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NSTAR 10-K 2005
FORM 10-K
Table of Contents

 

UNITED STATES SECURITIES AND

EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2004

 

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     

 

Commission file number 1-14768

 

NSTAR

(Exact name of registrant as specified in its charter)

 

Massachusetts   04-3466300
(State or other jurisdiction of incorporation or organization)   (IRS Employer Identification Number)
800 Boylston Street, Boston, Massachusetts   02199
(Address of principal executive offices)   (Zip code)

 

(617) 424-2000

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class


 

Name of each exchange on which registered


Common Shares, Par Value $1 per share  

New York Stock Exchange

Boston Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

x  Yes    ¨  No

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

x  Yes    ¨  No

 

The aggregate market value of the 53,118,873 shares of voting stock of the registrant held by non-affiliates of the registrant, computed as the average of the high and low market prices of the common shares as reported on the New York Stock Exchange consolidated transaction reporting system for NSTAR Common Shares as of the last business day of the registrant’s most recently completed second fiscal quarter: $2,543,331,639.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:

 

Class


 

Outstanding at February 18, 2005


Common Shares, $1 par value   53,336,360 Shares

 

Documents Incorporated by Reference

 

Sections of NSTAR’s Definitive Proxy Statement for the 2005 Annual Meeting of Shareholders to be held on April 28, 2005 are incorporated by reference into Parts I and III of this Form 10-K.

 



Table of Contents

NSTAR

 

Form 10-K Annual Report - December 31, 2004

 

          Page

     Part I     

Item 1.

  

Business

   2

Item 2.

  

Properties

   9

Item 3.

  

Legal Proceedings

   10

Item 4.

  

Submission of Matters to a Vote of Security Holders

   10

Item 4A.

  

Executive Officers of the Registrant

   10
     Part II     

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   11

Item 6.

  

Selected Consolidated Financial Data

   12

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   14

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   44

Item 8.

  

Financial Statements and Supplementary Data

   45

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   84

Item 9A.

  

Controls and Procedures

   84

Item 9B.

  

Other Information

   84
     Part III     

Item 10.

  

Trustees and Executive Officers of the Registrant

   85

Item 11.

  

Executive Compensation

   85

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management

   85

Item 13.

  

Certain Relationships and Related Transactions

   85

Item 14.

  

Principal Accountant Fees and Services

   85
     Part IV     

Item 15.

  

Exhibits and Financial Statement Schedules

   86

Signatures

   91

 

Important Shareholder Information

 

NSTAR files its Forms 10-K, 10-Q and 8-K reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may access materials NSTAR has filed with the SEC on the SEC’s website at www.sec.gov. In addition, NSTAR’s Board of Trustees has various committees, including an Audit, Finance and Risk Management Committee, an Executive Personnel Committee and a Board Governance and Nominating Committee. The Board also has a standing Executive Committee. The Board has adopted the NSTAR Board of Trustees Corporate Guidelines on Significant Corporate Governance Issues, a Code of Ethics for the Principal Executive Officer, General Counsel, and Senior Financial Officers, and a Code of Ethics and Business Conduct for Directors, Officers and Employees. NSTAR’s SEC filings and Corporate Governance documents, including charters, guidelines and codes, and any amendments to such charters, guidelines and codes that are applicable to NSTAR’s executive officers, senior financial officers or trustees can be accessed free of charge on NSTAR’s website at www.nstaronline.com. Copies of NSTAR’s SEC filings may also be obtained by writing or calling NSTAR’s Investor Relations Department at the address or phone number on the cover of this Form 10-K.

 

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Table of Contents

Part I

 

Item 1. Business

 

(a) General Development of Business

 

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy). NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2004, 2003 and 2002.

 

(b) Financial Information about Industry Segments

 

NSTAR’s principal operating segments are the electric and natural gas utility operations that provide energy delivery services in 107 cities and towns in Massachusetts and its unregulated operations. Refer to Note N of the accompanying Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data” for specific financial information related to NSTAR’s electric utility, gas utility and unregulated operating segments.

 

(c) Narrative Description of Business

 

Principal Products and Services

 

NSTAR Electric

 

NSTAR Electric currently supplies electricity at retail to an area of 1,702 square miles. The territory served includes the City of Boston and 80 surrounding cities and towns, including Cambridge, New Bedford, and Plymouth and the geographic area comprising Cape Cod and Martha’s Vineyard. The population of this area is approximately 2.3 million.

 

NSTAR Electric’s operating revenues and energy sales percentages by customer class for the years 2004, 2003 and 2002 consisted of the following:

 

     Revenues ($)

    Energy Sales (MWH)

 
     2004

    2003

    2002

    2004

    2003

    2002

 

Retail:

                                    

Commercial

   54 %   54 %   52 %   59 %   59 %   56 %

Residential

   39 %   38 %   37 %   31 %   31 %   29 %

Industrial and other

   6 %   7 %   8 %   9 %   9 %   10 %

Wholesale and contract sales

   1 %   1 %   3 %   1 %   1 %   5 %

 

Retail Electric Rates

 

Retail electric delivery rates are established by the Massachusetts Department of Telecommunications and Energy (MDTE) and are composed of:

 

    distribution charges, which include a fixed customer charge and energy and demand charges (to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating and maintenance costs),

 

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    a transition charge (to collect costs primarily for previously held investments in generating plants and costs related to above market power contracts),

 

    a transmission charge (to collect the cost of moving the electricity over high voltage lines from generating plants to substations located within NSTAR’s service area),

 

    an energy conservation charge (an MDTE - mandated charge to collect costs for demand-side management programs) and

 

    a renewable energy charge (an MDTE - mandated charge to collect the cost to support the development and promotion of renewable energy projects).

 

Beginning in 2004, rates applicable to NSTAR’s regulated electric utilities were increased to reflect the implementation of a rate mechanism to collect pension and postretirement benefit obligations other than pension (PBOP) costs on a fully reconciling basis. Refer to the accompanying Consolidated Financial Statements, Note I, for more detail.

 

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore, effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be provided default service, which will be designated basic service thereafter. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2004, 2003 and 2002, customers of NSTAR Electric had approximately 24%, 26% and 27%, respectively, of their load requirements provided by competitive suppliers.

 

Sources and Availability of Electric Power Supply

 

For default service power supply, NSTAR Electric makes periodic market solicitations consistent with provisions of the Restructuring Act and MDTE orders. During 2004, NSTAR Electric entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to its largest customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than to these large customers, for the second-half of 2005. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2005. A Request for Proposals will be issued quarterly in 2005 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. For 2004, NSTAR Electric entered into agreements ranging in length from three to twelve-months effective January 1, 2004 through December 31, 2004 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE.

 

For standard offer service power supply, NSTAR Electric has contracted with third party suppliers to provide 100% of its obligation through February 28, 2005, the date when standard offer service ends and all load migrates to either default service or competitive supply. NSTAR Electric is fully recovering its payments to suppliers through MDTE-approved rates billed to customers. NSTAR Electric, during 2004, entered into several agreements to buy-out or restructure certain of its long-term power purchase contracts. Refer to the accompanying Consolidated Financial Statements, Note O, for more detail.

 

NSTAR Electric’s load for 2004 reached a peak demand of 4,254 megawatts (MW) on August 30, which was 3.6% less than the all-time peak demand level of 4,415 MW established in 2002.

 

Wholesale Market Rule Changes

 

Standard Market Design (SMD)

 

Pursuant to orders issued by the Federal Energy Regulatory Commission (FERC), wholesale electric markets in New England have been operating under SMD since March 1, 2003. Under SMD, generators are dispatched on a

 

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least cost basis until the generation dispatched equals the amount of energy required. The clearing price is set at the price of the next available megawatt of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when transmission constraints prevent the lower cost generation from moving from one load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). NSTAR Electric’s service territory covers two of the eight load zones in New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is import-constrained and SEMA is export-constrained. The majority of NSTAR’s customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher LMP than SEMA. As part of SMD, load-serving entities, like NSTAR Electric, were granted proceeds from the auction of “financial transmission rights” that is conducted by the Independent System Operator (ISO-NE). NSTAR Electric uses these proceeds to mitigate costs to customers.

 

Locational Installed Capacity (LICAP)

 

The ISO-NE has proposed a new market rule designed to compensate wholesale generators for their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in New England, to count towards a LSE’s obligation, regardless of load zone. At this point, it appears likely that NSTAR’s new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to converge, which could ultimately render this locational aspect of LICAP a non-factor for NSTAR customers. (Refer to “Capital Expenditures and Financings” section for more information on NSTAR’s 345kV transmission project). However, since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of power to NSTAR’s customers. The proposed LICAP market rules are contentious and are currently being litigated at FERC and in the courts. A final FERC ruling on the issue is expected in 2005 and the current schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, NSTAR cannot predict the actual impact these changes will have on NSTAR Electric and its customers.

 

Regional Transmission Organization (RTO)

 

On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including NSTAR Electric. The filing requested an increase in the base ROE component of the regional and local transmission rates, to be provided under the Regional Transmission Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New England is provided under a two-tier structure, with the potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50 basis points in regional rates as an incentive for joining an RTO for regional service. In addition, FERC has also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. The Transmission Owners maintain that sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law judge and were unsuccessful. Hearings on the base ROE and 100 basis point adder began in January 2005.

 

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The joint ROE filing among the Transmission Owners was made in connection with the proposed formation of RTO-NE by the Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including NSTAR Electric, which resolved many issues left outstanding from FERC’s March 2004 Order conditionally approving the formation of RTO-NE. The November 3rd Order also provided clarification of certain aspects of the March 2004 Order regarding the Transmission Owners’ request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and the Transmission Owners’ proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. Finally, the November 3rd Order required the satisfaction of several ministerial conditions before ISO-NE could begin to operate as an RTO. ISO-NE and the Transmission Owners have since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the ISO-NE is an independent entity, without a financial interest in the region’s marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as NSTAR Electric and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE’s interactions with market participants and merchant transmission facilities. NSTAR’s management cannot estimate the impact of the RTO on the Company.

 

NSTAR Gas

 

NSTAR Gas distributes natural gas to approximately 300,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1.2 million. Twenty-five of these communities are also served with electricity by NSTAR Electric. Some of the larger communities served by NSTAR Gas include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston.

 

NSTAR Gas’ operating revenues and energy sales percentages by customer class for the years 2004, 2003 and 2002, consisted of the following:

 

     Revenues ($)

    Energy Sales (therms)

 
     2004

    2003

    2002

    2004

    2003

    2002

 

Gas Sales and Transportation:

                                    

Residential

   61 %   61 %   64 %   45 %   47 %   42 %

Commercial

   25 %   25 %   21 %   33 %   33 %   34 %

Industrial and other

   9 %   10 %   9 %   17 %   17 %   19 %

Off-System and contract sales

   5 %   4 %   6 %   5 %   3 %   5 %

 

Natural Gas Rates

 

NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers do not materially affect NSTAR Gas’ operating income because substantially the entire margin on such service is returned to its firm customers as cost reductions.

 

In addition to delivery service rates, NSTAR Gas’ tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas

 

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supply costs from firm sales customers and default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. In addition, NSTAR Gas is required to file interim changes to its CGAC factor when the actual costs of gas supply vary from projections by more than 5%.

 

Beginning in 2004, NSTAR Gas’ rates were increased to reflect the implementation of a rate mechanism to collect pension and PBOP costs on a fully reconciling basis. Refer to the Consolidated Financial Statements, Note I, for more detail.

 

Effective November 1, 2000, the MDTE approved regulations that expand the choice of gas suppliers to all customers of local gas distribution companies (LDCs) such as NSTAR Gas. The regulations established a five-year transition period and a three-year review of market conditions to determine whether the supply market has become sufficiently competitive to warrant removal or modification of the LDC’s service obligation with respect to planning and procurement. To meet the requirements of the regulations, NSTAR Gas has modified its billing, customer and gas supply systems to accommodate full retail choice. The MDTE previously had approved the compliance process submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. Among the important provisions are: setting the LDC as the default service provider, certification of competitive suppliers/marketers, extension of the MDTE’s consumer protection rules to residential customers taking competitive service, requirement for LDCs to provide suppliers/marketers with customers usage data, and requirement for suppliers/marketers to disclose service terms to potential customers. The MDTE has also ruled on requiring the mandatory assignment of the LDC’s upstream pipeline and storage capacity and downstream peaking capacity to customers who elect a competitive gas supply. This eliminates potential stranded cost exposure for the LDCs for the five-year transition period. In January 2004, the MDTE opened a new docket to determine whether the upstream capacity market is sufficiently competitive to warrant the voluntary assignment of interstate pipeline capacity to other entities. Such a determination could modify the mandatory approach to capacity assignment established in November 2000. NSTAR cannot predict or anticipate the outcome of this process or its impact on NSTAR or its customers.

 

Gas Supply, Transportation and Storage

 

NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services.

 

NSTAR Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that bring gas from major producing regions in the U.S., Gulf of Mexico and Canada to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its gas supply from third-party vendors, primarily under firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil producers. Based on its firm pipeline transportation capacity entitlements, NSTAR Gas contracts for up to 140,309 million British thermal units (MMbtu) per day of domestic production. In addition, NSTAR Gas has an agreement for up to 4,500 MMbtu per day of Canadian supplies.

 

In addition to the firm transportation and gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and liquefied natural gas (LNG) facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas’ distribution system and are used to liquefy and store pipeline gas during the warmer months for use during the heating season. The underground storage contracts are a combination of existing and new agreements that are the result of FERC Order 636 service unbundling. During the summer injection season, excess pipeline capacity is used to deliver and store gas in market area storage facilities, located in the New York and Pennsylvania region. Stored gas is withdrawn during the winter season to supplement pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm storage capacity entitlements of nearly 8.0 billion cubic feet (Bcf).

 

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A portion of the storage of gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly owned subsidiary of NSTAR. The facility in Hopkinton, Massachusetts consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 Bcf of natural gas.

 

In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 0.5 Bcf of natural gas that are filled with LNG trucked from the Hopkinton facility or purchased from third parties.

 

Based upon information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, NSTAR Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales.

 

Franchises

 

Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines or gas distribution lines and gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the MDTE and the municipality so affected.

 

Unregulated Operations

 

NSTAR’s unregulated operations segment engages in businesses that include district energy operations, telecommunications and liquefied natural gas service. District energy operations are principally provided through its Advanced Energy Systems, Inc. (AES) subsidiary that generates chilled water, steam and electricity for use by hospitals and teaching facilities located in Boston’s Longwood Medical Area. AES expanded its Medical Area Total Energy Plant (MATEP) facility in 2003 to provide additional capacity. NSTAR Steam also supplies steam to customers in Cambridge. Telecommunications services are provided through NSTAR Com, which installs, owns, operates and maintains a wholesale transport network for other telecommunications service providers in the metropolitan Boston area to deliver voice, video, data and internet services to customers. Liquefied natural gas service is provided by Hopkinton LNG Corp. Revenues earned from NSTAR’s unregulated operations account for approximately 4% of consolidated operating revenues in 2004, 2003 and 2002.

 

RCN Joint Venture, Investment Conversion and Abandonment

 

Beginning in 1997, NSTAR Com participated in a telecommunications venture with RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN Corporation (RCN). As part of the Joint Venture Agreement, NSTAR Com had the option to exchange portions of its joint venture interest for common shares of RCN at specified periods. NSTAR Com exercised this option and exchanged its entire joint venture interest for common shares of RCN over several years through 2002. As of December 31, 2002, NSTAR Com no longer participated in the joint venture but held approximately 11.6 million common shares of RCN. On December 24, 2003, NSTAR abandoned its common shares of RCN.

 

Regulation

 

NSTAR is a holding company exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended, except Section 9(c)(2) relating to SEC approval of certain acquisitions of securities of public utility or public utility holding companies.

 

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NSTAR Electric, NSTAR Gas, and Boston Edison’s wholly owned regulated subsidiary, Harbor Electric Energy Company, operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, natural gas and financing and investing activities. In addition, the FERC has jurisdiction over various phases of NSTAR Electric and NSTAR Gas utility businesses, including rates for electricity and natural gas sold at wholesale, facilities used for the transmission or sale of that energy, certain issuances of short-term debt and regulation of accounting.

 

Capital Expenditures and Financings

 

The most recent estimates of capital expenditures and long-term debt maturities for the years 2005 through 2009 are as follows:

 

(in thousands)


   2005

   2006

   2007

   2008

   2009

Capital expenditures

   $ 398,000    $ 313,000    $ 275,000    $ 240,000    $ 240,000

Long-term debt

   $ 149,245    $ 248,024    $ 83,218    $ 85,629    $ 75,962

 

Capital expenditures include costs related to NSTAR’s 345kV transmission project that in the aggregate is expected to total approximately $200 million. A significant portion of these costs will be incurred in 2005 and 2006. NSTAR has obtained regulatory approval to construct a 345 kV transmission line from Stoughton, Massachusetts, a southern suburb of Boston, to South Boston in order to assure continued reliability of service and improve power import capacity in the Northeast Massachusetts area (NEMA). Construction is set to begin in the first quarter of 2005, subject to final permitting. The entire new transmission line is anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost will be shared by all of New England and recovered by NSTAR through wholesale and retail transmission rates.

 

Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. Refer to the “Cautionary Statement” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Plant expenditures in 2004 were approximately $313 million and consisted primarily of additions to NSTAR’s distribution and transmission systems. The majority of these expenditures were for system reliability and performance improvements, customer service enhancements and capacity expansion to meet long-range growth in the NSTAR service territory.

 

Refer to the “Liquidity and Capital Resources” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information regarding capital resources to fund NSTAR’s construction programs.

 

Seasonal Nature of Business

 

NSTAR Electric’s kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. NSTAR Gas’ sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. Refer to the “Selected Quarterly Consolidated Financial Data” section in Item 6, “Selected Consolidated Financial Data” for specific financial information by quarter for 2004 and 2003.

 

Competitive Conditions

 

The electric and natural gas industries, in general, have continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These pressures have resulted in an increasing trend in the industry to seek efficiencies and other benefits through business combinations. NSTAR operates in this marketplace by combining the resources of its utility subsidiaries activities in the transmission and distribution of energy.

 

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Environmental Matters

 

NSTAR’s subsidiaries are subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. Refer to the “Contingencies - Environmental Matters” section in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

 

Management believes that its facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements.

 

Number of Employees

 

As of December 31, 2004, NSTAR had approximately 3,100 employees, including approximately 2,200, or 71%, who are represented by three units covered by separate collective bargaining contracts.

 

NSTAR’s contract with Local 369 of the Utility Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for Local 369 for a new labor contract. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Approximately 60 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, the International Union of Operating Engineers, AFL-CIO, under a contract that expires on September 30, 2006.

 

Management believes it has satisfactory relations with its employees.

 

(d) Financial Information about Foreign and Domestic Operations and Export Sales

 

None of NSTAR’s subsidiaries have any foreign operations or export sales.

 

Item 2. Properties

 

NSTAR Electric properties include an integrated system of distribution lines and substations, an office building and other structures such as garages and service centers that are located primarily in eastern Massachusetts.

 

At December 31, 2004, the NSTAR Electric primary and secondary transmission and distribution system consisted of approximately 20,300 circuit miles of overhead lines, approximately 9,000 circuit miles of underground lines, 258 substation facilities and approximately 1,312,000 active customer meters.

