10-K

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, 2005

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)	(I.R.S. 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

x  Yes    ¨  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

¨  Yes    x  No

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 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer, as defined in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act)

¨  Yes    x  No

The aggregate market value of the 106,808,376 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: $3,291,834,148.

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 17, 2006
Common Shares, $1 par value	106,808,376 Shares

Documents Incorporated by Reference

Sections of NSTAR’s Definitive Proxy Statement for the 2006 Annual Meeting of Shareholders to be held on May 4, 2006 are incorporated by reference into Parts I and III of this Form 10-K.

NSTAR

Form 10-K Annual Report - December 31, 2005

		Page
	Part I
Item 1.	Business	2
Item 1A	Risk Factors	9
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders	12
Item 4A.	Executive Officers of the Registrant	12
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Consolidated Financial Data	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A.	Controls and Procedures	89
Item 9B.	Other Information	89
	Part III
Item 10.	Trustees and Executive Officers of the Registrant	90
Item 11.	Executive Compensation	90
Item 12.	Security Ownership of Certain Beneficial Owners and Management	90
Item 13.	Certain Relationships and Related Transactions	90
Item 14.	Principal Accountant Fees and Services	90
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	91
Signatures		96

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.

1

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’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 primarily through its Advanced Energy Systems, Inc. subsidiary, 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 2005, 2004 and 2003.

(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, natural 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 2005, 2004 and 2003 consisted of the following:

	Revenues ($)						Energy Sales (mWh)
	2005		2004		2003		2005		2004		2003
Retail:
Commercial	54	%	54	%	54	%	60	%	59	%	59	%
Residential	39	%	39	%	38	%	31	%	31	%	31	%
Industrial and other	6	%	6	%	7	%	8	%	9	%	9	%
Wholesale and contract sales	1	%	1	%	1	%	1	%	1	%	1	%

Electric Rates

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

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

2

ongoing operating and maintenance costs), and a reconciling rate adjustment mechanism for recovery of costs associated with NSTAR’s obligation to provide its employees qualified pension and other postretirement benefits,

• 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 (legislatively-mandated charge to collect costs for demand-side management programs) and

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

Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers for those who choose not to buy energy from a competitive energy supplier. Standard offer service option for customers ended on February 28, 2005. Therefore, all customers who had not chosen to receive service from a competitive supplier were provided default service, which was designated basic service thereafter. Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. As of December 31, 2005, 2004 and 2003, customers of NSTAR Electric had approximately 32%, 24% and 26%, respectively, of their load requirements provided by competitive energy suppliers.

On December 30, 2005, the MDTE approved a rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners. The Settlement Agreement contains, among other items, a reduction to NSTAR Electric’s transition rates of $20 million from what would otherwise have been billed in 2006. Subsequently, any change in distribution rates will be offset by an equal and opposite change in the transition rates through 2012. This Settlement Agreement permits NSTAR Electric to increase its distribution rates by $30 million effective May 1, 2006, with a corresponding reduction in transition rates. For NSTAR Gas customers, the settlement includes an adjustment to the cost of gas adjustment clause to defer recovery of approximately $18.5 million beginning January 2006. Refer to the “Rate Settlement Agreement” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more details.

Sources and Availability of Electric Power Supply

For basic service power supply, NSTAR Electric makes periodic market solicitations consistent with MDTE regulations. During 2005, NSTAR Electric entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second-half of 2006. NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers. For 2005, NSTAR Electric entered into agreements ranging in length from three to twelve-months.

NSTAR Electric fully recovers its payments to suppliers through MDTE-approved rates billed to customers. During late 2004 and early 2005, NSTAR Electric completed several transactions 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.

The December 30, 2005 Settlement Agreement approved by the MDTE requires NSTAR Electric to design a policy for the procurement of basic service supply for residential customers to take effect July 1, 2006, permitting NSTAR Electric to execute energy supply contacts for one, two and three-years procuring fifty,

3

twenty-five and twenty-five percent, respectively, of its total energy load requirements. NSTAR Electric will work with the Attorney General of Massachusetts and a low-income support organization to develop a staggered schedule to implement this provision, including a method for further review and modification to potentially include longer-term contracts that are anticipated to reduce price volatility for small consumers.

