Under the terms of these asset divestitures, the purchasers agreed to assume responsibility for decommissioning their respective units. For further information regarding these divestitures and nuclear decommissioning, see Note 5, "Nuclear Generation Asset Divestitures," and Note 6F, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. For further information regarding spent nuclear fuel disposal costs, see Note 6C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial condition of CL&P. The following describes accounting policies and estimates that management believes are the most critical in nature: Presentation: In accordance with current accounting pronouncements, CL&P's consolidated financial statements include all subsidiaries upon which significant control is maintained and all intercompany transactions between these subsidiaries are eliminated as part of the consolidation process. CL&P has less than 50 percent ownership interests in the Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company, Maine Yankee Atomic Power Company, VYNPC, and two companies that transmit electricity imported from the Hydro-Quebec system, which are classified as variable interest entities under Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities," and for which CL&P is not the primary beneficiary. As a result, management does not expect the adoption of Interpretation No. 46 to result in the consolidation of any currently unconsolidated entities or to have any other material impacts on CL&P's consolidated financial statements. Revenue Recognition: Revenues are based on rates approved by the DPUC. These regulated rates are applied to customers' accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DPUC. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates. Regulatory Accounting and Assets: The accounting policies of CL&P historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." CL&P's transmission and distribution businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of this business no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write off regulatory assets. Such a write-off could have a material impact on CL&P's consolidated financial statements. The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, the regulatory commission can reach different conclusions about the recovery of costs, which can have a material impact on CL&P's consolidated financial statements. Management believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets. Pension and Postretirement Benefit Obligations: CL&P participates in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees and also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on CL&P's consolidated financial statements. CL&P's pre-tax periodic pension income for the Plan, excluding settlements, curtailments, and special termination benefits, totaled $50.6 million and $61.4 million for the years ended December 31, 2002 and 2001, respectively. Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 9.25 percent for 2002 and 9.5 percent for 2001. CL&P expects to use a long-term rate of return assumption of 8.75 percent for 2003. The pension income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," associated with early termination programs and the sale of the Millstone and Seabrook nuclear units. Net SFAS No. 88 expenses totaled $8.1 million and $1.2 million for the years ended December 31, 2002 and 2001, respectively. Approximately 40 percent of net pension income is capitalized as a reduction to capital additions to utility plant. In developing the expected long-term rate of return assumption, CL&P evaluated input from actuaries, consultants and economists as well as long- term inflation assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 45 percent in United States equities and 14 percent in non-United States equities, both with expected long-term rates of return of 9.25 percent, 3 percent in emerging market equities with an expected long-term return of 10.25 percent, 20 percent in fixed income securities with an expected long-term rate of return of 5.5 percent, 5 percent in high yield fixed income securities with expected long-term rates of return of 7.5 percent, 8 percent in private equities with expected long-term rates of return of 14.25 percent, and 5 percent in real estate with expected long-term rates of return of 7.5 percent. The combination of these target allocations and expected returns results in the overall assumed long-term rate of return of 8.75 percent for 2003. The actual asset allocation at December 31, 2002, was close to these target asset allocations, and NU regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted allocation when appropriate. NU reduced the long-term rate of return assumption by 0.5 percent and 0.25 percent, respectively, each of the last two years due to lower rate of return assumptions for most asset classes. CL&P believes that 8.75 percent is a reasonable long-term rate of return on Plan assets for 2003. CL&P will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary. CL&P bases the actuarial determination of Plan pension income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Plan assets. At December 31, 2002, CL&P's portion of the Plan had cumulative unrecognized investment losses of $234.2 million, which will increase Plan expense over the next four years by reducing the expected return on Plan assets. At December 31, 2002, CL&P's portion of the Plan also had cumulative unrecognized actuarial gains of $57.6 million, which will reduce Plan expenses over the expected future working lifetime of active Plan participants, or approximately 13 years. The combined total of unrecognized investment losses and actuarial gains at December 31, 2002 is $176.6 million. This amount impacts the actuarially determined prepaid pension amount recorded on the consolidated balance sheet but has no impact on expected Plan funding. The discount rate that is utilized in determining future pension obligations is based on a basket of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. To compensate for the Plan's longer duration 0.25 percent was added to this rating. The discount rate determined on this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent at December 31, 2002. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent and various other assumptions, CL&P estimates that pension income/expense for the Plan will be approximately $27 million in income, approximately $10 million in income and approximately $4 million in expense in 2003, 2004 and 2005, respectively. Future actual pension income/expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plan. The value of CL&P's portion of the Plan assets has decreased from $910.4 million at December 31, 2001 to $752.7 million at December 31, 2002. The investment performance returns and declining discount rates have reduced the funded status of CL&P's portion of the Plan, on a projected benefit obligation (PBO) basis, from an overfunded position of $284.4 million at December 31, 2001 to $72.3 million at December 31, 2002. The PBO includes expectations of future employee service and compensation increases. The significant deterioration in the funded position of the Plan will likely result in Plan contributions sooner than previously expected. CL&P has not made contributions since 1991. This deterioration could also lead to the requirement under defined benefit plan accounting to record an additional minimum liability. The total accumulated benefit obligation (ABO) of the entire Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the obligation for employee service provided through December 31, 2002. If the ABO exceeds Plan assets, CL&P may need to record an additional minimum liability in 2003. Income Taxes: Income tax expense is calculated for each period for which a statement of income is presented. This process involves estimating CL&P's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. CL&P must also assess the likelihood that the deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances. CL&P accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, CL&P has established a regulatory asset. This asset amounted to $170.5 million and $154.2 million at December 31, 2002 and 2001, respectively. Depreciation: Depreciation expense is calculated based on an asset's useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on CL&P's consolidated financial statements. Environmental Matters: At December 31, 2002, CL&P has recorded a reserve for various environmental liabilities. CL&P's environmental liabilities are based on the best estimate of the amounts to be incurred for the investigation, remediation and monitoring of the remediation sites. It is possible that future cost estimates will either increase or decrease as additional information becomes known. Special Purpose Entities: CL&P has two special purpose entities (SPE), which are currently consolidated in the financial statements. During 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established one SPE, CL&P Funding LLC. The funding company was created as part of state sponsored securitization programs. CL&P Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in CL&P's bankruptcy estate if it ever becomes involved in such bankruptcy proceedings. The CL&P Receivables Corporation (CRC) is an SPE that was incorporated on September 5, 1997, and is a wholly owned subsidiary of CL&P. The CRC was established for the sole purpose of selling CL&P's accounts receivable and is included in the consolidation of CL&P's financial statements. On July 10, 2002 the CRC renewed its Receivables Purchase and Sale Agreement with CL&P and a subsidiary of Citigroup, Inc. (Citigroup). The agreement gives the CRC the right to sell and Citigroup the right to purchase up to $100 million in receivables through July 9, 2003. At December 31, 2002 there was $40 million outstanding under this facility. Sales of receivables to Citigroup under this arrangement meet the accounting criteria for derecognition from the consolidated balance sheet. Accordingly, the $40 million outstanding under this facility is not reflected as debt or included in the consolidated financial statements. For further information regarding these types of activities, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 4, "Sale of Customer Receivables," Note 6B, "Commitments and Contingencies - Environmental Matters," and Note 12, "Income Tax Expense," to the consolidated financial statements. Other Matters Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 6, "Commitments and Contingencies," to the consolidated financial statements. Contractual Obligations and Commercial Commitments: Information regarding CL&P's contractual obligations and commercial commitments at December 31, 2002, is summarized through 2007 as follows: --------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 --------------------------------------------------------------------- Capital leases $ 2.6 $ 2.5 $ 2.4 $ 2.4 $ 2.4 Operating leases 12.0 11.0 10.2 9.1 6.1 Long-term contractual arrangements 230.3 231.9 233.7 236.7 240.4 --------------------------------------------------------------------- Totals $244.9 $245.4 $246.3 $248.2 $248.9 --------------------------------------------------------------------- Rate reduction bond amounts are not included in this table. For further information regarding CL&P's contractual obligations and commercial commitments, see Note 8, "Leases," and Note 6E, "Long-Term Contractual Arrangements," to the consolidated financial statements. Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors. Results of Operations The components of significant income statement variances for the past two years are provided in the table below.