 

NSTAR Electric’s high-voltage transmission lines are generally located on land either owned or subject to perpetual and exclusive easements in its favor. Its low-voltage distribution lines are located principally on public property under permits granted by municipal and other state authorities.

 

Cambridge Electric completed the sale of Blackstone Station in April 2003. NSTAR, through its Canal subsidiary, sold its 3.52% ownership interest (40.5 MW of capacity) in the Seabrook Nuclear Generating Station on November 1, 2002.

 

NSTAR Gas’ principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 2004, the gas system included approximately 2,950 miles of gas distribution lines, approximately 180,200 services and approximately 278,000 customer meters together with the necessary measuring and regulating equipment. In addition, Hopkinton LNG Corp. owns a liquefaction and vaporization plant, a satellite vaporization plant and above ground cryogenic storage tanks

 

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having an aggregate storage capacity equivalent to 3.5 Bcf of natural gas. NSTAR Gas owns an office and service building in Southborough, Massachusetts, three district office buildings and several natural gas receiving and take stations.

 

In 2002, NSTAR’s utility subsidiaries purchased a 370,000 square foot office building (the Summit) sited on 33 acres in the Boston suburb of Westwood, Massachusetts. This site is centrally located in NSTAR’s service area and houses its central administrative offices including customer care, finance, human resources, sales, engineering, and information technology.

 

District energy operations primarily consist of AES’ MATEP facility located in the Longwood Medical Area of Boston. MATEP provides steam, chilled water and electricity to over 9 million square feet of medical and teaching facilities. NSTAR Steam’s distribution system consists primarily of approximately 3.5 miles of steam lines utilized to provide service to customers in Cambridge, MA.

 

Item 3. Legal Proceedings

 

In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, NSTAR does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.

 

Item 4. Submission of Matters to a Vote of Security Holders

 

There were no matters submitted to a vote of security holders during the fourth quarter of 2004.

 

Item 4A. Executive Officers of Registrant

 

Identification of Executive Officers

 

Name of Officer


  

Position and Business Experience


   Age at
December 31, 2004


Thomas J. May

   Chairman, President (since 2002), Chief Executive Officer and a Trustee (since 1999); Director, Bank of America Corporation and Liberty Mutual Holding Company Inc.    57

Douglas S. Horan

   Senior Vice President - Strategy, Law and Policy, Secretary and General Counsel (since 2000); formerly Senior Vice President - Strategy, Law and Policy (1999-2000).    55

James J. Judge

   Senior Vice President, Treasurer and Chief Financial Officer (since 2000); formerly Senior Vice President and Chief Financial Officer (1999-2000).    48

Timothy R. Manning

   Senior Vice President - Human Resources (since 2002); formerly Vice President Human Resources (2001); Director of Employee and Labor Relations (1999-2001).    53

Joseph R. Nolan, Jr.

   Senior Vice President - Customer and Corporate Relations (since 2002); formerly Senior Vice President - Corporate Relations (2000-2002); Vice President of Government Affairs (1999-2000).    41

 

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Name of Officer


  

Position and Business Experience


   Age at
December 31, 2004


Werner J. Schweiger

   Senior Vice President - Operations (since 2002); formerly Vice President, Office of Electric Operations/Transmission and Distribution Management, Keyspan Energy Corporation (1997-2002).    45

Eugene J. Zimon

   Senior Vice President - Information Technology (since 2001); formerly Vice President, Business Development for Utilities, Oracle Corporation (2000-2001).    56

Robert J. Weafer, Jr.

   Vice President, Controller and Chief Accounting Officer (since 1999).    57

 

PART II

 

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

(a) Market Information

 

The NSTAR Common Shares, $1 par value, are listed on the New York and Boston Stock Exchanges under the symbol “NST”. NSTAR’s Common Shares closing market price at December 31, 2004 was $54.28 per share.

 

The NSTAR Common Shares high and low sales prices as reported by the New York Stock Exchange composite transaction reporting system for each of the quarters in 2004 and 2003 were as follows:

 

     2004

   2003

     High

   Low

   High

   Low

First quarter

   $ 52.85    $ 48.00    $ 46.12    $ 38.67

Second quarter

   $ 52.00    $ 45.30    $ 48.00    $ 39.78

Third quarter

   $ 50.50    $ 46.01    $ 48.34    $ 43.63

Fourth quarter

   $ 54.45    $ 48.17    $ 48.96    $ 45.08

 

In December 2004, NSTAR announced its intention to split its common shares two-for-one, subject to market conditions and shareholder approval of an amendment to the Company’s Declaration of Trust which would increase the number of NSTAR’s authorized common shares, at the April 28, 2005 Annual Meeting of Shareholders.

 

(b) Holders

 

As of December 31, 2004, there were 24,653 registered holders of NSTAR Common Shares.

 

(c) Dividends

 

Dividends declared per Common Share for each quarter of 2004 and 2003 were as follows:

 

     2004

   2003

First quarter

   $ 0.555    $ 0.54

Second quarter

   $ 0.555    $ 0.54

Third quarter

   $ 0.555    $ 0.54

Fourth quarter

   $ 0.58    $ 0.555

 

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NSTAR paid common share dividends to shareholders totaling $117.9 million and $114.6 million in 2004 and 2003, respectively.

 

(d) Securities authorized for issuance under equity compensation plans

 

The following table provides information about NSTAR’s equity compensation plans as of December 31, 2004.

 

Plan Category


  Number of securities
to be issued upon
exercise of
outstanding options


   Weighted-average
exercise price of
outstanding
options


   Number of
securities remaining
available for
future issuance
under equity
compensation plans


Equity compensation plans approved by shareholders

  1,456,169    $ 43.45    1,992,027

Equity compensation plans not approved by shareholders

  —        —      —  
   
  

  

Total

  1,456,169    $ 43.45    1,992,027
   
  

  

 

(e) Purchases of equity securities

 

Common Shares of NSTAR issued under the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, the 1997 Share Incentive Plan and the NSTAR Savings Plan in connection with common share grants and the exercise of stock options may consist of newly issued shares from the Company or shares purchased in the open market by the Company or an independent agent. During the three-month period ended December 31, 2004, the shares listed below were acquired in the open market primarily in connection with the NSTAR Savings Plan.

 

     Total Number of
Common Shares
Purchased


   Average Price
Paid Per Share


October

   48,700    $ 49.66

November

   16,100    $ 50.79

December

   14,200    $ 53.26

 

Item 6. Selected Consolidated Financial Data

 

The following table summarizes five years of selected consolidated financial data.

 

(in thousands, except per share data)


   2004

   2003

   2002

   2001

    2000

Operating revenues

   $ 2,954,332    $ 2,911,711    $ 2,690,625    $ 3,181,167     $ 2,692,198

Net income (loss)(a)

   $ 188,481    $ 181,574    $ 161,707    $ (2,426 )   $ 175,002

Earnings (loss) per common share:

                                   

Basic (a)

   $ 3.55    $ 3.42    $ 3.05    $ (0.05 )   $ 3.19

Diluted (a)

   $ 3.51    $ 3.40    $ 3.03    $ (0.05 )   $ 3.18

Total assets

   $ 7,117,229    $ 6,332,151    $ 6,338,454    $ 5,328,191     $ 5,547,715

Long-term debt (b)

   $ 1,792,654    $ 1,602,402    $ 1,645,465    $ 1,377,899     $ 1,440,431

Transition property securitization (b)

   $ 308,748    $ 377,150    $ 445,890    $ 513,904     $ 584,130

Preferred stock of subsidiary (b)

   $ 43,000    $ 43,000    $ 43,000    $ 43,000     $ 43,000

Cash dividends declared per common share

   $ 2.245    $ 2.175    $ 2.13    $ 2.075     $ 2.015

(a) 2002 and 2001 include non-cash, after-tax charges of $17.7 million and $173.9 million, or $0.33 per share and $3.28 per basic share, respectively, related to NSTAR’s investment in RCN Corporation.

 

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(b) Excludes the current portion of long-term debt and preferred stock.

 

Selected Quarterly Consolidated Financial Data (Unaudited)

 

(in thousands, except earnings per share)


         
     Operating
Revenues


   Operating
Income


   Net
Income (a)


   Earnings
Per Basic
Common Share
(a)(b)


2004

                           

First quarter

   $ 809,908    $ 87,507    $ 49,716    $ 0.94

Second quarter

   $ 649,787    $ 73,407    $ 37,525    $ 0.71

Third quarter

   $ 781,510    $ 101,268    $ 63,281    $ 1.19

Fourth quarter

   $ 713,127    $ 76,146    $ 37,959    $ 0.71

2003

                           

First quarter

   $ 762,932    $ 84,601    $ 42,338    $ 0.80

Second quarter

   $ 647,029    $ 73,261    $ 39,154    $ 0.74

Third quarter

   $ 817,333    $ 102,299    $ 63,662    $ 1.20

Fourth quarter

   $ 684,417    $ 72,350    $ 36,420    $ 0.69

(a) The fourth quarter of 2003 includes a non-cash after-tax charge of $4.5 million, or $0.08 per basic share, related to NSTAR’s abandonment of its investment in RCN Corporation fully offset by the recognition of related tax benefits of $4.5 million.

 

(b) The sum of the quarters may not equal basic annual earnings per share.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)

 

Overview

 

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy and Commonwealth Energy System. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of consolidated operating revenues in 2004, 2003 and 2002.

 

NSTAR generates its revenues primarily from the sale of energy, distribution and transmission services to customers and from its unregulated businesses. NSTAR’s earnings are impacted by fluctuations in unit sales of kWh and MMbtu, which directly determine the level of distribution and transmission revenues recognized. In accordance with the regulatory rate structure in which NSTAR operates, its recovery of energy costs are fully reconciled with the level of energy revenues currently recorded and, therefore, do not have an impact on earnings. As a result of this rate structure, any variability in the cost of energy supply purchased will impact purchased power and cost of gas sold expense and corresponding revenues but will not affect the Company’s earnings.

 

Cautionary Statement

 

The MD&A, as well as other portions of this report, contain statements that are considered forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements may also be contained in other filings with the Securities and Exchange Commission (SEC), in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward-looking statements may not turn out to be what NSTAR expected. Actual results could differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.

 

Examples of some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to, the following:

 

    impact of continued cost control procedures on operating results

 

    weather conditions that directly influence the demand for electricity and natural gas

 

    changes in tax laws, regulations and rates

 

    financial market conditions including, but not limited to, changes in interest rates and the availability and cost of capital

 

    prices and availability of operating supplies

 

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    prevailing governmental policies and regulatory actions (including those of the Massachusetts Department of Telecommunications and Energy (MDTE) and Federal Energy Regulatory Commission (FERC) with respect to allowed rates of return, rate structure, continued recovery of regulatory assets, financings, purchased power, acquisition and disposition of assets, operation and construction of facilities, changes in tax laws and policies and changes in, and compliance with, environmental and safety laws and policies

 

    changes in financial accounting and reporting standards

 

    new governmental regulations or changes to existing regulations that impose additional operating requirements or liabilities

 

    changes in specific hazardous waste site conditions and the specific cleanup technology

 

    impact of uninsured losses

 

    changes in available information and circumstances regarding legal issues and the resulting impact on our estimated litigation costs

 

    future economic conditions in the regional and national markets

 

    ability to maintain current credit ratings, and

 

    the impact of terrorist acts

 

Any forward-looking statement speaks only as of the date of this filing and NSTAR undertakes no obligation to publicly update forward-looking statements, whether as a result of new information, future events, or otherwise. You are advised, however, to consult all further disclosures NSTAR makes in its filings to the SEC. Other factors in addition to those listed here could also adversely affect NSTAR. This report also describes material contingencies and critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements and NSTAR encourages a review of these Notes.

 

Critical Accounting Policies and Estimates

 

NSTAR’s discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and judgements that affect the reported amount of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Actual results may differ from these estimates under different assumptions or conditions.

 

Critical accounting policies and estimates are defined as those that require significant judgment and uncertainties, and potentially may result in materially different outcomes under different assumptions and conditions. NSTAR believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below.

 

a. Revenue Recognition

 

Utility revenues are based on authorized rates approved by the MDTE and FERC. Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters that are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory

 

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load), estimated line losses and applicable customer rates. Unbilled natural gas revenues are estimated based on estimated purchased gas volumes, estimated gas losses and tariffed rates in effect. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2004 and 2003 were $54 million and $46 million, respectively.

 

NSTAR’s non-utility revenues are recognized when services are rendered or when the energy is delivered. Revenues are based, for the most part, on long-term contractual rates.

 

The level of unbilled revenues is subject to seasonal weather conditions. Electric sales volumes are typically higher in the winter and summer than in the spring or fall. Gas sales volumes are impacted by colder weather since a substantial portion of NSTAR’s customer base uses natural gas for heating purposes. As a result, NSTAR records a higher level of unbilled revenue during the seasonal periods mentioned above.

 

b. Regulatory Accounting

 

NSTAR follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a rate-regulated company, NSTAR’s utility subsidiaries are subject to the Financial Accounting Standards Board, Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain revenues and expenses from those of other businesses and industries. NSTAR’s energy delivery businesses remain subject to rate-regulation and continue to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash inflows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2004 and 2003, NSTAR has recorded regulatory assets of $2.2 billion and $1.9 billion, respectively. NSTAR continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. NSTAR expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, NSTAR would be required to charge these assets to current earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

 

c. Derivative Instruments - Power Contracts

 

The electric distribution industry may contract to buy and sell electricity under option contracts, which allow the distribution company the flexibility to determine when and in what quantity to take electricity in order to align with its demand for electricity. These contracts would normally meet the definition of a derivative instrument requiring mark-to-market accounting. However, because electricity cannot be stored and utilities are obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting.

 

NSTAR Electric has long-term purchase power agreements that are used primarily to meet its standard offer obligation. The majority of these agreements are not reflected as an asset or liability on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, based on DIG interpretations, NSTAR, as of December 31, 2004, recorded four contracts at fair value on its accompanying Consolidated Balance Sheets. At December 31, 2003, NSTAR recorded six purchase power contracts at fair value. In anticipation of the end of standard offer service in February 2005, two of the six contracts were divested in 2004 through regulatory-approved agreements. Refer to the Consolidated Financial Statements, Note O, for more detail on the buy-out of certain purchase power contracts. As a result, the recognition of a liability for the fair value of the above-market portion of the four contracts at December 31, 2004 and for the fair value of the above-market portion of the six contracts at December 31, 2003 is approximately $472 million and $666 million, respectively, and are reflected as a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets.

 

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During the first quarter of 2005, NSTAR expects to close on a securitization financing that will affect these four contracts that are classified as derivative instruments. NSTAR Electric has entered into buy-out agreements for all four contracts and expects to finance the buy-out payments through a securitization financing. When this occurs, the fair value of these four contracts will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an offsetting regulatory asset.

 

At December 31, 2004, the four contracts were valued using a discounted cash flow model and a 7.5% discount rate. The market value assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the values of the contracts at December 31, 2004 and 2003 would have changed significantly. A one percent increase or decrease to the discount rate would change the above market value for the four contracts by approximately $19 million from what is presently recorded at December 31, 2004.

 

NSTAR Electric recovers all of its electricity supply costs, including the above-market costs from customers. For the four purchase power agreements at December 31, 2004, the recovery of its above-market costs occurs through 2013 for Boston Edison and through 2017 for ComElectric. These recovery periods coincide with the contractual terms of these purchase power agreements. Therefore, in addition to the liability recorded, NSTAR also recorded a corresponding regulatory asset representing the future recovery of these actual costs. As a result, any changes to the fair value of these contracts will not have an effect on NSTAR’s earnings.

 

d. Pension and Other Postretirement Benefits

 

NSTAR’s annual pension and other postretirement benefits costs are dependent upon several factors and assumptions, such as employee demographics, plan design, the level of cash contributions made to the plans, expected and actual earnings on the plans’ assets, the discount rate, the expected long-term rate of return on the plans’ assets and health care cost trends.

 

In accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS 106), changes in pension and postretirement benefit obligations other than pensions (PBOP) associated with these factors are not immediately recognized as pension and PBOP costs in the statements of income, but generally are recognized in future years over the remaining average service period of the plans’ participants.

 

There were no significant changes to NSTAR’s pension benefits in 2004, 2003 and 2002 that had a significant impact on recorded pension costs. As further described in Note H to the accompanying Consolidated Financial Statements, NSTAR revised the discount rate at December 31, 2004 to 5.75% from 6.25% at December 31, 2003 to reflect market conditions and the characteristics of NSTAR’s pension obligation. The expected long-term rate of return on its pension plan assets for 2004 remained at 8.4% (net of plan expenses), the same as 2003. These assumptions will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact, however, will be mitigated through NSTAR’s regulatory accounting treatment of qualified pension and PBOP costs. (See further discussion of regulatory accounting treatment below). In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.

 

NSTAR’s Pension Plan (the Plan) assets, which partially consist of equity investments, were affected by significant declines in the financial markets from 2000 through 2002 and improvements in the financial markets for both 2003 and 2004. Fluctuations in market returns impacted the funded status of the Plan at both December 31, 2004 and 2003, and will affect pension costs in future periods.

 

The following chart reflects the projected benefit obligation and cost sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption.

 

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(in thousands)

 

Actuarial Assumption


   Change in Assumption

   Impact on
Projected Benefit
Obligation


    Impact on 2004 Cost
Increase/(Decrease)


 

Pension:

                     

Increase in discount rate

   50 basis points    $ (58,418 )   $ (4,112 )

Decrease in discount rate

   50 basis points    $ 64,463     $ 4,442  

Increase in expected long-term rate of return on plan assets

   50 basis points      N/A     $ (4,141 )

Decrease in expected long-term rate of return on plan assets

   50 basis points      N/A     $ 4,140  

Other Postretirement Benefits:

                     

Increase in discount rate

   50 basis points    $ (40,300 )   $ (3,338 )

Decrease in discount rate

   50 basis points    $ 45,080     $ 3,671  

Increase in expected long-term rate of return on plan assets

   50 basis points      N/A     $ (1,367 )

Decrease in expected long-term rate of return on plan assets

   50 basis points      N/A     $ 1,367  

N/A - not applicable

                     

 

The Plans’ discount rates are based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Company’s plans and through periodic bond portfolio matching. Both of these factors contribute to management’s decision for selecting the discount rate.

 

In determining the expected long-term rate of return on plan assets, NSTAR considers past performance and economic forecasts for the types of investments held by the Plan as well as the target allocation for the investments over a 20-year time period. In 2004, NSTAR kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for equity market returns. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for both 2004 and 2003.

 

At December 31, 2003, the Plan’s accumulated benefit obligation (ABO) exceeded Plan assets. The ABO represents the present value of benefits earned without considering future salary increases. Since the fair value of its Plan assets was less than the ABO, NSTAR was required to record this difference as an additional minimum pension liability on the accompanying Consolidated Balance Sheets as of December 31, 2003.

 

In 2004, due to positive Plan investment performance and Company contributions over the last two years of $120 million, the fair value of the Plan’s assets exceeded the Plan’s ABO at December 31, 2004. As a result, the minimum liability has been reversed and the prepaid pension amount has been restored to the accompanying Consolidated Balance Sheet at December 31, 2004.

 

On October 31, 2003, the MDTE approved NSTAR’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, NSTAR is allowed to record a regulatory asset in lieu of taking a charge to Other Comprehensive Income for the required additional minimum liability adjustment. As of December 31, 2003, NSTAR recorded a regulatory asset of $299 million. At December 31, 2004, the regulatory asset was reversed and the prepaid pension asset of $298 million was reinstated in the accompanying Consolidated Balance Sheets.