NSTAR Electric’s load for 2005 reached an all-time peak demand of 4,621 megawatts (MW) on July 27, 2005 which was 4.7% more than the previous level of 4,415 MW established in 2002 and 8.6% more than the 2004 peak demand of 4,254 MW.

Wholesale Market and Transmission Rule Changes

Locational Installed Capacity (LICAP)

On March 23, 2005, the Federal Energy Regulatory Commission (FERC) unanimously approved an Independent System Operator-New England (ISO-New England) plan to implement LICAP, a new market rule designed to compensate wholesale generators for their capacity with an implementation date of January 1, 2006. FERC subsequently revised this date to no earlier than October 2006. The new LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to utilize capacity within the zones where load is served. The current market structure allows capacity located anywhere in New England to count towards an LSE’s obligation, regardless of load zone. NSTAR Electric’s service territory covers two of the five capacity zones in New England: Northeastern Massachusetts (NEMA) and Rest of Pool (ROP). NEMA is import-constrained and could potentially see higher capacity prices than the ROP. The majority of NSTAR Electric’s customers are in the NEMA load zone. At this point, it is likely that the completion of NSTAR Electric’s 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and ROP to converge. This could ultimately render this locational aspect of LICAP a minimal factor for NSTAR Electric’s customers. However, since the new market rules require that a certain amount of capacity be utilized in the NEMA zone, these requirements could impact pricing for capacity in the NEMA zone.

Additionally, several generators in the NEMA zone have filed 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 new LICAP rules are likely to increase 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. NSTAR is opposed to LICAP as it will likely increase the price of power to NSTAR Electric’s customers without any assurance that new capacity will be built. As a result, NSTAR (and other parties) have appealed the FERC’s LICAP decision in federal court. Additionally, while LICAP has been approved by FERC, the specific parameters of the capacity pricing mechanism are still being contested at FERC. A final decision on these matters is expected sometime in 2006. On October 21, 2005, FERC issued an Interim Order Regarding Settlement Procedures and Directing Compliance Filing. In this Order, the FERC gives the parties in this proceeding a further opportunity to pursue settlement on an alternative to the LICAP mechanism. FERC further directed that a settlement judge be appointed to manage the process. On January 31, 2006, this Settlement Judge, along with other parties, requested from the FERC an extension to file the Settlement Agreement and accompanying documents within 34 days, by March 6, 2006. NSTAR cannot predict the actual impact these changes will have on NSTAR Electric and its customers, but expects all costs incurred to be fully recoverable. In addition, the Company’s December 30, 2005 rate Settlement Agreement provides an incentive mechanism for the recovery of litigation costs associated with NSTAR’s efforts to reduce wholesale energy and capacity costs and sharing of customer benefits realized from those efforts with the potential for the Company to retain 25% of any resulting savings.

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. Refer to the accompanying “Management’s Discussion and Analysis” for more detail on proceedings before the FERC.

4

Effective February 1, 2005, the Independent System Operator – New England (ISO-NE) became 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 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 2005, 2004 and 2003, consisted of the following:

	Revenues ($)						Energy Sales (therms)
	2005		2004		2003		2005		2004		2003
Gas Sales and Transportation:
Residential	64	%	61	%	61	%	46	%	45	%	47	%
Commercial	23	%	25	%	25	%	32	%	33	%	33	%
Industrial and other	8	%	9	%	10	%	17	%	17	%	17	%
Off-System and contract sales	5	%	5	%	4	%	5	%	5	%	3	%

Gas Rates

NSTAR Gas’ revenues are primarily from 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 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%.

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to ultimately lock in prices for approximately one-third of its projected normal winter gas requirements. NSTAR Gas will not take physical delivery of the gas when the financial contracts are executed. All costs incurred will continue to be included in the CGAC. Refer to the Consolidated Financial Statements, Note F, for more details.

Under the MDTE approved 2000 regulations, expanding the choice of gas suppliers to all customers and providing for a five-year transition period, a three-year review of market conditions was established to determine

5

whether the supply market had become sufficiently competitive to warrant removal or modification of the LDC’s service obligation with respect to planning and procurement. 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. On June 6, 2005, the MDTE ruled that mandatory capacity assignment based upon “slice of system”, or the proportionate share of all upstream capacity resources, should continue.

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, but have recently primarily been major marketers. 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. 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 contracts and total storage capacity entitlements of nearly 8 billion cubic feet (Bcf).

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 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 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.

