EX-13.1 34 nuannualreport2002.txt EXHIBIT 13.1 ANNUAL REPORT OF NORTHEAST UTILITIES MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION -------------------------------------------------------------------------------- OVERVIEW Northeast Utilities and subsidiaries (NU or the company) reported 2001 earnings of $243.5 million, or $1.79 per share on a fully diluted basis, compared with a loss of $28.6 million, or $0.20 per share on a fully diluted basis in 2000 and earnings of $34.2 million, or $0.26 per share on a fully diluted basis in 1999. In 2001 and 2000, NU's results were affected significantly by nonrecurring items. In 2001, NU recorded an after-tax gain of $115.6 million, or $0.85 per share, in connection with the sale of the Millstone nuclear units to a subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc. (DNCI). In 2001, NU also recorded an after-tax nonrecurring loss of $22.4 million, or $0.17 per share, as a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and an after-tax mark-to- market loss of $35.4 million, or $0.26 per share, associated with the repurchase of NU shares in the first half of 2001. In 2000, NU recorded an extraordinary after-tax loss of $233.9 million, or $1.65 per share, primarily associated with electric utility industry restructuring in New Hampshire. Excluding the effect of these nonrecurring items, NU earned $185.7 million, or $1.37 per share on a fully diluted basis, in 2001, compared with $205.3 million, or $1.45 per share on a fully diluted basis, in 2000. The decline in operating results at NU's regulated companies was due to a number of factors. Earnings at both The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO) decreased primarily because the sale of Millstone three months into 2001 removed a significant source of earnings as compared with 2000. Earnings before preferred dividends at CL&P totaled $109.8 million in 2001, compared with $148.1 million in 2000 and a loss of $13.6 million in 1999. Earnings before preferred dividends at WMECO totaled $15 million in 2001, compared with $35.3 million in 2000 and $2.9 million in 1999. In addition to the sale of Millstone, CL&P's lower earnings also reflect a $21.1 million reduction in distribution and transmission rates the Connecticut Department of Public Utility Control (DPUC) imposed, which was effective on June 20, 2001. Operating results at Public Service Company of New Hampshire (PSNH) and North Atlantic Energy Corporation (NAEC) declined as a result of the implementation of industry restructuring and an 11 percent reduction in retail rates on May 1, 2001. Earnings before preferred dividends at PSNH totaled $81.8 million in 2001, compared with a loss of $146.7 million in 2000 and earnings of $84.2 million in 1999. The PSNH results included an after-tax gain of $15.5 million associated with the Millstone sale in 2001 and an after-tax $214.2 million extraordinary charge associated with electric industry restructuring in 2000. Earnings at NAEC totaled $4.2 million in 2001, compared with $32.5 million in 2000 and $29.6 million in 1999. The lower results at NAEC reflect a reduction in payments made by PSNH to NAEC due to a buydown of the Seabrook Power Contracts with the proceeds from the sale of rate reduction bonds. Management expects combined operating results at PSNH and NAEC to continue to decline in 2002, reflecting the effects of a full year of electric utility industry restructuring. Results at NU's competitive energy subsidiaries also declined in 2001. The competitive energy subsidiaries earned $5 million on revenues of $3 billion in 2001, compared with a contribution towards NU's consolidated earnings of $13.6 million on revenues of $1.9 billion in 2000 and a loss of $37 million on revenues of $0.6 billion in 1999, excluding nonrecurring items. The decline was primarily due to higher purchased power costs in the winter of 2001 and lower than expected summer and fall customer loads due to mild weather conditions. Partially offsetting those declines in operating results was a significant increase in earnings at Yankee Energy System, Inc. (Yankee), which NU acquired on March 1, 2000. Yankee earned $25.8 million in 2001, compared with a loss of $0.7 million during the 10 months of 2000 it was part of the Northeast Utilities system (NU system). The improved results were primarily due to the inclusion of January 2001 and February 2001 results in 2001 earnings and the settlement of property tax litigation with the City of Meriden, Connecticut. NU's earnings per share (EPS) benefited from the repurchase of approximately 14.3 million NU common shares in 2001. NU's outstanding share count totaled 130.1 million shares on December 31, 2001, compared with 143.8 million shares outstanding on December 31, 2000. FUTURE OUTLOOK NU estimates that its EPS will range between $1.40 per share and $1.65 per share in 2002, excluding significant nonrecurring items. NU expects that no retail rate cases will be filed in 2002. The company therefore expects the financial performance of its regulated businesses to be relatively stable and predictable in 2002, absent significant adverse events, such as a catastrophic storm. Also affecting the 2002 earnings range is the income associated with NU's qualified pension plan. In 2001, NU's operating results included pretax pension income of approximately $101 million associated with this plan, excluding the effects of the Voluntary Separation Program. NU currently expects pretax pension income in 2002 to be reduced to approximately $73 million. Pension income is annually adjusted during the second quarter based upon updated actuarial evaluations, and the 2002 estimate may be modified at that time. Additionally, a prime determinant of where NU performs within the aforementioned 2002 earnings range is the performance of the company's competitive energy subsidiaries. NU expects revenues from its competitive energy subsidiaries to exceed $3.8 billion in 2002. Much of that increase over 2001 is the result of Select Energy, Inc.'s (Select Energy) acquisition of Niagara Mohawk Energy Marketing, Inc. (NMEM) in late November 2001 for approximately $31.7 million. That business was subsequently renamed Select Energy New York, Inc. (SENY). In 2001, Select Energy's profits from its wholesale electric sales were reduced by its obligation to serve 50 percent of CL&P's standard offer service load at below market rates. Select Energy's obligation to serve that load, continues through 2003. Select Energy's results would benefit from an increase in the pricing for CL&P's standard offer service load. A proceeding to begin this process was filed with the DPUC in 2001, and management is pursuing raising those prices in 2002 and 2003. Select Energy's profits also will depend on its ability to renew and expand its wholesale business in its 12-state Northeastern market area, as well as to continue to grow its retail natural gas and electric businesses. CONSOLIDATED EDISON, INC. MERGER LITIGATION On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' October 13, 1999, Agreement and Plan of Merger, as amended and restated as of January 11, 2000, (Merger Agreement). That same day, NU notified Con Edison that it would treat Con Edison's refusal to proceed with the merger as a repudiation and breach of the Merger Agreement, and would file suit to obtain the benefits of the transaction for NU shareholders. On March 6, 2001, Con Edison filed suit in the United States District Court for the Southern District of New York (District Court) seeking a declaratory judgment that it had been relieved of its obligation to proceed with the merger due to, among other things, NU's alleged breach of the Merger Agreement and the alleged occurrence of a "Material Adverse Change" with respect to NU as that term is defined in the Merger Agreement. Con Edison also contends that it is entitled to recover damages from NU equal to the benefits it would have received if the merger had been consummated together with the costs incurred in preparing for and seeking approval of the merger. NU believes that Con Edison's claim for damages is without merit and, in any event, that Con Edison's proposed measure of damages is inappropriate. On March 12, 2001, NU filed suit against Con Edison in the District Court seeking damages in excess of $1 billion arising from Con Edison's breach of the Merger Agreement. On May 11, 2001, in accordance with a stipulation of the parties and order of the District Court, Con Edison filed an amended complaint in which it added claims seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. On June 1, 2001, NU answered Con Edison's amended complaint, denying all of its material allegations and asserting affirmative defenses, and asserted a counterclaim seeking damages in excess of $1 billion against Con Edison for breach of the Merger Agreement. NU subsequently dismissed its March 12, 2001, complaint as duplicative of the June 1, 2001, counterclaim. On June 8, 2001, Con Edison answered NU's counterclaim, denying its material allegations and asserting affirmative defenses. The parties substantially completed fact discovery in the litigation on December 21, 2001, and are currently conducting expert discovery. The case schedule currently calls for the parties to be prepared for trial on or after June 21, 2002; however no trial date has yet been set by the court. In addition, separate petitions were filed with the DPUC asking that its merger approval be rescinded or reversed. The DPUC reopened its docket approving the merger and asked parties to comment on the question of whether a date certain should be imposed for consummation of the merger and whether that date should be January 31, 2002. On January 30, 2002, the DPUC issued a decision establishing January 31, 2002, as the deadline for merger consummation. As a result, the DPUC's prior approval of the merger is no longer effective. At this early stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU. LIQUIDITY The year 2001 was marked by tremendous inflows of cash into the NU system as a result of the securitization of stranded costs and the sale of the Millstone units. During a seven-week period between March 30, 2001, and May 17, 2001, NU's subsidiaries' liquidity benefited from the issuance of $2.1 billion in rate reduction bonds and certificates and the receipt of the $1.2 billion from the sale of the Millstone units. The largest share of those proceeds was used for the repayment of debt and preferred securities. As a result, NU's combined short-term and long-term debt other than rate reduction bonds decreased to approximately $2.6 billion at the end of 2001 from approximately $3.7 billion at the end of 2000. Capital lease obligations declined to $17.5 million at the end of 2001 from $159.9 million at the end of 2000. In 2001, CL&P also repaid $100 million of Monthly Income Preferred Securities and reduced the amount outstanding under its accounts receivable facility by $170 million. WMECO and PSNH repaid all of their preferred stock, leaving CL&P's $116.2 million of preferred stock not subject to mandatory redemption as the only preferred securities in the NU system. Of the $2.1 billion of rate reduction bonds and certificates issued by CL&P, PSNH and WMECO, approximately $1.2 billion was used to buyout or buydown high-cost, long-term purchased-power contracts. PSNH paid approximately another $50 million in December 2001 to buyout other purchased-power contracts and issued an equivalent amount of rate reduction bonds in January 2002, to pay for those costs. PSNH continues to negotiate buyout or buydown arrangements with other plant operators and may require additional funds if successfully renegotiated agreements are approved by the New Hampshire Public Utilities Commission (NHPUC) and result in upfront payments. The remaining proceeds from the Millstone sale were used primarily to pay state and federal income taxes on the Millstone sale and return equity capital to NU parent from the regulated electric companies. Including both return of capital and common dividends, CL&P, PSNH, WMECO, and NAEC paid $60.1 million, $287 million, $37 million, and $136 million, respectively, to NU parent in 2001. Yankee paid no dividends to NU parent in 2001, as NU parent used Yankee earnings and the receipt of approximately $20 million from the sale of interests in certain electric generating facilities owned by Yankee subsidiaries to repay debt and fund Yankee's expanded capital expenditure program. NU parent used the dividends and return of capital primarily to repurchase approximately 14.3 million NU common shares in 2001 of which approximately 10.3 million shares were repurchased in the second quarter of 2001. In July 2001, the NU Board of Trustees authorized the repurchase of 15 million additional NU common shares by July 2003. Under this authorization, NU repurchased approximately 4 million shares by the end of the year and has authorization to repurchase approximately another 11 million shares. In addition to repurchasing shares, NU spent another $31.7 million through Select Energy to acquire NMEM and through its subsidiary Mode 1 Communications, Inc. (Mode 1) lent $15 million to NEON Communications, Inc. (NEON) in the form of subordinated convertible notes. On December 6, 2001, NEON announced that it had retained an unaffiliated financial institution to explore, among other options, debt restructuring. On January 22, 2002, NEON announced it was seeking a waiver from one of its significant unaffiliated suppliers on a $7.3 million payment that had been due on December 31, 2001. If that supplier accelerates payment on its $42 million note from NEON, the action would trigger a cross-default on $180 million of senior notes previously issued by NEON. If NEON were to restructure its debt obligations or declare bankruptcy, NU management believes that some or all of its debt and equity investment in NEON would be impaired. In addition to the $15 million of subordinated convertible notes, Mode 1 owns approximately 4 million shares of NEON common stock. This equity investment had a book value of $4.6 million, and a fair value of $11.2 million at December 31, 2001. Subsequent to December 31, 2001, the market value of NEON stock has decreased significantly. NU continues to pursue additional investments in both the regulated and unregulated energy businesses in the Northeast United States or other strategic initiatives from time to time and will weigh making those investments against continued share repurchases. Aside from the issuance of rate reduction bonds and certificates, the NU system undertook a number of refinancings in 2001. On February 28, 2001, NU issued $263 million of variable-rate unsecured notes to repay an equal amount of bank debt incurred a year earlier when NU acquired Yankee. On October 18, 2001, Northeast Generation Company (NGC) issued $440 million of amortizing senior secured debt. The $440 million includes $120 million of bonds that mature on October 15, 2005, at an interest rate of 4.998 percent, and $320 million of bonds that mature on October 15, 2026, at an interest rate of 8.812 percent. Proceeds from the issuance plus cash on hand were used to return $75 million to NU parent through a combination of capital and common dividends and to repay bank borrowings NGC had incurred to acquire 1,289 megawatts (MW) of predominantly hydroelectric generation assets in early 2000. On December 19, 2001, PSNH refinanced $287.5 million of tax-exempt pollution control revenue bonds (PCRBs) by issuing $109 million of insured lower fixed-rate bonds and $178.5 million of insured variable-rate bonds. At current rates, that refinancing is expected to save PSNH in excess of $10 million annually. Also, in late 2001, Holyoke Water Power Company (HWP) repaid all of its public debt in connection with the sale of its hydroelectric generation assets and electric distribution system to the City of Holyoke for $17.5 million. Primarily as a result of the Millstone sale and the issuance of rate reduction bonds and certificates, NU's consolidated capitalization ratio was significantly stronger at the end of 2001 than it was a year earlier. Including capital lease obligations, but excluding rate reduction bonds as these bonds are nonrecourse to the NU system, NU's capitalization ratio was 54.3 percent debt, 2.4 percent preferred securities and 43.3 percent common equity at the end of 2001, compared with 60.4 percent debt, 4.4 percent preferred securities and 35.2 percent common equity at the end of 2000. The improved capitalization ratio and lowered overall risk profile resulted in a series of upgrades of the NU system securities through 2001. At the end of 2001, senior debt ratings on NU parent securities were Baa1 and BBB, A2 and A- for CL&P, A3 and BBB+ for WMECO, and A3, BBB+, and BBB for PSNH. Overall, those ratings were the highest for NU securities in decades and are expected to continue to enhance the NU system's access to low-cost capital. NU's net cash flows provided by operating activities declined to $376.7 million in 2001, compared with $578.4 million in 2000 and $614.2 million in 1999. In 2001, cash flows provided by operating activities, decreased primarily due to an increase in receivables and unbilled revenues, net, associated with the sales growth at NU's competitive energy subsidiaries. The level of common dividends totaled $60.9 million in 2001, as compared to $57.4 million in 2000 and $13.2 million in 1999. This increase was a result of NU paying a $0.10 per share quarterly common dividend in the first two quarters of 2001 and a $0.125 per share quarterly common dividend in the last two quarters of 2001, as compared to paying a $0.10 per share quarterly common dividend for all of 2000. The level of preferred dividends decreased to $7.3 million in 2001, compared with $14.2 million in 2000 and $22.8 million in 1999, reflecting NU's ongoing effort to reduce preferred stock outstanding. The NU system companies currently forecast construction expenditures of up to $593 million for the year 2002. On September 28, 2001, NU paid a quarterly dividend of $0.125 per share, an increase of 25 percent from a quarterly dividend of $0.10 per share declared since the fourth quarter of 1999. Similar dividends were declared for payment on December 31, 2001, and were declared in January 2002 for payment on March 29, 2002. NU anticipates increasing its dividend by approximately 10 percent annually and eventually paying out approximately 50 percent of the aggregate earnings of its regulated companies in the form of common dividends. Such a program will be dependent upon numerous factors, including NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time. Over the coming years, management expects WMECO and NAEC to pay out substantially all of their earnings as dividends to the parent company. PSNH is expected to pay out most of its earnings in the form of dividends to the parent company. There may also be an additional dividend to NU near the end of 2002, depending on the amount of cash received as a result of the sale of Seabrook. NGC also is expected to pay annual dividends to NU as allowed by the bond covenants contained in NGC's 2001 bond indenture. Yankee Gas Services Company (Yankee Gas) is expected to reinvest its earnings in its distribution expansion program. NU is expected to make an additional equity contribution to Yankee Gas in 2002 to help fund its expansion program. CL&P's dividend policy will depend largely on its earnings and the timing and scope of its expected increasing investment in its distribution and transmission system. In 2002, both CL&P and WMECO may make additional dividend payments to NU to help achieve their target leverage ratios of approximately 55 percent, excluding rate reduction bonds. As of December 31, 2001, CL&P's capitalization included total debt of approximately 48 percent and WMECO's capitalization included total debt of approximately 52 percent, in each case excluding rate reduction bonds. The NU system has $50.5 million of sinking fund obligations due in 2002, primarily at NU parent and NGC. Management expects to meet those obligations through operating cash flows. Additionally, NU plans to refinance a $263 million variable-rate note with a fixed-rate note in April 2002, to take advantage of current interest rates. NU also expects to meet its capital expenditure and common dividend obligations in 2002 primarily through operating cash flows, while maintaining excess funds for further common share repurchases. Beyond 2001, management expects that Yankee Gas will likely need to issue additional long-term debt to fund its capital investment program, even without paying any common dividends to NU. CL&P also may need to issue long-term debt if its currently planned transmission construction program is approved by regulators. Current debt levels at WMECO are expected to remain stable in future years and the level at PSNH may decline, contingent upon the results of the sale of NAEC's share of Seabrook. The NU system could need additional sources of capital to fund expansion of its competitive energy subsidiaries in future years, but management cannot currently estimate that amount. COMPETITIVE ENERGY SUBSIDIARIES NU's competitive energy subsidiaries grew significantly in 2001 with revenues of $3 billion, compared with revenues of $1.9 billion in 2000. Earnings, however, declined to $5 million before the cumulative effect of an accounting change in 2001, as compared to a contribution toward NU's consolidated earnings of $13.6 million before an extraordinary charge in 2000. NU's competitive energy subsidiaries own and manage 1,436 MW of generation capacity, including 1,289 MW at NGC and 147 MW at HWP. These businesses also include wholesale and retail energy marketing organizations and an expanding trading business. The energy marketing organizations also buy and sell natural gas and other fuels. The competitive energy subsidiaries also include Select Energy Services, Inc. (SES) (formerly HEC Inc.), which performs energy management services for large industrial, commercial and institutional facilities, including the United States Department of Defense, and Northeast Generation Services Company (NGS), which operates and maintains NGC's and HWP's generation assets and provides third-party contracting services for power plants and large industrial facilities. NU operates its competitive energy subsidiaries as a combined entity. However, in connection with the initial financing of NGC and its issuance of nonrecourse debt, Select Energy has an above-market contract to purchase energy and related products from NGC. Select Energy's performance under that contract is guaranteed by NU. Select Energy has another contract to acquire power from HWP's 147 megawatt coal-fired Mount Tom generating unit in Holyoke, Massachusetts. Primarily as a result of the favorable terms to NGC and HWP in those contracts, NGC earned $42.3 