 

The Plan currently meets the minimum funding requirements of the Employee Retirement Income Security Act of 1974. While not required to make contributions to the Plan, NSTAR anticipates that it will contribute approximately $35 million to the Plan in 2005. NSTAR believes it has adequate access to capital resources to support these contributions.

 

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e. Decommissioning Cost Estimates

 

The accounting for decommissioning costs of nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Changes in these estimates will not affect NSTAR’s results of operations or cash flows because these costs will be collected from customers through NSTAR’s transition charge filings with the MDTE.

 

While NSTAR no longer directly owns any operating nuclear power plants, NSTAR Electric collectively owns, through its equity investments, 14% of Connecticut Yankee Atomic Power Company, 14% of Yankee Atomic Electric Company, and 4% of Maine Yankee Atomic Power Company, (collectively, the “Yankee Companies”). Periodically, NSTAR obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY), the Yankee Atomic nuclear unit (YA), and the Maine Yankee nuclear unit (MY). These nuclear units are completely shut down and are currently conducting decommissioning activities.

 

Based on estimates from the Yankee Companies’ management as of December 31, 2004, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $630 million for CY, $119 million for YA and $292 million for MY. Of these amounts, NSTAR Electric is obligated to pay $88.2 million towards the decommissioning of CY, $16.7 million toward YA, and $11.7 million toward MY. These amounts are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current results of operations and cash flow. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.

 

The Yankee Companies have received approval from FERC for recovery of these costs and NSTAR expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including NSTAR Electric. NSTAR Electric would recover its share of any allowed increases from customers through the transition charge.

 

CY’s estimated decommissioning costs increased significantly in 2003 and the increase reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). In July 2004, CY filed with FERC for recovery of these increased costs. In August 2004, FERC issued an order accepting the new rates, beginning in February 2005, subject to refund.

 

CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY’s real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the sponsors’ periodic payments, up to a total of $41.7 million, all of which the sponsors, which include NSTAR Electric, are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the ability of Bechtel to attach these assets. Discovery is underway and a trial has been scheduled for May 2006. NSTAR cannot predict the timing or outcome of the litigation with Bechtel but does not expect a material impact on NSTAR’s financial position, results of operation or cash flows.

 

Asset Retirement Obligations

 

On January 1, 2003, NSTAR adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal

 

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operation of a long-lived asset, except for certain obligations under lease arrangements. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

 

NSTAR has identified certain immaterial long-lived assets, including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.

 

For its regulated utility businesses, NSTAR has identified legal retirement obligations that are currently not material to its financial statements. The recognition of a potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, for NSTAR’s rate-regulated utilities, NSTAR would establish regulatory assets or liabilities to defer any differences between the liabilities established for ratemaking purposes and those recorded as required under SFAS 143.

 

For NSTAR’s regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million and $223 million, respectively, based on the estimated cost of removal component in current depreciation rates.

 

NSTAR has also identified several long-lived assets, in which it has legal obligations to remove such property, for its non-regulated businesses. As a result, in 2003, NSTAR recorded an increase in non-utility property of approximately $0.6 million, an asset retirement liability of approximately $1 million and a cumulative effect of adoption after tax, reducing net income by $0.4 million in 2003. The cumulative effect adjustment was recorded as part of 2003 Depreciation and amortization expense on the accompanying Consolidated Statements of Income.

 

During 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The interpretation clarifies when an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability rather than the recognition of the liability. The interpretation would be effective for NSTAR no later than the end of fiscal year 2005. NSTAR is currently assessing the impact that the interpretation will have on its consolidated financial position, results of operations and cash flows.

 

Variable Interest Entities

 

In 2004, the FASB issued an exposure draft, “Consolidation of Variable Interest Entities,” as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.

 

NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to undertake the sale of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates this entity. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003, NSTAR reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, NSTAR has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by NSTAR.

 

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For the March 31, 2004 effective date of FIN 46R, NSTAR evaluated other entities with which it conducts significant transactions, including companies that supply power to NSTAR through its purchase power agreements. NSTAR determined that it is possible that five of these companies may be considered VIEs. These companies have power plants that have daily capacity output ranging from 20 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, NSTAR purchased a total of approximately 4,001 megawatt-hours (MWH) and 4,487 MWH, respectively, under these agreements. These purchases approximate 17% of the total MWH purchased by NSTAR for years ended December 31, 2004 and 2003 and amounted to approximately $381 million and $386 million, respectively. In order to determine if these counterparties are VIEs and if NSTAR is the primary beneficiary of these counterparties, NSTAR concluded that it needed more information from the entities. NSTAR attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since NSTAR was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which NSTAR has a purchase power agreement.

 

Additionally, during 2004, NSTAR executed purchase power buy-out/restructuring agreements with a majority of the entities from which NSTAR attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructuring agreements received regulatory approval in January 2005. Refer to Consolidated Financial Statements, Note O, for more detail on the purchase power buy-out agreements. As a result, NSTAR will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.

 

New Accounting Standards

 

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. This Standard also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. NSTAR is currently assessing its valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual earnings by approximately $1.5 million pre-tax, or $0.02 per share.

 

Generating Assets Divestiture

 

Blackstone Station

 

On April 8, 2003, Cambridge Electric completed the sale of Blackstone Station to Harvard University (Harvard) for $14.6 million; the net proceeds ($10.4 million) from the sale were used to reduce Cambridge Electric’s transition charge. The sale was approved by the MDTE on March 14, 2003. Also on April 8, 2003, NSTAR Steam Corporation completed the sale of its Blackstone Station steam assets to Harvard for $3 million. The net impact of these transactions resulted in a pretax gain of $1.3 million. Under terms of an operating agreement, NSTAR Steam continued to manage the day-to-day operations of the steam plant on this site until April 8, 2004.

 

Rate and Regulatory Proceedings

 

a. Service Quality Indicators

 

Service quality indicators are established performance benchmarks for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. NSTAR Electric and NSTAR Gas are required to report annually to the MDTE concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks.

 

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On March 1, 2004, NSTAR Electric and NSTAR Gas filed their 2003 Service Quality Reports with the MDTE that demonstrated the Companies’ achieved levels of reliability and performance; the reports indicate that no penalty was assessable for 2003. The MDTE concurred with NSTAR’s determination in an order issued in October 2004. NSTAR monitors its service quality continuously to determine its contingent liability, and if it’s probable that a liability has been incurred and is estimable, a liability would be accrued. Annually, each NSTAR utility subsidiary makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability. Recently, the MDTE voted to initiate an investigation into potentially modifying the service quality indicators for all Massachusetts utilities. Until any such order is issued, the current service quality indicators will remain in place. NSTAR currently cannot predict the outcome of this investigation or its impact.

 

As of December 31, 2004, NSTAR Electric’s and NSTAR Gas’ 2004 performance has exceeded the applicable established benchmarks and, as such, that no liability has been accrued for 2004.

 

b. Retail Electric Rates

 

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore, effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be provided default service. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2004, 2003 and 2002, customers of NSTAR Electric had approximately 24%, 26% and 27%, respectively, of their load requirements provided by competitive suppliers.

 

On December 21, 2004, the FERC issued an order approving Boston Edison’s October 2004 request to modify its Open Access Transmission Tariff (OATT). Effective January 1, 2005, Boston Edison is allowed to include 50 percent of construction work in progress in its rate base for transmission projects by including this amount in its local network service transmission rate formula, rather than capitalizing Allowance for Funds Used During Construction (AFUDC) charges on the entire construction expense balance. The order is subject to Boston Edison filing annual reports of its long-term transmission plan.

 

In December 2004, NSTAR Electric filed proposed transition rate adjustments for 2005, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2004. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2005. The filings are to be updated in February 2005 to reflect final 2004 costs and revenues which are subject to final reconciliation.

 

On February 1, 2005, the Independent System Operator – New England began operating as a Regional Transmission Organization. As a result, NSTAR has given notice to the RTO and other interested parties of its intent to file for proposed changes to its OATT. This change is expected to provide for consistent application of the OATT among all NSTAR Electric companies. The 2004 OATT and the related revenue have been based on this proposed change. If successful, NSTAR Electric expects to include the impact in its 2005 billing rates.

 

Effective January 1, 2005, NSTAR Electric’s Standard Offer Service Fuel Adjustment (SOSFA) rates for each of Boston Edison, ComElectric and Cambridge were modified to a level of 1.564 cents per kilowatt-hour with the approval of the MDTE.

 

Effective October 1, 2004, Boston Edison’s SOSFA rate was modified to 1.223 cents per kilowatt-hour from zero upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service customers. Effective September 1, 2003, the Boston Edison SOSFA

 

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was reduced to zero while the ComElectric and Cambridge Electric SOSFAs were increased to 1.424 cents per kilowatt-hour until January 1, 2004 when they were reduced to 1.223 cents per kilowatt-hour. These changes followed an increase in this rate adjustment from zero to 0.902 cents per kilowatt-hour that was effective May 1, 2003 for all three NSTAR Electric companies. The SOSFA was at zero from April 1, 2002 through April 30, 2003 for all three NSTAR Electric companies. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the 1997 Massachusetts Electric Restructuring Act.

 

In December 2003, NSTAR Electric filed proposed transition rate adjustments for 2004, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2003. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2004. The filings were updated in February 2004 to include final costs and revenues for 2003.

 

On December 1, 2003, NSTAR Electric and NSTAR Gas filed their annual reconciliation report on their pension and PBOP rate adjustment mechanism. Hearings were held during 2004. NSTAR anticipates an order by the end of the first quarter of 2005. NSTAR cannot predict the overall timing and result of this order on its financial position or results of operations.

 

c. Wholesale Market Rule Changes

 

Standard Market Design (SMD)

 

Pursuant to orders issued by the FERC, wholesale electric markets in New England have been operating under SMD since March 1, 2003. Under SMD, generators are dispatched on a least cost basis until the generation dispatched equals the amount of energy required. The clearing price is set at the price of the next available megawatt of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when transmission constraints prevent the lower cost generation from moving from one load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). NSTAR Electric’s service territory covers two of the eight load zones in New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is import-constrained and SEMA is export-constrained. The majority of NSTAR’s customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher LMP than SEMA. As part of SMD, load-serving entities, like NSTAR Electric, were granted proceeds from the auction of “financial transmission rights” that is conducted by ISO-NE. NSTAR Electric uses proceeds to mitigate costs to customers.

 

Locational Installed Capacity (LICAP)

 

The ISO-NE has proposed a new market rule designed to compensate wholesale generators for their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in New England, to count towards a LSE’s obligation, regardless of load zone. At this point, it appears likely that NSTAR’s new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to converge, which could ultimately render this locational aspect of LICAP a non-factor for NSTAR customers. However, since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of power to NSTAR’s customers. The proposed LICAP market

 

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rules are contentious and are currently being litigated at FERC and in the courts. A final FERC ruling on the issue is expected in 2005 and the current schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, NSTAR cannot predict the actual impact these changes will have on NSTAR Electric and its customers.

 

Regional Transmission Organization (RTO)

 

On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including NSTAR Electric. The filing requested an increase in the base ROE component of the regional and local transmission rates, to be provided under the Regional Transmission Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New England is provided under a two-tier structure, with the potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50 basis points in regional rates as an incentive for joining an RTO for regional service. In addition, FERC also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. The Transmission Owners maintain that sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law judge and were unsuccessful. Hearings on the base ROE and 100 basis point adder began in January 2005.

 

The joint ROE filing among the Transmission Owners was made in connection with the proposed formation of RTO-NE by the Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including NSTAR Electric, which resolved many issues left outstanding from FERC’s March 2004 Order conditionally approving the formation of RTO-NE. The November 3rd Order also provided clarification of certain aspects of the March 2004 Order regarding the Transmission Owners’ request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and the Transmission Owner’s proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. Finally, the November 3rd Order required the satisfaction of several ministerial conditions before ISO-NE could begin to operate as an RTO. ISO-NE and the Transmission Owners have since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the ISO-NE is an independent entity, without a financial interest in the region’s marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as NSTAR Electric, and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE’s interactions with market participants and merchant transmission facilities. NSTAR’s management cannot estimate the impact of the RTO on the Company.

 

d. Natural Gas Rates

 

NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers do not materially affect NSTAR Gas’ operating income because substantially the entire margin on such service is returned to its firm customers as rate reductions.

 

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In addition to delivery service rates, NSTAR Gas’ tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas supply costs from firm sales customers or default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. In addition, NSTAR Gas is required to file interim changes to its CGAC factor when the actual costs of gas supply vary from projections by more than 5%.

 

Due to the increase in wholesale natural gas prices, NSTAR Gas was allowed by the MDTE to increase its winter seasonal CGAC factor effective November 1, 2002 by 16.7% over the prior winter season’s factor. The CGAC factor was allowed to increase two additional times during that winter season due to the increases in the wholesale cost of gas. On November 1, 2003, the winter season CGAC factor was set at a level 10% higher than the average for the prior winter season due to higher wholesale gas costs. On January 1, 2004, the CGAC factor was allowed to increase by 9.9% to reflect an additional increase in the cost of gas.

 

In the last three years, the winter season CGAC factor was revised upward to reflect increases in the cost of gas caused by varying market conditions. To date, the CGAC factor for the winter of 2003-2004 has ranged from $0.8121 per therm to $0.8925; in the winter of 2002-2003, the CGAC ranged from $0.6139 per therm to $0.8936 per therm; the range for the winter of 2001-2002 was $0.5261 per them to $0.6139 per therm.

 

Other Legal Matters

 

In the normal course of its business, NSTAR and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, NSTAR does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations for a reporting period.

 

RCN Abandonment

 

On December 24, 2003, NSTAR exited its investment in RCN and formally abandoned its 11.6 million shares of RCN common stock. As a result, NSTAR recorded a pre-tax charge of approximately $6.8 million, or $0.08 per share. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR determined other alternatives such as a sale of the shares would be less beneficial as a result of the number of shares held by NSTAR; the trading value in shares of RCN common stock; the potential negative impact that a large volume of sales of RCN common stock could have on the value of such shares; the length of time required to exit such investment through a sale of such shares and the fact that no block purchasers expressed an interest in purchasing such shares. NSTAR determined that the benefit of a tax realization event at that time and in that manner outweighed any benefit that it would likely realize from any other alternative, including the future sale of such shares in an orderly fashion consistent with all laws, rules and regulations. As a result of this abandonment, the investment was written down to zero as of December 31, 2003. The cumulative increase in fair value of these shares since December 31, 2002, including the impact of the abandonment charge for these shares, is included in Other comprehensive income, net on the accompanying Consolidated Statements of Comprehensive Income.

 

Income Tax Matters

 

a. RCN Abandonment Tax Treatment

 

As a result of the RCN share abandonment, the Company claimed an ordinary loss on its 2003 tax return for this item. The ordinary loss tax treatment resulted in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-down of this asset for financial reporting purposes.

 

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The requirement for a tax valuation allowance, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.

 

The Company believes it is more likely than not that it is entitled to this ordinary loss deduction. The Company expects the Internal Revenue Service (IRS) to review this transaction and it is possible that the IRS will disagree. In accordance with the Company’s tax policy as it relates to uncertain tax positions, the Company has established a loss contingency of approximately $44 million at December 31, 2003. This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss. This contingent liability is recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.

 

If the Company’s position is not upheld, the Company may be required to make future cash expenditures to the IRS that may impact NSTAR’s cash requirements in future periods.

 

b. Tax Valuation Allowance

 

SFAS 109, “Accounting for Income Taxes,” prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. NSTAR had determined that it was more likely than not that a current or future income tax benefit would not be realized relating to the write-downs of its RCN investment that were recorded in the second and fourth quarters of 2002 and previously in the first quarter of 2001. These write-downs resulted from the significant declines in the market value of the telecommunications sector, including RCN. As a result of this uncertainty, NSTAR recorded a $77.6 million tax valuation allowance on the entire tax benefit associated with these write-downs during 2001 and 2002. During 2003 and 2002, as a result of previously unanticipated capital gain transactions, NSTAR recognized $8.5 million and $3.9 million, respectively, of this tax benefit.

 

Additionally, based on the IRS review of NSTAR’s 1999 and 2000 federal income tax returns, NSTAR recognized the tax benefits relating to the incremental operating losses from the joint venture that were allocated to NSTAR. These tax returns are currently at the Office of IRS Appeals on other matters. The tax valuation allowance included reserves related to the tax treatment of these losses through June 19, 2002, the final date of JV loss allocation to NSTAR. Each of the tax returns filed for 1999 through 2001 claimed operating losses. The tax return filed for 2002 claimed the remaining portion of these operating losses. Based on the IRS examining agent’s review, no adjustment for the years under audit was proposed. This determination was arrived at in the fourth quarter of 2002 and, as a result, NSTAR applied the treatment of these operating losses for all years on a consistent basis, allowing a reduction to its valuation allowance of approximately $19.7 million as a reduction to income tax expense included as a component of the write-down to the RCN investment.

 

On December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 11.6 million shares of RCN common stock. As mentioned above, a tax valuation allowance had been established in a previous year to offset the potential future tax benefits resulting from write-downs of NSTAR’s investment in RCN. As a result of the abandonment, the Company claimed an ordinary loss on its 2003 tax return. This treatment results in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-downs of this investment for financial reporting purposes. The requirement for a tax valuation allowance, therefore, is no longer applicable. As a result, the Company reduced the remaining valuation allowance to zero at December 31, 2003.

 

Results of Operations

 

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2004, 2003 and 2002 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included elsewhere in this report.

 

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2004 compared to 2003

 

Earnings and Operations Overview

 

Earnings per common share were as follows:

 

     Years ended December 31,

     2004

   2003

   % Change

Basic

   $ 3.55    $ 3.42    3.8

Diluted

   $ 3.51    $ 3.40    3.2

 

Net income was $188.5 million for 2004 compared to $181.6 million for 2003. Factors that contributed to the $6.9 million, or 3.8%, increase in 2004 earnings include higher electric distribution revenues due to higher rates, interest savings on the Company’s outstanding indebtedness, and a reduction in operations and maintenance expense. In addition, 2004 results reflect the first full year of the Company’s pension and other postretirement benefit obligations other than pension (PBOP) rate mechanism. This mechanism was implemented in September 2003 and, at that time, the Company expensed $18 million of pension and PBOP costs, which were deferred during the first eight months of 2003. See “Critical Accounting Policies and Estimates,” Pension and Other Postretirement Benefits, in this MD&A for more information on the MDTE order.

 

NSTAR in 2004 generated $437.5 million of cash from operations sufficient to fund approximately $313.4 million of net capital expenditures, and $119.8 million of cash dividends. The Company’s capital expenditures contributed to NSTAR ‘s solid operational performance in reliability, restoration, and customer service measurements. Favorable market conditions and the Company’s strong credit ratings contributed to the Company’s 2004 refinancing activities. These financing activities included the retirement of $181 million of 7.80% series of Debentures in March 2004 and a reduction in short-term borrowings of $77.7 million from year-end 2003. This retirement was temporarily funded with short-term borrowings, which were subsequently paid down with the proceeds from the issuance of a 10-year, $300 million 4.875% series of Debentures, which was completed in April 2004.