6

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 provided through its Advanced Energy Systems, Inc. (AES) subsidiary that sells chilled water, steam and electricity to 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. A former NSTAR subsidiary, NSTAR Steam Corporation, sold its assets to a non-affiliated entity in September 2005. 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. Revenues earned from NSTAR’s unregulated operations accounted for approximately 4% of consolidated operating revenues in 2005, 2004 and 2003.

RCN Joint Venture, Investment Conversion and Abandonment

NSTAR Com participated in a telecommunications venture with RCN Telecom Services 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

The Energy Policy Act of 2005 repealed the 70-year-old Holding Company Act, which established a regulatory regime overseen by the Securities and Exchange Commission, and replaced it with a new statute focused on increased access to holding company books and records to assist the FERC and state utility regulators in protecting customers of regulated utilities. On December 8, 2005, the FERC finalized rules to implement the Congressionally mandated repeal of the Public Utility Holding Company Act (PUHCA) of 1935 and enactment of the PUHCA of 2005. Congress mandated that the FERC issue its final rules by December 8, 2005, for the rules to be in place by February 8, 2006, the date the 1935 law was repealed and the new PUHCA 2005 took effect. NSTAR is a holding company exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended, except for Section 9(c)(2). NSTAR anticipates filing for a waiver from the PUHCA 2005 revisions in the first quarter of 2006.

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

7

jurisdiction over various phases of NSTAR Electric and NSTAR Gas utility businesses, conditions under which natural gas is sold at wholesale, facilities used for the transmission or sale of that energy, certain issuances of short-term debt and regulation of accounting.

Plant Expenditures and Financings

The most recent estimates of plant expenditures and long-term debt maturities for the years 2006 and 2007-2010 are as follows:

(in thousands)	2006		2007-2010
Plant expenditures	$	408,000	$	1,200,000
Long-term debt	$	123,140	$	1,247,857

Plant expenditures include costs related to NSTAR’s 345kV transmission project that in the aggregate is expected to total approximately $220 million. A significant portion of these costs ($120 million) was incurred in 2005 ($11 million spent in 2004) and the remaining balance will be expended in 2006. In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. To date, this project is approximately 60% complete. This transmission line is expected to ensure continued reliability of electric service and improve power import capability in the Northeast Massachusetts area. For 2006, construction expenditures are estimated at $89 million and this project is expected to be placed in service during the summer of 2006.

As part of NSTAR’s Settlement Agreement approved by the MDTE on December 30, 2005, NSTAR Electric has provided the MDTE with a list of potential projects that are designed to improve reliability and safety. These projects are limited to capital additions and incremental operations and maintenance expenses related to programs for stray-voltage inspection survey and remediation, double pole inspection, replacement/restoration and transfer and manhole inspection, repair and upgrade. NSTAR Electric has agreed to spend at least $10 million in 2006 on these programs. The capital component of these programs is included in the above 2006 plant expenditure estimate.

Plant expenditures in 2005 were approximately $383.6 million and consisted primarily of additions to NSTAR’s distribution and transmission systems with a significant amount related to the 345kV project previously referenced. The majority of these expenditures were for system reliability and performance improvements, customer service enhancements and capacity expansion to meet expected growth in the NSTAR service territory.

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” and “Liquidity and Capital Resources” sections of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 2005 and 2004.

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

8

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.

Environmental Matters

NSTAR’s subsidiaries are subject to numerous federal, state and local standards with respect to the management of wastes and other environmental considerations. NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential liability for the majority of these sites. 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” and to the Consolidated Financial Statements, Note P, 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, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by three units covered by separate collective bargaining contracts.

NSTAR’s labor contract with Local 369 of the Utility Workers Union of America, AFL-CIO, expired on May 15, 2005. After a brief strike, on May 29, 2005, NSTAR management and union officials agreed upon a new four year contract expiring June 1, 2009. The union members, which represent approximately 1,850 employees, ratified the contract on May 31, 2005. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Management and Union officials are currently negotiating a new contract. Management cannot predict the outcome of this negotiation. 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 1A. Risk Factors

In addition to the other information in this Annual Report on Form 10-K, shareholders or prospective investors should carefully consider the following risk factors.

Our electric and gas operations are highly regulated, and any adverse regulatory changes could have a significant impact on the Company’s results of operations and its financial position.