million on revenues of $129.7 million in 2001 and HWP earned $4.4 million on revenues of $55.2 million in 2001. Both of NU's primary energy services businesses also were profitable in 2001 with NGS earning $4.6 million on revenues of $112 million and SES earning $2.4 million on revenues of $102 million. Select Energy's marketing and trading business combines the output and capacity from NGC and HWP with other generation and provides wholesale and retail electric service throughout the Northeast United States. In addition to electricity, Select Energy sells natural gas and other fuels on a wholesale and retail basis. NU's investment in Select Energy grew in 2001 due in large part to the acquisition of NMEM, and the need to post additional working capital as a result of a significantly increased level of business. NU invested $109.4 million of equity in Select Energy in 2001 and Select Energy had borrowings from the parent company of $162 million and $114.1 million at December 31, 2001 and 2000, respectively. This investment was partially offset by the return of $75 million to NU parent through a combination of capital and common dividends by NGC in October 2001. One of management's primary goals in 2002 is to improve the results of Select Energy's energy marketing and trading businesses. To reduce risk, Select Energy has already procured almost 100 percent of the projected on-peak and the vast majority of the off-peak electricity requirements needed to serve the CL&P standard offer service load. In addition, management continues to work with state regulators to increase CL&P's standard offer service price to make it more competitive with alternative energy suppliers. Select Energy management also continues to work with third parties to arrange new profitable energy contracts to replace a number of wholesale contracts that are in the process of expiring. Management also expects the operations of SENY to significantly increase its business in New York and to generate positive net income in 2002. NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its competitive energy subsidiaries. NU currently has authorization from the Securities and Exchange Commission (SEC) to provide up to $500 million of guarantees, and has applied for authority to increase this amount to $750 million. As of December 31, 2001, NU had provided approximately $268.2 million and $45 million of such guarantees and letters of credit, respectively. In addition, NU's "aggregate investment" in Select Energy and its other energy service companies (but not including NGC, HWP or certain subsidiaries of SES) (which is inclusive of most of such credit assurances) is limited by SEC rule to 15 percent of NU's most recent quarterly consolidated capitalization. In light of the increasing size of the energy marketing and trading businesses, NU has applied to the SEC for authority to exempt Select Energy and SENY from this limitation. COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS NU's competitive energy subsidiaries, as major providers of electricity and natural gas, are exposed to certain market risks inherent in their business activities. The competitive energy subsidiaries enter into contracts of varying lengths of time to buy and sell energy commodities, primarily electricity, natural gas and oil. Market risk represents the risk of loss that may impact the companies' financial statements due to adverse changes in commodity market prices. The competitive energy subsidiaries manage their portfolio of contracts and assets to maximize value and minimize associated risks. The lengths of contracts to buy and sell energy vary in duration from daily/hourly to several years. At any point in time, the portfolio may be long (purchases exceed sales) or short (sales exceed purchases). Portfolio and risk management disciplines are used to manage exposures to market risks. Policies and procedures have been established to manage these risks. At market spot prices in effect at December 31, 2001, the portfolio had a positive mark-to-market position. There is significant volatility in the energy commodities market, and for certain of the energy products and contracts there has been limited liquidity. The position increased in value due to the decline in energy prices in the region and new transactions entered into during 2001. Select Energy also engages in the trading of commodity derivatives, which are accounted for using the mark-to-market method under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." All other nontrading transactions are recognized when settled. All trading positions are marked-to-market daily at the end of each trading day. All NYMEX futures and options are marked to closing exchange prices. Over-the-counter forwards and options are marked to the mid-point of bid and ask quotes. In most cases there are multiple sources of over-the-counter and broker quotes. Options, for which specific quotes are not available, are marked-to-market using a forward volatility curve derived from other options for which quotes are available. As of and for the year ended December 31, 2001, the sources of the fair value of these trading activities and the change in fair value of these trading activities are as follows:
-------------------------------------------------------------------------------- (Millions of Dollars) Fair Value of Contracts at December 31, 2001 -------------------------------------------------------------------------------- Maturity Maturity Maturity in Less than of One to Excess of Total Sources of Fair Value One Year Four Years Four Years Fair Value -------------------------------------------------------------------------------- Prices actively quoted $ 1.0 $ 0.2 $ -- $ 1.2 Prices provided by external sources 6.5 15.9 20.8 43.2 Prices based on model or other valuation method -- -- -- -- -------------------------------------------------------------------------------- Totals $ 7.5 $16.1 $20.8 $44.4 ================================================================================
-------------------------------------------------------------------------------- (Millions of Dollars) Total Fair Value -------------------------------------------------------------------------------- Fair value at beginning of period (January 1, 2001) $13.8 Contracts realized or otherwise settled during the period (7.9) Fair value of new contracts entered into during the period 17.7 Changes in fair value of contracts that existed at the beginning of the period 20.8 -------------------------------------------------------------------------------- Fair value at end of period (December 31, 2001) $44.4 ================================================================================
For further information see Note 1J, "Summary of Significant Accounting Policies - Accounting for Competitive Energy Contracts," Note 9, "Market Risk and Risk Management Instruments," and Note 12, "Other Comprehensive Income," to the consolidated financial statements. BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES In 2001, NU system companies announced a number of initiatives to significantly increase their investment in regulated electric transmission and natural gas distribution facilities, particularly in Connecticut. CL&P announced that it planned to construct two new 345,000 volt transmission line facilities totaling approximately 85 miles into Norwalk, Connecticut at a combined cost of approximately $520 million. An application to construct one of the facilities, an approximately 20 mile facility from Bethel, Connecticut to Norwalk, Connecticut, was filed in October 2001 with the Connecticut Siting Council. A decision is expected by the fall of 2002. The application related to a second facility from Middletown, Connecticut to Norwalk, Connecticut will be filed with the Connecticut Siting Council later in 2002. CL&P also has proposed replacing the existing 138,000 volt transmission line beneath Long Island Sound between Norwalk, Connecticut and Northport - Long Island, New York. CL&P, which owns an equal share of the existing line with the Long Island Power Authority, would bear approximately half of the cost of the $80 million project. That project would require Connecticut, New York and federal regulatory approvals. This application was filed with the Connecticut Siting Council in February 2002. If approved, these three projects would increase CL&P's capital expenditures. CL&P's capital investments in electric utility plant totaled $237.4 million in 2001 and $208.2 million in 2000, well above the $132.2 million level of 1998, primarily as a result of increased spending on CL&P's distribution system. CL&P's capital expenditures are expected to total $244 million in 2002 and higher in 2003 through 2005, if the transmission projects are approved. In addition to the three CL&P transmission projects noted above, the NU system announced plans for a fourth project involving construction of a new undersea direct-current line between Norwalk, Connecticut and western Long Island that is projected to be in service by no later than 2005. The cost of that line, which will require several regulatory approvals, depends on a number of factors, including its size and route. Management expects the line to be built and owned by a new NU transmission subsidiary that will secure its own external financing and receive an equity contribution from NU. Yankee Gas received approval for a significant expansion of its distribution system as it has a relatively low penetration rate for gas service in its service territory. To begin increasing that penetration rate, Yankee Gas commenced work in 2001 on 12 projects expected to cost $23 million in total. As a result, Yankee Gas' capital expenditures were $47.8 million in 2001, compared with $21.6 million in 2000. Yankee Gas has proposed system expansion projects totaling $190 million through 2005, including the 12 projects announced in 2001. Yankee Gas also is considering construction of a liquefied natural gas storage terminal in Waterbury, Connecticut that could cost in excess of $50 million. Yankee Gas may issue up to $100 million of long-term debt in 2002 to finance its capital needs and may require additional debt issuances in later years, depending on the extent of its capital program. Capital investments in electric utility plant at PSNH and WMECO totaled $92.6 million and $30.9 million, respectively, in 2001, as compared to $69.5 million and $27.3 million, respectively, in 2000. The company anticipates no material increase in capital expenditures at those subsidiaries in the next several years. Capital expenditures at NU's competitive energy subsidiaries are expected to be modest over the next several years. The most significant ongoing project is a repowering of six hydroelectric generation units at the Cabot Facility in Turners Falls, Massachusetts. That project began in 2001 and is expected to cost approximately $7 million per year and continue through 2003. NU continues to search for investment opportunities in competitive energy businesses in the Northeast United States. Over the past three years, NU acquired Denron, a heating, ventilating and air conditioning contractor based in New Hampshire; E.S. Boulos Company (Boulos), a high-voltage electrical contractor based in Maine, and; NMEM, an energy marketing company based in New York. NU also invested $10 million in Acumentrics, a Massachusetts firm that manufactures power quality and uninterruptible power quality components. The NMEM acquisition at approximately $31.7 million, was the largest investment of the four aforementioned investments. With approximately $570 million in revenues in 2001, this acquisition is expected to increase Select Energy's consolidated revenues by approximately 25 percent in 2002 and significantly increase Select Energy's activities in the New York market. RESTRUCTURING AND RATE MATTERS Connecticut - CL&P: Industry restructuring for CL&P was essentially completed in 2000. In June 2001, the DPUC concluded an investigation of potential overearnings by CL&P and ordered a $21.1 million reduction in CL&P's electric transmission and distribution rates and an equal increase in CL&P's Generation Services Charge. The DPUC also implemented an earnings sharing mechanism under which earnings in excess of a 10.3 percent return on equity will be shared equally by shareholders and ratepayers. On September 28, 2001, the DPUC ordered a $21.3 million annual reduction in CL&P's System Benefits Charge as a result of a sharp reduction in decommissioning collections and an equal increase in the Competitive Transition Assessment, effective January 1, 2002. Also, 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 approximately $98.5 million of deferred fuel costs. The net result of these decisions was a reduction in CL&P's pretax earnings of $21.1 million beginning June 20, 2001, an acceleration of CL&P's recovery of stranded costs in 2002 and 2003, and further enhancement of CL&P's cash flows. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale of the Millstone units to DNCI. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. A decision from the DPUC is expected in the first half of 2002. Since retail competition began in Connecticut in 2000, an extremely small number of CL&P customers have opted to choose their retail supplier. As of December 31, 2001, virtually all of CL&P's customers were procuring their electricity through CL&P's standard offer service. Through December 2003, 50 percent of CL&P's standard offer service requirements will be purchased from Select Energy with the remaining 50 percent being purchased from two unaffiliated companies. On November 18, 2001, at the request of one of the unaffiliated companies, CL&P filed a request with the DPUC to raise the standard offer service rate from an average of $0.0495 per kWh to $0.0595 per kWh to help promote competition in advance of the January 1, 2004, termination of the standard offer service period and to provide financial relief to the 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 electric competition in Connecticut and the financial condition of the suppliers. The dockets will include the gathering of information regarding the viability of the standard offer service contracts, their reliability and whether the standard offer service contracts should be linked to market conditions. The DPUC held hearings in February 2002. A decision in this docket which could lead to the re-opening of CL&P's standard offer docket to consider these issues is expected to be issued in the first half of 2002. Connecticut - Yankee Gas: On July 24, 2001, Yankee Gas filed a rate application with the DPUC requesting a 7.64 percent or $29.2 million increase in rates to fund system reliability projects and a proposed expansion of its distribution system. On January 30, 2002, the DPUC issued a final decision which ordered a $4 million rate decrease effective March 1, 2002. This rate decrease was, in part, based upon adjustments that Yankee Gas had agreed to during the proceedings. The final decision however, approved partially or fully many of the proposals made by Yankee Gas in its filing. The decision endorses Yankee Gas' distribution system expansion plan, subject to annual reviews and approves, with some conditions, its ratemaking recovery mechanism (Infrastructure Expansion Rate Mechanism). The final decision also authorizes an 11 percent return on equity for Yankee Gas and a sharing formula for earnings above that level from 2002 through 2005. Subsequent to the final decision, the effective date of the rate decrease was delayed until April 1, 2002. New Hampshire: On May 1, 2001, PSNH implemented industry restructuring allowing its customers to begin choosing their electric suppliers (competition day). They also received an overall reduction of 10 percent, in addition to the 5 percent reduction they received on October 1, 2000. On May 22, 2001, the Governor of New Hampshire signed a bill modifying the state's 1996 and 2000 electric utility industry restructuring laws. The revisions delay the sale of PSNH's fossil and hydroelectric generation assets to no sooner than 33 months after restructuring takes effect, or February 1, 2004. The revisions also fixed the charges retail customers will pay PSNH for electric supply, or transition service. PSNH and NAEC have entered into two contracts where PSNH is obligated to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook. The 2001 amended restructuring bill requires the NHPUC to complete the sale of NAEC's share of Seabrook in an expeditious manner. In late 2001, the NHPUC and the DPUC named J. P. Morgan as the selling agent for all owners seeking to sell their Seabrook shares. Those owners, which include CL&P with its 4.06 percent share, collectively own approximately 88 percent of Seabrook. J. P. Morgan expects to consummate the sale in late 2002. NAEC's proceeds will be used to repay all $90 million of NAEC's outstanding debt and return all NAEC's equity, which totaled $35 million as of December 31, 2001, to NU. Following the sale of NAEC's share of Seabrook, the Seabrook Power Contracts will be terminated. PSNH will use these proceeds to more quickly amortize stranded costs. On October 10, 2000, NU reached an agreement with an unaffiliated joint owner of Seabrook under which that joint owner would include its aggregate 15 percent ownership share of Seabrook in the upcoming sale. Under the terms of the agreement, in the event that the sale yields proceeds for that joint owner of more than $87.2 million, NU and that joint owner would share the excess proceeds. Should those sales proceeds be less than $87.2 million, NU would make up the difference below that amount up to a maximum of $17.4 million. The agreement also limits any top-off amount required to be funded by that joint owner for decommissioning as part of the sale process at the amount required by the Nuclear Regulatory Commission (NRC) regulations. Massachusetts: Unlike Connecticut, Massachusetts has experienced a continued expansion in the number of customers securing their electric supply through competitive suppliers. In January 2001, WMECO instituted approximately a 17 percent overall rate increase for its customers taking standard offer service. The increase reflected a sharp increase, from approximately $0.045 per kWh to approximately $0.073 per kWh, in prices paid to third-party suppliers during 2001. In December 2001, however, the Massachusetts Department of Telecommunications and Energy approved approximately a 14 percent reduction in WMECO's overall rates for standard offer service customers, primarily reflecting a reduction in WMECO's standard offer service supply costs in 2002 to approximately $0.048 per kWh. The significant reduction in supply costs in 2002 will result in a material reduction in WMECO's operating revenues and purchased power costs in 2002, but should not have a significant impact on financial performance since electric supply costs are passed through to customers. For further information regarding commitments and contingencies related to restructuring, see Note 7A, "Commitments and Contingencies - Restructuring," to the consolidated financial statements. REGIONAL TRANSMISSION ORGANIZATION The Federal Energy Regulatory Commission (FERC) has required all transmission owning utilities to voluntarily start forming regional transmission organizations (RTO) or to state why this process has not begun. In July 2001, the FERC stated that the three existing Northeastern Independent System Operators (ISO) (PJM, New York and New England) should work together to form one RTO. The FERC initiated a mediation effort between all interested parties to begin the process of forming such an entity. NU has been discussing with the other transmission owners in the three pool area the potential to form an Independent Transmission Company (ITC). 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 and deal with the energy market and short-term reliability. Together, the ITC and ISO form the FERC desired RTO. In January 2002, the New York and New England ISOs announced their intention to form an RTO. NU is working with the other transmission owners in these two power pools to create an ITC. The agreements needed to create the ITC and to define the working relationships among the ISO, the ITC and the transmission owners should be created in 2002 and will allow the ITC to begin operation shortly thereafter. The ITC and/or ISO will have the responsibility to collect the revenue requirements of each transmission owning entity from the market place through FERC approved tariffs. The creation of the ITC and/or RTO will require a FERC rate case and the impact on NU's return on equity as a result of this rate case cannot be estimated at this time. NUCLEAR PLANT PERFORMANCE AND OTHER MATTERS Seabrook: Seabrook operated at a capacity factor of 85.9 percent in 2001. After returning from a scheduled refueling outage in January 2001, Seabrook operated at a capacity factor of 93.4 percent. Seabrook is scheduled to undergo a refueling outage in the spring of 2002. The NU system companies own 40.04 percent of Seabrook. Yankee Companies: In August 2001, Vermont Yankee Nuclear Power Corporation announced it would sell the unit to an unaffiliated company for $180 million, including $145 million for the plant and materials and supplies and $35 million for the nuclear fuel. NU subsidiaries own 16 percent of the unit, and under the terms of the sale, will continue to buy 16 percent of the plant's output through March 2012 at a range of fixed prices. The sale requires several regulatory approvals and is scheduled to close during the first half of 2002. Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to DNCI. Additionally, CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to DNCI. On October 5, 2001, NU issued a report, following an extensive search, concerning two missing fuel pins at the retired Millstone 1 nuclear unit, which was sold to DNCI on March 31, 2001. As of December 31, 2001, costs related to this search totaled $7.1 million. The report concluded that the pins are currently located in one of four facilities licensed to store low or high-level nuclear waste and that they are not a threat to public health and safety. A follow-up review by the NRC commenced shortly after the report was filed and resulted in a NRC sponsored public meeting on January 15, 2002. In February 2002, the NRC issued a written inspection report which concluded that NU's investigation was thorough and complete, and that its conclusions were reasonable and supportable. NUCLEAR DECOMMISSIONING In connection with the aforementioned sale of the Millstone units, DNCI has agreed to assume responsibility for decommissioning those units. For further information regarding nuclear decommissioning, see Note 8, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. SPENT NUCLEAR FUEL DISPOSAL COSTS The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent nuclear fuel on January 31, 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. NU has the primary responsibility for the interim storage of its spent nuclear fuel prior to divestiture of its remaining operating nuclear units, Seabrook and Vermont Yankee, as well as the three nuclear units currently undergoing decommissioning, Connecticut Yankee, Maine Yankee and Yankee Rowe. For further information regarding spent nuclear fuel disposal costs, see Note 7C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. OTHER MATTERS Critical Accounting Policies: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Accounting policies related to the recoverability of certain regulatory assets, the performance of impairment assessments of recorded goodwill and other long-lived assets, mark-to-market accounting and the related treatment of derivative instruments and certain trading and hedging activities, and the assumptions used in developing the pension and postretirement benefit obligations are the accounting principles that management believes are critical and could have a significant impact on NU's consolidated financial statements. Regulatory Assets: The accounting policies of the NU system's regulated operating companies historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Through their cost-of-service rate regulated transmission and distribution businesses, CL&P, PSNH and WMECO are currently recovering their investments in long-lived assets, including regulatory assets, and management believes that the application of SFAS No. 71 to that portion of their businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of these investments is no longer recoverable under SFAS No. 71, that portion would be written off. Such a write-off could have a material impact on NU's consolidated financial statements. Management currently believes that all long-lived assets, including regulatory assets, are recoverable. Goodwill and Other Intangible Assets: Effective January 1, 2002, under SFAS No. 142, "Goodwill and Other Intangible Assets," NU is required to perform at least an annual assessment for impairment of goodwill by applying a fair value-based test. Management is in the process of the first assessment of impairment of goodwill and expects to complete this assessment by the June 30, 2002, deadline imposed by SFAS No. 142. Upon adoption of the impairment testing rules under SFAS No. 142, there may be a cumulative effect of an accounting change which management has not evaluated at this time. Mark-To-Market Accounting: At each balance sheet date, NU's energy trading positions are marked-to-market using closing exchange prices or quotes from external sources. Market risk represents the risk of loss that may impact NU's financial statements due to adverse changes in commodity market prices which could affect the realizability of the positive mark-to-market position of $44.4 million at December 31, 2001. Additionally, the mark-to-market position for certain effective hedging activities is currently included in other comprehensive income. If it is determined that these hedging activities are no longer effective, as defined in SFAS No. 133, this mark-to-market position would be included currently in earnings. This mark-to-market position was a negative $36.9 million at December 31, 2001, net of tax (decrease to equity). Pension and Postretirement Benefit Obligations: The NU system companies participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. These assumptions primarily relate to the application of a discount rate, expected long-term rate of return and other trend rates. 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 NU's consolidated financial statements. For further information regarding these types of activities, see Note 1G, "Regulatory Accounting and Assets," Note 1C, "New Accounting Standards," Note 9, "Market Risk and Risk Management Instruments," and Note 4, "Employee Benefits," to the consolidated financial statements. Environmental Matters: The NU system is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 7B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements. Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 7, "Commitments and Contingencies," to the consolidated financial statements. Contractual Obligations and Commercial Commitments: Aggregated information regarding the NU system's contractual obligations and commercial commitments as of December 31, 2001, is summarized as follows:
--------------------------------------------------------------------------------------------------------------------- (Millions of Dollars) 2002 2003 2004 2005 2006 Totals --------------------------------------------------------------------------------------------------------------------- Notes payable to banks $ 290.5 $ -- $ -- $ -- $ -- $ 290.5 Long-term debt 50.5 318.6 58.5 86.6 24.3 538.5 Capital leases 3.1 3.1 3.0 2.8 2.7 14.7 Operating leases 23.7 18.4 15.5 13.3 11.1 82.0 Long-term contractual obligations 442.1 450.8 459.3 462.2 411.9 2,226.3 Select Energy purchase agreements 2,416.2 836.2 145.9 95.7 34.8 3,528.8 --------------------------------------------------------------------------------------------------------------------- Totals $3,226.1 $1,627.1 $ 682.2 $ 660.6 $ 484.8 $6,680.8 =====================================================================================================================
For further information regarding NU's contractual obligations and commercial commitments, see the Consolidated Statements of Capitalization and related footnotes, and Note 2, "Short-Term Debt," Note 3, "Leases," and Note 7E, "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 historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, 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. -------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------- Income Statement Variances 2001 over/(under) 2000 2000 over/(under) 1999 ------------------------- -------------------------- (Millions of Dollars) Amount Percent Amount Percent ----------------------------------------------------------------------------------------------------------------------- Operating Revenues $ 997 17% $1,405 31% ----------------------------------------------------------------------------------------------------------------------- Operating Expenses: Fuel, purchased and net interchange power 1,237 37 1,406 74 Other operation (93) (11) 11 1 Maintenance 3 1 (85) (25) Depreciation (39) (16) (62) (21) Amortization of regulatory assets, net 706 (a) (320) (54) Taxes other than income taxes (19) (8) (23) (9) Gain on sale of utility plant (642) (100) 309 100 ----------------------------------------------------------------------------------------------------------------------- Total operating expenses 1,153 22 1,236 31 ----------------------------------------------------------------------------------------------------------------------- Operating Income (156) (22) 169 32 Other income (loss), net 202 (a) 92 87 Interest expense, net (19) (7) 36 14 ----------------------------------------------------------------------------------------------------------------------- Income before income tax expense 65 17 225 (a) Income tax expense 12 7 63 64 Preferred dividends of subsidiaries (7) (47) (9) (38) ----------------------------------------------------------------------------------------------------------------------- Income before extraordinary loss and cumulative effect of accounting change 60 30 171 (a) Extraordinary loss, net of tax benefit 234 100 (234) 100 Cumulative effect of accounting change, net of tax benefit (22) 100 -- -- ----------------------------------------------------------------------------------------------------------------------- Net income/(loss) $ 272 (a) $ (63) (a) =======================================================================================================================
(a) Percent greater than 100. OPERATING REVENUES Total revenues increased by $997 million or 17 percent in the year 2001, compared with the year 2000, primarily due to higher revenues from the competitive energy subsidiaries ($1,069 million which reflects eliminations of sales to other NU affiliates), higher revenues from Yankee Gas ($127 million) and higher regulated retail electric revenues ($33 million), partially offset by lower wholesale regulated revenues ($190 million) and lower transmission revenues ($26 million). The competitive energy subsidiaries' increase is primarily due to higher revenues from Select Energy as a result of new contracts for energy services. The Yankee Gas increase is primarily due to a full year of revenue in 2001 versus ten months post merger in 2000. The regulated retail increase is primarily due to a 1.7 percent increase in sales ($41 million), the increase in WMECO's standard offer service rate ($59 million) and the recovery of previously deferred fuel costs for CL&P ($19 million), partially offset by the 5 and 11 percent rate decreases for PSNH that were effective October 1, 2000 and May 1, 2001, respectively ($89 million). Wholesale revenues were lower primarily due to the sale of Millstone at the end of the first quarter of 2001. Total revenues increased by $1,405 million or 31 percent in 2000, primarily due to higher revenues from the competitive energy subsidiaries ($1,246 million of which $669 million represents sales to other NU affiliates which are eliminated in consolidation), the acquisition of Yankee ($262 million) and higher regulated wholesale revenues ($727 million of which $281 million represents sales to other NU affiliates which are eliminated in consolidation), partially offset by lower regulated retail revenues ($26 million). The competitive energy subsidiaries' increase is primarily due to higher revenues from Select Energy as a result of new contracts for energy sales and services. The regulated wholesale revenue increase is primarily due to higher PSNH energy sales and higher CL&P and WMECO revenue from the sale of the output from Millstone 2 and 3. The regulated retail decrease is primarily due to retail rate reductions for CL&P and PSNH ($108 and $8 million, respectively), partially offset by the impact of Millstone 2 being returned to CL&P's rate base ($33 million), higher retail sales ($18 million), higher fuel revenues for PSNH ($15 million), and higher retail revenue attributed to lower price discounts in 2000 and changing customer mix ($24 million). Regulated retail kWh sales increased by 0.8 percent in 2000. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased in 2001, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($1,252 million which reflects eliminations of purchases from other NU affiliates), higher expense for Yankee primarily due to a full year in 2001 and higher gas prices ($83 million), and higher expense for WMECO primarily due to the increased cost of the standard offer supply ($70 million), partially offset by lower wholesale cost for CL&P and PSNH ($173 million, net of eliminations). Fuel, purchased and net interchange power expense increased in 2000, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($1,036 million of which $660 million represents purchases from other NU affiliates which are eliminated in consolidation), Yankee expenses ($135 million) and higher purchased power for regulated subsidiaries ($235 million). OTHER OPERATION AND MAINTENANCE Other operation and maintenance (O&M) expenses decreased $90 million in 2001, primarily due to lower nuclear expenses ($133 million) as a result of the sale of the Millstone units at the end of the first quarter of 2001, partially offset by higher O&M expenses for the competitive energy subsidiaries, primarily due to the acquisition of Boulos ($49 million). Other O&M expenses decreased $74 million in 2000, primarily due to lower spending at the nuclear units due to better performance ($75 million), lower expenses due to the sale of certain CL&P and WMECO fossil and hydroelectric generation assets ($74 million), lower corporate support ($38 million), the decommissioning status of Millstone 1 ($17 million), lower environmental- related costs ($12 million) and 1999 expenses associated with the Con Edison merger ($12 million), partially offset by the addition of Yankee ($60 million), higher O&M expenses for the unregulated businesses ($84 million), primarily due to the business expansion, and higher distribution expenses ($29 million), including increased conservation program expenses. DEPRECIATION Depreciation expense decreased $39 million 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 ($25 million) and the buydown of the Seabrook Power Contracts ($14 million). Depreciation decreased $62 million in 2000, primarily due to the effect of discontinuing SFAS No. 71 for the portion of the generation business for CL&P and WMECO and the resulting reclassification of depreciable nuclear plant balances to regulatory assets ($84 million) and the sale of certain CL&P and WMECO fossil and hydroelectric generation assets, partially offset by the addition of Yankee ($23 million). AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net increased in 2001, primarily due to the amortization in 2001 related to the gain on sale of the Millstone units by CL&P and WMECO ($641 million) and higher amortization related to restructuring. Amortization of regulatory assets, net decreased in 2000, primarily due to the amortization in 1999 of the gain on sale of fossil and hydroelectric generation assets for WMECO and CL&P ($309 million), and changes in amortization levels as a result of industry restructuring ($95 million). These decreases were partially offset by higher amortization associated with the reclassified nuclear plant balances ($84 million). TAXES OTHER THAN INCOME TAXES Taxes other than income taxes decreased in 2001, primarily due to settlement of a property tax appeal with the City of Meriden for CL&P and Yankee in 2001 ($15 million), the reduction in property tax for CL&P and WMECO due to the sale of the Millstone units ($16 million) and lower New Hampshire franchise tax ($5 million), partially offset by higher Connecticut gross earnings taxes ($14 million) on higher CL&P revenues. Taxes other than income taxes decreased in 2000, primarily due to lower Connecticut gross earnings taxes ($12 million) and lower payroll taxes ($7 million). GAIN ON SALE OF UTILITY PLANT NU recorded gains on the sale of CL&P's and WMECO's ownership interests in Millstone. A corresponding amount of amortization expense was recorded in 2001. CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric generation assets in 1999. A corresponding amount of amortization expense was recorded. OTHER INCOME/(LOSS), NET Other income/(loss), net increased primarily due to NU's recognition in 2001 of a gain in connection with the sale of the Millstone nuclear units to DNCI (the pretax amount of $189 million is included in other income with an offsetting income tax expense impact of $73 million), lower nuclear related costs in 2001 ($18 million), lower environmental reserve expense in 2001 ($10 million), and higher interest and dividend income ($20 million), partially offset by the charge related to the forward purchase of 10.1 million NU common shares ($35 million). Other income/(loss), net increased in 2000, primarily due to lower nuclear related costs in 2000 ($53 million), a one-time gain related to the company's investment in NEON of Mode 1 ($17 million), and the loss in 1999 on the CL&P assignment of market-based contracts to Select Energy ($15 million). INTEREST EXPENSE, NET Interest expense, net decreased in 2001, primarily due to reacquisitions and retirements of long-term debt ($54 million) and higher short-term borrowings in 2000 associated with asset transfers and the Yankee merger ($54 million), partially offset by the interest expense associated with the issuance of rate reduction bonds and certificates in 2001 ($88 million). Interest expense, net increased in 2000, primarily due to higher short-term borrowings associated with the NGC asset transfer and the Yankee merger, partially offset by lower long-term debt as a result of reacquisitions and retirements. INCOME TAX EXPENSE The consolidated statement of income taxes provides a reconciliation of actual and expected tax expense. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. In past years, this rate-making treatment has required the company to provide the customers with a portion of the tax benefits associated with accelerated tax depreciation in the year it is generated (flow-through depreciation). As these flow-through differences turn around, higher tax expense is recorded. Federal and state income taxes combined increased in 2001, primarily due to higher taxable income. The increase in income taxes as a result of higher taxable income was partially offset by a reduction in income taxes as a result of the favorable resolution of certain tax contingencies. For further information regarding income taxes, see the Consolidated Statements of Income Taxes. Federal and state income tax expense increased approximately $63 million in 2000. Significant variances responsible for this increase include higher pretax earnings ($90 million) and lower adjustments to the tax valuation allowance ($21 million). Reduction in flow-through depreciation and amortization ($51 million) partially offset the overall change. PREFERRED DIVIDENDS OF SUBSIDIARIES Preferred dividends decreased in 1999, 2000, and 2001 primarily due to lower preferred stock outstanding. EXTRAORDINARY LOSS, NET OF TAX BENEFIT The extraordinary loss, net of tax benefit, is primarily due to an after-tax write-off by PSNH of approximately $225 million of stranded costs under an industry restructuring settlement with the state of New Hampshire, combined with other positive effects on PSNH from the discontinuance of SFAS No. 71 ($11 million) and a loss associated with the then pending sale of certain HWP assets ($20 million). CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX BENEFIT The cumulative effect of accounting change, net of tax benefit, recorded in 2001, represents the effect of the adoption of SFAS No. 133 ($22 million). COMPANY REPORT ------------------------------------------------------------------------------- The accompanying consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this annual report were prepared by the company. These financial statements, which were audited by Arthur Andersen LLP, were prepared in accordance with accounting principles generally accepted in the United States using estimates and judgments, where required, and giving consideration to materiality. The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. The company maintains a system of internal controls over financial reporting, which is designed to provide reasonable assurance to the company's management and Board of Trustees regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and policies prohibiting conflicts of interest. The Audit Committee of the Board of Trustees is composed entirely of independent trustees. The Audit Committee meets periodically with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting and the adequacy of internal controls. Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal accounting controls and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ------------------------------------------------------------------------------- To the Board of Trustees and Shareholders of Northeast Utilities: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for each of the three years in the period ended December 31, 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 Northeast Utilities 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. As discussed in Note 1C to the consolidated financial statements, effective January 1, 2001, the company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. /s/ ARTHUR ANDERSEN LLP ------------------- ARTHUR ANDERSEN LLP Hartford, Connecticut January 22, 2002 CONSOLIDATED STATEMENTS OF INCOME
------------------------------------------------------------------------------------------------------------------ For the Years Ended December 31, ------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars, except share information) 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $6,873,826 $5,876,620 $4,471,251 ------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES: Operation -- Fuel, purchased and net interchange power 4,541,342 3,303,995 1,898,314 Other 773,058 866,742 855,917 Maintenance 258,961 255,884 340,419 Depreciation 201,013 239,798 302,305 Amortization of regulatory assets, net 983,037 276,821 596,437 Taxes other than income taxes 219,197 238,587 261,353 Gain on sale of utility plant (641,956) -- (308,914) ------------------------------------------------------------------------------------------------------------------- Total operating expenses 6,334,652 5,181,827 3,945,831 ------------------------------------------------------------------------------------------------------------------- Operating Income 539,174 694,793 525,420 Other Income/(Loss), Net 187,627 (14,309) (106,187) ------------------------------------------------------------------------------------------------------------------- Income Before Interest and Income Tax Expense 726,801 680,484 419,233 ------------------------------------------------------------------------------------------------------------------- INTEREST EXPENSE: Interest on long-term debt 147,049 200,697 258,093 Interest on rate reduction bonds 87,616 -- -- Other interest 44,993 98,605 5,558 ------------------------------------------------------------------------------------------------------------------- Interest expense, net 279,658 299,302 263,651 ------------------------------------------------------------------------------------------------------------------- Income Before Income Tax Expense 447,143 381,182 155,582 Income Tax Expense 173,952 161,725 98,611 ------------------------------------------------------------------------------------------------------------------- Income Before Preferred Dividends of Subsidiaries 273,191 219,457 56,971 Preferred Dividends of Subsidiaries 7,249 14,162 22,755 ------------------------------------------------------------------------------------------------------------------- Income before extraordinary loss and cumulative effect of accounting change, net of tax benefits 265,942 205,295 34,216 Extraordinary loss, net of tax benefit of $169,562 -- (233,881) -- Cumulative effect of accounting change, net of tax benefit of $14,908 (22,432) -- -- ------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $243,510 $(28,586) $34,216 =================================================================================================================== BASIC EARNINGS/(LOSS) PER COMMON SHARE: Income before extraordinary loss and cumulative effect of accounting change, net of tax benefits $1.97 $1.45 $0.26 Extraordinary loss, net of tax benefit -- (1.65) -- Cumulative effect of accounting change, net of tax benefit (0.17) -- -- ------------------------------------------------------------------------------------------------------------------- Basic Earnings/(Loss) Per Common Share $1.80 $(0.20) $0.26 =================================================================================================================== FULLY DILUTED EARNINGS/(LOSS) PER COMMON SHARE: Income before extraordinary loss and cumulative effect of accounting change, net of tax benefits $1.96 $1.45 $0.26 Extraordinary loss, net of tax benefit -- (1.65) -- Cumulative effect of accounting change, net of tax benefit (0.17) -- -- ------------------------------------------------------------------------------------------------------------------- Fully Diluted Earnings/(Loss) Per Common Share $1.79 $(0.20) $0.26 =================================================================================================================== Basic Common Shares Outstanding (average) 135,632,126 141,549,860 131,415,126 =================================================================================================================== Fully Diluted Common Shares Outstanding (average) 135,917,423 141,967,216 132,031,573 ===================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