 

Energy sales and weather

 

The following is a summary of retail electric and firm gas energy sales for the years indicated:

 

     Years ended December 31,

 
     2004

   2003

   % Change

 

Retail Electric Sales - MWH

                

Residential

   6,564,494    6,492,738    1.1  

Commercial

   12,693,217    12,417,719    2.2  

Industrial

   1,651,389    1,694,184    (2.5 )

Other

   168,733    170,012    (0.8 )
    
  
  

Total retail sales

   21,077,833    20,774,653    1.5  
    
  
  

     Years ended December 31,

 
     2004

   2003

   % Change

 

Firm Gas Sales - BBTU

                

Residential

   23,051    24,062    (4.2 )

Commercial

   15,614    16,152    (3.3 )

Industrial and other

   8,302    8,175    1.6  
    
  
  

Total firm sales

   46,967    48,389    (2.9 )
    
  
  

 

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In terms of customer sector characteristics, industrial sales are less sensitive to weather than residential and commercial sales which are influenced by temperature extremes. Despite the overall warmer winter weather in 2004, the increase in electric sales is attributable in part to the commercial sector where building expansions created the resulting additional energy use. Electric residential and commercial customers represented approximately 31% and 59%, respectively, of NSTAR’s total sales mix for 2004 and provided 39% and 54% of distribution and transmission revenues, respectively. Refer to the “Electric revenues” section below for a more detailed discussion. Industrial sales are primarily influenced by national and local economic conditions and sales to these customers reflect a sluggish economic environment and decreased manufacturing production.

 

Unit sales of electricity in 2005 are expected to grow at a rate of 2% to 3%. Firm gas sales are expected to grow at a rate of 5% to 6%. However, NSTAR forecasts its electric and natural gas sales based on normal weather conditions. Actual results may differ from those projected due to actual weather conditions above or below normal weather levels, and other factors. Refer to “Cautionary Statement” in this section.

 

     2004

    2003

    Normal
30-Year
Average


Heating degree-days

   5,986     6,263     6,033

Percentage (warmer) colder than prior year

   (4.4 )%   10.7 %    

Percentage (warmer) colder from 30-year average

   (0.8 )%   5.4 %    

Cooling degree-days

   632     755     777

Percentage (cooler) than prior year

   (16.3 )%   (22.3 )%    

Percentage (cooler) than 30-year average

   (18.7 )%   (2.8 )%    

 

Weather conditions impact electric and, to a greater extent during the winter, gas sales in NSTAR’s service area. Despite a very cold January, the first quarter of 2004 was 5.4% warmer than the same period in 2003, followed by continued warmer temperatures for the second quarter. The cooler than prior year third quarter resulted in reduced air conditioning demand that preceded a slightly colder fourth quarter of 2004. The comparative information above relates to heating and cooling degree-days for 2004 and 2003 and the number of degree-days in a “normal” year as represented by a 30-year average. A “degree-day” is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a base of 65 degrees. Each degree below or above the base temperature is measured as one degree-day.

 

Operating revenues

 

Operating revenues for 2004 increased 1.5% from 2003 as follows:

 

               Increase/(Decrease)

 

(in millions)


   2004

   2003

   Amount

    Percent

 

Electric revenues

                            

Retail distribution and transmission

   $ 852.7    $ 860.7    $ (8.0 )   (0.9 )

Energy, transition and other

     1,483.3      1,451.1      32.2     2.2  
    

  

  


 

Total retail

     2,336.0      2,311.8      24.2     1.0  

Wholesale

     16.9      21.5      (4.6 )   (21.4 )
    

  

  


 

Total electric revenues

     2,352.9      2,333.3      19.6     0.8  

Gas revenues

                            

Firm and transportation

     147.7      149.4      (1.7 )   (1.1 )

Energy supply and other

     344.6      315.8      28.8     9.1  
    

  

  


 

Total gas revenues

     492.3      465.2      27.1     5.8  

Unregulated operations revenues

     109.1      113.2      (4.1 )   (3.6 )
    

  

  


 

Total operating revenues

   $ 2,954.3    $ 2,911.7    $ 42.6     1.5  
    

  

  


 

 

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Table of Contents

Electric revenues

 

Electric retail distribution revenues primarily represent charges to customers for the Company’s recovery of its capital investment, including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage lines from the generator to the Company’s substations. Despite a 1.5% increase in retail MWH sales, substantially all in the residential and commercial sectors, the decrease in retail distribution and transmission revenues is primarily due to transmission-related true-up adjustments.

 

NSTAR’s largest earnings sources are the revenues derived from distribution rates approved by the MDTE. The level of distribution revenues is affected by weather conditions and the economy. Weather conditions affect sales to NSTAR’s residential and small commercial customers. Economic conditions affect NSTAR’s large commercial and industrial customers.

 

Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on behalf of its customers and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. The energy revenues relate to customers being provided energy supply under either standard offer or default service. Energy supply contract prices vary among the NSTAR Electric companies and for standard offer and default service customers. However, the retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on NSTAR’s consolidated net income. Furthermore, energy and transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings. Other revenues primarily relate to the Company’s ability to effectively reduce stranded costs (mitigation incentive), rental revenue from electric property and annual cost reconciliation true-up adjustments. In 2004, the cost reconciliation true-up adjustments increased revenues by approximately $4.7 million. The $32.3 million increase in energy, transition and other revenues is primarily attributable to higher rates for default service and standard offer service, which include ComElectric and Cambridge Electric standard offer service fuel index adjustments throughout 2004 and for Boston Edison in the fourth quarter of 2004.

 

Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. This decrease in 2004 wholesale revenues reflects the expiration of two wholesale power supply contracts in 2003 and one contract in 2004. After October 2005, NSTAR Electric anticipates it will no longer have contracts for the supply of wholesale power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts will have no impact on results of operations.

 

Gas revenues

 

Firm and transportation gas revenues primarily represent charges to customers for NSTAR Gas’ recovery of costs of its capital investment in its gas infrastructure, including a return component, and for the recovery of costs for the ongoing operation and maintenance of that infrastructure. The transportation revenue component represents charges to customers for the recovery of costs to move the natural gas over pipelines from gas suppliers to take stations located within NSTAR Gas’ service area. The $1.7 million decrease in firm and transportation revenues is attributable to warmer weather, conservation efforts, the decrease in sales volumes of 2.9% offset by increased revenues related to carrying costs earned as part of a reconciliation rate adjustment mechanism related to pension and PBOP that was approved by the MDTE in 2003.

 

NSTAR Gas’ sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes.

 

Energy supply and other gas revenues primarily represent charges to customers for the recovery of costs to the Company in order to acquire the natural gas in the marketplace and a charge for recovery of the Company’s gas

 

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supplier service costs. The current gas rate structure of NSTAR Gas includes a gas adjustment clause, pursuant to which variations between actual gas costs incurred and gas costs billed are deferred and refunded to or collected from customers in a subsequent period. The revenue increase of $28.8 million primarily reflects the impact of the higher cost of gas sold that reflected a weighted average cost of gas per therm increase over the same period in 2003 of approximately 5.3%. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings.

 

Unregulated operations revenues

 

Unregulated operations revenues are derived from NSTAR’s businesses that include district energy operations and telecommunications. Unregulated revenues were $109.1 million in 2004 compared to $113.2 million in 2003, a decrease of $4.1 million, or 4%. The decrease is primarily the result of the sale of Blackstone Station to Harvard University in April 2003 partially offset by an increase in the revenues from electric and chilled water services and higher steam revenues resulting from colder weather and higher fuel costs.

 

Operating expenses

 

Purchased power costs were $1,347.9 million for 2004 compared to $1,329.8 million in 2003, an increase of $18.1 million, or 1%. The increase is primarily the result of the higher costs of fuel, partially offset by the recognition of $44.2 million relating to the additional deferral of standard offer and default service supply costs. NSTAR Electric adjusts its rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to this rate adjustment mechanism, changes in the amount of energy supply expense have no impact on earnings.

 

The cost of gas sold, representing NSTAR Gas’ supply expense, was $313.2 million for 2004 compared to $284.5 million in 2003, an increase of $28.7 million, or 10%. Despite the lower volume of firm gas sales of 2.9%, the revenue increase reflects the higher costs of gas supply. NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. However, these expenses are also fully reconciled to the current level of revenues collected and have no impact on earnings.

 

Operations and maintenance expense was $421.4 million in 2004 compared to $443.9 million in 2003, a decrease of $22.5 million, or 5%. The decrease primarily reflects the first full year of the Company’s pension and PBOP rate mechanism. The mechanism was implemented in September 2003 and, at that time, the Company expensed approximately $18.0 million of pension and PBOP costs, which were deferred during the first eight months of 2003. Expenses in 2004 reflect lower labor and labor-related costs as well as the absence in 2004 of operation and maintenance costs associated with Blackstone Station, which was sold in April 2003.

 

Depreciation and amortization expense was $246.9 million in 2004 compared to $235.5 million in 2003, an increase of $11.4 million or 5%. The increase primarily reflects higher depreciable distribution and transmission plant in service, an increase to the transmission depreciation rate, and increased expense related to software and merger costs to achieve amortization.

 

DSM and renewable energy programs expense was $67.3 million in 2004 compared to $66.2 million in 2003, an increase of $1.1 million, or 2%, which are consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis plus a small incentive return.

 

Property and other taxes were $103.1 million in 2004 compared to $97.8 million in 2003, an increase of $5.3 million, or 5%. This increase was due to higher overall municipal property taxes of $5.1 million caused primarily by higher assessments. Higher property taxes are primarily due to increased plant investment and increased rates

 

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associated with legislation passed in Massachusetts allowing for the temporary shift of property tax burdens from residential to commercial property owners, in particular, in the City of Boston.

 

Income taxes attributable to operations were $116.2 million in 2004 compared to $121.4 million in 2003, a decrease of $5.2 million, or 4%. Despite higher pre-tax income in 2004, incomes taxes decreased due to the reversal of state tax reserves as a result of resolution of prior audit periods and permanent tax benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The tax benefit related to the Act will not impact NSTAR’s results of operations as these tax benefits are incorporated into the Company’s pension and PBOP rate adjustment mechanism.

 

Other income, net

 

Other income, net was approximately $7.3 million in 2004 compared to $14.4 million in 2003, a decrease in other income of $7.1 million. The decrease is primarily due to the absence in 2004 of the recognition of $4.6 million in tax benefits related to deferred tax valuation allowance adjustments recognized in 2003 and the 2003 sale of Blackstone Station to Harvard University that resulted in a pre-tax gain of $1.3 million. In 2004, other income includes proceeds from an executive life insurance policy of $1.2 million, $1.7 million in employee-related contract fees received associated with the operating agreement with Harvard University related to Blackstone Station and higher interest income on investments of $1 million.

 

Other deductions, net

 

Other deductions, net were approximately $1.5 million in 2004 compared to $6.2 million in 2003, including write-down of RCN investment, net. The $4.7 million decrease in other deductions in 2004 was due primarily to the absence of the RCN abandonment charge of $6.8 million (pre-tax) in 2003.

 

Interest charges

 

Interest on long-term debt and transition property securitization certificates was $147.3 million in 2004 compared to $153.7 million in 2003, a decrease of $6.4 million, or 4%. This decrease in interest expense primarily reflects the retirement of Boston Edison’s $181 million 7.80% Debentures on March 15, 2004 that lowered expense by $11.2 million, the absence of $2.1 million of interest expense in 2004 resulting from the retirement of Boston Edison’s $150 million 6.80% Debentures in March 2003, and the lower principal balance of transition property securitization certificates outstanding that resulted in reduced interest expense of $4.6 million. Securitization interest represents interest on debt of BEC Funding collateralized by the future income stream associated primarily with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison. Partially offsetting these interest expense declines was additional interest expense of $10.3 million on Boston Edison’s $300 million, 4.875% Debenture, issued on April 16, 2004 and an increase in interest expense of $1.4 million on ComElectric’s Term Loan issued on May 14, 2003 ($150 million, three-year, variable rate); (3.0275% at December 31, 2004).

 

Short-term and other interest expense was $7.4 million in 2004 compared to $8.0 in 2003, a decrease of $0.6 million, or 8%. The decrease in short-term and other interest expense primarily relates to a reduction in bank service fees and other charges ($1.9 million) resulting from a reduction in the level of NSTAR’s revolving line of credit. In addition, the decrease in short-term and other expenses includes a lower average level of debt outstanding of $164.9 million as compared to $234.8 million for 2004 and 2003, respectively, slightly offset by higher bank borrowing rates that averaged 1.38% through December 2004 as compared to 1.28% in the same period in 2003. Taken together, these factors decreased short-term borrowing costs by $0.6 million. Offsetting these decreases was an increase in regulatory interest due to higher customer deferral balances.

 

Allowance for funds used during construction/capitalized interest decreased $3.6 million, or 78%, in 2004, primarily due to the completion of construction in December 2003 of combustion turbines at AES’ MATEP facility.

 

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2003 compared to 2002

 

Earnings and Operations Overview

 

Earnings per common share were as follows:

 

     Years ended December 31,

     2003

   2002

   % Change

Basic

   $ 3.42    $ 3.05    12.1

Diluted

   $ 3.40    $ 3.03    12.2

 

Net income was $181.6 million for 2003 compared to $161.7 million for 2002. Three factors that contributed to the $19.9 million, or 12.3%, increase in 2003 earnings include increased retail electric and firm gas sales of 3.0% and 14.7%, respectively, as compared to 2002, interest savings on the Company’s outstanding indebtedness due to lower short-term and long-term interest and a lower level of borrowing in 2003, as well as a reduction in the impairment charges related to NSTAR’s investment in RCN Corporation (RCN) from 2002 to 2003.

 

NSTAR was able to achieve the earnings growth despite an increase in operation and maintenance expenses. The primary factor for the $12.2 million increase in these expenses from 2002 was higher benefit costs. These costs were somewhat mitigated, as a result of a MDTE order, effective September 1, 2003, which allowed the Company to defer approximately $9 million through December 31, 2003 in increased pension and other postretirement benefit costs. See “Critical Accounting Policies and Estimates,” Pension and Other Postretirement Benefits, in this MD&A for more information on the MDTE order.

 

From a cash flow perspective, NSTAR generated cash from operations sufficient to fund approximately $308 million of net capital expenditures and approximately $116 million of cash dividends. In comparison to the prior year, cash from operations decreased primarily due to the timing of the collection of energy costs and increased contributions to NSTAR’s pension and PBOP plans. The Company’s capital expenditures contributed to NSTAR’s solid operational performance in reliability, restoration, and customer service measurements. These measurements are reflected in NSTAR’s MDTE service quality indicator filings, which indicated that NSTAR has exceeded its service quality measures and, therefore, not subject to penalties for both 2003 and 2002. Cash expended for financing activities primarily reflect the payment of debt service requirements and dividends to shareholders.

 

Energy sales and weather

 

The following is a summary of retail electric and firm gas energy sales for the years indicated:

 

     Years ended December 31,

 
     2003

   2002

   % Change

 

Retail Electric Sales - MWH

                

Residential

   6,492,738    6,116,906    6.1  

Commercial

   12,417,719    12,089,839    2.7  

Industrial

   1,694,184    1,797,718    (5.8 )

Other

   170,012    171,527    (0.9 )
    
  
  

Total retail sales

   20,774,653    20,175,990    3.0  
    
  
  

     Years ended December 31,

 
     2003

   2002

   % Change

 

Firm Gas Sales - BBTU

                

Residential

   24,062    20,913    15.1  

Commercial

   16,152    14,914    8.3  

Industrial and other

   8,175    6,362    28.5  
    
  
  

Total firm sales

   48,389    42,189    14.7  
    
  
  

 

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In terms of customer sectors, industrial sales are less sensitive to weather while residential and commercial sales are influenced by temperature extremes. In addition to unseasonably cold winter weather and cool spring and summer conditions in 2003, the increase in sales is attributable in part to further home and commercial building and expansion of existing units and the resulting extension of residential and commercial energy uses. Residential and commercial customers were approximately 31% and 59%, respectively, of NSTAR’s total sales mix for 2003 and provided 45% and 49% of distribution revenues, respectively. Industrial sales are primarily influenced by national and global economic conditions and sales to these customers declined in 2003 primarily due to a slowdown in economic conditions that led to reduced production or facility closings.

 

NSTAR forecasts its electric and gas sales based on normal weather conditions. Actual results may differ from those projected due to actual weather conditions above or below normal weather levels, and other factors. Refer to “Cautionary Statement” in this section.

 

     2003

    2002

    Normal
30-Year
Average


Heating degree-days

   6,263     5,658     5,944

Percentage change from prior year

   10.7 %   0 %    

Percentage change from 30-year average

   5.4 %   (4.8 )%    

Cooling degree-days

   755     972     777

Percentage change from prior year

   (22.3 )%   18.2 %    

Percentage change from 30-year average

   (2.8 )%   25.1 %    

 

Weather conditions impact electric and, to a greater extent during the winter, gas sales in NSTAR’s service area. The first quarter of 2003 was significantly colder than the same period in 2002, followed by continued below normal temperatures for the second and third quarters, and warmer than prior year and normal conditions by 11.2% and 4.0% in the fourth quarter of 2003, respectively. The comparative information above relates to heating and cooling degree-days for 2003 and 2002 and the number of degree-days in a “normal” year as represented by a 30-year average. A “degree-day” is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a base of 65 degrees. Each degree below or above the base temperature is measured as one degree-day.

 

Operating revenues

 

Operating revenues for 2003 increased 8.2% from 2002 as follows:

 

(in millions)


             Increase/(Decrease)

 
   2003

   2002

   Amount

    Percent

 

Electric revenues

                            

Retail distribution and transmission

   $ 860.7    $ 810.9    $ 49.8     6.1  

Energy, transition and other

     1,451.1      1,380.5      70.6     5.1  
    

  

  


 

Total retail

     2,311.8      2,191.4      120.4     5.5  

Wholesale

     21.5      64.2      (42.7 )   (66.5 )
    

  

  


 

Total electric revenues

     2,333.3      2,255.6      77.7     3.4  

Gas revenues

                            

Firm and transportation

     149.4      131.1      18.3     14.0  

Energy supply and other

     315.8      200.7      115.1     57.3  
    

  

  


 

Total gas revenues

     465.2      331.8      133.4     40.2  

Unregulated operations revenues

     113.2      103.2      10.0     9.7  
    

  

  


 

Total operating revenues

   $ 2,911.7    $ 2,690.6    $ 221.1     8.2  
    

  

  


 

 

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Electric revenues

 

Electric retail distribution revenues primarily represent charges to customers for the Company’s recovery of its capital investment, including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage lines from the generator to the Company’s substations. The increase in retail revenues primarily reflects the 3% increase in retail MWH sales. Retail electric revenues for 2003 also include approximately $13 million in carrying charges on the Company’s average net prepaid pension and PBOP balances, as allowed under an order from the MDTE in 2003.

 

NSTAR’s largest earnings sources are the revenues derived from distribution rates approved by the MDTE. The level of distribution revenues is affected by weather conditions and the economy. Weather conditions affect sales to NSTAR’s residential and small commercial customers. Economic conditions affect NSTAR’s large commercial and industrial customers.

 

Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire the energy supply on behalf of its customers and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. The energy supply revenues relate to customers being provided energy supply under either standard offer or default service. Energy supply contract prices vary among the NSTAR Electric companies and for standard offer and default service customers. However, the retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on NSTAR’s consolidated net income. Furthermore, energy and transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings. Other revenues primarily relate to the Company’s ability to effectively reduce stranded costs (mitigation incentive) and rental revenue from electric property.