NSTAR’s electric and gas operations, including the rates charged, are regulated by the FERC and the MDTE. In addition, NSTAR’s accounting policies are prescribed by accounting principles generally accepted in the United States of America (GAAP), the FERC and the MDTE. Adverse regulatory changes could have a significant impact on results of operations and financial condition.

Potential competitive changes may adversely affect our regulated electricity and gas businesses.

Under Massachusetts law, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s service territory without the written consent of NSTAR Electric and/or NSTAR Gas. Although not a

9

trend, NSTAR’s operating utility companies could be exposed to municipalization risk, whereby a municipality could acquire the electric or gas delivery assets located in that city or town and take over the customer delivery service, thereby reducing NSTAR’s revenues. Any such action would require numerous legal and regulatory consents and approvals. In addition, NSTAR expects that any municipalization would require that NSTAR be compensated for its assets assumed.

Changes in environmental laws and regulations affecting our business could increase our costs or curtail our activities.

NSTAR and its subsidiaries are subject to a number of environmental laws and regulations that are currently in effect, including those related to the handling, disposal, and treatment of hazardous materials. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on us, all of which could have an adverse impact on NSTAR’s results of operations.

The Company may be required to conduct environmental remediation activities for power generating sites and other potentially unidentified sites.

NSTAR is subject to actual or potential claims and lawsuits involving environmental remediation activities for power generating sites previously owned and other potentially unidentified sites. NSTAR divested all of its generating assets over the past 10 years under terms which generally require the buyer to assume all responsibility for past and present environmental harm. Based on NSTAR’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, NSTAR does not believe that its known environmental remediation responsibilities will have a material adverse effect on NSTAR’s results of operations, cash flows or financial position. However, discovery of currently unknown conditions at existing sites, identification of additional contaminated sites or changes in environmental regulation, could have a material adverse impact on NSTAR’s results of operations, cash flows or financial position.

NSTAR is subject to operational risk that could cause us to incur substantial costs and liabilities.

Our business, which involves the transmission and distribution of natural gas and electricity that is used as an energy source by our customers, is subject to various operational risks, including incidents that expose the Company to potential claims for property damages or personal injuries beyond the scope of NSTAR’s insurance coverage, and equipment failures that could result in performance below assumed levels. For example, operational performance below established target benchmark levels could cause NSTAR to incur penalties imposed by the MDTE, up to a maximum of two percent of transmission and distribution revenues, under applicable Service Quality Indicators.

Increases in interest rates due to financial market conditions or changes in our credit ratings, could have an adverse impact on our access to capital markets at favorable rates, or at all, and could otherwise increase our costs of doing business.

NSTAR frequently accesses the capital markets to finance its working capital requirements, capital expenditures and to meet its long-term debt maturity obligations. Increased interest rates, or adverse changes in our credit ratings, would increase our cost of borrowing and other costs that could have an adverse impact on our results of operations and cash flow and ultimately have an adverse impact on the market price of our common shares. In addition, an adverse change in our credit ratings could, in addition to increasing our borrowing costs, trigger requirements that we obtain additional security for performance, such as a letter of credit, related to our energy procurement agreements. See Item 7A “Quantitative and Qualitative Disclosures About Market Risk” for a further discussion.

Our electric and gas businesses are sensitive to variations in weather and have seasonal variations. In addition, severe-storm related disasters could adversely affect the Company.

Sales of electricity and gas to residential and commercial customers are influenced by temperature fluctuations. Significant fluctuations in heating or cooling degree days could have a material impact on unit sales for any given period. In addition, extremely severe storms, such as hurricanes and ice storms, could cause damage to our

10

facilities which may require additional costs to repair and have a material adverse impact on the Company’s results of operations, cash flows or financial position. To the extent possible, NSTAR’s rate regulated subsidiaries would seek recovery of these costs through the regulatory process.

Economic downturn, and increased costs of energy supply, could adversely affect energy consumption and could adversely affect our results of operation.

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically lead to reductions in energy consumption and increased conservation measures. These conditions could adversely impact the level of energy sales and result in less demand for energy delivery. A recession or a prolonged lag of a subsequent recovery could have an adverse effect on NSTAR’s results of operations, cash flows or financial position.