------------------------------------------------------------------------------------------------------- For the Years Ended December 31, ------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2001 2000 1999 ------------------------------------------------------------------------------------------------------- NET INCOME/(LOSS) $243,510 $(28,586) $34,216 ------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE (LOSS)/INCOME, NET OF TAX: Qualified cash flow hedging instruments (36,859) -- -- Unrealized gains on securities 2,620 245 118 Foreign currency translation adjustments -- -- 1 ------------------------------------------------------------------------------------------------------- Other comprehensive (loss)/income, net of tax (34,239) 245 119 ------------------------------------------------------------------------------------------------------- COMPREHENSIVE INCOME/(LOSS) $209,271 $(28,341) $34,335 =======================================================================================================
The accompanying notes are an integral part of these financial statements. CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------------------------------------------------------ At December 31, ------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) 2001 2000 ------------------------------------------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS: Cash and cash equivalents $ 96,658 $ 200,017 Investments in securitizable assets 36,367 98,146 Receivables, less accumulated provision for uncollectible accounts of $16,353 in 2001 and $12,500 in 2000 831,221 472,863 Unbilled revenues 126,398 121,090 Fuel, materials and supplies, at average cost 108,516 163,711 Special deposits 60,261 2,624 Prepayments and other 126,233 91,904 ------------------------------------------------------------------------------------------------------------------------ 1,385,654 1,150,355 ------------------------------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT: Electric utility 5,743,575 9,003,298 Gas utility 634,884 608,153 Competitive energy 344,063 409,035 Other 195,741 211,417 ------------------------------------------------------------------------------------------------------------------------ 6,918,263 10,231,903 Less: Accumulated provision for depreciation 3,418,577 7,041,279 ------------------------------------------------------------------------------------------------------------------------ 3,499,686 3,190,624 Construction work in progress 289,889 228,330 Nuclear fuel, net 32,564 128,261 ------------------------------------------------------------------------------------------------------------------------ 3,822,139 3,547,215 ------------------------------------------------------------------------------------------------------------------------ DEFERRED DEBITS AND OTHER ASSETS: Regulatory assets 3,950,445 3,910,801 Goodwill and other purchased intangible assets, net 322,600 324,389 Prepaid pension 232,398 139,546 Nuclear decommissioning trusts, at market 61,713 740,058 Other 466,460 404,785 ------------------------------------------------------------------------------------------------------------------------ 5,033,616 5,519,579 ------------------------------------------------------------------------------------------------------------------------ Total Assets $10,241,409 $ 10,217,149 ========================================================================================================================
The accompanying notes are an integral part of these financial statements. CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------------------------------------------- At December 31, ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Notes payable to banks $ 290,500 $ 1,309,977 Long-term debt and preferred stock - current portion 50,462 340,041 Accounts payable 669,545 538,983 Accrued taxes 26,203 54,088 Accrued interest 35,659 41,131 Other 178,071 304,810 ----------------------------------------------------------------------------------------------------------------------------------- 1,250,440 2,589,030 ----------------------------------------------------------------------------------------------------------------------------------- Rate Reduction Bonds 2,018,351 -- ----------------------------------------------------------------------------------------------------------------------------------- Minority Interest in Consolidated Subsidiary -- 100,000 ----------------------------------------------------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accumulated deferred income taxes 1,491,394 1,585,494 Accumulated deferred investment tax credits 120,071 153,155 Decommissioning obligation - Millstone 1 -- 692,560 Deferred contractual obligations 216,566 244,608 Other 618,191 452,926 ----------------------------------------------------------------------------------------------------------------------------------- 2,446,222 3,128,743 ----------------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION: Long-Term Debt 2,292,556 2,029,593 ----------------------------------------------------------------------------------------------------------------------------------- Preferred Stock 116,200 151,200 ----------------------------------------------------------------------------------------------------------------------------------- COMMON SHAREHOLDERS' EQUITY: Common shares, $5 par value - authorized 225,000,000 shares; 148,890,640 shares issued and 130,132,136 shares outstanding in 2001 and 148,781,861 shares issued and 143,820,405 shares outstanding in 2000 744,453 693,345 Capital surplus, paid in 1,107,609 942,144 Temporary equity from stock forward -- 215,000 Deferred contribution plan - employee stock ownership plan (101,809) (114,463) Retained earnings 678,460 495,873 Accumulated other comprehensive (loss)/income (32,470) 1,769 Treasury stock (278,603) (15,085) ----------------------------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity 2,117,640 2,218,583 ----------------------------------------------------------------------------------------------------------------------------------- Total Capitalization 4,526,396 4,399,376 ----------------------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES (NOTE 7) Total Liabilities and Capitalization $10,241,409 $10,217,149 ===================================================================================================================================
The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
----------------------------------------------------------------------------------------------------------------------------------- Capital Accumulated Common Surplus, Deferred Retained Other Shares Paid In Contribution Earnings Comprehensive Treasury (Thousands of Dollars) (a) (a) Plan -- ESOP (b) Income/(Loss) Stock Total ----------------------------------------------------------------------------------------------------------------------------------- Balance as of January 1, 1999 $685,156 $ 941,960 $(140,619) $560,769 $ 1,405 $ (1,299) $2,047,372 ----------------------------------------------------------------------------------------------------------------------------------- Net income for 1999 34,216 34,216 Cash dividends on common shares-$0.10 per share (13,168) (13,168) Issuance of 362,565 common shares, $5 par value 1,813 3,505 5,318 Allocation of benefits-ESOP (3,053) 12,894 9,841 Unearned stock compensation (1,194) (1,194) Capital stock expenses, net 807 807 Other comprehensive income 119 119 ----------------------------------------------------------------------------------------------------------------------------------- Balance as of December 31, 1999 686,969 942,025 (127,725) 581,817 1,524 (1,299) 2,083,311 ----------------------------------------------------------------------------------------------------------------------------------- Net loss for 2000 (28,586) (28,586) Cash dividends on common shares-$0.40 per share (57,358) (57,358) Issuance of 11,388,032 common shares, $5 par value 56,940 164,443 221,383 Transaction fee on forward share purchase arrangement (13,786) (13,786) Allocation of benefits-ESOP (1,617) 13,262 11,645 Redemption of preferred stock (749) (749) Capital stock expenses, net 2,478 2,478 Other comprehensive income 245 245 ----------------------------------------------------------------------------------------------------------------------------------- Balance as of December 31, 2000 743,909 1,106,580 (114,463) 495,873 1,769 (15,085) 2,218,583 ----------------------------------------------------------------------------------------------------------------------------------- Net income for 2001 243,510 243,510 Cash dividends on common shares-$0.45 per share (60,923) (60,923) Issuance of 108,779 common shares, $5 par value 544 1,207 1,751 Transaction fee on forward share purchase arrangement (1,663) (1,663) Allocation of benefits-ESOP (2,296) 12,654 10,358 Repurchase of common shares (291,789) (291,789) Mark-to-market on forward share purchase arrangement 29,934 29,934 Capital stock expenses, net 2,118 2,118 Other comprehensive loss (34,239) (34,239) ----------------------------------------------------------------------------------------------------------------------------------- BALANCE AS OF DECEMBER 31, 2001 $744,453 $1,107,609 $(101,809) $678,460 $(32,470) $(278,603) $2,117,640 -----------------------------------------------------------------------------------------------------------------------------------
(a) In conjunction with NU's forward share purchase arrangement, 10,112,879 shares or $50.6 million and $164.4 million, respectively, were reclassified from Common Shares and Capital Surplus, Paid In, at December 31, 2000 and 1999, to Temporary Equity from Stock Forward. (b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2001, retained earnings available for payment of dividends totaled $267.5 million. The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2001 2000 1999 ----------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES: Income before preferred dividends of subsidiaries $ 273,191 $ 219,457 $ 56,971 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 201,013 239,798 302,305 Deferred income taxes and investment tax credits, net (116,704) (16,117) (183,356) Amortization of regulatory assets, net 983,037 276,821 596,437 Gain on sale of utility plant (641,956) -- (308,914) Cumulative effect of accounting change (22,432) -- -- Net other (uses)/sources of cash (80,362) (101,927) 36,360 Changes in working capital: Receivables and unbilled revenues, net (356,863) (104,868) (106,566) Fuel, materials and supplies 55,195 12,450 29,688 Accounts payable 130,562 171,148 8,709 Accrued taxes (27,885) (128,107) 107,929 Investments in securitizable assets 61,779 9,474 74,498 Other working capital (excludes cash) (81,837) 254 157 ----------------------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 376,738 578,383 614,218 ----------------------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES: Investments in regulated plant: Electric, gas and other utility plant (428,312) (345,596) (278,726) Nuclear fuel (14,275) (61,286) (42,471) ----------------------------------------------------------------------------------------------------------------------------------- Net cash flows used for investments in regulated plant (442,587) (406,882) (321,197) Investments in nuclear decommissioning trusts (105,076) (39,550) (74,231) Investments in competitive energy assets (15,368) (7,140) (31,897) Other investment activities, net (51,677) (28,478) 13,084 Net proceeds from the sale of utility plant 1,048,636 -- 565,436 Buyout/buydown of IPP contracts (1,176,872) -- -- Payment for the purchase of SENY, net of cash acquired (25,823) -- -- Payment for the purchase of Yankee, net of cash acquired -- (260,347) -- ----------------------------------------------------------------------------------------------------------------------------------- Net cash flows (used in)/provided by investing activities (768,767) (742,397) 151,195 ----------------------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES: Issuance of common shares 1,751 4,269 5,318 Repurchase of common shares (291,789) -- -- Issuance of long-term debt 703,000 26,477 200 Issuance of rate reduction bonds 2,118,400 -- -- Retirement of rate reduction bonds (100,049) -- -- Net (decrease)/increase in short-term debt (1,019,477) 961,977 248,000 Reacquisitions and retirements of long-term debt (714,226) (685,555) (817,759) Reacquisitions and retirements of preferred stock (60,768) (126,771) (46,250) Retirement of monthly income preferred securities (100,000) -- -- Retirement of capital lease obligation (180,000) -- -- Cash dividends on preferred stock (7,249) (14,162) (22,755) Cash dividends on common shares (60,923) (57,358) (13,168) ----------------------------------------------------------------------------------------------------------------------------------- Net cash flows provided by/(used in) financing activities 288,670 108,877 (646,414) ----------------------------------------------------------------------------------------------------------------------------------- Net (decrease)/increase in cash and cash equivalents (103,359) (55,137) 118,999 Cash and cash equivalents - beginning of year 200,017 255,154 136,155 ----------------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents - end of year $ 96,658 $200,017 $255,154 ===================================================================================================================================
The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF CAPITALIZATION
----------------------------------------------------------------------------------------------------------------------------------- At December 31, ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- COMMON SHAREHOLDERS' EQUITY (a) $ 2,117,640 $ 2,218,583 ----------------------------------------------------------------------------------------------------------------------------------- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES: $25 par value - authorized 36,600,000 shares at December 31, 2001 and 2000; no shares outstanding in 2001 and 1,630,722 shares outstanding in 2000 $50 par value - authorized 9,000,000 shares at December 31, 2001 and 2000; 2,324,000 shares outstanding in 2001 and 2000 $100 par value - authorized 1,000,000 shares at December 31, 2001 and 2000; no shares outstanding in 2001 and 200,000 shares outstanding in 2000 -----------------------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------------------------- At December 31, ----------------------------------------------------------------------------------------------------------------------------------- Current Redemption Current Shares Dividend Rates Prices Outstanding 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- NOT SUBJECT TO MANDATORY REDEMPTION: $50 par value - $1.90 to $3.28 $50.50 to $54.00 2,324,000 116,200 116,200 $100 par value - $7.72 -- -- -- 20,000 ----------------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock Not Subject to Mandatory Redemption 116,200 136,200 ----------------------------------------------------------------------------------------------------------------------------------- SUBJECT TO MANDATORY REDEMPTION: $25 par value - $1.90 to $2.65 -- -- -- 40,768 ----------------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock Subject to Mandatory Redemption -- -- 40,768 Less: Preferred Stock to Be Redeemed Within One Year -- -- 25,768 ----------------------------------------------------------------------------------------------------------------------------------- Preferred Stock Subject to Mandatory Redemption, Net -- -- 15,000 -----------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT: (b) First Mortgage Bonds -
----------------------------------------------------------------------------------------------------------------------------------- At December 31, ----------------------------------------------------------------------------------------------------------------------------------- Maturity Interest Rates 2001 2000 ----------------------------------------------------------------------------------------------------------------------------------- 2001 7.375% to 7.875% -- 220,000 2002 9.05% -- 375,000 2005 4.998% to 6.75% 140,000 20,000 2009-2012 6.20% to 7.19% 80,000 80,000 2019-2024 7.875% to 10.07% 255,945 313,050 2026 8.81% 320,000 -- ----------------------------------------------------------------------------------------------------------------------------------- Total First Mortgage Bonds 795,945 1,008,050 ----------------------------------------------------------------------------------------------------------------------------------- Other Long-Term Debt - Pollution Control Notes and Other Notes - (c) 2003-2006 Adjustable Rate and 6.24% to 8.58% 381,500 139,600 2013-2018 Adjustable Rate and 5.90% 25,400 33,400 2020 Adjustable Rate -- 15,300 2021-2022 Adjustable Rate and 5.45% to 7.65% 428,285 443,285 2028 5.85% to 5.95% 369,300 369,300 2031 Adjustable Rate 62,000 62,000 ----------------------------------------------------------------------------------------------------------------------------------- Total Pollution Control Notes and Other Notes 1,266,485 1,062,885 Fees and interest due for spent nuclear fuel disposal costs 249,314 240,303 Other 36,257 38,978 ----------------------------------------------------------------------------------------------------------------------------------- Total Other Long-Term Debt 1,552,056 1,342,166 ----------------------------------------------------------------------------------------------------------------------------------- Unamortized Premium and Discount, Net (4,983) (6,350) ----------------------------------------------------------------------------------------------------------------------------------- Total Long-Term Debt 2,343,018 2,343,866 Less: Amounts due within one year 50,462 314,273 ----------------------------------------------------------------------------------------------------------------------------------- Long-Term Debt, Net 2,292,556 2,029,593 ----------------------------------------------------------------------------------------------------------------------------------- TOTAL CAPITALIZATION $4,526,396 $4,399,376 ===================================================================================================================================
The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION (a) On January 2, 2001, NU modified its forward share purchase arrangements for NU common shares. To initially effect these arrangements, the financial institutions (counterparties) purchased approximately 10.1 million NU common shares on the open market in December 1999 and January 2000, in a total aggregate amount of $215 million, at an average price of $21.26. The counterparties maintained ownership of the shares until the transactions were settled. NU accrued charges on the total aggregate amount at LIBOR plus an agreed upon percentage per annum, until the transactions were settled. These transactions could have been settled in cash or NU common shares at the company's discretion. NU repurchased the shares from the counterparties in April 2001 with the proceeds from restructuring. This amount has been classified as temporary equity from stock forward on NU's consolidated balance sheets at December 31, 2000. (b) Long-term debt maturities and cash sinking fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 2001, for the years 2002 through 2006 are $50.5 million, $318.6 million, $58.5 million, $86.6 million, and $24.3 million, respectively. Essentially all utility plant of CL&P, PSNH, NGC, and Yankee is subject to the liens of each company's respective first mortgage bond indenture. CL&P has $315.5 million of pollution control notes secured by second mortgage liens on transmission assets, junior to the liens of their first mortgage bond indentures. CL&P has $62 million of tax-exempt 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. PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to which the BFA issued five series of PCRBs and loaned the proceeds to PSNH. At December 31, 2001 and 2000, $407.3 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by bond insurance and the first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. (c) The average effective interest rate on the variable-rate pollution control notes ranged from 1.2 percent to 3.8 percent for 2001 and 3.2 percent to 6.8 percent for 2000. Consolidated Statements of Income Taxes