-------------------------------------------------------------------------------- 2002 over/(under)2001 2001 over/(under) 2000 Income Statement Variances --------------------- ---------------------- (Millions of Dollars) Amount Percent Amount Percent -------------------------------------------------------------------------------- Operating Revenues $(139) (5)% $(290) (10)% Operating Expenses: Fuel, purchased and net interchange power (37) (2) (151) (9) Other operation (10) (3) (102) (25) Maintenance (26) (25) (30) (22) Depreciation 2 2 (21) (18) Amortization of regulatory assets, net (568) (76) 649 (a) Taxes other than income taxes 7 5 (7) (5) Gain on sale of utility plant 505 97 (522) (100) -------------------------------------------------------------------------------- Total operating expenses (127) (5) (184) (7) -------------------------------------------------------------------------------- Operating income (12) (4) (106) (29) Interest expense, net - - 22 23 Other income/(loss), net (30) (58) 75 (a) -------------------------------------------------------------------------------- Income before income tax expense (42) (22) (53) (22) Income tax expense (18) (21) (15) (15) -------------------------------------------------------------------------------- Net income/(loss) $ (24) (22)% $ (38) (26)% ================================================================================
(a) Percent greater than 100. Operating Revenues Operating revenues decreased $139 million or 5 percent in 2002, primarily due to lower wholesale and other revenues ($184 million), partially offset by higher retail revenues ($45 million). Wholesale revenues were lower due to the inclusion in 2001 of revenue from the output of the Millstone nuclear units ($62 million), lower revenues from sales of energy and capacity ($63 million) resulting from the buyout of cogenerator purchase contracts and lower wholesale market prices, and lower revenue from expiring market based contracts ($24 million). Retail revenues were higher due to the collection of deferred fuel costs ($25 million) and higher retail sales. Retail sales increased 1.8 percent compared to 2001. Total revenues decreased $290 million or 10 percent in 2001, primarily due to lower wholesale revenues ($325 million) and lower transmission revenues ($19 million), partially offset by higher retail revenues ($57 million). Wholesale revenues were lower primarily as a result of the sale of the Millstone units at the end of the first quarter of 2001 and lower sales of capacity and energy. The lower transmission revenues were partially offset by lower transmission expenses. Retail revenues increased primarily due to higher retail sales ($43 million) and the recovery of previously deferred fuel costs ($19 million), partially offset by a rate decrease ($5 million). Retail sales increased 2.4 percent compared to 2000. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $37 million in 2002 primarily due to lower purchased-power costs resulting from the buydown and buyout of various cogeneration contracts ($50 million), lower market-based contracts ($23 million) and lower nuclear fuel expense ($8 million), partially offset by the 2002 amortization of deferred fuel expenses which are being recovered ($25 million) and the higher expenses related to the standard offer supply and associated deferrals ($17 million). Fuel, purchased and net interchange power expense decreased in 2001, primarily due to lower purchased power costs resulting from the buydown and buyout of various cogeneration contracts and lower nuclear fuel expense. Other Operation and Maintenance Other operation and maintenance (O&M) expenses decreased $36 million in 2002, primarily due to lower nuclear expense as a result of the sale of the Millstone units at the end of the first quarter of 2001 ($52 million), lower distribution expenses ($8 million), partially offset by higher transmission expenses ($16 million) and higher administrative and general expenses ($10 million). Other O&M expenses decreased $132 million in 2001, primarily due to lower nuclear expenses ($95 million) as a result of the sale of the Millstone units at the end of the first quarter of 2001, lower administrative and general expenses ($22 million), lower transmission expenses ($16 million), and lower fossil/hydro expenses ($3 million), partially offset by higher distribution expenses ($4 million). Depreciation Depreciation expense increased $2 million in 2002, primarily due to higher utility plant balances. Depreciation expense decreased in 2001, primarily due to the elimination of decommissioning expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased $568 million in 2002, primarily due to lower amortizations related to the sale of the Millstone units ($524 million) and lower amortizations of the nuclear investment ($42 million). Amortization of regulatory assets, net increased in 2001, primarily due to the amortization related to the gain on the sale of the Millstone units ($524 million) and higher amortization related to securitized assets ($68 million), stranded costs ($30 million), and other amortizations related to restructuring ($27 million). Taxes Other Than Income Taxes Taxes other than income taxes increased $7 million in 2002, primarily due to payments to the Town of Waterford for its loss of property tax resulting from electric utility restructuring ($15 million), partially offset by the recognition of a Connecticut sales and use tax audit settlement for the years 1993 through 2001 ($7 million). CL&P is recovering through rates the additional property tax payments to the Town of Waterford. Taxes other than income taxes decreased in 2001, primarily due to settlement of a property tax appeal with the City of Meriden in 2001 ($5 million) and the reduction in property tax due to the sale of the Millstone units ($12 million), partially offset by higher gross earnings tax paid on higher revenues ($8 million). Gain on Sale of Utility Plant CL&P recorded a gain on the sale of its ownership share in Seabrook in 2002 ($16 million) as compared to the 2001 gain on the sale of the Millstone units ($522 million). A corresponding amount of amortization expenses was recorded. CL&P recorded a gain on the sale of its ownership share in the Millstone units. A corresponding amount of amortization expense was recorded in 2001. Interest Expense, Net Interest expense, net increased in 2001, primarily due to interest associated with the issuance of rate reduction certificates in 2001, partially offset by lower interest on other long-term debt resulting from reacquisitions and retirements of long-term debt in 2001. Other Income/(Loss), Net Other income, net decreased $30 million in 2002, primarily due to the gain recognized in 2001 on the sale of the Millstone units ($29 million). Other income/(loss), net increased in 2001, primarily due to the gain on the sale of CL&P's ownership share in the Millstone units ($29 million), the settlement, in 2000, of Millstone-related litigation, net of insurance proceeds ($9 million), a write-off associated with the former CMEEC nuclear entitlement ($6 million) in 2000 and higher interest income in 2001, including the allowed return on deferred fuel balances ($10 million), interest on an Internal Revenue Service tax settlement ($10 million), and interest income related to the City of Meriden property tax refund ($2 million). Income Tax Expense Income tax expense decreased in 2002 primarily due to lower book taxable income. Independent Auditors' Report ---------------------------- To the Board of Directors of The Connecticut Light and Power Company: We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. The consolidated financial statements of the Company as of December 31, 2000, and for the year then ended, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated January 22, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the 2002 and 2001 consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP --------------------- DELOITTE & TOUCHE LLP Hartford, Connecticut January 28, 2003 (February 27, 2003 as to Note 6A) Report of Independent Public Accountants ---------------------------------------- To the Board of Directors of The Connecticut Light and Power Company: We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. /s/ ARTHUR ANDERSEN LLP ------------------- ARTHUR ANDERSEN LLP Hartford, Connecticut January 22, 2002 Readers of these consolidated financial statements should be aware that this report is a copy of a previously issued Arthur Andersen LLP report and that this report has not been reissued by Arthur Andersen LLP. Furthermore, this report has not been updated since January 22, 2002, and Arthur Andersen LLP completed its last post-audit review of December 31, 2001, consolidated financial information on May 13, 2002. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