Item 1B. Unresolved Staff Comments

None

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, 2005, the NSTAR Electric primary and secondary transmission and distribution system consisted of approximately 21,550 circuit miles of overhead lines, approximately 12,125 circuit miles of underground lines, 256 substation facilities and approximately 1,145,550 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. During 2005, NSTAR Electric commenced construction on a 345 kV transmission project that will add approximately 18 miles of transmission lines. To date, this project is approximately 60% complete and is anticipated to be placed in service in 2006.

NSTAR Gas’ principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. In addition, it owns an office and service building, three district office buildings and several natural gas receiving and take stations. At December 31, 2005, the gas system included approximately 3,012 miles of gas distribution lines, approximately 181,816 services and approximately 283,060 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 having an aggregate storage capacity equivalent to 3.5 Bcf of natural gas.

District energy operations consist of AES’ cogeneration 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 Corporation sold its assets to a non-affiliated entity in September 2005. NSTAR Steam’s distribution system primarily consisted 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.

11

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 2005.

Item 4A. Executive Officers of Registrant

Identification of Executive Officers

Name of Officer	Position and Business Experience	Age at December 31, 2005
Thomas J. May	Chairman, President (since 2002) and Chief Executive Officer and a Trustee	58
Douglas S. Horan	Senior Vice President - Strategy, Law and Policy, Secretary and General Counsel	56
James J. Judge	Senior Vice President, Treasurer and Chief Financial Officer	49
Timothy R. Manning	Senior Vice President - Human Resources (since 2002); formerly Vice President Human Resources (2001); Director of Employee and Labor Relations (1999-2001)	54
Joseph R. Nolan, Jr.	Senior Vice President - Customer & Corporate Relations (since 2002); formerly Senior Vice President - Corporate Relations (2000-2002)	42
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)	46
Eugene J. Zimon	Senior Vice President - Information Technology (since 2001); formerly Vice President, Business Development for Utilities, Oracle Corporation (2000-2001)	57
Robert J. Weafer, Jr.	Vice President, Controller and Chief Accounting Officer	58

12

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, 2005 was $28.70 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 2005 and 2004 were as follows:

	2005				2004
	High		Low		High		Low
First quarter	$	29.68	$	26.33	$	26.43	$	24.00
Second quarter	$	30.98	$	26.80	$	26.00	$	22.65
Third quarter	$	31.46	$	28.55	$	25.25	$	23.00
Fourth quarter	$	30.02	$	24.90	$	27.23	$	24.09

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million. Subsequently, the Board of Trustees approved a two-for-one stock split of NSTAR’s common shares, in the form of a 100% common share dividend, to shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors. Common equity, common shares, and stock option activity for all periods presented have been restated to give retroactive recognition to the stock split. In addition, all references in the financial statements and notes to the financial statements, to weighted average number of basic and diluted shares, and per share amounts of the Company’s common shares have been restated to give retroactive recognition to the stock split.

(b) Holders

As of December 31, 2005, there were 23,575 registered holders of NSTAR Common Shares.

(c) Dividends

Dividends declared per Common Share for each quarter of 2005 and 2004 were as follows:

	2005			2004
First quarter	$	0.29		$	0.2775
Second quarter	$	0.29		$	0.2775
Third quarter	$	0.29		$	0.2775
Fourth quarter	$	0.3025	*	$	0.29

NSTAR paid common share dividends to shareholders totaling $123.8 million and $117.9 million in 2005 and 2004, respectively.

* As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

13

(d) Securities authorized for issuance under equity compensation plans

The following table provides information about NSTAR’s equity compensation plans as of December 31, 2005.

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	2,588,401	$	24.05	2,116,472
Equity compensation plans not approved by shareholders	—		—	—
Total	2,588,401	$	24.05	2,116,472

(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, 2005, 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	101,755	$	27.10
November	115,138	$	27.34
December	20,180	$	27.98

Item 6. Selected Consolidated Financial Data

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

(in thousands, except per share data)	2005		2004		2003		2002		2001
Operating revenues	$	3,243,120	$	2,954,332	$	2,911,711	$	2,690,625	$	3,181,167
Net income (loss)(a)	$	196,135	$	188,481	$	181,574	$	161,707	$	(2,426	)
Earnings (loss) per common share:
Basic (a)	$	1.84	$	1.77	$	1.71	$	1.52	$	(0.02	)
Diluted (a)	$	1.83	$	1.76	$	1.70	$	1.52	$	(0.02	)
Total assets	$	7,645,564	$	7,391,356	$	6,614,186	$	6,628,396	$	5,626,040
Long-term debt (b)	$	1,614,411	$	1,792,654	$	1,602,402	$	1,645,465	$	1,377,899
Transition property securitization (b)	$	787,966	$	308,748	$	377,150	$	445,890	$	513,904
Preferred stock of subsidiary (b)	$	43,000	$	43,000	$	43,000	$	43,000	$	43,000
Cash dividends declared per common share (c)	$	1.1725	$	1.1225	$	1.0875	$	1.065	$	1.0375