 

Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. This decrease in wholesale revenues reflects the expiration of two wholesale power supply contracts in 2003 and three other contracts during 2002. After October 31, 2005, NSTAR Electric will no longer have contracts for the supply of wholesale power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts will have no impact on results of operations. In October 2004, a municipal wholesale electric contract expired resulting in a decline in wholesale revenues and sales.

 

Gas revenues

 

Firm and transportation gas revenues primarily represent charges to customers for NSTAR Gas’ recovery of costs of its capital investment in its gas infrastructure, including a return component, and for the recovery of costs for the ongoing operation and maintenance of that infrastructure. The transportation revenue component represents charges to customers for the recovery of costs to move the natural gas over pipelines from gas suppliers to take stations located within NSTAR Gas’ service area. The $18.3 million increase in firm and transportation revenues is attributable to the 14.7% increase in energy sales due to the significantly colder winter weather, and additional customers. Firm gas revenues also include approximately $3 million in carrying charges on the Company’s average net prepaid pension and PBOP balances, as allowed under an order from the MDTE in 2003.

 

NSTAR Gas’ sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes.

 

Energy supply and other gas revenues primarily represent charges to customers for the recovery of costs to the Company in order to acquire the natural gas in the marketplace and a charge for recovery of the Company’s gas supplier service costs. This revenue increase of $115.1 million primarily reflects the higher costs of gas supply that reflected a weighted average cost of gas per therm increase over 2002 of approximately 88%. These revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings.

 

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Table of Contents

Unregulated operations revenues

 

Unregulated operations revenues are derived from NSTAR’s businesses that include district energy operations, telecommunications, and liquefied natural gas service. Unregulated revenues were $113.2 million in 2003 compared to $103.2 million in 2002, an increase of $10.0 million, or 10%. The increase in unregulated revenues is primarily the result of an increase in the rates for electric and chilled water services and higher steam revenues resulting from the significantly colder weather and higher fuel costs.

 

Operating expenses

 

Purchased power costs were $1,329.8 million for 2003 compared to $1,236.3 million in 2002, an increase of $93.5 million, or 8%. The increase is primarily the result of increased sales and the higher costs of fuel, partially offset by the recognition of $29.2 million relating to the deferred standard offer and default service supply costs for current period under-collection of these costs. NSTAR Electric adjusts its rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to the rate adjustment mechanisms, changes in the amount of energy supply expense have no impact on earnings.

 

The cost of gas sold, representing NSTAR Gas’ supply expense, was $284.5 million for 2003 compared to $176.5 million in 2002, an increase of $108.0 million, or 61%, due to recognition of the higher costs of gas supply and the significant increase in sales. NSTAR Gas maintains a flexible resource portfolio consisting of gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. However, these expenses are also fully reconciled to the current level of revenues collected.

 

Operations and maintenance expense was $443.9 million in 2003 compared to $431.7 million in 2002, an increase of $12.2 million, or 3%. This increase primarily reflects a higher overall level of pension and PBOP costs of approximately $33 million. This increase was somewhat mitigated, effective September 1, 2003, as a result of a MDTE order, which allowed NSTAR to defer approximately $9 million through December 31, 2003 of the increased pension and other postretirement benefits expense. This increase was partially offset by the reduction in operations and maintenance expense as the Company benefited from improvements made in electric distribution services in 2002 and overall cost reduction initiatives in 2003. Also, bad debt expense increased by $2.6 million due to higher retail revenue and receivables outstanding.

 

Depreciation and amortization expense was $235.5 million in 2003 compared to $239.2 million in 2002, a decrease of $3.7 million or 2%. The decrease primarily reflects the absence in 2003 of $7.3 million in accelerated amortization of regulatory assets associated with the Seabrook generating unit sale in 2002, partially offset by higher depreciable plant in service.

 

DSM and renewable energy programs expense was $66.2 million in 2003 compared to $69.0 million in 2002, a decrease of $2.8 million, or 4%, which are consistent with the collection of conservation and renewable energy revenues. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis plus a small incentive return.

 

Property and other taxes were $97.8 million in 2003 compared to $97.2 million in 2002, an increase of $0.6 million, or 1%. This increase was due to higher overall municipal property taxes of $2.1 million caused primarily by higher property assessments, capital additions and tax rates in the City of Boston, partially offset by lower payroll charges.

 

Income taxes attributable to operations were $121.4 million in 2003 compared to $107.1 million in 2002, an increase of $14.3 million, or 13%, reflecting higher pre-tax operating income in 2003 and the absence of tax benefits related to the sale of the Seabrook generating unit in 2002, which reduced income tax expense by approximately $4 million in 2002.

 

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Table of Contents

Other income, net

 

Other income, net was $14.4 million in 2003 compared to $22.4 million in 2002, a decrease in other income of $8.0 million. The decrease in 2003 income was due primarily to the absence of $4.9 million in gains realized in 2002 on the sale of demutualized insurance company common shares and the recognition of investment tax credits of $7.3 million as a result of the sale of the Seabrook generating unit in 2002, offset by the incremental benefit recognized related to deferred tax valuation allowance adjustments recognized in 2003 of approximately $4.6 million. Also, in 2003, other income, net includes the sale of Blackstone Station that resulted in a pretax gain of $1.3 million.

 

Other deductions, net

 

Other deductions, net, including write-down of RCN investment, net, were $6.2 million in 2003 and $19.7 million in 2002. In addition to the $4.5 million and the $17.7 million write-downs of the RCN investment in 2003 and 2002, other deductions in 2002 amounted to $2 million. The $4.2 million increase in other deductions in 2003 was due primarily to the RCN abandonment charge of $6.8 million (pre-tax). Offsetting this increase was the absence in 2003 of a $2 million accrual for shutdown costs recorded in 2002 for the Northwind district energy facility for expected equipment removal costs.

 

Interest charges

 

Interest on long-term debt and transition property securitization certificates was $153.7 million in 2003 compared to $152.6 million in 2002, an increase of $1.1 million, or 1%. This increase in interest expense primarily reflects the impact of the October 15, 2002 Boston Edison issuance of $400 million of 4.875% 10-year debentures and $100 million of 3-year floating rate debentures priced at three month LIBOR plus 50 basis points (1.65% at December 31, 2003). Also, contributing to this increase was ComElectric’s issuance of a $150 million variable rate (1.895% at December 31, 2003) Term Loan on May 14, 2003. These new debt issuances increased interest expense by $18.4 million in 2003. Partially offsetting these increases was the absence in 2003 of $11.6 million in interest due to Boston Edison’s early redemption of its $60 million 8.25% Debentures in September 2002 and its $150 million 6.80% Debentures retired in March 2003 and scheduled repayments of its transition property securitization certificates of $68.7 million that resulted in reduced interest expense of $4.4 million. Securitization interest represents interest on debt collateralized by the future income stream associated primarily with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison.

 

Short-term and other interest expense was $8 million in 2003 compared to $22.8 million in 2002, a decrease of $14.8 million, or 65%. This decrease is primarily attributable to both lower borrowing rates and a lower average level of short-term debt outstanding that averaged $234.8 million and $494.7 million in 2003 and 2002, respectively. Interest rates on these borrowings averaged 1.28% and 1.89% for 2003 and 2002, respectively.

 

The increase in long-term debt interest expense and the decrease in short-term debt interest expense is primarily due to the fact that NSTAR has refinanced some short-term debt with long-term debt in order to take advantage of favorable interest rates.

 

Allowance for funds used during construction/capitalized interest increased $1.7 million, or 59%, primarily due to a higher average balance of construction work in progress during the year due to the construction of new combustion turbines at AES’ MATEP facility.

 

Liquidity and Capital Resources

 

A major driver to NSTAR’s liquidity is the level of plant expenditures. Plant expenditures currently forecasted for 2005 are $398 million, consisting of approximately $392 million for electric and gas operations and $6 million for capital requirements of non-utility ventures. The plant expenditure level over the following four years (2006-2009) is currently forecasted to aggregate approximately $1.1 billion.

 

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Forecasted plant expenditures include NSTAR’s 345kV transmission project that, in the aggregate, is expected to total $200 million. A significant portion of these costs will be incurred in 2005 and 2006. NSTAR has obtained regulatory approval to construct a 345kV transmission line from Stoughton, Massachusetts, a southern suburb of Boston, to South Boston in order to assure continued reliability of service and improve power import capacity in the Northeast Massachusetts area (NEMA). Construction is set to begin in the first quarter of 2005, subject to final permitting. The new transmission line is anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost will be shared by all of New England and recovered in rates by NSTAR through wholesale and retail transmission rates.

 

In addition to plant expenditures, NSTAR’s primary estimated uses of cash for each of the years presented below include long-term debt principal and interest payments, minimum lease commitments, electric contractual capacity charge obligations, natural gas contractual agreements and purchase power contract buy-out/restructuring obligations.

 

(in millions)


   2005

   2006

   2007

   2008

   2009

   Years
Thereafter


   Total

Long-term debt

   $ 108    $ 179    $ 15    $ 17    $ 7    $ 1,588    $ 1,914

Interest obligation on long-term debt

     117      111      106      105      104      337      880

Transition property securitization *

     68      69      69      68      68      35      377

Interest obligation on transition property securitization *

     25      20      16      11      6      1      79

Leases

     20      14      13      11      9      39      106

Electric capacity obligations **

     29      2      2      2      2      24      61

Gas contractual obligations **

     48      45      36      35      34      92      290

Purchase power buy-out obligations **

     145      156      160      162      142      346      1,111
    

  

  

  

  

  

  

     $ 560    $ 596    $ 417    $ 411    $ 372    $ 2,462    $ 4,818
    

  

  

  

  

  

  


* Reflects securities issued by BEC Funding LLC, a subsidiary of Boston Edison. BEC Funding LLC recovers the principal and interest obligations for its transition property securitization bonds from customers of Boston Edison through a component of Boston Edison’s transition charge and, as a result, these payment obligations do not affect NSTAR’s overall cash flow. During the first half of 2005, NSTAR expects to issue additional transition property securitization bonds through BEC Funding II, LLC, a subsidiary of Boston Edison and CEC Funding, LLC, a subsidiary of ComElectric. This new obligation is not included in the table above as the exact amount of the obligation and the resulting yearly principal and interest payment requirements are not yet finalized.

 

** Reflects obligations for purchase power and the cost of gas. Boston Edison, Cambridge Electric and ComElectric recover capacity and buy-out/restructuring obligations from customers through a component of their transition charges and, as a result, these payment obligations do not affect NSTAR’s overall cash flow. NSTAR Gas recovers its contractual obligations from customers through its seasonal cost of gas adjustment clause and, as a result, these payment obligations do not affect NSTAR’s overall cash flow.

 

Current Cash Flow Activity

 

Operating activities in 2004 provided $437.5 million of cash. The Company used $303.2 million in its investing activities, primarily to fund $313.4 million of plant expenditures, which included system reliability infrastructure improvement projects incurred by NSTAR Electric and NSTAR Gas operations. Additionally, the Company used $138.3 million in financing activities to primarily fund $120 million of dividends.

 

Operating Activities

 

The net cash provided by 2004 operating activities increased $12.2 million from 2003 to $437.5 million. Major drivers to cash provided by operating activities are working capital and energy cost recoveries. From a working capital perspective, accounts payable increased approximately $15 million due to the timing of energy supply

 

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invoices and Company benefit plan contributions decreased approximately $59 million year-to-year. NSTAR contributed approximately $43 million to its pension plan and approximately $20 million to its other postretirement benefit plans in 2004. NSTAR currently anticipates that it will contribute approximately $35 million to its pension plan and approximately $20 million to its other postretirement benefit plans in 2005.

 

Offsetting the positive working capital components were decreased energy cost recoveries year-to-year by approximately $43 million. There is no impact to earnings, as energy costs are fully recoverable from customers through the transition charge.

 

During 2003 and 2004, NSTAR has benefited from bonus depreciation for income tax purposes (between 30% and 50% depreciation on new capital additions). As a result, NSTAR’s deferred income taxes have increased. As of December 31, 2004, the bonus depreciation rules have generally expired. Therefore, in 2005 and beyond, the cash flow benefit from bonus depreciation will be limited to certain qualified projects.

 

Investing Activities

 

The net cash used in investing activities in 2004 of $303.2 million consists primarily of capital expenditures related to infrastructure investments in transmission and distribution systems.

 

Financing Activities

 

The net cash used in financing activities in 2004 of $138.3 million reflects long-term debt redemptions and sinking funds payments of $258.4 million, dividends paid of $119.8 million and a reduction in short-term borrowings since December 2003 of $77.7 million as a result of the $300 million financing by Boston Edison in April 2004.

 

NSTAR’s banking arrangements provide for daily cash transfers to our disbursement accounts as vendor checks are presented for payment and where the right of offset does not exist among accounts. Changes in the balances of the disbursement accounts are reflected in financing activities in the accompanying Statement of Cash Flows.

 

Additionally, beginning in August 2004, NSTAR began issuing common shares for cash as part of its Dividend Reinvestment and Direct Common Shares Purchase Plan. As of December 31, 2004, NSTAR has issued approximately 156,000 common shares and has received approximately $7.6 million as a result of the plan.

 

Short-Term Financing Activities

 

NSTAR’s short-term debt decreased by $77.7 million to $161.4 million at December 31, 2004 as compared to $239.1 million at December 31, 2003. The decrease resulted primarily from the proceeds of the $300 million financing being used to pay down short-term debt balances.

 

Previously, on March 16, 2004, Boston Edison redeemed the entire $181 million aggregate principal amount of its 7.80% Debentures due March 15, 2023. The redemption included payment of an approximate $6.1 million premium plus accrued interest.

 

Long-Term Financing Activities

 

In 2003, NSTAR Electric initiated a process to auction off certain purchase power agreements under which NSTAR Electric had entitlements to approximately 1,100 MW of capacity under long-term contracts with non-utility generators. The auction was intended to further NSTAR Electric’s efforts to mitigate stranded costs, which continue to be recovered from customers. One contract in which NSTAR Electric had entitlements to approximately 300 MW of the 1,100 MW of capacity, originally included in the auction, expired on December 31, 2004. Also in 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its

 

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purchase power agreements. These buy-out/restructuring agreements provide no economic benefit to NSTAR Electric and, therefore, the agreements’ contract termination costs will be recorded on the accompanying Consolidated Financial Statements. These agreements constitute approximately 685 MW of the 1,100 MW of capacity, originally included in the auction, and reduce the amount of NSTAR Electric’s future exposure to the above market costs that NSTAR Electric will collect from its customers through its transition charges. As of December 31, 2004, four of these agreements have received MDTE approval and have been recognized. Two of the four agreements require NSTAR Electric to make monthly payments through December 2008 totaling approximately $80 million. The other two agreements require NSTAR Electric to make monthly payments through September 2011 totaling approximately $125 million.

 

On January 7, 2005, NSTAR Electric received approval from the MDTE for an additional four agreements that are anticipated to be completed by February 2005. These four agreements were binding as of December 31, 2004 but were contingent upon regulatory approval. Since the contingency has been removed during February 2005, NSTAR recorded the contract termination costs as of December 31, 2004. One of the four agreements requires NSTAR Electric to make net monthly payments through September 2011 totaling approximately $416 million. The other three agreements require NSTAR Electric to make net monthly payments through September 2016 totaling approximately $490 million. NSTAR Electric anticipates making these cash payments from funds generated from operations and will be fully recovered through NSTAR Electric’s transition charge.

 

The total amount currently recognized for obligations relating to eight of the twelve contracts is approximately $852 million (in present day dollars); approximately $171 million as a component of current liabilities-power contracts and $681 million as a component of Deferred credits-power contracts on the accompanying Consolidated Balance Sheets. NSTAR Electric has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase in assets and liabilities.

 

Also in January 2005, the MDTE approved the remaining four contracts with two suppliers that reduced the overall amount of transition costs to be paid for above market contracts. The four contracts with the two suppliers are buy-out arrangements whereby NSTAR Electric has committed to pay amounts for the full release of its obligation under previous purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that seeks approval for full recovery of these buy-out costs and the issuance of $674.5 million in transition property securitization bonds to provide the funds for these four buy-out agreements. The MDTE approved the financing plan in January 2005. On February 15, 2005, the bonds were priced at a weighted average yield of 4.15%. NSTAR expects the securitization financing to close in March 2005.

 

Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the forecasts included in NSTAR’s 2004 Form 10-K are subject to revision due to changes in regulatory requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.

 

Sources of Additional Capital and Financial Covenant Requirements

 

NSTAR and Boston Edison have no financial covenant requirements under their respective long-term debt arrangements. ComElectric, Cambridge Electric and NSTAR Gas have financial covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2004 and 2003. NSTAR’s long-term debt other than the Mortgage Bonds/Notes of NSTAR Gas and Medical Area Total Energy Plant, Inc., a wholly owned subsidiary of AES, is unsecured.

 

The Transition Property Securitization Certificates issued by Boston Edison’s subsidiary, BEC Funding, LLC, are collaterized with a securitized regulatory asset that was sold to BEC Funding with a balance of $357.2 million and $425.4 million as of December 31, 2004 and 2003, respectively. Boston Edison, as servicing agent for BEC Funding, collected $96.0 million in 2004. These collected funds are remitted daily to an indenture trustee for BEC Funding. These Certificates are non-recourse to Boston Edison.

 

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In November 2004, NSTAR restructured its three-year, $175 million revolving credit agreement that was set to expire on November 15, 2005 into a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreement. This credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2004 and 2003, had $5 million and $1.5 million outstanding, respectively. Under the terms of the current credit agreement, NSTAR is required to maintain a maximum total consolidated debt to total capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous arrangement also required NSTAR to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. At December 31, 2004 and 2003, NSTAR was in full compliance with all of the aforementioned covenants.

 

In December 2003, Boston Edison filed a shelf registration with the SEC to allow Boston Edison to issue up to $500 million in debt securities. The registration became effective on January 9, 2004. On April 1, 2004, the MDTE approved the issuance by Boston Edison of up to $500 million of debt securities from time to time on or before December 31, 2005. On April 16, 2004, Boston Edison sold $300 million of ten-year fixed rate (4.875%) Debentures under this shelf registration. The net proceeds were primarily used to repay outstanding short-term debt balances.

 

As of September 28, 2004, Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. In addition, in November 2004, Boston Edison restructured its $350 million revolving credit agreement that expired in November 2004 into a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first draw under the agreement. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreements. This credit facility serves as backup to Boston Edison’s $350 million commercial paper program that had a $46.5 million and $182.5 million balance at December 31, 2004 and 2003, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not greater than 60%. At December 31, 2004 and 2003, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.

 

In addition, as of December 31, 2004, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $145 million available under several lines of credit and had $109.9 million and $55.1 million outstanding under these lines of credit at December 31, 2004 and 2003, respectively. As of September 28, 2004, ComElectric and Cambridge Electric have FERC authorization to issue short-term debt securities from time-to-time on or before November 30, 2006 and June 27, 2006, with maturity dates no later than November 30, 2007 and June 27, 2007, respectively, in amounts such that the aggregate principal does not exceed $125 million and $60 million, respectively, at any one time. NSTAR Gas is not required to seek approval from FERC to issue short-term debt.