---------------------------------------------------------------------------------------------- At December 31, 2002 2001 ---------------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents.................................. $ 159 $ 773 Investments in securitizable assets........................ 178,908 206,367 Receivables, less provision for uncollectible accounts of $525 in 2002 and 2001 ........................ 88,001 77,801 Accounts receivable from affiliated companies.............. 51,060 22,134 Unbilled revenues.......................................... 5,801 7,492 Notes receivable from affiliated companies................. 1,900 77,200 Fuel, materials and supplies, at average cost.............. 32,379 33,085 Prepayments and other...................................... 19,407 17,873 ---------- ---------- 377,615 442,725 ---------- ---------- Property, Plant and Equipment: Electric utility........................................... 3,139,128 3,127,548 Less: Accumulated depreciation.......................... 1,113,991 1,236,638 ---------- ---------- 2,025,137 1,890,910 Construction work in progress.............................. 153,556 134,964 Nuclear fuel, net.......................................... - 3,299 ---------- ---------- 2,178,693 2,029,173 ---------- ---------- Deferred Debits and Other Assets: Regulatory assets.......................................... 1,702,677 1,877,191 Prepaid pension............................................ 276,173 233,692 Nuclear decommissioning trusts, at market.................. - 6,231 Other...................................................... 96,925 138,715 ---------- ---------- 2,075,775 2,255,829 ---------- ---------- Total Assets................................................. $4,632,083 $4,727,727 ========== ==========
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, 2002 2001 ---------------------------------------------------------------------------------------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Accounts payable....................................... $ 174,890 $ 132,593 Accounts payable to affiliated companies............... 117,904 85,057 Accrued taxes.......................................... 34,350 34,993 Accrued interest....................................... 10,077 10,369 Other.................................................. 48,495 47,342 ---------- ---------- 385,716 310,354 ---------- ---------- Rate Reduction Bonds..................................... 1,245,728 1,358,653 ---------- ---------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes...................... 756,461 820,444 Accumulated deferred investment tax credits............ 93,408 95,996 Deferred contractual obligations....................... 234,537 141,497 Other.................................................. 276,325 283,399 ---------- ---------- 1,360,731 1,341,336 ---------- ---------- Capitalization: Long-Term Debt......................................... 827,866 824,349 ---------- ---------- Preferred Stock - Nonredeemable........................ 116,200 116,200 ---------- ---------- Common Stockholder's Equity: Common stock, $10 par value - authorized 24,500,000 shares; 6,035,205 shares outstanding in 2002 and 7,584,884 shares outstanding in 2001.... 60,352 75,849 Capital surplus, paid in............................. 327,299 414,018 Retained earnings.................................... 308,554 286,901 Accumulated other comprehensive (loss)/income........ (363) 67 ---------- ---------- Common Stockholder's Equity............................ 695,842 776,835 ---------- ---------- Total Capitalization..................................... 1,639,908 1,717,384 ---------- ---------- Commitments and Contingencies (Note 6) Total Liabilities and Capitalization..................... $4,632,083 $4,727,727 ========== ==========
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, 2002 2001 2000 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.......................................... $2,507,036 $2,646,123 $2,935,922 ---------- ---------- ---------- Operating Expenses: Operation - Fuel, purchased and net interchange power.............. 1,477,347 1,514,418 1,665,806 Other.................................................. 300,439 310,477 412,230 Maintenance............................................... 80,132 106,228 136,141 Depreciation.............................................. 98,360 96,212 117,305 Amortization of regulatory assets, net.................... 178,274 746,693 97,315 Taxes other than income taxes............................. 137,299 130,656 137,846 Gain on sale of utility plant............................. (16,143) (521,590) - ---------- ---------- ---------- Total operating expenses................................ 2,255,708 2,383,094 2,566,643 ---------- ---------- ---------- Operating Income............................................ 251,328 263,029 369,279 Interest Expense: Interest on long-term debt................................ 41,332 56,527 85,980 Interest on rate reduction bonds.......................... 75,705 60,644 - Other interest............................................ 3,925 3,958 12,886 ---------- ---------- ---------- Interest expense, net................................... 120,962 121,129 98,866 ---------- ---------- ---------- Other Income/(Loss), Net.................................... 22,112 52,804 (22,224) ---------- ---------- ---------- Income Before Income Tax Expense............................ 152,478 194,704 248,189 Income Tax Expense.......................................... 66,866 84,901 100,054 ---------- ---------- ---------- Net Income.................................................. $ 85,612 $ 109,803 $ 148,135 ========== ========== ========== CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Net Income................................................. $ 85,612 $ 109,803 $ 148,135 ---------- ---------- ---------- Other comprehensive (loss)/income, net of tax: Unrealized (losses)/gains on securities.................. (452) (439) 90 Minimum pension liability adjustments.................... (22) - - ---------- ---------- ---------- Other comprehensive (loss)/income, net of tax......... (474) (439) 90 ---------- ---------- ---------- Comprehensive Income....................................... $ 85,138 $ 109,364 $ 148,225 ========== ========== ==========
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 Capital Other Common Surplus, Retained Comprehensive Total Stock Paid In Earnings Income/(Loss) (a) ------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 2000........................ $122,229 $665,598 $153,254 $ 416 $941,497 Net income for 2000........................... 148,135 148,135 Cash dividends on preferred stock............. (7,402) (7,402) Cash dividends on common stock................ (72,014) (72,014) Redemption of preferred stock................. (749) (749) Repurchase of common stock.................... (46,380) (253,620) (300,000) Capital stock expenses, net................... 1,963 1,963 Allocation of benefits - ESOP (b)............. 21,224 21,224 Other comprehensive income.................... 90 90 -------- -------- -------- ----- -------- Balance at December 31, 2000...................... 75,849 413,192 243,197 506 732,744 Net income for 2001........................... 109,803 109,803 Cash dividends on preferred stock............. (5,559) (5,559) Cash dividends on common stock................ (60,072) (60,072) Capital stock expenses, net................... 826 826 Allocation of benefits - ESOP................. (468) (468) Other comprehensive loss...................... (439) (439) -------- -------- -------- ----- -------- Balance at December 31, 2001...................... 75,849 414,018 286,901 67 776,835 Net income for 2002........................... 85,612 85,612 Cash dividends on preferred stock............. (5,559) (5,559) Cash dividends on common stock................ (60,145) (60,145) Repurchase of common stock.................... (15,497) (84,493) (99,990) Capital stock expenses, net................... 232 232 Allocation of benefits - ESOP................. (2,458) 1,745 (713) Other comprehensive loss...................... (430) (430) -------- -------- -------- ----- -------- Balance at December 31, 2002...................... $ 60,352 $327,299 $308,554 $(363) $695,842 ======== ======== ======== ===== ========