(a) 2002 and 2001 include non-cash, after-tax charges of $17.7 million and $173.9 million, or $0.17 per share and $1.64 per basic share, respectively, related to NSTAR’s investment in RCN Corporation.

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

(c) As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

14

Selected Quarterly Consolidated Financial Data (Unaudited)

(in thousands, except earnings per share)
	Operating Revenues		Operating Income		Net Income		Earnings Per Share (a)
							Basic		Diluted
2005
First quarter	$	880,045	$	86,132	$	46,269	$	0.43	$	0.43
Second quarter	$	692,005	$	76,088	$	33,151	$	0.31	$	0.31
Third quarter	$	858,495	$	119,478	$	78,010	$	0.73	$	0.72
Fourth quarter	$	812,575	$	73,872	$	38,705	$	0.36	$	0.36
2004
First quarter	$	809,908	$	87,507	$	49,716	$	0.47	$	0.46
Second quarter	$	649,787	$	73,407	$	37,525	$	0.35	$	0.35
Third quarter	$	781,510	$	101,268	$	63,281	$	0.60	$	0.59
Fourth quarter	$	713,127	$	76,146	$	37,959	$	0.36	$	0.35

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

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’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 through its Advanced Energy Systems, Inc. subsidiary, 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 2005, 2004 and 2003.

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.

Rate Settlement Agreement

On December 30, 2005, the Massachusetts Department of Telecommunications and Energy (MDTE) approved a seven-year rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners. The Settlement Agreement requires NSTAR Electric to lower its transition rates by $20 million from what would otherwise have been billed in 2006, and then any change in distribution rates will be offset by an equal and opposite change in the transition rates, through 2012. For NSTAR Gas customers, the settlement includes an adjustment to the cost of gas adjustment clause to defer recovery of approximately $18.5 million beginning January 2006. NSTAR Gas would be allowed to recover this deferral, with interest at the effective prime rate, over a twelve-month period commencing no earlier than May 1, 2006.

15

Major components of the agreement include:

• A reduction in annual transition rates of $20 million effective January 1, 2006 and on May 1, 2006, a distribution rate increase of $30 million with a corresponding reduction in transition charges. Uncollected transition charges as a result of the reductions in transition rates will be deferred and collected through future rates with carrying charges at a rate of 10.88%.

• The implementation of performance-based distribution rates (PBR) beginning January 1, 2007. The PBR will result in annual inflation-adjusted distribution rate increases that will be offset by a decrease in transition charge prices through 2012.

• A 50% / 50% earnings sharing mechanism based on NSTAR Electric’s aggregate return on equity should it exceed 12.5% or fall below 8.5%.

• NSTAR Electric will be permitted to collect certain safety and reliability costs through distribution rates beginning in 2007.

• Preliminary Agreement with respect to certain terms of a merger of Cambridge Electric, ComElectric and Canal into Boston Edison; the merger will require approval by the MDTE.

• A sharing of costs and benefits resulting from NSTAR Electric’s efforts to mitigate wholesale electric market inefficiencies.

• The adoption of certain new Service Quality Index performance incentives and penalties.

This Settlement Agreement will provide NSTAR with financial resources to continue with its important infrastructure improvements, while at the same time provide more certain levels of revenues than it otherwise would have available during the seven-year rate period.

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 and cost for electricity and natural gas and major storms

• 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

• prevailing governmental policies and regulatory actions (including those of the MDTE and Federal Energy Regulatory Commission (FERC) with respect to allowed rates of return, rate structure, continued

16

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 union contract negotiations

• 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 judgments 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 delivery service 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 systematic meter readings 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 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, 2005 and 2004 were $59 million and $54 million, respectively.