--------------------------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, --------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- The components of the federal and state income tax provisions charged to the operations are: Current income taxes: Federal $ 244,501 $ 154,790 $ 248,012 State 46,155 23,052 33,955 --------------------------------------------------------------------------------------------------------------------------------- Total current 290,656 177,842 281,967 --------------------------------------------------------------------------------------------------------------------------------- Deferred income taxes, net: Federal (80,968) 7,297 (134,773) State (15,644) (5,529) (28,789) --------------------------------------------------------------------------------------------------------------------------------- Total deferred (96,612) 1,768 (163,562) --------------------------------------------------------------------------------------------------------------------------------- Investment tax credits, net (20,092) (17,885) (19,794) --------------------------------------------------------------------------------------------------------------------------------- TOTAL INCOME TAX EXPENSE $ 173,952 $ 161,725 $ 98,611 ================================================================================================================================= Deferred income taxes are comprised of the tax effects of temporary differences as follows: Deferred tax asset associated with net operating losses $ 2,206 $ 1,563 $ 14,801 Depreciation, leased nuclear fuel, settlement credits and disposal costs (185,850) 9,514 (4,580) Regulatory deferral (33,187) (34,486) (27,297) Regulatory disallowance 2,323 -- (30,719) Sale of generation assets (225,019) -- (125,807) Pension 24,183 25,751 8,936 Loss on bond redemptions 12,396 655 314 Securitized contract termination costs and other 279,673 -- -- Contract settlements 16,640 (4,442) (7,622) Other 10,023 3,213 8,412 --------------------------------------------------------------------------------------------------------------------------------- DEFERRED INCOME TAXES, NET $ (96,612) $ 1,768 $(163,562) ================================================================================================================================= A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows: Expected federal income tax $ 156,500 $ 133,413 $ 54,454 Tax effect of differences: Depreciation 5,313 2,882 24,583 Amortization of regulatory assets 5,748 16,835 45,825 Amortization of PSNH acquisition costs 4,512 9,946 9,946 Investment tax credit amortization (20,092) (17,885) (19,794) State income taxes, net of federal benefit 19,832 11,390 3,358 Nondeductible stock expenses 12,388 -- -- Dividends received deduction (3,382) (8,618) (1,314) Tax asset valuation allowance/reserve adjustments (7,000) (2,136) (23,129) Merger-related expenditures (4,589) 5,829 4,597 Other, net 4,722 10,069 85 --------------------------------------------------------------------------------------------------------------------------------- TOTAL INCOME TAX EXPENSE $ 173,952 $ 161,725 $ 98,611 =================================================================================================================================
The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About Northeast Utilities Northeast Utilities (NU or the company) is the parent company of the Northeast Utilities system (NU system). Through its regulated utilities and competitive energy subsidiaries, NU strives to become the leading regional provider of energy products and services, and one of the major energy traders in the Northeast. The NU system's regulated utilities furnish franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through three wholly owned subsidiaries: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another wholly owned subsidiary, North Atlantic Energy Corporation (NAEC), sells 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). A fifth wholly owned subsidiary, Holyoke Water Power Company (HWP), also is engaged in the production of electric power. A sixth wholly owned subsidiary, Yankee Energy System, Inc. (Yankee), the parent company of Yankee Gas Services Company (Yankee Gas), is Connecticut's largest natural gas distribution system. On November 30, 2001, Select Energy, Inc. (Select Energy) acquired Niagara Mohawk Energy Marketing, Inc. (NMEM) for $31.7 million. Assuming Select Energy and NMEM had been combined as of January 1, 2001, NU's operating revenues, income before extraordinary loss and cumulative effect of accounting change, net income, and total fully diluted earnings per share (EPS) would have been $7.4 billion, $255.5 million, $245.8 million, and $1.81, respectively, for the year ended December 31, 2001. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and the NU system is subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating subsidiaries are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. NU Enterprises, Inc. is a wholly owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries. These subsidiaries include Select Energy Services, Inc. (SES), a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; Northeast Generation Company (NGC), a corporation that acquires and manages generation facilities; Northeast Generation Services Company (NGS), a corporation that maintains and services any fossil or hydroelectric facility that is acquired or contracted with for fossil or hydroelectric generation services, and; Select Energy, a corporation engaged in the marketing, transportation, storage, and sale of energy commodities, at wholesale, in designated geographical areas and in the marketing of electricity to retail customers. Another subsidiary is Mode 1 Communications, Inc. (Mode 1), an investor in a fiber-optic communications network. Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to the NU system companies. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies. B. Presentation The consolidated financial statements of the NU system 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 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 Derivative Instruments: Effective January 1, 2001, NU adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. All derivative instruments have been identified and recorded at fair value effective January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships. For those contracts that do not meet the hedging requirements, the changes in fair value of those contracts were recognized currently in earnings. As explained in Note 9, commodity derivatives that are utilized for trading purposes are accounted for using the mark-to-market method, under Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." On June 27, 2001, the Financial Accounting Standards Board (FASB) cleared SFAS No. 133 Implementation Issue No. C15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity." Under Issue No. C15, power purchase or sales agreements, including capacity contracts, for the purchase or sale of electricity would qualify for the normal purchases and normal sales exception provided that certain criteria are met. The company has reviewed its capacity contracts and other applicable energy contracts and has determined that they should not be marked-to-market under the criteria in the guidance cleared by the FASB on June 27, 2001. On December 19, 2001, the FASB issued revised guidance regarding power purchase and sales agreements. The revised guidance is effective on July 1, 2002. Management is currently evaluating the impacts of the guidance issued by the FASB on December 19, 2001, on its accounting for capacity contracts, however, management does not expect it to have a material effect on its consolidated financial statements. Goodwill and Other Intangible Assets: In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This statement requires that goodwill and indefinite-lived intangible assets not be amortized effective January 1, 2002. This statement also requires that goodwill will be subject to at least an annual assessment for impairment by applying a fair value-based test also effective January 1, 2002. Based on the goodwill and intangible assets maintained by the NU system companies, management believes that upon adoption of SFAS No. 142, annual goodwill amortization expense will be reduced by $9 million. Management is in the process of the first assessment of impairment of goodwill and expects to complete this assessment by the June 30, 2002, deadline. Upon adoption of the impairment testing rules under SFAS No. 142, there may be a cumulative effect of an accounting change which management has not evaluated at this time. Asset Retirement Obligations: Also in June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and applies to (a) all entities and (b) legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of a long-lived asset, except for certain obligations of lessees. SFAS No. 143 is effective for NU's 2003 calendar year. Upon adoption of SFAS No. 143, there may be an impact on NU's consolidated financial statements which management has not estimated at this time. Long-Lived Assets: In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement modifies financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 is effective for NU's 2002 calendar year. Currently, management does not expect the adoption of SFAS No. 144 to have a material impact on NU's consolidated financial statements. D. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock in four regional nuclear companies (Yankee Companies). The NU system's ownership interests in the Yankee Companies at December 31, 2001 and 2000, which are accounted for on the equity method due to the NU system companies' ability to exercise significant influence over their operating and financial policies are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). The NU system's total equity investment in the Yankee Companies at December 31, 2001 and 2000, is $52.5 million and $62.5 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC was the only unit still in operation at December 31, 2001. Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership interest in Seabrook, a 1,148 megawatt nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook to PSNH under the Seabrook Power Contracts. CL&P and NAEC expect to sell their joint ownership interests in Seabrook around the end of 2002 through a public auction. Plant-in-service and the accumulated provision for depreciation for the NU system's share of Millstone 2 and 3 and Seabrook are as follows: --------------------------------------------------------------------- At December 31, --------------------------------------------------------------------- (Millions of Dollar) 2001 2000 --------------------------------------------------------------------- Plant-in-service: Millstone 2 $ -- $ 962.0 Millstone 3 -- 2,427.2 Seabrook 912.5 909.3 Accumulated provision for depreciation: Millstone 2 $ -- $ 953.6 Millstone 3 -- 2,214.3 Seabrook 840.6 821.3 ===================================================================== Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling $13.6 million and $15 million at December 31, 2001 and 2000, respectively, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. 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, 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 plant-in-service are equivalent to a composite rate of 3.1 percent in 2001 and 2000 and 3.3 percent in 1999. As a result of discontinuing the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation businesses in 1999, including CL&P's ownership interest in Seabrook, NU recorded a charge to accumulated depreciation for the nuclear plant in excess of the estimated fair market value at the time in the amount of approximately $2 billion and a corresponding regulatory asset was created. In 2000, HWP discontinued SFAS No. 71 and recorded a charge to accumulated depreciation for the plant in excess of fair value for certain hydroelectric generation assets, which was recorded as an extraordinary loss. These assets were sold in the fourth quarter of 2001. F. Revenues Regulated utility revenues are based on authorized rates applied to each customer's use of energy. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. Revenues for NU's competitive energy subsidiaries, including Select Energy and NGC, are recognized when the energy is delivered or service is provided. At the end of each accounting period, CL&P, PSNH, WMECO, Select Energy, and Yankee Gas accrue a revenue estimate for the amount of energy delivered but unbilled. G. Regulatory Accounting and Assets The accounting policies of the NU system regulated operating companies conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. CL&P's, PSNH's and WMECO'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 the NU system operating companies will recover their investments in long-lived assets, including regulatory assets. These costs will be recovered over a period of time ranging from 7 to 26 years, subject to certain adjustments. Stranded costs for CL&P and WMECO will be recovered through a transition charge over a 12-year period. PSNH has three categories of stranded costs. Part 1 costs are securitized regulatory assets that are recovered over the life of the rate reduction bonds. Part 2 costs are ongoing costs consisting of nuclear decommissioning and independent power producer costs that are recovered as incurred, over the time period PSNH is responsible for those costs. Part 3 costs are nonsecuritized regulatory assets which must be recovered by a recovery end date to be determined in accordance with the "Agreement to Settle PSNH Restructuring" (Settlement Agreement) or which will be written off as stipulated by that Settlement Agreement. Based on current projections, PSNH expects to fully recover all of its Part 3 costs by the recovery end date. In March 2000, CL&P and WMECO completed the auction of certain hydroelectric generation assets with a book value of $129 million. NGC was the winning bidder in the auction and paid approximately $865.5 million for these assets. Restructuring legislation in both Connecticut and Massachusetts requires gains from the sale of generation to be used to reduce regulatory assets and other stranded costs. Since the entities to the transaction are all wholly owned by NU, a gain was not recognized. In connection with this transaction, the remaining unamortized balance of the regulatory asset created of $654.5 million will be recovered over the next 24 years. This regulatory asset is not specifically earning a return in rates. Management continues to evaluate the recovery of this regulatory asset for impairment and has concluded the asset is not impaired at this time. In addition, all other remaining material regulatory assets are earning a return. The components of the NU system companies' regulatory assets are as follows: ------------------------------------------------------------------- At December 31, ------------------------------------------------------------------- (Millions of Dollars) 2001 2000 ------------------------------------------------------------------- Recoverable nuclear costs $ 894.5 $2,565.8 Securitized regulatory assets 2,004.1 -- Income taxes, net 312.8 504.7 Unrecovered contractual obligations 78.3 255.8 Recoverable energy costs, net 334.5 332.5 Other 326.2 252.0 ------------------------------------------------------------------- Totals $3,950.4 $3,910.8 =================================================================== As a result of discontinuing the application of SFAS No. 71 for CL&P's and WMECO's generation businesses, CL&P and WMECO had unamortized balances of $1.35 billion and $286.9 million, respectively, included in recoverable nuclear costs at December 31, 2000. These amounts were the result of reclassified nuclear plant in excess of its estimated fair market value from plant to regulatory assets, which took place in 1999. In March 2001, CL&P and WMECO sold their ownership interests in the Millstone units. The gain on these sales in the amount of approximately $521.6 million and $119.8 million, respectively, for CL&P and WMECO were used to offset recoverable nuclear costs, resulting in unamortized balances of $690.3 million and $130.7 million, respectively, after the current year's amortization expense. Also included in that regulatory asset component for 2001 and 2000 are $44.5 million and $449.2 million, respectively, which includes Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets ($44.5 million and $90.8 million, respectively) and the decommissioning and closure obligation ($358.4 million in 2000). Additionally, in March 2001, PSNH recorded a regulatory asset in conjunction with the sale of the Millstone units. The unamortized balance of $29 million as of December 31, 2001, is included in recoverable nuclear costs. In 2000, PSNH discontinued the application of SFAS No. 71 for its generation business, and created a regulatory asset for Seabrook over market generation, which was classified as recoverable nuclear costs. The unamortized balance of the regulatory asset created was $484.7 million as of December 31, 2000. In April 2001, PSNH issued rate reduction bonds in the amount of $525 million. PSNH used the majority of this amount to buydown its power contracts with NAEC. The Seabrook over market generation was securitized at that time and was reclassified as a securitized regulatory asset as of December 31, 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. WMECO, issued rate reduction certificates in the amount of $155 million in May of 2001 and used $99.7 million of those proceeds to buyout two 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, WMECO and PSNH, under the terms of contracts with the Yankee Companies, are responsible for their proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations was securitized in 2001 and is included in securitized regulatory assets. CL&P, PSNH, WMECO, and NAEC, under the Energy Policy Act of 1992 (Energy Act), are assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs through rates. As of December 31, 2001 and 2000, the NU system's total D&D Assessment deferrals were $35.4 million and $34.5 million, respectively, and have been recorded as recoverable energy costs, net. In addition, 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. Coincident with the start of restructuring, the energy adjustment clause was terminated. Energy costs deferred and not yet collected under the energy adjustment clause amounted to $59 million and $61.1 million at December 31, 2001 and 2000, respectively, which have been recorded as recoverable energy costs, net. In conjunction with the implementation of restructuring under the Settlement Agreement on May 1, 2001, the fuel and purchased-power adjustment clause (FPPAC) was discontinued. At December 31, 2001 and 2000, PSNH had $251.4 million and $230.1 million, respectively, of recoverable energy costs deferred under the FPPAC, including previous deferrals of purchases from independent power producers. Under the Settlement Agreement, the FPPAC deferrals are recovered as a Part 3 regulatory asset through a transition charge, subject to a prudence determination by the New Hampshire Public Utilities Commission (NHPUC). 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. 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) 2001 2000 ------------------------------------------------------------------- Accelerated depreciation and other plant-related differences $ 574.1 $ 756.0 Regulatory assets: Nuclear stranded investment 328.4 608.9 Securitized contract termination costs and other 279.7 -- Income tax gross-up 190.0 189.1 Other 119.2 31.5 ------------------------------------------------------------------- Totals $1,491.4 $1,585.5 =================================================================== 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. Accounting for Competitive Energy Contracts The accounting treatment for energy contracts entered into by Select Energy varies between contracts and depends primarily on the intended use of the particular contract. Contracts that are entered into to provide the normal purchase or sale of energy to customers are recorded at the point of delivery in accordance with accrual accounting. Contracts that are entered into to speculate in the commodity market are marked-to-market in accordance with EITF Issue No. 98-10 and recognized currently in earnings. Contracts that hedge the purchase or delivery of commodities are marked-to-market in accordance with SFAS No. 133 and earnings are deferred in other comprehensive income until the contracts are utilized. K. Other Income/(Loss), Net The components of the NU system companies' other income/(loss), net items are as follows: ------------------------------------------------------------------------ For the Years Ended December 31, ------------------------------------------------------------------------ (Millions of Dollars) 2001 2000 1999 ------------------------------------------------------------------------ Gain related to Millstone sale $ 189.3 $ -- $ -- Loss on share repurchase contracts (35.4) -- -- Other nuclear-related costs -- (17.9) (71.1) Other, net 33.7 3.6 (35.1) ------------------------------------------------------------------------ Totals $ 187.6 $ (14.3) $(106.2) ======================================================================== L. Supplemental Cash Flow Information In conjunction with the Yankee acquisition on March 1, 2000, common stock was issued and debt was assumed as follows (millions of dollars): ------------------------------------------------ Fair value of assets acquired, net of liabilities assumed $712.5 Cash paid (261.4) NU common stock issued (217.1) ------------------------------------------------ $234.0 ================================================ -------------------------------------------------------------------- For the Years Ended December 31, -------------------------------------------------------------------- (Millions of Dollars) 2001 2000 1999 -------------------------------------------------------------------- Cash paid during the year for: Interest, net of amounts capitalized $ 275.3 $ 269.7 $ 266.8 Income taxes $ 321.0 $ 253.4 $ 86.2 ==================================================================== Increase in obligations: Niantic Bay Fuel Trust and other capital leases $ 2.2 $ 8.1 $ 5.9 ==================================================================== 2. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by NU and the NU system operating companies is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. Currently, SEC authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $400 million, $375 million, $250 million, and $100 million, respectively. In addition, the charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. As of December 31, 2001, CL&P's charter permits CL&P to incur $535 million of additional unsecured debt. PSNH and NAEC are authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million and $260 million, respectively. Credit Agreements: Regulated Companies: On November 16, 2001, CL&P, PSNH, WMECO, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $350 million. This facility replaced a $250 million facility for CL&P and WMECO and a $60 million facility for Yankee Gas, both of which expired on November 16, 2001. CL&P may draw up to $150 million under the facility. PSNH, WMECO and Yankee Gas each may draw up to $100 million, subject to the $350 million maximum borrowing limit under the facility. Unless extended, the credit facility will expire on November 15, 2002. At December 31, 2001 and 2000, there were $160.5 million and $225 million, respectively, in borrowings under these facilities. NU Parent: To support the working capital needs of NU and its competitive energy subsidiaries, NU replaced its $400 million 364-day unsecured revolving credit facility which was to expire on November 16, 2001, with a 364-day unsecured revolving credit facility on November 16, 2001. This facility provides a total commitment of $300 million which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $300 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in notional amounts up to $200 million. Unless extended, this credit facility will expire on November 15, 2002. At December 31, 2001 and 2000, there were $40 million and $173 million, respectively, in borrowings under these facilities. With regard to credit support, NU had $45 million and $40 million, respectively, in letters of credit issued under these facilities at December 31, 2001 and 2000. NAEC: On November 9, 2001, NAEC entered into an unsecured 364-day term credit agreement for $90 million. This term credit agreement replaced a $200 million term credit agreement which expired on November 9, 2001. The term credit agreement contains a mandatory prepayment provision requiring 100 percent prepayment of the aggregate amount outstanding within two days of the sale of Seabrook. Unless extended, the term credit agreement will expire on November 8, 2002. At December 31, 2001 and 2000, there were $90 million and $200 million, respectively, in borrowings under these term credit agreements. Under the aforementioned credit agreements, the respective borrowers may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on the NU system companies' notes payable to banks outstanding on December 31, 2001 and 2000, was 3.38 percent and 8.85 percent, respectively. These credit agreements provide that the parties to these agreements must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios, consolidated debt ratios and interest coverage ratios. The parties to the credit agreements currently are and expect to remain in compliance with these covenants. Guarantees: NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its competitive energy subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of guarantees, and has applied for authority to increase this amount to $750 million. As of December 31, 2001, NU had provided approximately $268.2 million and $45 million of such guarantees and letters of credit, respectively. 3. Leases The NU system companies have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $13.1 million in 2001, $50.1 million in 2000, and $20.8 million in 1999. Interest included in capital lease rental payments was $4.7 million in 2001, $11.6 million in 2000, and $13.7 million in 1999. Operating lease rental payments charged to expense were $7 million in 2001, $10.1 million in 2000 and $7.5 million in 1999. Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2001 are as follows: ------------------------------------------------------------ (Millions of Dollars) Capital Operating Year Leases Leases ------------------------------------------------------------ 2002 $ 3.1 $ 23.7 2003 3.1 18.4 2004 3.0 15.5 2005 2.8 13.3 2006 2.7 11.1 After 2006 25.1 23.6 ------------------------------------------------------------ Future minimum lease payments 39.8 $105.6 Less amount representing interest 22.3 ------------------------------------------------------------ Present value of future minimum lease payments $ 17.5 ============================================================ 4. EMPLOYEE BENEFITS A. Pension Benefits and Postretirement Benefits Other Than Pensions The NU system companies, participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. The total pension credit, part of which was credited to utility plant, was $191.7 million in 2001, $97.9 million in 2000, and $33.7 million in 1999. In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, NU recorded $90.7 million in settlement and curtailment gains in 2001. This amount is included in the $191.7 million in pension credit recorded 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 nonbargaining unit employees who, by February 1, 2002, would be at least age 50, with a minimum of five years of credited service, and as of December 15, 2000, were assigned to certain groups and in eligible job classifications. One component of the VSP included special termination benefits equal to the greater of 5 years added to both age and credited service of eligible participants or two weeks pay for each year of service subject to a minimum level of 12 weeks and a maximum level of 52 weeks for eligible participants. The special termination benefits associated with the VSP approximated $93.3 million. The net of the settlement and curtailment gains and the special termination benefits was approximately $2.6 million, of which $7.5 million was included in earnings, $5.1 million was deferred as a regulatory liability and is expected to be returned to customers and $0.2 million was billed to the joint owners of Millstone and Seabrook. Currently, the NU system companies' 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. The NU system companies 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 the NU system 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. The NU system companies annually fund postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. 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) 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year $(1,670.9) $(1,516.6) $ (335.3) $ (306.8) Yankee merger -- (66.7) -- (9.9) Service cost (35.7) (41.2) (6.2) (7.6) Interest cost (119.7) (118.5) (27.2) (25.5) Employee contribution -- -- -- (0.1) Actuarial loss (72.2) (39.4) (76.2) (13.6) Benefits paid 228.3 109.5 38.0 27.5 Settlements and other (17.4) 2.0 6.9 0.7 ----------------------------------------------------------------------------------------------------------------- BENEFIT OBLIGATION AT END OF YEAR $(1,687.6) $(1,670.9) $ (400.0) $ (335.3) ----------------------------------------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at beginning of year $ 2,319.4 $ 2,330.2 $ 197.6 $ 170.7 Yankee merger -- 107.5 -- 16.1 Actual return on plan assets (100.7) (8.8) (17.1) 8.6 Employer contribution -- -- 28.6 29.6 Employee contribution -- -- -- 0.1 Benefits paid (228.3) (109.5) (38.0) (27.5) ----------------------------------------------------------------------------------------------------------------- FAIR VALUE OF PLAN ASSETS AT END OF YEAR $ 1,990.4 $ 2,319.4 $ 171.1 $ 197.6 ----------------------------------------------------------------------------------------------------------------- Funded status at December 31 $ 302.8 $ 648.5 $ (228.9) $ (137.7) Unrecognized transition (asset)/obligation (3.6) (5.8) 159.1 180.9 Unrecognized prior service cost 72.8 90.9 -- -- Unrecognized net (gain)/loss (139.6) (594.1) 55.4 (35.5) ----------------------------------------------------------------------------------------------------------------- PREPAID/(ACCRUED) BENEFIT COST $ 232.4 $ 139.5 $ (14.4) $ 7.7 =================================================================================================================
The following actuarial assumptions were used in calculating the plans' year end funded status:
----------------------------------------------------------------------------------------------- At December 31, ----------------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ----------------------------------------------------------------------------------------------- 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------- Discount rate 7.25% 7.50% 7.25% 7.50% Compensation/progression rate 4.25 4.50 4.25 4.50 Health care cost trend rate (a) N/A N/A 11.00 5.26 ===============================================================================================
(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 (credit)/cost are:
---------------------------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, ---------------------------------------------------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits ---------------------------------------------------------------------------------------------------------------------------------- (Millions of Dollars) 2001 2000 1999 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------------- Service cost $ 35.7 $ 41.2 $ 43.7 $ 6.2 $ 7.6 $ 7.6 Interest cost 119.7 118.5 106.3 27.2 25.5 21.8 Expected return on plan assets (214.1) (205.1) (175.5) (17.0) (15.3) (11.7) Amortization of unrecognized net transition (asset)/obligation (1.5) (1.4) (1.5) 14.5 15.1 15.1 Amortization of prior service cost 6.9 7.9 7.9 -- -- -- Amortization of actuarial gain (47.7) (52.4) (33.5) -- -- -- Other amortization, net -- -- -- (2.6) (4.3) (3.1) Settlements and other (90.7) (6.6) 18.9 11.9 -- -- ---------------------------------------------------------------------------------------------------------------------------------- NET PERIODIC BENEFIT (CREDIT)/COST $(191.7) $ (97.9) $ (33.7) $ 40.2 $ 28.6 $ 29.7 ==================================================================================================================================
For calculating pension and postretirement benefit costs, the following assumptions were used:
--------------------------------------------------------------------------------------------------------------------------------- For the Years Ended December 31, --------------------------------------------------------------------------------------------------------------------------------- Pension Benefits Postretirement Benefits --------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- Discount rate 7.50% 7.75% 7.00% 7.50% 7.75% 7.00% Expected long-term rate of return 9.50 9.50 9.50 N/A N/A N/A Compensation/progression rate 4.50 4.75 4.25 4.50 4.75 4.25 Long-term rate of return - Health assets, net of tax N/A N/A N/A 7.50 7.50 7.50 Life assets N/A N/A N/A 9.50 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 One Percentage Percentage Point Point (Millions of Dollars) Increase Decrease -------------------------------------------------------- Effect on total service and interest cost components $ 1.1 $ (1.0) Effect on postretirement benefit obligation $13.4 $(12.4) ======================================================== The trust holding the health plan assets is subject to federal income taxes. B. 401(k) Savings Plan NU maintains a 401(k) Savings Plan for substantially all NU system employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of 3 percent of eligible compensation with cash and NU stock. The matching contributions made by NU were $11.7 million in 2001, $13.6 million in 2000, and $13.8 million in 1999. C. ESOP NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in the NU system's 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were lent to the ESOP trust for the purchase of 10.8 million newly issued NU common shares (ESOP shares). The ESOP trust is obligated to make principal and interest payments on the ESOP notes at the same rate that ESOP shares are allocated to employees. NU makes annual contributions to the ESOP equal to the ESOP's debt service, less dividends received by the ESOP. All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the fourth quarter of 1999 through the second quarter of 2001, NU declared a $0.10 per share quarterly dividend. During the third quarter of 2001 through the fourth quarter of 2001, NU declared a $0.125 per share quarterly dividend. In 2001 and 2000, the ESOP trust issued 546,610 and 572,863 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. As of December 31, 2001 and 2000, the total allocated ESOP shares were 6,401,309 and 5,854,699, respectively, and total unallocated ESOP shares were 4,398,876 and 4,945,486, respectively. The fair market value of unallocated ESOP shares as of December 31, 2001 and 2000, was $77.6 million and $119.9 million, respectively. D. Stock-Based Compensation Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system has maintained an ESPP for all eligible employees. Under the ESPP, shares of NU common stock were purchased at 6-month intervals at 85 percent of the lower of the price on the first or last day of each 6-month period. Employees may purchase shares having a value not exceeding 25 percent of their compensation at the beginning of the purchase period. During 2000, employees purchased 199,520 shares at discounted prices ranging from $17.48 to $18.49. At December 31, 2000, 1,417,156 shares remained reserved for future issuance under the ESPP. Effective January 1, 2001, the ESPP was terminated because of the then pending merger. In the second quarter of 2001, a new ESPP was adopted by NU's Board of Trustees and approved by NU's shareholders. Shares under the new ESPP were issued in the first quarter of 2002. Incentive Plans: The NU system has long-term incentive plans authorizing various types of share-based awards, including stock options, to be made to eligible employees and board members. The exercise price of stock options, as set at the time of grant, is generally equal to the fair market value per share at the date of grant. Under the Northeast Utilities Incentive Plan (Incentive Plan), the number of shares which may be utilized for awards granted during a given calendar year may not exceed one percent of the total number of shares of NU common stock outstanding as of the first day of that calendar year. Stock option transactions for 1999, 2000 and 2001, including those options acquired in connection with the Yankee merger, are as follows:
----------------------------------------------------------------------------------------------------------------------------- Exercise Price Per Share --------------------------------------- Weighted Options Range Average ----------------------------------------------------------------------------------------------------------------------------- Outstanding December 31, 1998 1,233,678 $ 9.6250 -- $ 16.8125 $ 13.5213 Granted 644,123 $ 14.9375 -- $ 21.1250 $ 15.2514 Exercised (19,368) $ 16.3125 -- $ 16.8125 $ 16.3986 Forfeited (32,177) $ 14.9375 -- $ 16.3125 $ 15.8714 ----------------------------------------------------------------------------------------------------------------------------- Outstanding December 31, 1999 1,826,256 $ 9.6250 -- $ 21.1250 $ 14.0585 Granted 669,470 $ 18.4375 -- $ 22.2500 $ 18.7029 Yankee merger 10,167 $ 9.3640 -- $ 12.6888 $ 10.7653 Exercised (43,750) $ 14.9375 -- $ 19.5000 $ 16.0658 Forfeited (28,281) $ 14.9375 -- $ 19.5000 $ 16.6515 ----------------------------------------------------------------------------------------------------------------------------- Outstanding December 31, 2000 2,433,862 $ 9.3640 -- $ 22.2500 $ 15.2569 Granted 817,300 $ 17.4000 -- $ 21.0300 $ 20.2065 Exercised (108,779) $ 9.3640 -- $ 19.5000 $ 16.0970 Forfeited (132,467) $ 14.8750 -- $ 21.0300 $ 18.2217 ----------------------------------------------------------------------------------------------------------------------------- OUTSTANDING DECEMBER 31, 2001 3,009,916 $ 9.6250 -- $ 22.2500 $ 16.4467 ============================================================================================================================= Exercisable December 31, 1999 711,787 $ 9.6250 -- $ 21.1250 $ 14.0102 Exercisable December 31, 2000 1,298,339 $ 9.3640 -- $ 22.2500 $ 14.2021 ----------------------------------------------------------------------------------------------------------------------------- EXERCISABLE DECEMBER 31, 2001 1,712,260 $ 9.6250 -- $ 22.2500 $ 14.4650 =============================================================================================================================
For certain options that were granted in 2001 and 2000, and for the options that were granted in 1999, the vesting schedule for these options is ratably over three years from the date of grant. Other options granted in 2001 and 2000 vest 50 percent at the date of grant and 50 percent one year from the date of grant. Also under the Incentive Plan, the NU system awarded 91,120 of restricted shares in 1999. These shares have the same vesting schedule as the options granted under the Incentive Plan. The NU system has also made several small grants of restricted stock and other incentive-based stock compensation. During 2001, 2000 and 1999, $1.2 million, $1.9 million and $2.2 million, respectively, was expensed for stock-based compensation. Had compensation cost been determined for the ESPP and the Incentive Plan stock options under the fair value method as opposed to the intrinsic value method followed by the NU system, net income/(loss) and net income/(loss) per share would have been as follows: ---------------------------------------------------------------------------- (Millions of Dollars, except per share amounts) 2001 2000 1999 ---------------------------------------------------------------------------- Net income/(loss) $ 239.1 $ (33.9) $ 29.6 Basic income/(loss) per common share $ 1.76 $ (0.24) $ 0.23 Diluted income/(loss) per common share $ 1.76 $ (0.24) $ 0.22 ============================================================================ The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: ------------------------------------------------------------- 2001 2000 1999 ------------------------------------------------------------- Risk-free interest rate 5.34% 6.56% 5.69% Expected life 10 years 10 years 10 years Expected volatility 25.47% 26.15% 36.21% Expected dividend yield 2.11% 1.82% 1.89% ============================================================= The weighted average grant date fair values of options granted during 2001, 2000 and 1999 were $6.94, $7.50, and $6.79, respectively. As of December 31, 2001 and 2000, the weighted average remaining contractual lives for those options outstanding are 7.50 years and 7.92 years, respectively. 5. SALE OF CUSTOMER RECEIVABLES On July 11, 2001, CL&P renewed its accounts receivable securitization credit line for one year. At that time, the credit line capacity was reduced from $200 million to $100 million. As of December 31, 2001, CL&P had no amounts outstanding through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. As of December 31, 2000, CL&P had sold accounts receivable of $170 million to a third-party purchaser with limited recourse through the CRC. In addition, at December 31, 2000, $18.9 million of accounts receivable were designated as collateral under the agreement with the CRC. Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. 6. NUCLEAR GENERATION ASSETS DIVESTITURE On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc. (DNCI). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to DNCI. This sale included all of the respective joint ownership interests of CL&P, PSNH and WMECO in Millstone 3. The NU system received approximately $1.2 billion of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity at CL&P, PSNH and WMECO. As part of the sale, DNCI assumed responsibility for decommissioning the three Millstone units. In connection with the sale, CL&P and WMECO recorded a gain in the amount of $642 million which was used to offset stranded costs. Additionally, NU recorded an after-tax gain of $115.6 million related to the prior settlement of Millstone 3 joint owner claims. 7. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters Connecticut: On September 27, 2001, CL&P filed its application with the Connecticut Department of Public Utility Control (DPUC) for approval of the disposition of the proceeds from the sale of the Millstone units to DNCI. 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. There are certain contingencies related to this filing regarding the potential disallowance of what management believes were prudently incurred costs. Management believes the recoverability of these costs is probable. A decision from the DPUC is expected in the first half of 2002. New Hampshire: In July 2001, the NHPUC opened a docket to review the FPPAC cost accruals between August 2, 1999, and April 30, 2001. Hearings at the NHPUC are expected to be held during the spring of 2002. Under the Settlement Agreement, the FPPAC deferrals are recovered as a Part 3 regulatory asset through a stranded cost recovery charge. At December 31, 2001 and 2000, PSNH had $183.3 million and $145.9 million, respectively, of recoverable deferred energy costs deferred under the FPPAC, excluding previous deferrals of purchases from independent power producers. Management does not expect the outcome of these hearings to have a material impact on its earnings. Massachusetts: During the first quarter of 2000, WMECO filed its first annual stranded cost reconciliation filing covering the period March 1, 1998 through December 31, 1999. The hearing and briefing processes related to this filing were completed during the second quarter of 2001. A Massachusetts Department of Telecommunications and Energy (DTE) decision is expected in the first half of 2002. On March 30, 2001, WMECO also filed its second annual stranded cost reconciliation with the DTE for calendar year 2000 with the related review and hearing processes anticipated to be scheduled for the first half of 2002. The cumulative deferral of unrecovered stranded costs, as filed through calendar year 2000, is approximately $4 million. Management believes these costs are fully recoverable. WMECO is in the process of finalizing its 2001 annual transition cost reconciliation which is expected to be filed with the DTE on March 29, 2002. This filing reconciles the recovery of stranded generation costs for calendar year 2001. Also included in this filing are the sales proceeds from WMECO's portion of Millstone, the impact of securitization and an approximate $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process. The inclusion of these items as part of the reconciliation filing allows WMECO to accelerate the recovery of total stranded generation assets. Management anticipates a formal hearing in 2002 regarding this filing after a period of data discovery by the DTE and other intervenors. B. Environmental Matters The NU system 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, the NU system 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 the NU system 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 the NU system's financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 2001 and 2000, the liability recorded by the NU system for its estimated environmental remediation costs amounted to $46.2 million and $58.2 million, respectively. C. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. As of December 31, 2001 and 2000, fees due to the DOE for the disposal of Prior Period Fuel were $249.3 million and $240.3 million, respectively, including interest costs of $167.2 million and $158.2 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. NU remains responsible for fees to be paid for fuel burned until the divestiture of the Millstone and Seabrook nuclear units. D. Nuclear Insurance Contingencies Insurance policies covering the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. The NU system is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $4.3 million, $1.4 million and $6.7 million, respectively. In addition, insurance has been purchased in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the NU system could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system would be subject to an additional 5 percent, or $4.2 million, liability, in proportion to its ownership interests in each of its nuclear units. Based upon its ownership interest in Seabrook, the NU system's maximum liability, including any additional assessments, would be $34.9 million per incident, of which payments would be limited to $4.8 million per year. In addition, through purchased-power contracts with VYNPC, the NU system would be responsible for up to an additional assessment of $14.1 million per incident, of which payments would be limited to $1.6 million per year. NU expects to terminate its nuclear insurance upon the divestiture of its remaining nuclear units. E. Long-Term Contractual Arrangements Yankee Companies: Under the terms of their agreements, the NU system companies paid their 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. These costs were recorded as purchased-power expenses. The total cost of purchases under contracts with VYNPC amounted to $25.3 million in 2001, $24.9 million in 2000, and $29.2 million in 1999. VYNPC is in the process of selling its nuclear unit. Upon completion of the sale, it is expected that these long-term contracts will be replaced with different contracts with the new buyer. Energy Procurement Contracts: CL&P, PSNH and WMECO have entered into various arrangements for the purchase of capacity and energy. The total cost of purchases under these arrangements amounted to $363.9 million in 2001, $482.1 million in 2000 and $461.8 million in 1999. Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of gas in the normal course of business as part of its portfolio to meet its actual sales commitments. These contracts extend through 2006. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities. Estimated Annual Costs: The estimated annual costs of the NU system's significant long-term contractual arrangements, absent the effects of any contract terminations, buydowns or buyouts, or sales of generation assets are as follows:
----------------------------------------------------------------------------------------------------- (Millions of Dollars) 2002 2003 2004 2005 2006 Totals ----------------------------------------------------------------------------------------------------- VYNPC $ 30.9 $ 29.4 $ 33.5 $ 34.0 $ 30.8 $ 158.6 Energy Procurement Contracts 331.5 341.1 345.6 350.5 350.1 1,718.8 Gas Procurement Contracts 52.6 54.2 55.2 53.6 9.3 224.9 Hydro-Quebec 27.1 26.1 25.0 24.1 21.7 124.0 ----------------------------------------------------------------------------------------------------- Totals $ 442.1 $ 450.8 $ 459.3 $ 462.2 $ 411.9 $2,226.3 =====================================================================================================
Select Energy: Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $3.5 billion at December 31, 2001. These contracts extend through 2006 as follows: -------------------------------------------------------------- (Millions of Dollars) -------------------------------------------------------------- Year -------------------------------------------------------------- 2002 $ 2,416.2 2003 836.2 2004 145.9 2005 95.7 2006 34.8 -------------------------------------------------------------- Total $ 3,528.8 ============================================================== F. Consolidated Edison, Inc. Merger Litigation Certain gain and loss contingencies exist with regard to the litigation related to the merger agreement between NU and Consolidated Edison, Inc. For further information regarding this litigation, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Consolidated Edison, Inc. Merger Litigation." 8. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS Seabrook: Seabrook has a service life that is expected to end in 2026, and upon retirement, must be decommissioned. The NU system's ownership share of the estimated cost of decommissioning Seabrook, in year end 2001 dollars, is $222.5 million. Nuclear decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense and the accumulated provision for depreciation. Nuclear decommissioning expenses for Seabrook amounted to $7.8 million in 2001, $7.7 million in 2000 and $7.6 million in 1999. Through December 31, 2001 and 2000, total decommissioning expenses of $52.5 million and $44.7 million, respectively, have been collected from customers related to Seabrook and are reflected in the accumulated provision for depreciation. Payments for the NU system's ownership share of the cost of decommissioning Seabrook are paid to an independent decommissioning financing fund managed by the state of New Hampshire. As of December 31, 2001 and 2000, $52 million and $44.2 million, respectively, have been transferred to the Seabrook external decommissioning trust. Earnings on the decommissioning trust increase the decommissioning trust balance and the accumulated provision for depreciation. Unrealized gains and losses associated with the decommissioning trust also impact the balance of the trust and the accumulated provision for depreciation. The fair values of the amounts in the Seabrook external decommissioning trust were $61.7 million and $56.6 million at December 31, 2001 and 2000, respectively. Upon divestiture, the balance in the Seabrook decommissioning trust will be transferred to the buyer. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. The NU system's ownership share of estimated costs, in year end 2001 dollars, of decommissioning this unit is $75.4 million. In August 2001, VYNPC agreed to sell its nuclear generating unit for $180 million, including $35 million for nuclear fuel, to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the obligation to decommission the unit after it is taken out of service and agreed to provide the current level of output from the unit through 2012. The sale is subject to the approval of the Vermont Public Service Board, the Nuclear Regulatory Commission, the FERC and other regulatory authorities. The closing on the sale is expected to be in the first half of 2002. As of December 31, 2001 and 2000, NU's remaining estimated obligations, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down were $216.6 million and $244.6 million, respectively. 9. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS Competitive Energy Subsidiaries: Select Energy provides both firm requirement energy services to its customers and engages in energy trading and marketing activities. Select Energy manages its exposure to risk from existing contractual commitments and provides risk management services to its customers through forward contracts, futures, over-the-counter swap agreements, and options (commodity derivatives). Select Energy has utilized the sensitivity analysis methodology to disclose the quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Commodity Price Risk - Trading Activities: As a market participant in the Northeast United States, Select Energy conducts commodity-trading activities in electricity and its related products, natural gas and oil and, therefore, experiences net open positions. Select Energy manages these open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposure. Commodity derivatives utilized for trading purposes are accounted for using the mark-to-market method, under EITF Issue No. 98-10. Under this methodology, these instruments are adjusted to market value, and the unrealized gains and losses are recognized in income in the current period in the consolidated statements of income as fuel, purchased and net interchange power and in the consolidated balance sheets as prepayments and other. The mark-to-market positions at December 31, 2001 and 2000, were a positive $44.4 million and a positive $13.8 million, respectively. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at market, based on closing exchange prices. As of December 31, 2001, Select Energy has calculated the market price resulting from a 10 percent unfavorable change in forward market prices. That 10 percent change would result in approximately a $0.6 million decline in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in the sensitivity analysis above. Commodity Price Risk - Nontrading Activities: Select Energy utilizes derivative financial and commodity instruments (derivatives), including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas sold under firm commitments with certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply requirements. These derivative instruments have been designated as cash flow hedging instruments. When conducting sensitivity analysis of the change in the fair value of Select Energy's electricity, natural gas and oil nontrading portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair value of the contracts are determined from models which take into account estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange. Select Energy has determined a hypothetical change in the fair value for its nontrading electricity, natural gas and oil contracts, assuming a 10 percent unfavorable change in forward market prices. As of December 31, 2001, an unfavorable 10 percent change in forward market price would have resulted in a decrease in fair value of approximately $29 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's nontrading contracts on December 31, 2001, is not necessarily representative of the results that will be realized when these contracts are physically delivered. Select Energy also maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2004. Select Energy has hedged its gas supply risk under these agreements through NYMEX contracts. Under these contracts, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements, which extend through 2004. As of December 31, 2001, the NYMEX contracts had a notional value of $91.3 million and a negative after-tax mark-to-market position of $14.7 million. Derivative Cash Flow Hedge Accounting: Derivative instruments recorded which were effective cash flow hedges resulted in an increase in other comprehensive income of $12.3 million, net of tax, upon the adoption of SFAS No. 133. During 2001, a positive $4.5 million, net of tax, was reclassified from other comprehensive income upon the conclusion of these hedged transactions and recognized in earnings. An additional $1.3 million, net of tax, was recognized in earnings for those derivatives that were determined to be ineffective. Also, during 2001, new cash flow hedge transactions were entered into which hedge cash flows through 2027. As a result of these new transactions and market value changes since January 1, 2001, other comprehensive income decreased by $53.7 million, net of tax. Accumulated other comprehensive income at December 31, 2001, was a negative $36.9 million, net of tax (decrease to equity), relating to hedged transactions and it is estimated that $29.4 million, net of tax, will be reclassified as a charge to earnings within the next twelve months. Cash flows from the hedge contracts are reported in the same category as cash flows from the hedged assets. Credit Risk: NU serves a wide variety of customers and suppliers that include independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms. This multifaceted book of business requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process. Market risks are monitored regularly by a Risk Oversight Council operating outside of the units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies. NU tracks and re-balances the risk in its portfolio in accordance with mark-to-market and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. New York Mercantile Exchange (Exchange) traded futures and option contracts are guaranteed by the Exchange and have a modest credit risk. NU has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial conditions (including credit rating), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and theuse of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to NU entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact NU's overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. Regulated Entities: Interest Rate Risk - Nontrading Activities: NU manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. In addition, Yankee has entered into an interest rate sensitive derivative. Yankee uses swap instruments with financial institutions to exchange fixed-rate interest obligations to a blend between fixed and variable-rate obligations without exchanging the underlying notional amounts. These instruments convert fixed interest rate obligations to variable rates. The notional amounts parallel the underlying debt levels and are used to measure interest to be paid or received and do not represent the exposure to credit loss. As of December 31, 2001, Yankee had outstanding agreements with a total notional value of $48 million and a positive mark-to-market position of $0.2 million, which is included within the $36.9 million reported for accumulated other comprehensive income related to hedging activities. Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a master swap agreement with one customer to supply gas at fixed prices for a 10-year term extending through 2005. Under this master swap agreement, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreement, which extends through 2005. As of December 31, 2001, the commodity swap agreement had a notional value of $16.9 million and a negative mark-to-market position of $1.4 million, net of tax, which is included within the $36.9 million reported for accumulated other comprehensive income related to hedging activities. 10. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership in CL&P LP, as a general partner, and was the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture was eliminated, and the MIPS securities were accounted for as a minority interest. In the second quarter of 2001, CL&P repaid the $100 million in notes associated with the MIPS. 11. 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. Supplemental Executive Retirement Plan (SERP) Investments: Investments held for the benefit of the SERP are recorded at fair market value. The investments having a cost basis of $6.3 million and $6.5 million held for benefit of the SERP were recorded at their fair market values at December 31, 2001 and 2000, of $9 million and $10.1 million, respectively. Nuclear decommissioning trusts: The investments held in the NU system companies' nuclear decommissioning trusts were marked-to-market by a negative $2.5 million as of December 31, 2001, and a positive $117.6 million as of December 31, 2000, with corresponding offsets to the accumulated provision for depreciation. Preferred stock and long-term debt: The fair value of the NU system'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 the NU system's financial instruments and the estimated fair values are as follows: ------------------------------------------------------------ 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 795.9 847.2 Other long-term debt 1,552.1 1,554.6 Rate reduction bonds 2,018.4 2,061.8 ============================================================ ------------------------------------------------------------ At December 31, 2000 ------------------------------------------------------------ (Millions of Dollars) Carrying Amount Fair Value ------------------------------------------------------------ Preferred stock not subject to mandatory redemption $ 136.2 $ 159.9 Preferred stock subject to mandatory redemption 40.8 42.0 Long-term debt-- First mortgage bonds 1,008.1 1,012.5 Other long-term debt 1,342.2 1,290.6 MIPS 100.0 100.5 ============================================================ 12. OTHER COMPREHENSIVE INCOME The accumulated balance for each other comprehensive income item is as follows: ----------------------------------------------------------------------------- December 31, Current December 31, (Millions of Dollars) 2000 Period Change 2001 ----------------------------------------------------------------------------- Qualified cash flow hedging instruments $ -- $(36.9) $(36.9) Unrealized gains on securities 2.4 2.6 5.0 Minimum pension liability adjustments (0.6) -- (0.6) ----------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $ 1.8 $(34.3) $(32.5) ============================================================================= ----------------------------------------------------------------------------- December 31, Current December 31, (Millions of Dollars) 1999 Period Change 2000 ----------------------------------------------------------------------------- Qualified cash flow hedging instruments $ -- $ -- $ -- Unrealized gains on securities 2.1 0.3 2.4 Minimum pension liability adjustments (0.6) -- (0.6) ----------------------------------------------------------------------------- Accumulated other comprehensive income $ 1.5 $ 0.3 $ 1.8 ============================================================================= The changes in the components of other comprehensive income are reported net of the following income tax effects: ----------------------------------------------------------------------------- (Millions of Dollars) 2001 2000 1999 ----------------------------------------------------------------------------- Qualified cash flow hedging instruments $ 2.3 $ -- $ -- Unrealized gains on securities (1.9) (0.2) (0.1) Minimum pension liability adjustments -- -- -- ----------------------------------------------------------------------------- Accumulated other comprehensive income/ (loss) $ 0.4 $(0.2) $(0.1) ============================================================================ Accumulated other comprehensive income mark-to-market adjustments of NU's qualified cash flow hedging instruments are as follows: ------------------------------------------------------------------------------- (Millions of Dollars, Net of Tax) December 31, 2001 ------------------------------------------------------------------------------- Balance at January 1, 2001 (inception date) $ 12.3 ------------------------------------------------------------------------------- Hedged transactions recognized into earnings 4.5 Change in fair value (29.6) Cash flow transactions entered into for the period (24.1) ------------------------------------------------------------------------------- Net change associated with the current period hedging transactions (49.2) ------------------------------------------------------------------------------- Total mark-to-market adjustments included in accumulated other comprehensive loss $ (36.9) =============================================================================== 13. EARNINGS PER SHARE EPS is computed based upon the weighted average number of common shares outstanding during each year. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The following table sets forth the components of basic and diluted EPS:
---------------------------------------------------------------------------------------------------------------------------------- (Millions of Dollars, except share information) 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $ 273.2 $ 219.5 $ 57.0 Preferred dividends of subsidiaries 7.3 14.2 22.8 ---------------------------------------------------------------------------------------------------------------------------------- Income before extraordinary loss and cumulative effect of accounting change 265.9 205.3 34.2 Extraordinary loss, net of tax benefit -- (233.9) -- Cumulative effect of accounting change, net of tax benefit (22.4) -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net income/(loss) $ 243.5 $ (28.6) $ 34.2 ================================================================================================================================== Basic EPS common shares outstanding (average) 135,632,126 141,549,860 131,415,126 Dilutive effect of employee stock options 285,297 417,356 616,447 ---------------------------------------------------------------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 135,917,423 141,967,216 132,031,573 ---------------------------------------------------------------------------------------------------------------------------------- Basic earnings/(loss) per common share: Income before extraordinary loss and cumulative effect of accounting change $ 1.97 $ 1.45 $ 0.26 Extraordinary loss, net of tax benefit -- (1.65) -- Cumulative effect of accounting change, net of tax benefit (0.17) -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net income/(loss) $ 1.80 $ (0.20) $ 0.26 ================================================================================================================================== Fully diluted earnings/(loss) per common share: Income before extraordinary loss and cumulative effect of accounting change $ 1.96 $ 1.45 $ 0.26 Extraordinary loss, net of tax benefit -- (1.65) -- Cumulative effect of accounting change, net of tax benefit (0.17) -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net income/(loss) $ 1.79 $ (0.20) $ 0.26 ==================================================================================================================================
14. SEGMENT INFORMATION The NU system is organized between regulated utilities (electric and gas since March 1, 2000) and competitive energy subsidiaries. The regulated utilities segment represents approximately 68 percent and 85 percent of the NU system's total revenues for the years ended December 31, 2001 and 2000, respectively, and is comprised of several business units. Regulated utilities revenues primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. In 2001, the competitive energy subsidiaries segment had one customer with revenues in excess of 10 percent of its total revenues, CL&P. The purchases by CL&P represented approximately 22 percent, of total competitive energy subsidiaries' revenues for the year ended December 31, 2001. In 2000, the purchases by two customers, one unaffiliated company and CL&P, represented approximately 15 percent and 34 percent, respectively, of total competitive energy subsidiaries' revenues for the year ended December 31, 2000. The competitive energy subsidiaries segment in the following table includes SES, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; HWP, a company engaged in the production of electric power; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services any fossil or hydroelectric facility that is acquired or contracted with for fossil or hydroelectric generation services, and; Select Energy, a corporation engaged in the marketing, transportation, storage, and sale of energy commodities, at wholesale, in designated geographical areas and in the marketing of electricity to retail customers. Other in the following table includes the results for Mode 1, an investor in a fiber-optic communications network. Other also includes the results of the nonenergy related subsidiaries of Yankee. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations are also included in Other.