(a) The company has a dividend restriction as well as two tests it must meet before it can pay out any dividends. The most restrictive of which limits the company's ability to pay out approximately $275.4 million of equity at December 31, 2002. (b) In June 1999, CL&P paid NU parent $30.5 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to CL&P. The amount in 2000 represents the remaining previously unallocated 1993 through 1999 NU parent losses. The accompanying notes are an integral part of these consolidated financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net income....................................................... $ 85,612 $ 109,803 $ 148,135 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation................................................... 98,360 96,212 117,305 Deferred income taxes and investment tax credits, net.......... (71,880) (144,559) 5,672 Net amortization of recoverable energy costs................... 30,787 5,162 4,155 Amortization of regulatory assets, net......................... 178,274 746,693 97,315 Tax benefit for 1993-1999 from reduction in NU parent losses................................ - - 21,461 Gain on sale of utility plant.................................. (16,143) (521,590) - Prepaid pension................................................ (42,481) (63,020) (170,672) Net other sources/(uses) of cash............................... 62,868 (107,024) 111,594 Changes in working capital: Receivables and unbilled revenues, net......................... (37,435) (144,419) (109,938) Fuel, materials and supplies................................... (1,017) 3,247 1,271 Accounts payable............................................... 74,831 (58,400) 171,729 Accrued taxes.................................................. (643) 1,922 (136,313) Investments in securitizable assets............................ 27,459 61,779 9,474 Other working capital (excludes cash).......................... (1,184) 26,440 3,204 -------- ---------- --------- Net cash flows provided by operating activities.................... 387,408 12,246 274,392 -------- ---------- --------- Investing Activities: Investments in plant: Electric utility plant......................................... (242,301) (237,423) (208,249) Nuclear fuel................................................... (57) (1,992) (35,709) --------- ---------- --------- Cash flows used for investments in plant......................... (242,358) (239,415) (243,958) NU system Money Pool borrowing/(lending)......................... 75,300 (39,200) (49,700) Investments in nuclear decommissioning trusts.................... (1,086) (74,866) (25,133) Net proceeds from the sale of utility plant...................... 35,887 827,681 686,807 Buyout/buydown of IPP contracts.................................. - (1,029,008) - Other investment activities, net................................. 23,395 (10,164) 10,246 --------- ---------- --------- Net cash flows (used in)/provided by investing activities.......... (108,862) (564,972) 378,262 -------- ----------- --------- Financing Activities: Repurchase of common stock....................................... (99,990) - (300,000) Issuance of rate reduction bonds................................. - 1,438,400 - Retirement of rate reduction bonds............................... (112,924) (79,747) - Net(decrease)/increase in short-term debt........................ - (115,000) 25,000 Reacquisitions and retirements of long-term debt................. - (416,155) (179,071) Reacquisitions and retirements of preferred stock................ - - (99,539) Retirement of monthly income preferred securities................ - (100,000) - Retirement of capital lease obligation........................... - (145,800) - Cash dividends on preferred stock................................ (5,559) (5,559) (7,402) Cash dividends on common stock................................... (60,145) (60,072) (72,014) Other financing activities, net.................................. (542) 31,971 (14,531) --------- ---------- --------- Net cash flows (used in)/provided by financing activities.......... (279,160) 548,038 (647,557) --------- ---------- --------- Net (decrease)/increase in cash and cash equivalents............... (614) (4,688) 5,097 Cash and cash equivalents - beginning of year...................... 773 5,461 364 --------- ---------- --------- Cash and cash equivalents - end of year............................ $ 159 $ 773 $ 5,461 ========= ========== ========= Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized............................. $ 117,718 $ 120,645 $ 96,735 ========= ========== ========= Income taxes..................................................... $ 141,724 $ 230,144 $ 226,380 ========= ========== =========
The accompanying notes are an integral part of these consolidated financial statements. Notes to Consolidated Financial Statements 1. Summary of Significant Accounting Policies A. About The Connecticut Light and Power Power Company The Connecticut Light and Power Company (CL&P or the company) along with the Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), Holyoke Water Power Company (HWP), and Yankee Energy System, Inc. (Yankee) are the operating companies comprising the Northeast Utilities system and are wholly owned by Northeast Utilities (NU). CL&P furnishes franchised retail electric service in Connecticut, while PSNH and WMECO furnish franchised retail electric service in New Hampshire and western Massachusetts. NAEC previously sold all of its entitlement to the capacity and output of the Seabrook Station nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). Seabrook was sold on November 1, 2002. NU's other subsidiaries include HWP, a company engaged in the production of electric power, Yankee, the parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's largest natural gas distribution system, and several competitive subsidiaries including Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc. CL&P is registered with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934. NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and NU, including CL&P, is subject to the provisions of the 1935 Act. Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC). Several wholly owned subsidiaries of NU provide support services for NU's companies, including CL&P, and in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to NU's companies. Until the sale of Seabrook on November 1, 2002, North Atlantic Energy Service Corporation had operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies. B. Presentation The consolidated financial statements of CL&P include the accounts of all subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. C. New Accounting Standards Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 is effective on January 1, 2003, for CL&P. Management has completed its review process for potential asset retirement obligations (AROs) and has not identified any material AROs which have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. A portion of CL&P's regulated rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2002, CL&P maintained approximately $154.5 million in cost of removal regulatory liabilities, which are included in its accumulated provision for depreciation. Guarantees: In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of Interpretation No. 45 are applicable to CL&P on a prospective basis to guarantees issued or modified after January 1, 2003. Currently, management does not expect the adoption of the initial recognition and initial measurement provisions of Interpretation No. 45 to have a material impact on CL&P's consolidated financial statements. Consolidation of Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." Interpretation No. 46 addresses the consolidation and disclosure requirements for companies that hold an equity interest in a variable interest entity (VIE), regardless of the date on which the VIE was created. Interpretation No. 46 requires consolidation of a VIE's assets, liabilities and noncontrolling interests at fair value when a company is the primary beneficiary, which is defined as a company that absorbs a majority of the expected losses, risks and revenues from the VIE as a result of holding a contractual or other financial interest in the VIE. Consolidation is not required under Interpretation No. 46 for those companies that hold a significant equity interest in a VIE but are not the primary beneficiary. Interpretation No. 46 is effective for CL&P beginning in the third quarter of 2003. At December 31, 2002, CL&P held equity interests in various VIEs, for which CL&P was not the primary beneficiary, as CL&P does not absorb a majority of the expected losses, risks and revenues from the VIEs or provide a substantial portion of financial support. As a result, management does not expect the adoption of Interpretation No. 46 to have a material impact on CL&P's consolidated financial statements. For further information regarding CL&P's investments in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric Utility Plant" to the consolidated financial statements. D. Equity Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P owns common stock in four regional nuclear companies (Yankee Companies). CL&P's ownership interests in the Yankee Companies at December 31, 2002 and 2001, which are accounted for on the equity method, are 34.5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 24.5 percent of the Yankee Atomic Electric Company (YAEC), 12 percent of the Maine Yankee Atomic Power Company (MYAPC), and 10.1 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). CL&P's total equity investment in the Yankee Companies and its exposure to loss as a result of these investments at December 31, 2002 and 2001, is $32.2 million and $34.7 million, respectively. These investments are VIE's under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee Company owns a single decommissioned nuclear generating plant. On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation for approximately $180 million. Seabrook: CL&P had a 4.06 percent joint ownership interest in Seabrook, a 1,148 megawatt nuclear generating unit. On November 1, 2002, CL&P consummated the sale of its ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). At December 31, 2001, plant-in-service and the accumulated provision for depreciation for CL&P's share of Seabrook totaled $174.7 million and $164.8 million, respectively. E. Depreciation The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable utility plant- in-service, which range primarily from 3 years to 50 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in- service from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric utility plant-in- service are equivalent to a composite rate of 3.2 percent in 2002 and 3.1 percent in 2001 and 3 percent in 2000. F. Revenues Revenues are based on rates approved by the DPUC. These regulated rates are applied to customer's accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DPUC. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates. G. Regulatory Accounting and Assets The accounting policies of CL&P conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." CL&P's transmission and distribution businesses continue to be cost-of- service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management also believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return, except for securitized regulatory assets. The components of CL&P's regulatory assets are as follows: --------------------------------------------------------------------- At December 31, --------------------------------------------------------------------- (Millions of Dollars) 2002 2001 --------------------------------------------------------------------- Recoverable nuclear costs $ 10.6 $ 158.1 Securitized regulatory assets 1,244.5 1,356.3 Income taxes, net 170.5 154.2 Unrecovered contractual obligations 116.8 2.1 Recoverable energy costs, net 49.3 80.1 Other 111.0 126.4 --------------------------------------------------------------------- Totals $1,702.7 $1,877.2 --------------------------------------------------------------------- In March 2001, CL&P sold its ownership interests in the Millstone units. The gain on this sale of approximately $521.6 million was used to offset recoverable nuclear costs, resulting in an unamortized balance of $6 million and $148.9 million at December 31, 2002 and 2001, respectively. Also included in recoverable nuclear costs is $4.6 million and $9.2 million at December 31, 2002 and 2001, respectively, associated with Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets. In March 2001, CL&P issued $1.4 billion in rate reduction certificates and used $1.1 billion of those proceeds to buyout or buydown certain contracts with independent power producers. The majority of the payments to buyout or buydown these contracts were recorded as securitized regulatory assets. CL&P also securitized a portion of its SFAS No. 109 regulatory asset. CL&P, under the terms of contracts with the Yankee Companies, is responsible for its proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations was securitized in 2001 and is included in securitized regulatory assets. During 2002, CL&P was notified by the Yankee Companies that the estimated cost of decommissioning their units had increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. In December 2002, CL&P recorded an additional $115.6 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs. CL&P, under the Energy Policy Act of 1992 (Energy Act), was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment) when they owned nuclear generating plants. The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P is currently recovering these costs through rates. At December 31, 2002 and 2001, CL&P's total D&D Assessment deferrals were $17.6 million and $21.1 million, respectively, and have been recorded as recoverable energy costs, net. Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. CL&P's energy costs deferred and not yet collected under the energy adjustment clause amounted to $31.7 million and $59 million at December 31, 2002 and 2001, respectively, which have been recorded as recoverable energy costs, net. On July 26, 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour (kWh) from August 2001 through December 2003 to collect these costs. H. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109, "Accounting for Income Taxes." The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: --------------------------------------------------------------------- At December 31, --------------------------------------------------------------------- (Millions of Dollars) 2002 2001 --------------------------------------------------------------------- Accelerated depreciation and other plant-related differences $239.6 $279.1 Regulatory assets: Nuclear stranded investment and other asset divestitures 213.5 276.1 Securitized contract termination costs and other 57.5 63.4 Income tax gross-up 134.4 134.4 Other 111.5 67.4 --------------------------------------------------------------------- Totals $756.5 $820.4 --------------------------------------------------------------------- I. Cash and Cash Equivalents Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. J. Other Income/(Loss), Net The pre-tax components of CL&P's other income/(loss), net items are as follows: --------------------------------------------------------------------- For the Years Ended December 31, --------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2000 --------------------------------------------------------------------- Seabrook-related gains $ 2.1 $ - $ - Gain related to Millstone sale - 29.5 - Nuclear related costs - - (14.1) Investment income 10.2 12.9 6.5 Other, net 9.8 10.4 (14.6) --------------------------------------------------------------------- Totals $22.1 $52.8 $(22.2) --------------------------------------------------------------------- 2. Short-Term Debt Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by the DPUC. Currently, SEC authorization allows CL&P to incur total short- term borrowings up to a maximum of $375 million. In addition, the charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At December 31, 2002, CL&P's charter permits CL&P to incur $480 million of additional unsecured debt. Credit Agreement: On November 12, 2002, CL&P, PSNH, WMECO, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaced a $350 million facility for CL&P, PSNH, WMECO and Yankee Gas, which expired on November 15, 2002 and CL&P may draw up to $150 million under the facility. Unless extended, the credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were no borrowings under these facilities. Under the aforementioned credit agreement, CL&P may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. This credit agreement provides that CL&P must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, consolidated debt ratios and interest coverage ratios. CL&P currently is and expects to remain in compliance with these covenants. Money Pool: CL&P is a member of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of NU and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2002 and 2001, CL&P had $1.9 million and $77.2 million of lendings to the Pool, respectively. The interest rate on lendings to the Pool at December 31, 2002 and 2001 was 1.2 percent and 1.5 percent, respectively. 3. Pension Benefits and Postretirement Benefits Other Than Pensions Pension Benefits: CL&P participates in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Pre-tax pension income, approximately 40 percent of which was credited to utility plant, was $50.6 million in 2002, $61.4 million in 2001, and $57.2 million in 2000. These amounts exclude pension settlements, curtailments and net special termination expenses of $8.1 million and $1.2 million in 2002 and 2001, respectively. There were no pension settlements, curtailments, or net special termination expenses recognized in 2000. Pension income attributable to earnings is as follows: -------------------------------------------------------------------------- For Years Ended December 31, -------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2000 -------------------------------------------------------------------------- Pension income before settlements, curtailments and special termination benefits $(50.6) $(61.4) $(57.2) Net pension income capitalized as utility plant (a) 20.2 24.6 22.9 -------------------------------------------------------------------------- Net pension income before settlements, curtailments and special termination benefits (30.4) (36.8) (34.3) Settlements, curtailments and special termnination benefits reflected in earnings - 3.3 - -------------------------------------------------------------------------- Total pension income included in earnings $(30.4) $(33.5) $(34.3) -------------------------------------------------------------------------- (a) Net pension income capitalized as utility plant was calculated utilizing an average of 40 