17

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 (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 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, 2005 and 2004, NSTAR has recorded regulatory assets of $2.7 billion and $2.9 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. 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, 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 2005, 2004 and 2003 that had an impact on recorded pension costs. As further described in Note I to the accompanying Consolidated Financial Statements, NSTAR’s discount rate for December 31, 2005 and 2004 was 5.75% and aligns with market conditions and the characteristics of NSTAR’s pension obligation. The expected long-term rate of return on its pension plan assets for 2005 remained at 8.4% (net of plan expenses), the same as 2004. These assumptions will have an impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87. 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, are affected by fluctuations in the financial markets. These fluctuations in market returns will have an impact on pension costs in future periods.

18

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.

(in thousands)
Actuarial Assumption	Change in Assumption	Impact on Projected Benefit Obligation Increase/(Decrease)			Impact on 2005 Cost Increase/(Decrease)
Pension:
Increase in discount rate	50 basis points	$	(59,718	)	$	(4,213	)
Decrease in discount rate	50 basis points	$	62,789		$	4,572
Increase in expected long-term rate of return on plan assets	50 basis points		N/A		$	(4,410	)
Decrease in expected long-term rate of return on plan assets	50 basis points		N/A		$	4,410
Other Postretirement Benefits:
Increase in discount rate	50 basis points	$	(41,073	)	$	(3,068	)
Decrease in discount rate	50 basis points	$	46,119		$	3,378
Increase in expected long-term rate of return on plan assets	50 basis points		N/A		$	(1,453	)
Decrease in expected long-term rate of return on plan assets	50 basis points		N/A		$	1,453

N/A - not applicable

Management evaluates the appropriateness of the discount rate through the modeling of a bond portfolio which approximates the Plan liabilities. Management further considers 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.

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 2005, NSTAR kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for investment returns. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for both 2005 and 2004.

The expected long-term rate of return on Plan assets could vary from actual returns as well as the target allocation for investments overtime. As such these fluctuations could impact NSTAR’s capital resources to meet its plan contributions.

As a result of the MDTE approved Pension and PBOP cost reconciliation rate adjustment mechanism tariff (PAM), NSTAR is authorized to recover its pension and PBOP expense through this reconciling rate mechanism. This PAM removes the volatility in earnings that could result from fluctuations in market conditions and plan assumptions.

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 contributed $75 million during 2005, $40 million of which was contributed in December 2005. This was incremental to the planned contributions for the year of $35 million. As a result, NSTAR anticipates that it will not contribute to the Plan in 2006.

19

d. 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), and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.

The Maine Yankee nuclear unit (MY) was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. The NRC has amended MY’s license, reducing the land under the license from approximately 179 acres to the 12 acre Independent Spent Fuel Storage Installation (ISFSI) that includes a dry cask storage facility, and marks the first time a commercial nuclear power plant in the United States has been fully decommissioned with all plant buildings removed. MY’s amended license will continue to apply to the ISFSI where spent nuclear fuel from the plant’s 23 years of operation is stored. MY remains responsible for the security and protection of the ISFSI and is required to maintain a radiation monitoring program at the site.

Based on estimates from the Yankee Companies’ management as of December 31, 2005, the total remaining approximate cost for decommissioning and/or security or protection of each nuclear unit is as follows: $515.7 million for CY, $149.3 million for YA and $242.5 million for MY. Of these amounts, NSTAR Electric is obligated to pay $72.2 million towards the decommissioning of CY, $20.9 million toward YA, and $9.7 million toward MY. These amounts are recorded in the accompanying Consolidated Balance Sheets as Energy 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 to reflect 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 the outcome of a hearing and refund to allow for this recovery.

CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims including 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. On January 27, 2006, the Connecticut Superior court issued a finding that the real property and the periodic payments were subject to attachment and garnishment, respectively, which is likely to result in the implementation of the stipulated escrowing arrangement. CY may appeal the Superior Court finding. Discovery

20

in the termination litigation is drawing to a close, 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.

On November 22, 2005, FERC’s Administrative Law Judge (ALJ) issued an Initial Decision (ID) that found in favor of CY on all imprudence claims, finding that no disallowance was warranted. The only adjustment the ID would make in CY’s proposed decommissioning charges is with respect to the escalation rate used to factor the effects of inflation into the estimate. Because the ALJ found that CY had dispelled all claims of imprudence, the ALJ did not address any party’s proposed disallowance whether on the grounds of imprudence or under the 2003 Settlement’s budget incentive mechanism.