 

On June 30, 2004, NSTAR filed an S-3 Registration Statement with the SEC for the purpose of registering two million common shares in connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan. The Registration Statement became effective on July 29, 2004. Since the effective date, NSTAR has issued approximately 156,000 shares under this registration and received approximately $7.6 million. Additionally, NSTAR issued approximately 86,000 shares as part of its Share Incentive Plan. No cash was received from this issuance.

 

On December 16, 2004, NSTAR announced its intention to split its common shares two-for-one, subject to market conditions and shareholder approval of an amendment to the Company’s Declaration of Trust that would

 

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increase the number of NSTAR’s authorized common shares, at the April 28, 2005 Annual Meeting of Shareholders.

 

Historically, NSTAR and its subsidiaries have had a variety of external sources of financing available, as indicated above, at favorable rates and terms to finance its external cash requirements. However, the availability of such financing at favorable rates and terms depends heavily upon prevailing market conditions and NSTAR’s or its subsidiaries’ financial condition and credit ratings.

 

An adverse change in NSTAR’s or its subsidiaries’ credit ratings or market conditions could have an adverse impact on the terms and conditions upon which NSTAR or its subsidiaries have access to capital markets. Currently, NSTAR and its subsidiaries have “A level” ratings at Standard & Poor’s, Moody’s and Fitch Ratings with a stable outlook for NSTAR and its subsidiaries. NSTAR has no financial guarantees, commitments, debt or lease agreements that would require a change in terms and conditions, such as acceleration of payment obligations, as a result of a change in its credit rating. However, NSTAR’s subsidiaries could be required to provide additional security for power supply contract performance, such as a letter of credit for their pro-rata share of the remaining value of such contracts. Refer to “Performance Assurances from Electricity and Gas Supply Agreements” and “Financial and Performance Guarantees” as disclosed in this MD&A.

 

NSTAR’s goal is to maintain a capital structure that preserves an appropriate balance between debt and equity. Based on NSTAR’s key cash resources available as discussed above, management believes its liquidity and capital resources are sufficient to meet its current and projected requirements.

 

Other Events

 

On July 14, 2003, Mirant Corporation and certain of its subsidiaries (Mirant) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. Mirant currently supplies, among other services, standard offer service for approximately 12% of NSTAR Electric’s standard offer load. Should Mirant fail to perform under this agreement, NSTAR Electric would be required to seek replacement energy supply to meet its standard offer obligation. NSTAR’s current expectation is that Mirant will continue to perform under its agreements with NSTAR, and, as a result, NSTAR does not expect the Mirant bankruptcy to have a material impact to its earnings or cash flows.

 

Performance Assurances from Electricity and Gas Supply Agreements

 

NSTAR Electric has contracted with a third party supplier to provide 100% of its standard offer service supply obligations through February 28, 2005. In addition, NSTAR Electric has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation, other than large customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than large customers, for the second half of 2005. NSTAR Electric has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation for large customers through March 2005. These agreements are for a term of three to twelve months. NSTAR Electric currently is recovering payments it is making to suppliers from its customers. Most of NSTAR Electric’s power suppliers are either investment grade companies or are subsidiaries of larger companies with investment grade or better credit ratings. In accordance with NSTAR’s Internal Credit Policy, and to minimize NSTAR Electric risk in the event the supplier encounters financial difficulties or otherwise fails to perform, NSTAR has financial assurances and guarantees that include both parental guarantees and letters of credit in place from the parent company of the supplier. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit rating, it is required to provide additional security for performance of its obligations. In view of current volatility in the energy supply industry, NSTAR Electric is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) does not provide the required additional security within the required time frames, NSTAR Electric may then terminate the agreement. In such event, NSTAR may be

 

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required to secure alternative sources of supply at higher or lower prices than provided under the terminated agreements. Some of these agreements include a reciprocal provision, where in the event that an NSTAR Electric distribution company receives a downgrade, that company could be required to provide additional security for performance, such as a letter of credit.

 

Virtually all of NSTAR Gas’ firm gas supply agreements are short-term (less than one year) and utilize market-based, monthly indexed pricing mechanisms so the financial risk to the Company would be minimal if a supplier were to fail to perform. However, in the event that a firm supplier does fail to perform under its firm gas supply agreement pricing provisions, the Company would be entitled to any positive difference between the monthly supply price and the cost of replacement supplies.

 

The cost of gas procured for firm gas sales customers is recovered through a semi-annual cost of gas adjustment mechanism. Under MDTE regulations, interim adjustments to the cost of gas may also be requested when the actual costs of gas supply vary from projections by more than 5%.

 

NSTAR Gas continually evaluates the financial stability of current and prospective gas suppliers. Firm suppliers are required to have and maintain investment grade credit ratings or financial assurances and guarantees that include both parental guarantees and letters of credit in place from the parent company of the supplier and the firm gas supply agreements allow either party to require financial assurance, or, if necessary, contract termination in the event that either party is downgraded below investment grade level and is unable to provide financial assurance acceptable to NSTAR Gas.

 

Financial and Performance Guarantees

 

On a limited basis, NSTAR and certain of its subsidiaries may enter into agreements providing financial assurance to third parties. Such agreements include letters of credit, surety bonds, and other guarantees.

 

At December 31, 2004, outstanding guarantees totaled $30.3 million as follows:

 

(in thousands)


    

Letters of Credit

   $ 5,560

Surety Bonds

     15,281

Other Guarantees

     9,500
    

Total Guarantees

   $ 30,341
    

 

The $5.6 million letter of credit is for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of NSTAR’s subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. As of December 31, 2004, there have been no amounts drawn under this letter of credit.

 

As of December 31, 2004, certain of NSTAR’s subsidiaries have purchased a total of $0.6 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, NSTAR and certain of its subsidiaries has purchased approximately $14.7 million in workers’ compensation self-insurer bonds. These bonds support the guarantee by NSTAR and certain of its subsidiaries to the Commonwealth of Massachusetts required as part of the Company’s workers’ compensation self-insurance program.

 

NSTAR and its subsidiaries have also issued $9.5 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.

 

Management believes the likelihood NSTAR would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.

 

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Contingencies

 

Environmental Matters

 

As of December 31, 2004, NSTAR’s subsidiaries are involved in four state regulated properties (“Massachusetts Contingency Plan, or “MCP” sites”) where oil or other hazardous materials were previously spilled or released. The NSTAR subsidiaries are required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.5 million and $0.7 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2003, respectively.

 

In addition to the MCP sites, NSTAR subsidiaries also face possible liability as a result of involvement in 15 multi-party disposal sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2003.

 

The MCP and multi-party disposal site amounts have not been reduced by any potential rate recovery treatment of these costs or any potential recovery from NSTAR’s insurance carriers. Prospectively, should NSTAR be allowed to collect these specific costs from customers, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs.

 

NSTAR Gas is participating in the assessment or remediation of five former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether NSTAR Gas may be responsible for remedial action. The MDTE has approved recovery of costs associated with MGP sites over a 7-year period, without carrying costs. As of December 31, 2004 and 2003, NSTAR has recorded a liability of approximately $3.8 million and $4.4 million, respectively, as an estimate for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset has been recorded that reflects the future rate recovery for these costs.

 

Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs and as either additional sites are identified or NSTAR’s responsibilities for such sites evolve or are resolved. NSTAR’s ultimate liability for future environmental remediation costs may vary from these estimates. Based on NSTAR’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that these environmental remediation costs will have a material adverse effect on NSTAR’s consolidated financial position, results of operations and cash flows for a reporting period.

 

Employees and Employee Relations

 

As of December 31, 2004, NSTAR had approximately 3,100 employees, including approximately 2,200, or 71%, who are represented by three units covered by separate collective bargaining contracts.

 

NSTAR’s contract with Local 369 of the Utility Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for Local 369 for a new labor contract. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Approximately 60 employees of Advanced Energy Systems’ MATEP subsidiary are represented by Local 877, the International Union of Operating Engineers, AFL-CIO, under a contract that expires on September 30, 2006.

 

Management believes it has satisfactory relations with its employees.

 

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Fair Value of Financial Instruments

 

Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2004 and 2003, were as follows:

 

     2004

   2003

(in thousands)


   Carrying
Amount


   Fair Value

   Carrying
Amount


   Fair Value

Long-term indebtedness (including current maturities)

   $ 2,250,647    $ 2,483,220    $ 2,209,585    $ 2,485,190

 

As discussed in the following section, NSTAR’s exposure to financial market risk results primarily from fluctuations in interest rates.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Although NSTAR has material commodity purchase contracts, these instruments are not subject to market risk. NSTAR’s electric and gas distribution subsidiaries have rate-making mechanisms that allow for the recovery of energy supply costs from customers, who make commodity purchases from NSTAR’s electric and gas subsidiaries, rather than from the competitive market. All energy supply costs incurred by NSTAR’s electric and gas subsidiaries to provide electricity for retail customers purchasing standard offer service (which expires on February 28, 2005) and default service or retail gas customers are recovered on a fully reconciling basis.

 

In addition, NSTAR’s exposure to financial market risk results primarily from fluctuations in interest rates. NSTAR is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for long-term indebtedness, including current maturities were 6.23% and 6.45% in 2004 and 2003, respectively.

 

On May 14, 2003, ComElectric entered into a $150 million, three-year variable rate unsecured Term Loan with a group of banks priced at LIBOR plus 62.5 basis points. An immediate change of one percent on this Term Loan would cause a change in interest expense of approximately $1.5 million per year.

 

On October 15, 2002, Boston Edison issued $100 million of 3-year floating rate debentures priced at LIBOR plus 50 basis points. An immediate change of one percent for these variable rate debentures would cause a change in interest expense of approximately $1 million per year.

 

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Item 8. Financial Statements and Supplementary Data

 

NSTAR

Consolidated Statements of Income

 

     Years ended December 31,

 
     2004

    2003

    2002

 
     (in thousands, except earnings per share)  

Operating revenues

   $ 2,954,332     $ 2,911,711     $ 2,690,625  
    


 


 


Operating expenses:

                        

Purchased power and cost of gas sold

     1,661,100       1,614,290       1,412,794  

Operations and maintenance

     421,367       443,931       431,740  

Depreciation and amortization

     246,944       235,516       239,233  

Demand side management and renewable energy programs

     67,294       66,217       68,986  

Property and other taxes

     103,061       97,837       97,204  

Income taxes

     116,238       121,409       107,113  
    


 


 


Total operating expenses

     2,616,004       2,579,200       2,357,070  
    


 


 


Operating income

     338,328       332,511       333,555  
    


 


 


Other income (deductions):

                        

Write-down of RCN investment, net

     —         (4,450 )     (17,677 )

Other income, net

     7,305       14,397       22,364  

Other deductions, net

     (1,487 )     (1,712 )     (1,994 )
    


 


 


Total other income, net

     5,818       8,235       2,693  
    


 


 


Interest charges:

                        

Long-term debt

     119,164       121,027       115,473  

Transition property securitization

     28,150       32,715       37,135  

Short-term debt and other

     7,394       8,043       22,848  

Allowance for borrowed funds used during construction and capitalized interest

     (1,003 )     (4,573 )     (2,875 )
    


 


 


Total interest charges

     153,705       157,212       172,581  
    


 


 


Preferred stock dividends of subsidiary

     1,960       1,960       1,960  
    


 


 


Net income

   $ 188,481     $ 181,574     $ 161,707  
    


 


 


Weighted average common shares outstanding:

                        

Basic

     53,134       53,033       53,033  

Diluted

     53,646       53,399       53,297  

Earnings per common share:

                        

Basic

   $ 3.55     $ 3.42     $ 3.05  

Diluted

   $ 3.51     $ 3.40     $ 3.03  

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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NSTAR

Consolidated Statements of Comprehensive Income

 

     Years ended December 31,

 
     2004

    2003

    2002

 
     (in thousands)  

Net income

   $ 188,481     $ 181,574     $ 161,707  

Other comprehensive income, net:

                        

Unrealized gain (loss) on investments

     —         2,783       (17,819 )

Reclassification adjustment for (gain) loss included in net income

     —         (2,783 )     15,110  

Additional minimum pension liability

     (5,817 )     1,104       (12,470 )

Deferred income taxes (benefit)

     2,414       (389 )     5,927  
    


 


 


Comprehensive income

   $ 185,078     $ 182,289     $ 152,455  
    


 


 


 

The accompanying notes are an integral part of the consolidated financial statements.

 

NSTAR

Consolidated Statements of Retained Earnings

 

     Years ended December 31,

     2004

   2003

   2002

     (in thousands)

Balance at the beginning of the year

   $ 449,114    $ 382,886    $ 334,138

Add:

                    

Net income

     188,481      181,574      161,707
    

  

  

Subtotal

     637,595      564,460      495,845
    

  

  

Deduct:

                    

Dividends declared:

                    

Common shares

     119,343      115,346      112,959
    

  

  

Balance at the end of the year

   $ 518,252    $ 449,114    $ 382,886
    

  

  

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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NSTAR

Consolidated Balance Sheets

 

    December 31,

    (in thousands)
    2004

   2003

Assets

                            

Utility plant in service, at original cost

  $ 4,412,073            $ 4,254,848        

Less: accumulated depreciation

    1,090,924     $ 3,321,149      1,109,248     $ 3,145,600
   


        


     

Construction work in progress

            103,866              70,500
           

          

Net utility plant

            3,425,015              3,216,100

Non-utility property, net

            154,963              160,556

Goodwill

            426,870              439,122

Equity investments

            13,887              15,322

Other investments

            59,096              53,566

Current assets:

                            

Cash and cash equivalents

    12,497              16,526        

Restricted cash

    10,254              13,144        

Accounts receivable, net of allowance of $21,804 and $23,424, respectively

    302,194              306,815        

Accrued unbilled revenues

    53,752              45,559        

Regulatory assets

    280,078              142,182        

Inventory, at average cost

    86,397              79,743        

Other

    32,497       777,669      39,172       643,141
   


        


     

Deferred debits:

                            

Regulatory assets - power contracts

            1,269,651              782,856

Regulatory assets - retiree benefit costs

            11,897              319,425

Regulatory assets - other

            595,140              610,584

Prepaid pension

            297,746              —  

Other

            85,295              91,479
           

          

Total assets

          $ 7,117,229            $ 6,332,151
           

          

Capitalization and Liabilities

                            

Common equity:

                            

Common shares, par value $1 per share, 100,000,000 shares authorized; 53,275,141 shares in 2004 and 53,032,546 shares in 2003 issued and outstanding

  $ 53,275            $ 53,033        

Premium on common shares

    872,729              866,221        

Retained earnings

    518,252              449,114        

Accumulated other comprehensive loss

    (3,374 )   $ 1,440,882      (6,776 )   $ 1,361,592
   


        


     

Cumulative non-mandatory redeemable preferred stock of subsidiary

            43,000              43,000

Long-term debt

            1,792,654              1,602,402

Transition property securitization

            308,748              377,150

Current liabilities:

                            

Long-term debt

    108,197              189,956        

Transition property securitization

    41,048              40,077        

Notes payable

    161,400              239,100        

Deferred income taxes

    8,072              13,961        

Accounts payable

    239,613              224,987        

Power contracts

    171,312              16,231        

Accrued interest

    33,073              34,490        

Dividends payable

    31,227              29,760        

Accrued expenses

    93,844              95,624        

Other

    73,346       961,132      71,964       956,150
   


        


     

Deferred credits:

                            

Accumulated deferred income taxes and unamortized investment tax credits

            840,461              765,507

Power contracts

            1,269,651              782,856

Pension liability

            31,296              46,659

Regulatory liability - cost of removal

            258,722              223,074

Other

            170,683              173,761

Commitments and contingencies

                            
           

          

Total capitalization and liabilities

          $ 7,117,229            $ 6,332,151
           

          

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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NSTAR

Consolidated Statements of Cash Flows

 

     Years ended December 31,

 
     2004

    2003

    2002

 
     (in thousands)  

Operating activities:

                        

Net income

   $ 188,481     $ 181,574     $ 161,707  

Adjustments to reconcile net income to net cash provided by operating activities:

                        

Depreciation and amortization

     246,363       236,336       239,800  

Deferred income taxes

     79,570       128,379       (13,311 )

Loss on write-down of RCN investment

     —         6,146       37,343  

Allowance for borrowed funds used during construction/capitalized interest

     (1,003 )     (4,573 )     (2,875 )

Power contract buy-out

     (5,310 )     (12,741 )     (12,741 )

Net changes in:

                        

Accounts receivable and accrued unbilled revenues

     (3,572 )     (6,526 )     166,425  

Inventory, at average cost

     (6,812 )     (21,188 )     9,554  

Other current assets

     (128,821 )     (3,531 )     17,422  

Accounts payable

     8,014       10,536       15,869  

Other current liabilities

     147,377       1,151       (105,582 )

Deferred debits and credits

     (291,562 )     (86,314 )     68,165  

Net change from other miscellaneous operating activities

     204,739       (3,970 )     (13,439 )
    


 


 


Net cash provided by operating activities

     437,464       425,279       568,337  
    


 


 


Investing activities:

                        

Plant expenditures (excluding AFUDC/capitalized interest)

     (313,387 )     (307,655 )     (368,084 )

Proceeds on sale of property, net

     14,252       17,572       26,866  

Investments

     (4,095 )     669       9,445  
    


 


 


Net cash used in investing activities

     (303,230 )     (289,414 )     (331,773 )
    


 


 


Financing activities (Note O):

                        

Long-term debt redemptions

     (258,357 )     (242,357 )     (166,917 )

Debt issue costs

     (1,851 )     (663 )     (5,218 )

Issuance of long-term debt

     300,000       150,000       500,000  

Net change in notes payable

     (77,700 )     40,500       (426,247 )

Change in disbursement accounts

     11,922       (3,747 )     17,990  

Common stock issuance

     7,558       —         —    

Dividends paid

     (119,835 )     (116,510 )     (114,389 )
    


 


 


Net cash used in financing activities

     (138,263 )     (172,777 )     (194,781 )
    


 


 


Net (decrease) increase in cash and cash equivalents

     (4,029 )     (36,912 )     41,783  

Cash and cash equivalents at the beginning of the year

     16,526       53,438       11,655  
    


 


 


Cash and cash equivalents at the end of the year

   $ 12,497     $ 16,526     $ 53,438  
    


 


 


Supplemental disclosures of cash flow information:

                        

Cash paid (received) during the year for:

                        

Interest, net of amounts capitalized

   $ 144,762     $ 154,956     $ 155,265  

Income taxes (refund)

   $ 34,627     $ (4,526 )   $ 95,980  

Non-cash financing activity:

                        

Non-cash common share issuance

   $ 4,063     $ —       $ —    

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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Notes to Consolidated Financial Statements

 

Note A. Business Organization and Summary of Significant Accounting Policies

 

1. About NSTAR

 

NSTAR (or the Company) is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy and Commonwealth Energy System. NSTAR’s retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR’s three retail electric companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean the registrant NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR’s non-utility, unregulated operations include district energy operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation), telecommunications operations (NSTAR Communications, Inc. (NSTAR Com)) and a liquefied natural gas service company (Hopkinton LNG Corp.).

 

2. Basis of Consolidation and Accounting

 

The accompanying Consolidated Financial Statements reflect the results of operations, comprehensive income, retained earnings, financial position and cash flows of NSTAR and its subsidiaries. All significant intercompany transactions have been eliminated in consolidation. Certain immaterial reclassifications have been made to prior year amounts to conform to the current year’s presentation.