percent. Effective February 1, 2002, certain CL&P employees who were displaced were eligible for a Voluntary Retirement Program (VRP). The VRP supplements NU's Plan and provides special provisions. Eligible employees include non- bargaining unit employees or employees belonging to a collective bargaining unit that has agreed to accept the VRP who are active participants in NU's Plan at January 1, 2002, and that have been displaced as part of the reorganization between January 22, 2002 and March 3, 2003. Eligible employees received a special retirement benefit under the VRP whose value was roughly equivalent to a multiple of base pay based on years of credited service. During 2002, CL&P recorded an expense of $8.1 million associated with special pension termination benefits related to the VRP. CL&P believes that the cost of the VRP is probable of recovery through regulated utility rates, and accordingly, the $8.1 million was recorded as a regulatory asset with no impact on 2002 earnings. In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, CL&P recorded $1.6 million in settlement income and $0.8 million in curtailment income in 2001. The VSP was intended to reduce the generation-related support staff between March 1, 2001 and February 28, 2002, and was available to non-bargaining unit employees who, by February 1, 2002, were at least age 50, with a minimum of five years of credited service, and at December 15, 2000, were assigned to certain groups and in eligible job classifications. One component of the VSP included special pension termination benefits equal to the greater of five years added to both age and credited service of eligible participants or two weeks of pay for each year of service subject to a minimum level of 12 weeks and a maximum of 52 weeks for eligible participants. The special pension termination benefits expense associated with the VSP totaled $3.6 million in 2001. The net total of the settlement and curtailment income and the special termination benefits expense was $1.2 million, of which $3.3 million of costs were included in operating expenses and $2.1 million was deferred as a regulatory liability and has been returned to customers. Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries, including CL&P, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from NU who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. CL&P annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. In 2001, CL&P recorded PBOP special termination benefits expense of $0.7 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through regulated utility rates in 2002. In 2002, the PBOP plan was amended to change the claims experience basis, to increase minimum retiree contributions and to reduce the cap on the company's subsidy to the dental plan. These amendments resulted in a $13.5 million decrease in CL&P's benefit obligation under the PBOP plan at December 31, 2002. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
------------------------------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2002 2001 ------------------------------------------------------------------------------------------------- Change in benefit obligation Benefit obligation at beginning of year $(626.0) $(587.3) $(165.7) $(136.3) Service cost (11.7) (10.0) (2.0) (1.9) Interest cost (44.8) (43.7) (13.4) (11.1) Plan amendment (4.5) - 13.5 - Transfers (2.2) (2.4) (20.4) - Actuarial loss (45.3) (24.9) (17.7) (32.2) Benefits paid - excluding lump sum payments 41.5 40.2 18.3 16.0 Benefits paid - lump sum payments 20.7 4.9 - - Curtailments and settlements - 0.8 - (0.2) Special termination benefits (8.1) (3.6) - - ------------------------------------------------------------------------------------------------- Benefit obligation at end of year $(680.4) $(626.0) $(187.4) $(165.7) ------------------------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year $ 910.4 $ 998.8 $ 55.7 $ 62.4 Actual return on plan assets (97.7) (45.7) (5.9) (5.8) Employer contribution - - 18.3 14.5 Benefits paid - excluding lump sum payments (41.5) (40.2) (18.3) (16.0) Benefits paid - lump sum payments (20.7) (4.9) - - Transfers 2.2 2.4 9.5 0.6 ------------------------------------------------------------------------------------------------- Fair value of plan assets at end of year $ 752.7 $ 910.4 $ 59.3 $ 55.7 ------------------------------------------------------------------------------------------------- Funded status at December 31 $ 72.3 $ 284.4 $(128.1) $(110.0) Unrecognized transition (asset)/obligation (1.8) (2.7) 62.7 80.3 Unrecognized prior service cost 29.1 27.6 (2.9) - Unrecognized net loss/(gain) 176.6 (75.6) 60.9 29.1 ------------------------------------------------------------------------------------------------- Prepaid/(accrued) benefit cost $ 276.2 $ 233.7 $ (7.4) $ (0.6) -------------------------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plans' year end funded status: ------------------------------------------------------------------------------- At December 31, ------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ------------------------------------------------------------------------------- 2002 2001 2002 2001 ------------------------------------------------------------------------------- Discount rate 6.75% 7.25% 6.75% 7.25% Compensation/progression rate 4.00% 4.25% 4.00% 4.25% Health care cost trend rate (a) N/A N/A 10.00% 11.00% ------------------------------------------------------------------------------- (a) The annual per capita cost of covered health care benefits was assumed to decrease to 5.00 percent by 2007. The components of net periodic benefit (income)/expense are as follows:
--------------------------------------------------------------------------------------------------- For the Years Ended December 31, --------------------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits --------------------------------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2000 2002 2001 2000 --------------------------------------------------------------------------------------------------- Service cost $ 11.7 $ 10.0 $ 9.7 $ 2.0 $ 1.9 $ 1.9 Interest cost 44.8 43.7 42.3 13.4 11.1 10.1 Expected return on plan assets (94.2) (95.3) (88.4) (6.3) (5.5) (4.9) Amortization of unrecognized net transition (asset)/obligation (0.9) (0.9) (0.9) 6.9 7.3 7.3 Amortization of prior service cost 3.0 2.6 2.7 - - - Amortization of actuarial gain (15.0) (21.5) (22.6) - - - Other amortization, net - - - 2.0 (0.5) (1.9) --------------------------------------------------------------------------------------------------- Net periodic (income)/expense - before settlements, curtailments and special termination benefits (50.6) (61.4) (57.2) 18.0 14.3 12.5 --------------------------------------------------------------------------------------------------- Settlement income - (1.6) - - - - Curtailment income - (0.8) - - - - Special termination benefits expense 8.1 3.6 - - 0.7 - --------------------------------------------------------------------------------------------------- Total - settlements, curtailments and special termination benefits 8.1 1.2 - - 0.7 - --------------------------------------------------------------------------------------------------- Total - net periodic (income)/expense $(42.5) $(60.2) $(57.2) $18.0 $15.0 $12.5 ---------------------------------------------------------------------------------------------------
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
----------------------------------------------------------------------------------------- For the Years Ended December 31, ----------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ----------------------------------------------------------------------------------------- 2002 2001 2000 2002 2001 2000 ----------------------------------------------------------------------------------------- Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75% Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75% Long-term rate of return - Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50% Life assets N/A N/A N/A 9.25% 9.50% 9.50% -----------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: -------------------------------------------------------------------------- One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease -------------------------------------------------------------------------- Effect on total service and interest cost components $0.4 $(0.4) Effect on postretirement benefit obligation $5.7 $(5.1) -------------------------------------------------------------------------- Currently, CL&P's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. The trust holding the postretirement benefit health plan assets is subject to federal income taxes. 4. Sale of Customer Receivables At December 31, 2002, CL&P had sold accounts receivable of $40 million to a subsidiary of Citigroup, Inc. with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at December 31, 2002, $3.8 million of assets were designated as collateral and restricted under the agreement with the CRC and included in the consolidated balance sheets as cash and cash equivalents. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At December 31, 2002, amounts sold to CRC from CL&P, but not sold to the Citgroup, Inc. subsidiary, totaling $178.9 million are included in investments in securitizable assets on the consolidated balance sheets. No amounts were sold in 2001. 5. Nuclear Generation Asset Divestitures Seabrook: On November 1, 2002, CL&P consummated the sale of its 4.06 percent ownership interest in Seabrook to a subsidiary of FPL. CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. CL&P received approximately $36 million of total cash proceeds from the sale of Seabrook. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. In connection with the sale, CL&P recorded a gain in the amount of approximately $16 million, which was primarily used to offset stranded costs. In the third quarter of 2002, CL&P received regulatory approvals for the sale of Seabrook from the DPUC. As a result of these approvals, CL&P eliminated $0.6 million, on a pre-tax basis, of reserves related to its ownership shares of certain Seabrook assets. VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. Under the terms of the sale, CL&P will continue to buy 9.5 percent of the plant's output through March 2012 at a range of fixed prices. Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc. (Dominion). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to Dominion along with all of the unaffiliated joint ownership interests in Millstone 3. CL&P received approximately $828 million of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity. As part of the sale, Dominion assumed responsibility for decommissioning the three Millstone units. In connection with the sale, CL&P recorded a gain in the amount of $521.6 million, which was used to offset stranded costs. 6. Commitments and Contingencies A. Restructuring and Rate Matters On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units to a subsidiary of Dominion. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. The DPUC's final decision regarding this application was received on February 27, 2003, and did not have a material impact on NU's 2002 results of operations. B. Environmental Matters CL&P is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. As such, CL&P has active environmental auditing and training programs and believes it is substantially in compliance with the current laws and regulations. However, the normal course of operations may involve activities and substances that expose CL&P to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on CL&P's consolidated financial statements. Based upon currently available information for the estimated remediation costs at December 31, 2002 and 2001, the liability recorded by CL&P for its estimated environmental remediation costs amounted to $7.3 million and $2.5 million, respectively. C. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2002 and 2001, fees due to the DOE for the disposal of Prior Period Fuel were $205.5 million and $201.9 million, respectively, including interest costs of $138.9 million and $135.4 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and paid to the DOE on a quarterly basis. At December 31, 2002, as CL&P's ownership shares of Millstone and Seabrook have been sold, CL&P is no longer responsible for fees relating to current fuel burned at these facilities. D. Nuclear Insurance Contingencies In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, NU and CL&P terminated their nuclear insurance related to these plants, and CL&P has no further exposure for potential assessments related to Millstone and Seabrook. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and CYAPC and VYNPC, NU is subject to potential retrospective assessments totaling $0.8 million under its respective NEIL insurance policies. E. Long-Term Contractual Arrangements VYNPC: Previously, under the terms of its agreements, CL&P paid its ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million. Under the terms of the sale, CL&P will continue to buy 9.5 percent of the plant's output through March 2012 at a range of fixed prices. CL&P's cost of purchases under contracts with VYNPC amounted to $16.4 million in 2002, $14.7 million in 2001, and $14.5 million in 2000. Electricity Procurement Contracts: CL&P has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $154.6 million in 2002, $205 million in 2001, and $308.6 million in 2000. These amounts are for independent power producer contracts and do not include contractual commitments related to CL&P's standard offer. Hydro-Quebec: Along with other New England utilities, CL&P has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities. Estimated Future Annual Costs: The estimated future annual costs of CL&P's significant long-term contractual arrangements are as follows: ------------------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 ------------------------------------------------------------------------------- VYNPC $ 18.3 $ 17.4 $ 16.1 $ 16.8 $ 16.3 Electricity Procurement Contracts 197.0 200.0 203.4 206.9 211.7 Hydro-Quebec 15.0 14.5 14.2 13.0 12.4 ------------------------------------------------------------------------------- Totals $230.3 $231.9 $233.7 $236.7 $240.4 ------------------------------------------------------------------------------- F. Nuclear Decommissioning and Plant Closure Costs In conjunction with the Millstone, Seabrook and VYNPC nuclear generation asset divestitures, the applicable liabilities and nuclear decommissioning trusts were transferred to the purchasers and the purchasers agreed to assume responsibility for decommissioning their respective units. During 2002, NU, along with the other joint owners, were notified by the Yankee Companies that the estimated cost of decommissioning the units owned by CYAPC, YAEC and MYAPC increased in total by approximately $380 million over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. CL&P's share of this increase would total $115.6 million. Following rate cases to be filed by the Yankee Companies with the FERC, NU will seek recovery of the higher decommissioning costs from retail customers through the appropriate state regulatory agency. At December 31, 2002 and 2001, CL&P's remaining estimated obligations, for decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down, were $234.5 million and $141.5 million, respectively. 7. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and Cash Equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents. Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows: -------------------------------------------------------------------------- At December 31, 2002 -------------------------------------------------------------------------- (Millions of Dollars) Carrying Amount Fair Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption $ 116.2 $ 84.0 Long-term debt - First mortgage bonds 198.8 242.0 Other long-term debt 629.3 643.0 Rate reduction bonds 1,245.7 1,356.1 -------------------------------------------------------------------------- -------------------------------------------------------------------------- At December 31, 2001 -------------------------------------------------------------------------- (Millions of Dollars) Carrying Amount Fair Value -------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption $ 116.2 $ 62.4 Long-term debt - First mortgage bonds 198.8 212.8 Other long-term debt 625.8 615.1 Rate reduction bonds 1,358.7 1,388.3 -------------------------------------------------------------------------- Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value. 8. Leases CL&P has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $3 million in 2002, $9.2 million in 2001, and $36.3 million in 2000. Interest included in capital lease rental payments was $2 million in 2002, $3.4 million in 2001, and $7.9 million in 2000. Operating lease rental payments charged to expense were $6.9 million in 2002, $7.1 million in 2001, and $9.8 million in 2000. Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2002 are as follows: -------------------------------------------------------------------------- (Millions of Dollars) Capital Operating Year Leases Leases -------------------------------------------------------------------------- 2003 $ 2.6 $12.0 2004 2.5 11.0 2005 2.4 10.2 2006 2.4 9.1 2007 2.4 6.1 After 2007 22.2 15.2 -------------------------------------------------------------------------- Future minimum lease payments $34.5 $63.6 Less amount representing interest 19.0 -------------------------------------------------------------------------- Present value of future minimum lease payments $15.5 -------------------------------------------------------------------------- 9. Accumulated Other Comprehensive Income/(Loss) The accumulated balance for each other comprehensive income/(loss) item is as follows: -------------------------------------------------------------------------- Current December 31, Period December 31, (Millions of Dollars 2001 Change 2002 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $ 0.4 $(0.5) $(0.1) Minimum pension liability adjustments (0.3) - (0.3) -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $ 0.1 $(0.5) $(0.4) -------------------------------------------------------------------------- -------------------------------------------------------------------------- Current December 31, Period December 31, (Millions of Dollars 2000 Change 2001 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $ 0.8 $(0.4) $ 0.4 Minimum pension liability adjustments (0.3) - (0.3) -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $ 0.5 $(0.4) $ 0.1 -------------------------------------------------------------------------- The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects: -------------------------------------------------------------------------- (Millions of Dollars 2002 2001 2000 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $0.3 $0.3 $(0.1) Minimum pension liability adjustments - - - -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $0.3 $0.3 $(0.1) -------------------------------------------------------------------------- 10. Preferred Stock Not Subject to Mandatory Redemption Details of preferred stock not subject to mandatory redemption are as follows: ------------------------------------------------------------------------------ Shares December 31, Outstanding 2002 at December 31, Redemption December 31, ------------ Description Price 2002 2002 2001 ------------------------------------------------------------------------------ (Millions of Dollars) $1.90 Series of 1947 $52.50 163,912 $ 8.2 $ 8.2 $2.00 Series of 1947 54.00 336,088 16.8 16.8 $2.04 Series of 1949 52.00 100,000 5.0 5.0 $2.20 Series of 1949 52.50 200,000 10.0 10.0 3.90% Series of 1949 50.50 160,000 8.0 8.0 $2.06 Series E of 1954 51.00 200,000 10.0 10.0 $2.09 Series F of 1955 51.00 100,000 5.0 5.0 4.50% Series of 1956 50.75 104,000 5.2 5.2 4.96% Series of 1958 50.50 100,000 5.0 5.0 4.50% Series of 1963 50.50 160,000 8.0 8.0 5.28% Series of 1967 51.43 200,000 10.0 10.0 $3.24 Series G of 1968 51.84 300,000 15.0 15.0 6.56% Series of 1968 51.44 200,000 10.0 10.0 ------------------------------------------------------------------------------- Totals $116.2 $116.2 ------------------------------------------------------------------------------- 11. Long-Term Debt Details of long-term debt outstanding are as follows: ------------------------------------------------------------------------------- At December 31, 2002 2001 ------------------------------------------------------------------------------- (Millions of Dollars) First Mortgage Bonds: 8 1/2% Series C due 2024 $ 59.0 $ 59.0 7 7/8% Series D due 2024 139.8 139.8 ------ ------ 198.8 198.8 Pollution Control Notes: Fixed rate, due 2016-2022 46.4 46.4 Fixed rate, tax exempt, due 2028 315.5 315.5 Variable rate, tax exempt, due 2031 62.0 62.0 Fees and interest due for spent nuclear fuel disposal costs 205.5 201.9 ------ ------ 629.4 625.8 Less amounts due within one year - - Unamortized premium and discount, net (0.3) (0.3) ------------------------------------------------------------------------------- Long-term debt $827.9 $824.3 ------------------------------------------------------------------------------- Essentially, all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture. CL&P has secured $315.5 million of pollution control notes secured by second mortgage liens on transmission assets, junior to the liens of their first mortgage bond indentures. CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance secured by the first mortgage bonds and a liquidity facility. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless CL&P failed to meet its obligations under the PCRBs. The average effective interest rates on the variable-rate pollution control notes ranged from 1.2 percent to 1.7 percent for 2002 and from 1.3 percent to 3.6 percent for 2001. 12. Income Tax Expense The components of the federal and state income tax provisions were charged/(credited) to operations as follows: ------------------------------------------------------------------------------- For the Years Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------- (Millions of Dollars) Current income taxes: Federal $114.4 $190.7 $ 77.2 State 24.3 38.8 17.2 ------ ------ ------ Total current 138.7 229.5 94.4 ------ ------ ------ Deferred income taxes, net: Federal (53.3) (117.0) 10.6 State (15.2) (23.8) 2.4 ------ ------ ------ Total deferred (68.5) (140.8) 13.0 ------ ------ ------ Investment tax credits, net (3.3) (3.8) (7.3) ------------------------------------------------------------------------------- Total income tax expense $ 66.9 $ 84.9 $100.1 ------------------------------------------------------------------------------- Deferred income taxes are comprised of the tax effects of temporary differences as follows: ------------------------------------------------------------------------------- For the Years Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------- (Millions of Dollars Depreciation, leased nuclear fuel, settlement credits and disposal costs $ 34.4 $ (9.2) $ 13.8 Regulatory deferral (68.3) (33.1) (14.1) State net operating loss carryforward - - - Regulatory disallowance 0.3 - - Sale of generation assets (18.4) (197.6) - Pension (deferral)/accrual (6.3) 19.9 13.6 Securitized contract termination costs and other (5.9) 63.4 - Other (4.3) 15.8 (0.3) ------------------------------------------------------------------------------- Deferred income taxes, net $(68.5) $(140.8) $ 13.0 ------------------------------------------------------------------------------- A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows: ------------------------------------------------------------------------------- For the Years Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------- (Millions of Dollars Expected federal income tax $53.4 $68.1 $ 86.9 Tax effect of differences: Depreciation 3.8 4.0 5.8 Amortization of regulatory assets 13.7 (0.6) 3.6 Investment tax credit amortization (3.3) (3.8) (7.3) State income taxes, net of federal benefit 5.9 9.8 12.7 Other, net (6.6) 7.4 (1.6) ------------------------------------------------------------------------------- Total income tax expense $66.9 $84.9 $100.1 ------------------------------------------------------------------------------- 13. Segment Information NU is organized between regulated utilities (electric and gas since the March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries. CL&P is included in the regulated utilities segment of NU and has no other reportable segments.
-------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data -------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2002 2001 2000 1999 1998 -------------------------------------------------------------------------------------------------------- Operating Revenues $2,507,036 $2,646,123 $2,935,922 $2,452,855 $2,386,864 Net Income/(Loss) 85,612 109,803 148,135 (13,568) (195,725) Cash Dividends on Common Stock 60,145 60,072 72,014 - - Total Assets 4,632,083 4,727,727 4,764,198 5,298,284 6,050,198 Rate Reduction Bonds 1,245,728 1,358,653 - - - Long-Term Debt (a) 827,866 824,349 1,232,688 1,400,056 2,007,957 Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 116,200 116,200 116,200 Preferred Stock Subject to Mandatory Redemption (a) - - - 99,539 119,289 Obligations Under Capital Leases (a) 15,499 16,040 129,869 144,400 162,884 --------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------- Consolidated Quarterly Financial Data (Unaudited) ------------------------------------------------------------------------------- (Thousands of Dollars) Quarter Ended ------------------------------------------------------------------------------- 2002 March 31 June 30 September 30 December 31 ------------------------------------------------------------------------------- Operating Revenues $604,420 $581,731 $687,938 $632,947 Operating Income $ 64,111 $ 45,528 $ 72,946 $ 68,743 Net Income $ 21,684 $ 11,407 $ 29,297 $ 23,224 ------------------------------------------------------------------------------- 2001 ------------------------------------------------------------------------------- Operating Revenues $733,905 $610,275 $675,578 $626,365 Operating Income $ 65,096 $ 68,114 $ 63,103 $ 66,716 Net Income $ 38,300 $ 18,812 $ 18,824 $ 33,867 ------------------------------------------------------------------------------- (a) Includes portions due within one year. ------------------------------------------------------------------------------- Consolidated Statistics (Unaudited) ------------------------------------------------------------------------------- Gross Electric Utility Plant Average Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (a) (Millions) Customer (kWh) (Average) December 31, ------------------------------------------------------------------------------- 2002 $3,292,685 29,623 9,244 1,158,307 2,130 2001 3,265,811 32,645 8,884 1,153,234 2,160 2000 5,964,605 42,120 8,976 1,121,551 2,057 1999 6,007,421 29,235 8,969 1,120,846 2,377 1998 6,345,215 27,300 8,476 1,111,370 2,379 (a) Amount includes construction work in progress.