----------------------------------------------------------------------------------------------------------- For the Year Ended December 31, 2001 ----------------------------------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations ------------------- Energy and (Millions of Dollars) Electric Gas Subsidiaries Other Total ----------------------------------------------------------------------------------------------------------- Operating revenues $ 4,287.0 $ 378.0 $ 2,964.0 $ (755.2) $ 6,873.8 Operating expenses (3,795.5) (327.9) (2,919.1) 707.8 (6,334.7) ----------------------------------------------------------------------------------------------------------- Operating income/(loss) 491.5 50.1 44.9 (47.4) 539.1 Other income, net 72.8 4.1 5.8 104.9 187.6 Interest expense, net (199.3) (14.0) (42.9) (23.4) (279.6) Income tax expense (154.3) (14.3) (2.8) (2.5) (173.9) Preferred dividends (7.3) -- -- -- (7.3) ----------------------------------------------------------------------------------------------------------- Income before cumulative effect of accounting change 203.4 25.9 5.0 31.6 265.9 Cumulative effect of accounting change, net of tax benefit -- -- (22.0) (0.4) (22.4) ----------------------------------------------------------------------------------------------------------- Net income/(loss) $ 203.4 $ 25.9 $ (17.0) $ 31.2 $ 243.5 ----------------------------------------------------------------------------------------------------------- Total assets $ 8,730.3 $ 890.0 $ 1,017.9 $ (396.8) $10,241.4 ===========================================================================================================
-------------------------------------------------------------------------------------------------------- For the Year Ended December 31, 2000 -------------------------------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations ------------------- Energy and (Millions of Dollars) Electric Gas Subsidiaries Other Total -------------------------------------------------------------------------------------------------------- Operating revenues $ 4,738.5 $ 251.2 $ 1,894.9 $(1,008.0) $ 5,876.6 Operating expenses (4,078.1) (224.2) (1,830.0) 950.5 (5,181.8) -------------------------------------------------------------------------------------------------------- Operating income/(loss) 660.4 27.0 64.9 (57.5) 694.8 Other (loss)/income, net (11.6) (7.1) (4.7) 9.1 (14.3) Interest expense, net (191.9) (12.2) (53.4) (41.8) (299.3) Income tax expense (173.4) (6.5) (0.1) 18.3 (161.7) Preferred dividends (14.2) -- -- -- (14.2) -------------------------------------------------------------------------------------------------------- Income/(loss) before extraordinary loss 269.3 1.2 6.7 (71.9) 205.3 Extraordinary loss, net of tax benefit (214.2) -- (19.7) -- (233.9) -------------------------------------------------------------------------------------------------------- Net income/(loss) $ 55.1 $ 1.2 $ (13.0) $ (71.9) $ (28.6) -------------------------------------------------------------------------------------------------------- Total assets $ 9,620.0 $ 912.6 $ 684.1 $ (999.6) $10,217.1 ========================================================================================================
----------------------------------------------------------------------------------------------- For the Year Ended December 31, 1999 ----------------------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations ------------------- Energy and (Millions of Dollars) Electric Subsidiaries Other Total ----------------------------------------------------------------------------------------------- Operating revenues $3,846.1 $ 648.8 $ (23.7) $4,471.2 Operating expenses (3,241.4) (713.5) 9.1 (3,945.8) ---------------------------------------------------------------------------------------------- Operating income/(loss) 604.7 (64.7) (14.6) 525.4 Other (loss)/income, net (105.2) 5.6 (6.6) (106.2) Interest expense, net (245.5) (3.2) (14.9) (263.6) Income tax expense (150.9) 25.3 27.0 (98.6) Preferred dividends (22.8) -- -- (22.8) ---------------------------------------------------------------------------------------------- Net income/(loss) $ 80.3 $ (37.0) $ (9.1) $ 34.2 ---------------------------------------------------------------------------------------------- Total assets $9,302.6 $ 308.2 $ 77.3 $9,688.1 ==============================================================================================
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
----------------------------------------------------------------------------------------------------------------------------- Quarter Ended (a) (b) ----------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except per share information) March 31 June 30 September 30 December 31 ----------------------------------------------------------------------------------------------------------------------------- 2001 ----------------------------------------------------------------------------------------------------------------------------- Operating Revenues $ 1,800,544 $ 1,583,294 $ 1,723,894 $ 1,766,094 Operating Income 159,595 133,472 113,378 132,729 Income Before Cumulative Effect of Accounting Change 134,595 46,732 34,631 49,984 Cumulative Effect of Accounting Change, Net of Tax Benefit (22,432) -- -- -- ----------------------------------------------------------------------------------------------------------------------------- Net Income $ 112,163 $ 46,732 $ 34,631 $ 49,984 ============================================================================================================================= Basic Earnings/(Loss) per Common Share: Income Before Cumulative Effect of Accounting Change $ 0.93 $ 0.35 $ 0.26 $ 0.38 Cumulative Effect of Accounting Change, Net of Tax Benefit (0.15) -- -- -- ----------------------------------------------------------------------------------------------------------------------------- Net Income $ 0.78 $ 0.35 $ 0.26 $ 0.38 ============================================================================================================================= Diluted Earnings/(Loss) per Common Share: Income Before Cumulative Effect of Accounting Change $ 0.93 $ 0.35 $ 0.26 $ 0.38 Cumulative Effect of Accounting Change, Net of Tax Benefit (0.15) -- -- -- ----------------------------------------------------------------------------------------------------------------------------- Net Income $ 0.78 $ 0.35 $ 0.26 $ 0.38 ----------------------------------------------------------------------------------------------------------------------------- 2000 ----------------------------------------------------------------------------------------------------------------------------- Operating Revenues $ 1,382,321 $ 1,414,973 $ 1,581,947 $ 1,497,379 Operating Income 197,834 146,537 177,343 173,079 Income Before Extraordinary Loss 74,587 12,206 65,543 52,959 Extraordinary Loss, Net of Tax Benefit -- -- -- (233,881) ----------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 74,587 $ 12,206 $ 65,543 $ (180,922) ============================================================================================================================= Basic Earnings/(Loss) Per Common Share: Income Before Extraordinary Loss $ 0.55 $ 0.09 $ 0.46 $ 0.37 Extraordinary Loss, Net of Tax Benefit -- -- -- (1.63) ----------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 0.55 $ 0.09 $ 0.46 $ (1.26) ============================================================================================================================= Diluted Earnings/(Loss) Per Common Share: Income Before Extraordinary Loss $ 0.55 $ 0.08 $ 0.45 $ 0.37 Extraordinary Loss, Net of Tax Benefit -- -- -- (1.63) ----------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 0.55 $ 0.08 $ 0.45 $ (1.26) =============================================================================================================================
(a) Certain reclassifications of prior years' data have been made to conform with the current year's presentation. (b) Summation of quarterly data may not equal annual data due to rounding. SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
---------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except percentages and share information) 2001 2000 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET DATA: Property, Plant and Equipment, Net $ 3,822,139 $ 3,547,215 $ 3,947,434 $ 6,170,881 $ 6,463,158 Total Assets 10,241,409 10,217,149 9,688,052 10,387,381 10,414,412 Total Capitalization (a) 4,576,858 4,739,417 5,216,456 6,030,402 6,472,504 Obligations Under Capital Leases (a) 17,539 159,879 181,293 209,279 207,731 ---------------------------------------------------------------------------------------------------------------------------------- INCOME DATA: Operating Revenues $ 6,873,826 $ 5,876,620 $ 4,471,251 $ 3,767,714 $ 3,834,806 Income/(Loss) Before Extraordinary Loss and Cumulative Effect of Accounting Change, Net of Tax Benefits 265,942 205,295 34,216 (146,753) (129,962) Extraordinary Loss, Net of Tax Benefit -- (233,881) -- -- -- Cumulative Effect of Accounting Change, Net of Tax Benefit (22,432) -- -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 243,510 $ (28,586) $ 34,216 $ (146,753) $ (129,962) ================================================================================================================================== COMMON SHARE DATA: Basic Earnings/(Loss) Per Common Share: Income/(Loss) Before Extraordinary Loss and Cumulative Effect of Accounting Change, Net of Tax Benefits $ 1.97 $ 1.45 $ 0.26 $ (1.12) $ (1.01) Extraordinary Loss, Net of Tax Benefit -- (1.65) -- -- -- Cumulative Effect of Accounting Change, Net of Tax Benefit (0.17) -- -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 1.80 $ (0.20) $ 0.26 $ (1.12) $ (1.01) ================================================================================================================================== Fully Diluted Earnings/(Loss) per Common Share: Income/(Loss) Before Extraordinary Loss and Cumulative Effect of Accounting Change, Net of Tax Benefits $ 1.96 $ 1.45 $ 0.26 $ (1.12) $ (1.01) Extraordinary Loss, Net of Tax Benefit -- (1.65) -- -- -- Cumulative Effect of Accounting Change, Net of Tax Benefit (0.17) -- -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net Income/(Loss) $ 1.79 $ (0.20) $ 0.26 $ (1.12) $ (1.01) ================================================================================================================================== Basic Common Shares Outstanding (Average) 135,632,126 141,549,860 131,415,126 130,549,760 129,567,708 Fully Diluted Common Shares Outstanding (Average) 135,917,423 141,967,216 132,031,573 130,549,760 129,567,708 Dividends Per Share $ 0.45 $ 0.40 $ 0.10 $ -- $ 0.25 Market Price - Closing (high) (c) $ 23.75 $ 24.25 $ 22.00 $ 17.25 $ 14.25 Market Price - Closing (low) (c) $ 16.80 $ 18.25 $ 13.56 $ 11.69 $ 7.63 Market Price - Closing (end of year) (c) $ 17.63 $ 24.25 $ 20.56 $ 16.00 $ 11.81 Book Value Per Share (end of year) $ 16.27 $ 15.43 $ 15.80 $ 15.63 $ 16.67 Rate of Return Earned on Average Common Equity (%) 11.2 (1.3) 1.6 (7.0) (5.8) Market-to-Book Ratio (end of year) 1.1 1.6 1.3 1.0 0.7 ---------------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION: Common Shareholders' Equity 46% 47% 40% 34% 34% Preferred Stock (a) (b) 3 4 5 5 6 Long-Term Debt (a) 51 49 55 61 60 ---------------------------------------------------------------------------------------------------------------------------------- 100% 100% 100% 100% 100% ==================================================================================================================================
(a) Includes portions due within one year. (b) Excludes $100 million of MIPS. (c) Market price information reflects closing prices as presented in the Wall Street Journal. CONSOLIDATED ELECTRIC SALES STATISTICS (UNAUDITED)
------------------------------------------------------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------ REVENUES: (THOUSANDS) Residential $ 1,490,487 $1,469,439 $1,517,913 $1,475,363 $1,499,394 Commercial 1,303,351 1,256,126 1,272,969 1,273,146 1,266,449 Industrial 549,808 566,625 560,801 568,913 560,782 Other Utilities 2,663,930 1,884,082 926,056 336,623 329,764 Streetlighting and Railroads 43,889 45,998 45,564 47,682 48,867 Nonfranchised Sales (438) 16,932 24,659 22,479 21,476 Miscellaneous 115,196 96,666 52,357 16,429 47,446 ------------------------------------------------------------------------------------------------------------------------------ Total Electric 6,166,223 5,335,868 4,400,319 3,740,635 3,774,178 Gas 566,814 461,716 -- -- -- Other 140,789 79,036 70,932 27,079 60,628 ------------------------------------------------------------------------------------------------------------------------------ Total $ 6,873,826 $5,876,620 $4,471,251 $3,767,714 $3,834,806 ============================================================================================================================== SALES: (kWh - MILLIONS) Residential 13,322 12,940 12,912 12,162 12,099 Commercial 13,751 13,023 12,850 12,477 12,091 Industrial 6,790 7,130 7,050 6,948 6,801 Other Utilities 51,789 42,127 33,575 9,742 8,034 Streetlighting and Railroads 332 333 314 320 318 Nonfranchised Sales -- 107 147 193 241 ------------------------------------------------------------------------------------------------------------------------------ Total 85,984 75,660 66,848 41,842 39,584 ============================================================================================================================== CUSTOMERS: (AVERAGE) Residential 1,610,154 1,576,068 1,569,932 1,555,013 1,535,134 Commercial 171,218 166,114 164,932 162,500 159,350 Industrial 7,730 7,701 7,721 7,847 7,804 Other 3,969 3,917 3,908 3,890 3,929 ------------------------------------------------------------------------------------------------------------------------------ Total Electric 1,793,071 1,753,800 1,746,493 1,729,250 1,706,217 Gas 190,998 185,328 -- -- -- ------------------------------------------------------------------------------------------------------------------------------ Total 1,984,069 1,939,128 1,746,493 1,729,250 1,706,217 ============================================================================================================================== AVERAGE ANNUAL USE PER RESIDENTIAL CUSTOMER (kWh) 8,251 8,233 8,243 7,799 7,898 ============================================================================================================================== AVERAGE ANNUAL BILL PER RESIDENTIAL CUSTOMER $ 923.70 $ 934.94 $ 969.38 $ 946.80 $ 978.72 ============================================================================================================================== AVERAGE REVENUE PER kWh: Residential 11.20(cent) 11.36(cent) 11.76(cent) 12.14(cent) 12.39(cent) Commercial 9.48 9.65 9.91 10.20 10.47 Industrial 8.10 7.95 7.95 8.19 8.25 ==============================================================================================================================