 

NSTAR’s utility subsidiaries follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, NSTAR and its subsidiaries are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying Consolidated Financial Statements conform to accounting principles generally accepted in the United States of America (GAAP). The utility subsidiaries are subject to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from those of other businesses and industries. The distribution and transmission businesses remain subject to rate-regulation and continue to meet the criteria for application of SFAS 71. Refer to Note D to these Consolidated Financial Statements for more information on regulatory assets.

 

The preparation of financial statements in conformity with GAAP requires management of NSTAR and its subsidiaries to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and 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 these estimates.

 

3. Revenues

 

Utility revenues are based on authorized rates approved by the MDTE and FERC. Estimates of distribution and transition revenues for electricity and natural gas delivered to customers but not yet billed are accrued at the end of each accounting period.

 

Revenues for NSTAR’s non-utility subsidiaries are recognized when services are rendered or when the energy is delivered.

 

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4. Utility Plant

 

Utility plant is stated at original cost. The cost of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, is charged to accumulated depreciation. The incurred related cost of removal is charged against the Regulatory liability - cost of removal.

 

5. Non-Utility Plant

 

Non-utility property is stated at cost or its net realizable value. The following is a summary of non-utility property and equipment, at cost less accumulated depreciation, at December 31:

 

(in thousands)


   2004

    2003

 

Land

   $ 15,700     $ 15,604  

Energy production equipment

     136,929       132,487  

Telecommunications equipment

     39,287       38,314  

Gas storage

     42,701       42,701  

Buildings and improvements

     2,992       2,992  
    


 


       237,609       232,098  

Less: accumulated depreciation

     (83,104 )     (72,123 )
    


 


       154,505       159,975  

Construction work in progress

     458       581  
    


 


     $ 154,963     $ 160,556  
    


 


 

6. Depreciation

 

Depreciation of utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. The composite rates are subject to the approval of the MDTE and FERC. The overall composite depreciation rates for utility property were 3.02%, 3.04% and 3.26% in 2004, 2003 and 2002, respectively. The rates include a cost of removal component, which is collected from customers.

 

Depreciation of non-utility property is computed on a straight-line basis over the estimated life of the asset. The estimated depreciable service lives (in years) of the major components of non-utility property and equipment are as follows:

 

Plant Component


   Depreciable
Life


Energy production equipment

   25-35

Telecommunications equipment

   10

Liquefied gas storage facilities

   28

Buildings and improvements

   40

 

Depreciation expense on non-utility property and equipment was $13 million, $12 million and $9 million for 2004, 2003 and 2002, respectively.

 

7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock

 

Consistent with the recovery in utility rates, discounts, redemption premiums and related costs associated with the issuance and redemption of long-term debt and preferred stock are deferred and amortized as an addition to interest expense over the life of the original or replacement debt. Costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.

 

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8. Allowance for Borrowed Funds Used During Construction (AFUDC)/Capitalized Interest

 

AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2004, 2003 and 2002 were 1.72%, 1.60% and 2.26%, respectively, and represented only the costs of short-term debt.

 

NSTAR capitalizes interest costs on long-term construction projects related to its unregulated businesses. Interest costs of $3.7 million during 2003 were capitalized for the construction of new combustion turbines at AES’ MATEP facility. No interest costs were capitalized during 2004.

 

9. Cash, Cash Equivalents and Restricted Cash

 

Cash, cash equivalents and restricted cash are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the remainder of the net proceeds from the sale of Canal’s generation assets that are required to be used to reduce the transition costs that otherwise would be billed to customers, funds held by a trustee in connection with Advanced Energy System’s 6.924% Note Agreement, and funds held in reserve for a trust on behalf of Boston Edison to pay the principal and interest on the transition property securitization.

 

NSTAR’s banking arrangements provide for daily cash transfers to our disbursement accounts as vendor checks are presented for payment. The balances of the disbursement accounts amount to $26,165 and $14,243 at December 31, 2004 and 2003, respectively, and are included in accounts payable on the accompanying Consolidated Balance Sheets. Changes in the balances of the disbursement accounts are reflected in financing activities in the accompanying Statement of Cash Flows.

 

10. Equity Method of Accounting

 

NSTAR uses the equity method of accounting for investments in corporate joint ventures in which it does not have a controlling interest. Under this method, it records as income or loss the proportionate share of the net earnings or losses of the joint ventures with a corresponding increase or decrease in the carrying value of the investment. The investment is reduced as cash dividends are received. NSTAR participates in several corporate joint ventures in which it has investments, principally its 14.5% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec System in Canada, and its equity investments ranging from 4% to 14% in three regional nuclear facilities that are currently being decommissioned.

 

11. Goodwill and Costs to Achieve

 

The merger that created NSTAR was accounted for using the purchase method of accounting. The premium (Goodwill) associated with the acquisition was approximately $490 million, while the original estimate of transaction and integration costs to achieve the merger was $111 million. The merger premium is reflected on the accompanying Consolidated Balance Sheets as Goodwill. In accordance with the MDTE’s order, this premium is being amortized over 40 years at an annual rate of $12.2 million, while the costs to achieve (CTA) are being amortized over 10 years. CTA are the costs incurred to execute the merger including the costs of a voluntary severance program, costs of financial advisors, legal costs, and other transaction and systems integration costs. CTA was being amortized at an annual rate of $11.1 million through the rate freeze period based on the original rate plan, as approved by the MDTE. Effective upon completion of the four-year rate freeze on August 25, 2003, the amortization expense was increased to reflect the actual CTA expenditures incurred. As a result, the total CTA amortization expense for 2004 and 2003 was approximately $16.4 million and $12.9 million, respectively. In 2003, NSTAR, as mandated by the MDTE, filed a Revised Savings Report which detailed the actual realized savings as a result of the merger that created NSTAR. The filing included an update on the actual CTA costs

 

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incurred. This report included a final accounting of the deductibility for income tax purposes of each component of CTA. In 2004, the MDTE determined that no further action was required on the Revised Savings Report. The total CTA is approximately $143 million. This increase from the original estimate is partially mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. NSTAR anticipates that these incremental costs are probable of recovery in future rates. The CTA and Goodwill amounts were filed and approved as part of the rate plan.

 

12. Stock Option Plan

 

NSTAR’s 1997 Share Incentive Plan is a stock-based employee compensation plan and is described more fully in the accompanying Note J to Consolidated Financial Statements. NSTAR applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and related Interpretations in accounting for this plan. Currently, no stock-based employee compensation expense for option grants is reflected in net income, as all options granted under this plan had an exercise price equal to the market value of the underlying common shares on the date of grant. The following table illustrates the effect on net income and earnings per common share if NSTAR had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” to stock-based employee compensation.

 

(in thousands, except earnings per common share amounts)


      
     Years ended December 31,

 
     2004

    2003

    2002

 

Net income

   $ 188,481     $ 181,574     $ 161,707  

Add: Share grant incentive compensation expense included in reported net income, net of related tax effects

     2,608       2,147       1,642  

Deduct: Total share grant and stock option compensation expense determined under fair value method for all awards, net of related tax effects

     (3,385 )     (2,870 )     (2,489 )
    


 


 


Pro forma net income

   $ 187,704     $ 180,851     $ 160,860  
    


 


 


Earnings per common share:

                        

Basic - as reported

   $ 3.55     $ 3.42     $ 3.05  

Basic - pro forma

   $ 3.53     $ 3.41     $ 3.03  

Diluted - as reported

   $ 3.51     $ 3.40     $ 3.03  

Diluted - pro forma

   $ 3.50     $ 3.39     $ 3.02  

 

13. Other Income (Deductions), net

 

Major components of other income, net were as follows:

 

     Years ended December 31,

 

(in thousands)


   2004

    2003

    2002

 

Equity earnings, dividends and other investment income

   $ 1,607     $ 2,205     $ 2,667  

Interest and rental income

     4,859       3,244       5,025  

Sale of Blackstone Station

     1,700       1,386       —    

Tax valuation allowance adjustment

     —         8,485       3,849  

Gain on demutualized securities

     —         —         4,928  

Investment tax credit

     —         —         7,272  

Miscellaneous other income, (includes applicable income tax expense)

     (861 )     (923 )     (1,377 )
    


 


 


     $ 7,305     $ 14,397     $ 22,364  
    


 


 


 

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Major components of other deductions, net were as follows:

 

     Years ended December 31,

 

(in thousands)


   2004

    2003

    2002

 

Charitable contributions

   $ (2,654 )   $ (1,268 )   $ (1,175 )

Shutdown costs of unregulated business

     —         —         (2,000 )

Miscellaneous other deductions, (includes applicable income tax benefit (expense))

     1,167       (444 )     1,181  
    


 


 


     $ (1,487 )   $ (1,712 )   $ (1,994 )
    


 


 


 

14. New Accounting Standards

 

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. This Standard eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. NSTAR is currently assessing the valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual earnings by approximately $1.5 million pre-tax, or $0.02 per share.

 

15. Purchases and Sales Transactions with Independent System Operator - New England (ISO-NE)

 

As part of NSTAR Electric’s normal business operations in order to meet its energy obligation to its standard offer customers, NSTAR Electric entered into hourly transactions to purchase or sell energy supply to its ISO-NE. The NSTAR Electric transactions with the ISO-NE have been treated as the ISO-NE servicing the incremental needs of NSTAR Electric, that is, transactions with ISO-NE associated with the difference between NSTAR Electric’s resource needs compared to NSTAR Electric’s resource availability. NSTAR Electric records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense.

 

During 2004 and 2003, NSTAR Electric entered into an agreement whereby all of its energy supply resource entitlements are transferred to an independent energy supplier, following which NSTAR Electric repurchases its energy resource needs from this independent energy supplier for NSTAR Electric’s ultimate sale to its standard offer customers. This transaction has been and will continue to be recorded as a net purchase of electricity.

 

Note B. Earnings Per Common Share

 

Basic earnings per common share (EPS) is calculated by dividing net income, after deductions for preferred dividends, by the weighted average common shares outstanding during the year. SFAS No. 128, “Earnings per Share,” requires the disclosure of diluted EPS. Diluted EPS is similar to the computation of basic EPS except that the weighted average common shares are increased to include the number of potential dilutive common shares. Diluted EPS reflects the impact on shares outstanding of the deferred (nonvested) shares and stock options granted under the NSTAR Share Incentive Plan.

 

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The following table summarizes the reconciling amounts between basic and diluted EPS:

 

(in thousands, except per share amounts)


   2004

   2003

   2002

Net income

   $ 188,481    $ 181,574    $ 161,707

Basic EPS

   $ 3.55    $ 3.42    $ 3.05

Diluted EPS

   $ 3.51    $ 3.40    $ 3.03

Weighted average common shares outstanding for basic EPS

     53,134      53,033      53,033

Effect of dilutive shares:

                    

Weighted average dilutive potential common shares

     512      366      264
    

  

  

Weighted average common shares outstanding for diluted EPS

     53,646      53,399      53,297
    

  

  

 

Note C. Asset Retirement Obligations

 

On January 1, 2003, NSTAR adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to 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 under lease arrangements. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

 

NSTAR has identified certain immaterial long-lived assets, including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.

 

For its regulated utility businesses, NSTAR has identified legal retirement obligations that are currently not material to its financial statements. The recognition of a potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, for NSTAR’s rate-regulated utilities, NSTAR would establish regulatory assets or liabilities to defer any differences between the liabilities established for ratemaking purposes and those recorded as required under SFAS 143.

 

For NSTAR’s regulated utility businesses, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million and $223 million, respectively, based on the estimated cost of removal component in current depreciation rates.

 

NSTAR has identified several long-lived assets, in which it has legal obligations to remove such property, for its non-regulated businesses. As a result, in 2003, NSTAR recorded an increase in non-utility plant of approximately $0.6 million, an asset retirement liability of approximately $1 million and a cumulative effect of adoption after tax, reducing net income by $0.4 million in 2003. The cumulative effect adjustment was recorded as part of 2003 Depreciation and amortization expense on the accompanying Consolidated Statements of Income.

 

During 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The interpretation clarifies when an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability

 

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rather than the recognition of the liability. The interpretation would be effective for NSTAR no later than the end of fiscal year 2005. NSTAR is currently assessing the impact that the interpretation will have on its consolidated financial position, results of operation and cash flows.

 

Note D. Regulatory Assets

 

Regulatory assets represent costs incurred that are expected to be collected from customers through future rates in accordance with agreements with regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses.

 

Regulatory assets consisted of the following:

 

     December 31,

(in thousands)


   2004

   2003

Power contracts (including Yankee units)

   $ 1,440,963    $ 799,087

Retiree benefit costs

     34,558      340,111

Regulatory assets - other:

             

Generation-related plant, net

     520,481      504,594

Merger costs to achieve

     76,680      93,112

Income taxes, net

     50,292      50,161

Purchased power costs

     —        31,969

Redemption premiums

     16,785      12,340

Other

     17,007      23,673
    

  

Total current and long-term regulatory assets

   $ 2,156,766    $ 1,855,047
    

  

 

Under the traditional revenue requirements model, electric and gas rates are based on the cost of providing energy delivery service. Under this model, NSTAR Electric and NSTAR Gas are subject to certain accounting standards that are not applicable to other businesses and industries in general. The application of SFAS 71 requires companies to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected. This is applicable to NSTAR’s electric and gas distribution and transmission operations.

 

Power contracts

 

The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY), Yankee Atomic (YA) and Maine Yankee (MY) nuclear power plants was $116.6 million at December 31, 2004. NSTAR’s liability for CY decommissioning and its recovery ends in 2010, for YA in 2010 and for MY in 2010. However, should the actual costs exceed current estimates and anticipated decommissioning dates, NSTAR could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through NSTAR Electric’s transition charge. Refer to Note Q, “Commitments and Contingencies,” for more discussion.

 

In addition, at December 31, 2004 and 2003, $472.3 million and $665.8 million, respectively, represents the recognition of four purchase power contracts at December 31, 2004 and six purchase power contracts at December 31, 2003 as derivatives and their above-market value and future recovery through NSTAR Electric’s transition charges. Refer to Note F, “Derivative Instruments - Power Contracts” for further details.

 

The remaining balance at December 31, 2004 of $852.1 million represents the recognition of eight purchase power contract buy-out agreements that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electric’s transition charges. Refer to Note O, “Contracts for the Purchase of Energy” for further details.

 

Retiree benefit costs

 

The retiree benefit regulatory asset of $34.6 million is comprised of $17.4 million of carrying charges related to a 2003 MDTE order, which will be recovered from customers in 2005, and, $12.8 million of pension and other postretirement benefit obligations other than pension (PBOP) costs deferred under the MDTE order in 2003 and

 

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2004. Deferred pension and PBOP costs are amortized and collected from customers over three years. The remaining balance of $4.4 million relates to other pension and PBOP costs deferred in accordance with MDTE directives. These costs are being amortized over periods ranging from two to nine years. Refer to Note I of these Consolidated Financial Statements for further discussion on the MDTE order.

 

In 2003, the retiree benefit regulatory asset also included approximately $299.3 million, which represented the additional minimum pension liability charge required under SFAS 87. As of December 31, 2004, NSTAR’s Pension Plan did not incur an additional minimum pension liability. As a result, the liability was reversed. Refer to Note H, “Pension and Other Postretirement Benefits” for further details.

 

Generation-related plant

 

Plant and other regulatory assets related to the divestiture of NSTAR’s generation business are recovered with a return through the transition charge. This recovery occurs through 2019 for Boston Edison and through 2023 for ComElectric. This schedule is subject to adjustment by the MDTE.

 

As of December 31, 2004, $357.2 million of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding LLC. The certificates are non-recourse to Boston Edison.

 

Merger costs to achieve

 

An integral part of the merger was the MDTE-approved rate plan of the retail utility subsidiaries of NSTAR. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Costs to achieve were the costs incurred to execute the merger including costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These costs are collected from all NSTAR Electric and NSTAR Gas distribution customers and exclude a return component. The amortization of these costs have been adjusted since the original recovery began to reflect the actual costs incurred. Refer to Note A to these Consolidated Financial Statements for more information on merger costs to achieve.

 

Income taxes, net

 

The principal holder of this regulatory asset is Boston Edison. Approximately $29 million of this regulatory asset balance reflects deferred tax reserve deficiencies that are being recovered from customers over a 17-year period. In addition, approximately $37 million in additional Boston Edison deferred tax reserve deficiencies have been recorded in accordance with an MDTE-approved settlement agreement. Offsetting these amounts is approximately $16 million of a regulatory liability associated with unamortized investment tax credits relating to NSTAR Electric and NSTAR Gas.

 

Purchased power costs

 

The purchased power costs relate to deferred standard offer service and deferred default service costs. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through February 2005. Since 1998, NSTAR has been allowed to defer the difference between the standard offer and default service revenues and the cost to supply the power, plus carrying costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service and has not chosen to receive service from a competitive supplier. The market price for standard offer and default service may fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.

 

Redemption premiums

 

These amounts reflect the unamortized balance of redemption premiums on Boston Edison Debentures that are amortized and recovered over the life of the respective debentures pursuant to MDTE approval. There is no return recognized on this balance.

 

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Other

 

These amounts primarily consist of deferred transmission costs that are set to be recovered over a subsequent twelve-month period. The deferred costs represent the difference between the level of billed transmission revenues and the current period costs incurred to provide transmission-related services.

 

Also, included are environmental costs and response costs that represent the recovery of costs to clean up former gas manufacturing sites over a 7-year period without a return.

 

Note E. Derivative Instruments - Power Contracts

 

NSTAR accounts for its power contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and DIG interpretations. NSTAR, at December 31, 2004, recorded four contracts at fair value on its Consolidated Balance Sheets. At December 31, 2003, NSTAR recorded six purchase power contracts at fair value. Two of the six contracts were divested in 2004 through regulatory-approved buy-out agreements. Refer to Note O of these Consolidated Financial Statements for more detail on the purchase power contract buy-outs/restructurings. As a result, the recognition of a liability for the fair value of the above-market portion of the remaining four contracts at December 31, 2004 and for the fair value of the above-market portion of the six contracts at December 31, 2003 is approximately $472 million and $666 million and is a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets. NSTAR has recorded a corresponding regulatory asset to reflect the future recovery of the above-market component of these contracts through its electric distribution companies’ transition charge. Therefore, as a result of this regulatory treatment, the recording of these contracts on the accompanying Consolidated Balance Sheets does not result in an earnings impact.

 

During the first quarter of 2005, NSTAR expects to close on a securitization financing that will affect these four contracts that are classified as derivative instruments. NSTAR Electric has entered into buy-out agreements for all four contracts and expects to finance the buy-out payments through a securitization financing. When this occurs, the fair value of these four contracts will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an offsetting regulatory asset.

 

NSTAR has other purchase power contracts in which the contract value is significantly above-market. However, these contracts have met the criteria for the normal purchases and sales exception pursuant to SFAS 133 and DIG interpretations and have not been recorded on the accompanying Consolidated Balance Sheets. The above-market portion of these contracts is currently being recovered through the electric distribution companies’ transition charge. Therefore, NSTAR does not account for these types of capacity and energy contracts, gas supply contracts, or purchase orders for numerous supply arrangements as derivatives.

 

Note F. Variable Interest Entities

 

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.

 

NSTAR has a wholly owned special purpose subsidiary, BEC Funding LLC, established to undertake the sale of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates this entity. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003, NSTAR reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, NSTAR has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by NSTAR.

 

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For the March 31, 2004 effective date of FIN 46R, NSTAR evaluated other entities with which it conducts significant transactions, including companies that supply power to NSTAR Electric through its purchase power agreements. NSTAR determined that it is possible that five of these companies may be considered VIEs. These companies have power plants that have daily capacity output ranging from 20 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, NSTAR Electric purchased a total of approximately 4,001 megawatt-hours (MWH) and 4,487 MWH, respectively, under these agreements. These purchases approximate 17% of the total MWH purchased by NSTAR Electric for the years ended December 31, 2004 and 2003 and amounted to approximately $381 million and $386 million, respectively. In order to determine if these counterparties are VIEs and if NSTAR Electric is the primary beneficiary of these counterparties, NSTAR Electric concluded that it needed more information from the entities. NSTAR Electric attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since NSTAR Electric was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which NSTAR Electric has a purchase power agreement.

 

Additionally, during 2004, NSTAR Electric executed purchase power buy-out/restructuring agreements with a majority of the entities from which NSTAR Electric attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructurings agreements received regulatory approval in January 2005. Refer to Note O for more detail on the purchase power agreements. As a result, NSTAR will no longer pursue obtaining the necessary information to determine whether it has a variable interest in these entities.

 

Note G. Income Taxes

 

Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 71 and SFAS 109, net regulatory assets of $50.3 million and $50.2 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2004 and 2003, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.

 

Accumulated deferred income taxes and unamortized investment tax credits consisted of the following:

 

     December 31,

(in thousands)


   2004

   2003

Deferred tax liabilities:

             

Plant-related

   $ 555,095    $ 495,617

Transition costs

     151,015      178,840

Other

     263,783      239,531
    

  

       969,893      913,988
    

  

Deferred tax assets:

             

Plant-related

     50,864      55,503

Investment tax credits

     16,101      17,190

Other

     79,588      88,736
    

  

       146,553      161,429
    

  

Net accumulated deferred income taxes

     823,340      752,559

Accumulated unamortized investment tax credits

     25,193      26,909
    

  

     $ 848,533    $ 779,468
    

  

 

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Previously deferred investment tax credits are amortized over the estimated remaining lives of the property which generated the credits.

 

Components of income tax expense were as follows:

 

(in thousands)


   2004

    2003

    2002

 

Current income tax expense

   $ 36,668     $ 39,188     $ 89,201  

Deferred income tax expense

     81,286       83,944       19,886  

Investment tax credit amortization

     (1,716 )     (1,723 )     (1,974 )
    


 


 


Income taxes charged to operations

     116,238       121,409       107,113  
    


 


 


Tax expense (benefit) on other income net:

                        

Current income tax expense (benefit)

     2,989       (54,668 )     5,352  

Deferred income tax expense (benefit)

     —         46,157       (30,789 )
    


 


 


Income tax expense (benefit) on other income, net

     2,989       (8,511 )     (25,437 )
    


 


 


Total income tax expense

   $ 119,227     $ 112,898     $ 81,676  
    


 


 


 

In 2002, tax expense on other income, net reflects $7.3 million of investment tax credits recognized as a result of the sale of NSTAR’s equity interest in the Seabrook generating unit.

 

The effective income tax rates reflected in the accompanying consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:

 

     2004

    2003

    2002

 

Statutory tax rate

   35.0  %   35.0  %   35.0  %

State income tax, net of federal income tax benefit

   3.9     5.3     4.8  

Investment tax credits

   (0.6 )   (0.6 )   (3.2 )

Other

   0.4     1.4     1.0  
    

 

 

Effective tax rate before write-down and tax valuation allowance adjustment

   38.7     41.1     37.6  

Adjustment to tax valuation allowance and write-down of RCN investment (federal and state)

   —       (2.8 )   (4.0 )
    

 

 

Effective tax rate

   38.7  %   38.3  %   33.6  %
    

 

 

 

Income Tax Matters

 

a. RCN Abandonment Tax Treatment

 

As a result of the RCN share abandonment, the Company claimed an ordinary loss on its 2003 tax return for this item. The ordinary loss tax treatment resulted in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-down of this asset for financial reporting purposes. The requirement for a tax valuation allowance, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.

 

The Company believes it is more likely than not that it is entitled to this ordinary loss deduction. The Company expects the Internal Revenue Service (IRS) to review this transaction and it is possible that the IRS will disagree. In accordance with the Company’s tax policy as it relates to uncertain tax positions, the Company has established a loss contingency of approximately $44 million at December 31, 2003. This amount represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss. This contingent liability is recorded as part of Deferred credits - Other on the accompanying Consolidated Balance Sheets.

 

If the Company’s position is not upheld, the Company may be required to make future cash expenditures to the IRS that may impact NSTAR’s cash requirements in future periods.

 

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b. Tax Valuation Allowance

 

SFAS 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. NSTAR had determined that it was more likely than not that a current or future income tax benefit would not be realized relating to the write-downs of its RCN investment that were recorded in the second and fourth quarters of 2002 and previously in the first quarter of 2001. These write-downs resulted from the significant declines in the market value of the telecommunications sector, including RCN. As a result of this uncertainty, NSTAR recorded a $77.6 million tax valuation allowance on the entire tax benefit associated with these write-downs during 2001 and 2002. During 2003 and 2002, as a result of previously unanticipated capital gain transactions, NSTAR recognized $8.5 million and $3.9 million, respectively, of this tax benefit.

 

Additionally, based on the IRS review of NSTAR’s 1999 and 2000 federal income tax returns, NSTAR recognized the tax benefits relating to the incremental operating losses from the joint venture that were allocated to NSTAR. These tax returns are currently at the Office of IRS Appeals on other matters. The tax valuation allowance included reserves related to the tax treatment of these losses through June 19, 2002, the final date of joint venture loss allocation to NSTAR. Each of the tax returns filed for 1999 through 2001 claimed operating losses. The tax return filed for 2002 claimed the remaining portion of these operating losses. Based on the IRS examining agent’s review, no adjustment for the years under audit was proposed. This determination was arrived at in the fourth quarter of 2002 and, as a result, NSTAR applied the treatment of these operating losses for all years on a consistent basis, allowing a reduction to its valuation allowance of approximately $19.7 million as a reduction to income tax expense included as a component of the write-down of the RCN investment.

 

On December 24, 2003, NSTAR exited from its investment in RCN and formally abandoned the 11.6 million shares of RCN common stock. As mentioned above, a tax valuation allowance had been established in a previous year to offset the potential future tax benefits resulting from write-downs of NSTAR’s investment in RCN. As a result of the abandonment, the Company claimed an ordinary loss on its 2003 tax return. This treatment results in the Company realizing the benefits represented by the tax asset recorded on its books that resulted from the previous write-downs of this investment for financial reporting purposes. The requirement for a tax valuation allowance, therefore, no longer exists. As a result, the Company reduced the remaining valuation allowance from approximately $53 million at December 31, 2002 to zero at December 31, 2003. See a further discussion on this matter in Note Q, “Commitments and Contingencies.”

 

c. Tax Gain on Generating Assets

 

The cost of transitioning to retail open access was mitigated, in part, by the sale of Commonwealth Energy System’s (COM/Energy) (now a wholly owned subsidiary of NSTAR) non-nuclear generating assets. COM/Energy completed the sale of substantially all of its non-nuclear generating assets in 1998. Proceeds from the sale of these assets amounted to approximately $453.9 million, or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments amounted to $358.6 million and are required to be used for the benefit of COM/Energy customers under MDTE rate setting policies. In this instance, the amount was used to reduce transition costs of Cambridge Electric and ComElectric related to electric industry restructuring. COM/Energy determined that this transaction was not a taxable event because it did not provide an economic benefit to its shareholders.

 

In order to complete its audit of COM/Energy’s tax returns for the years 1997, 1998 and 1999, the IRS needed to determine whether this transaction was taxable. The local IRS examining agent filed a Request for Technical Advice with its National Office on June 5, 2003.

 

On August 28, 2003, NSTAR received a response from the IRS National Office to a Request for Technical Advice, requesting advice as to whether the gain on the sale of the COM/Energy non-nuclear generating assets in 1998 was a taxable transaction. The Technical Advice Memorandum upheld COM/Energy’s position. This ruling now completes the audits by the IRS of COM/Energy’s 1997, 1998 and 1999 federal income tax returns. This decision did not require the Company to make tax and interest payments to the IRS of approximately $140 million.

 

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Note H. Pension and Other Postretirement Benefits

 

1. Pension

 

NSTAR sponsors a defined benefit retirement plan, the NSTAR Pension Plan (the Plan), that covers substantially all employees. NSTAR also maintains nonqualified retirement plans for certain management employees.

 

The Plan uses December 31st for the measurement date to determine its projected benefit obligation, fair value of plan assets, and net periodic benefit costs for the following year.

 

The changes in benefit obligation and Plan assets were as follows:

 

     December 31,

 

(in thousands)


   2004

    2003

 

Change in benefit obligation:

                

Benefit obligation, beginning of the year

   $ 961,029     $ 949,646  

Service cost

     19,038       17,976  

Interest cost

     60,165       58,826  

Plan participants’ contributions

     61       72  

Actuarial loss

     90,693       4,920  

Settlement payments

     (18,588 )     (18,846 )

Benefits paid

     (53,000 )     (51,565 )
    


 


Benefit obligation, end of the year

   $ 1,059,398     $ 961,029  
    


 


Change in Plan assets:

                

Fair value of Plan assets, beginning of the year

   $ 829,126     $ 665,897  

Actual gain on Plan assets, net

     94,431       150,978  

Employer contribution

     42,724       82,590  

Plan participants’ contributions

     61       72  

Settlement payments

     (18,588 )     (18,846 )

Benefits paid

     (53,000 )     (51,565 )
    


 


Fair value of Plan assets, end of the year

   $ 894,754     $ 829,126  
    


 


 

The Plan’s funded status was as follows:

 

     December 31,

 

(in thousands)


   2004

    2003

 

Funded status

   $ (164,644 )   $ (131,903 )

Unrecognized actuarial net loss

     443,437       403,312  

Unrecognized transition obligation

     —         379  

Unrecognized prior service cost

     (3,096 )     (2,962 )
    


 


Net amount recognized

   $ 275,697     $ 268,826  
    


 


 

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:

 

     December 31,

 

(in thousands)


   2004

    2003

 

Accrued retirement liability

   $ (31,297 )   $ (46,659 )

Intangible asset

     3,513       4,835  

Accumulated other comprehensive income

     5,735       11,368  

Prepaid pension

     297,746       —    

Regulatory asset

     —         299,282  
    


 


Net amount recognized

   $ 275,697     $ 268,826  
    


 


 

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The accumulated benefit obligation for the qualified retirement plan as of December 31, 2004 and 2003 were $870,730,000 and $843,609,000, respectively.

 

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the nonqualified retirement plan were $36,415,000, $31,297,000 and $0, respectively, as of December 31, 2004 and $34,317,000, $32,176,000 and $0, respectively, as of December 31, 2003.

 

Weighted average assumptions were as follows:

 

     2004

    2003

    2002

 

Discount rate at the end of the year

   5.75 %   6.25 %   6.5 %

Expected return on Plan assets for the year (net of expenses)

   8.4 %   8.4 %   9.4 %

Rate of compensation increase at the end of the year

   4.0 %   4.0 %   4.0 %

 

The Plans’ discount rates are based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Company’s plans and through periodic bond portfolio matching. The Plans’ long-term rates of return are based on past performance and economic forecasts for the types of investments held in the Plan as well as the target allocation of the investments over a 20-year time period. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for 2004 and 2003.

 

Components of net periodic benefit cost were as follows:

 

     Years ended December 31,

 

(in thousands)


   2004

    2003

    2002

 

Service cost

   $ 19,038     $ 17,976     $ 15,280  

Interest cost

     60,165       58,826       59,658  

Expected return on Plan assets

     (70,794 )     (58,917 )     (74,426 )

Amortization of prior service cost

     133       133       80  

Amortization of transition obligation

     379       601       601  

Recognized actuarial loss

     26,931       33,514       13,530  
    


 


 


Net periodic benefit cost

   $ 35,852     $ 52,133     $ 14,723  
    


 


 


 

Refer to Note I of these Consolidated Financial Statements for more information on the impact of periodic benefit costs.

 

The following indicates the weighted average asset allocation percentage of the fair value of total Plan assets for each major type of Plan asset as of December 31st as well as the Plan’s target percentages and the permissible range:

 

     Plan Assets

   

Target

Percentages


   

Permissible

Ranges


  

Benchmark


     2004

    2003

        

Asset Category

                           

Equity securities

   54 %   50 %   50 %   45% - 55%    Russell 300 Index

Debt securities

   26 %   31 %   25 %   20% - 30%    Lehman Aggregate

Real Estate

   5 %   5 %   10 %   5% - 15%    Wilshire NAREIT Index

Other

   15 %   14 %   15 %   5% - 15%     
    

 

 

        

Total

   100 %   100 %   100 %         
    

 

 

        

 

In March 2003, the investment goals were revised and new target percentages and permissible ranges were identified. As a result, the 2003 asset allocation percentages may not fall within the revised permissible ranges.

 

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The primary investment goal of the Plan is to achieve a total annualized return of 9% (before expenses) over the long-term and to minimize unsystematic risk so that no single security or class of securities will have a disproportionate impact on the Plan. Risk is regularly evaluated, compared and benchmarked to plans with a similar investment strategy. NSTAR currently uses 18 asset managers to manage its plan assets. Assets are diversified by both asset class (i.e., equities, bonds) and within these classes (i.e., economic sector, industry), such that, for each asset manager:

 

    No more than 6% of an asset manager’s equity portfolio market value may be invested in one company

 

    Each portfolio should be invested in at least 20 different companies in different industries, and

 

    No more than 50% of each portfolio’s market value may be invested in one industry sector.

 

Each asset manager may invest in domestic and international fixed income investments and may include government obligations, corporate bonds, preferred stock, and asset-backed securities. In addition, no one asset manager may invest in more than 5% of any one security of an issuer, except the U.S. Government and its agencies.

 

Funded Status

 

At December 31, 2003, the accumulated benefit obligation of NSTAR’s qualified Plan exceeded Plan assets. Therefore, NSTAR was required to recognize an additional minimum liability adjustment as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.”

 

As a result of the additional minimum pension liability adjustment, the prepaid pension balance is removed from the balance sheet and a liability is recorded for the difference between the ABO and the plan assets. The net effect of this entry would ordinarily be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income and would not affect the results of operations.

 

On October 31, 2003, the MDTE approved NSTAR’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, NSTAR is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability adjustment. As of December 31, 2003, NSTAR recorded a regulatory asset of $299 million as the additional minimum liability adjustment. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability is adjusted each year to reflect this measurement. When Plan assets exceed the ABO, the minimum liability is reversed. In 2004, due to positive Plan investment performance and Company contributions over the last two years of approximately $120 million, the fair value of the Plan’s assets exceeded the Plan’s ABO at December 31, 2004. As a result, the minimum liability and regulatory asset have been removed and the prepaid pension balance has been restored to the accompanying Consolidated Balance Sheet

 

NSTAR anticipates contributing approximately $35 million to the Plan in 2005.

 

The estimated benefit payments for the years after 2004 are as follows:

 

(in thousands)


    

2005

   $ 60,574

2006

     61,944

2007

     64,946

2008

     66,687

2009

     75,545

2010 - 2014

     400,205
    

Total

   $ 729,901
    

 

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2. Other Postretirement Benefits

 

NSTAR also provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits include health and life insurance coverage and until April 1, 2003 included reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees are required to make contributions for postretirement benefits.

 

In December 2003, the FASB issued Staff Position (FSP) 106-1, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). The Act provides for prescription drug benefits for retirees over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who currently provide retiree medical programs for former employees over the age of 65, there are subsidies available that are inherent in the Act. The Act potentially entitles these employers to a direct tax-exempt federal subsidy. Pursuant to FSP 106-1, NSTAR elected to defer recognition of the provisions of this Act until further accounting guidance became effective.

 

In May 2004, the FASB issued FSP 106-2 effective July 2004 (retroactive to January 1, 2004) to provide guidance on the accounting for the effects of the Act. The guidance requires that, when an employer initially accounts for the effects of the Act, the impact on the accumulated postretirement benefits obligation (APBO) should be accounted for as an actuarial gain (assuming, no plan amendments are made). In accordance with this provision, NSTAR’s APBO was reduced approximately $51 million. In addition, since the subsidy affects the employer’s share of its plan’s costs, the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost when it is recognized as a component of net periodic postretirement benefits cost. NSTAR’s adoption of FSP 106-2 resulted in a reduction to the 2004 net periodic postretirement benefit cost of approximately $7 million. However, due to the Company’s pension and other postretirement benefits rate reconciliation adjustment mechanism that went into effect on September 1, 2003, this reduction in cost does not have a material impact on earnings.

 

NSTAR’s other postretirement plans use December 31st for the measurement date to determine its benefit obligation, fair value of plan assets, and net periodic benefit costs for the following year.

 

The changes in benefit obligation and plan assets were as follows:

 

     December 31,

 

(in thousands)


   2004

    2003

 

Change in benefit obligation:

                

Benefit obligation, beginning of the year

   $ 595,483     $ 571,673  

Service cost

     5,828       7,076  

Interest cost

     33,395       35,383  

Plan participants’ contributions

     1,835       1,517  

Plan amendments

     —         9,919  

Actuarial gain

     (6,993 )     (868 )

Benefits paid

     (29,118 )     (29,217 )
    


 


Benefit obligation, end of the year

   $ 600,430     $ 595,483  
    


 


Change in plan assets:

                

Fair value of plan assets, beginning of the year

   $ 280,032     $ 215,074  

Actual gain on plan assets

     32,539       53,737  

Employer contribution

     20,021       38,921  

Plan participants’ contributions

     1,835       1,517  

Benefits paid

     (29,118 )     (29,217 )
    


 


Fair value of plan assets, end of the year

   $ 305,309     $ 280,032  
    


 


 

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The plans’ funded status was as follows:

 

     December 31,

 

(in thousands)


   2004

    2003

 

Funded status

   $ (295,121 )   $ (315,451 )

Unrecognized actuarial net loss

     207,786       233,157  

Unrecognized transition obligation

     14,575       16,396  

Unrecognized prior service cost

     9,570       10,855  
    


 


Net amount recognized

   $ (63,190 )   $ (55,043 )
    


 


 

Weighted average assumptions were as follows:

 

     2004

    2003

    2002

 

Discount rate at the end of the year

   5.75 %   6.25 %   6.5 %

Expected return on plan assets for the year

   8.0 %   8.0 %   9.0 %

 

For measurement purposes, an 11% weighted annual rate increase in per capita cost of covered medical claims was assumed for 2005. This rate is assumed to decrease gradually to 5% in 2015 and remain at that level thereafter. Dental claims and Medicare premiums (through April 1, 2003) are assumed to increase at a weighted annual rate of 4%.

 

A 1% change in the assumed health care cost trend rate would have the following effects:

 

     One-Percentage-Point

 

(in thousands)


   Increase

   Decrease

 

Effect on total service and interest cost components for 2004

   $ 6,694    $ (5,256 )

Effect on December 31, 2004 postretirement benefit obligation

   $ 84,396    $ (67,845 )

 

Components of net periodic benefit cost were as follows:

 

     Years ended December 31,

 

(in thousands)


   2004

    2003

    2002

 

Service cost

   $ 5,828     $ 7,076     $ 5,204  

Interest cost

     33,395