Under FERC’s rules, the ID becomes final only if no party takes exception to it; if any party does take exception, the full FERC will review the ID, and FERC can reach different conclusions. CY expects that the interveners who unsuccessfully raised imprudence claims before the ALJ will pursue those claims before the full FERC.

During the course of carrying out the decommissioning work, YA has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards beyond the levels assumed in the 2003 Estimate. On November 23, 2005, YA submitted a filing to the FERC for adjustments to its Rate Schedules to revise the level of collections to recover the costs of completing the decommissioning of YA’s retired nuclear generating plant (the 2005 Estimate). The schedule for the completion of physical work will need to extend until the end of August 2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of the 2003 FERC settlement. Based on this allocation increase, NSTAR Electric is obligated to pay $8.8 million to the decommissioning of YA. Most of the cost increase relates to decommissioning expenditures that will be made during 2006, followed by a significant reduction in those charges during the years 2007 through 2010. On January 31, 2006, FERC issued an order accepting the rates for filing, effective February 1, 2006, subject to hearing and refund. FERC ordered the hearing held in abeyance pending the outcome of settlement procedures. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions.

Derivative Instruments

Energy 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 the FASB Statement of Financial Accounting Standard (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 accounts for its energy contracts in accordance with SFAS No. 133 and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.”

NSTAR Electric has long-term purchase power agreements that are used primarily to meet its customer obligations. 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 SFAS 133 and DIG interpretations, NSTAR, as of December 31, 2004, had four remaining contracts that were recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these remaining four contracts that were classified as derivative instruments at December 31, 2004. These four contracts had an aggregate fair value of approximately $472 million at December 31, 2004 and were therefore removed as a derivative instrument from Deferred credits - Energy contracts, along with the offsetting regulatory asset, on the accompanying

21

Consolidated Balance Sheets. The securitization debt obligation was recorded along with an offsetting regulatory asset to reflect the future recovery of the debt obligation through its electric distribution companies’ transition charge. At December 31, 2005, NSTAR does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements, Note O, for more detail on the buy-out of certain purchase power contracts.

Hedging Agreements

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. Ultimately, this will minimize fluctuations in prices to NSTAR firm gas sales customers. NSTAR Gas will not take physical delivery of gas when the financial contracts are executed. These contracts qualify as derivative financial instruments and specifically cash flow hedges under SFAS 133, as amended by SFAS 149. Accordingly, the fair value of these instruments will be recognized on the accompanying Consolidated Balance Sheet as a deferred asset or liability representing amounts due from or payable to the counter parties of NSTAR Gas. All costs incurred are included in the firm sales Cost of Gas Adjustment Clause (CGAC). Therefore, NSTAR Gas will record an offsetting regulatory asset or liability. Management has begun to implement this practice with two major financial institutions. Currently, these derivative contracts extend through April 2006. At December 31, 2005, NSTAR has recorded a liability and a corresponding regulatory asset of $0.3 million reflecting the fair value of these contracts.

Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143” (FIN 47), “Accounting for Asset Retirement Obligations” (SFAS 143). In 2003, NSTAR adopted SFAS 143 that established accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation (ARO) 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. FIN 47 clarifies when an entity would be required to recognize a liability for the fair value of an ARO 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 are factored into the measurement of the liability rather than the existence of the liability.

NSTAR adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO within its regulated utility businesses has no impact on NSTAR’s earnings. In accordance with SFAS 71, for its rate-regulated utilities, NSTAR established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. NSTAR has identified several plant assets in which this condition exists and is related to plant assets containing asbestos materials. As a result, in December 2005, NSTAR recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $9.4 million and a regulatory asset of $9 million.

For comparative purposes, the pro forma ARO that would have been recognized in accordance with FIN 47 as of December 31, 2004 and January 1, 2004 would have amounted to $8.8 million and $8.4 million, respectively.

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, 2005 and 2004, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million based on the estimated cost of removal component in current depreciation rates.

22

Variable Interest Entities

In 2004, the FASB issued its interpretation, “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 three wholly owned special purpose subsidiaries, BEC Funding LLC., established in 1999, BEC Funding II, LLC and CEC Funding, LLC both established in 2004, to undertake the sale of $725 million, $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates these entities. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003 or 2004, NSTAR reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, NSTAR has concluded that BEC Funding LLC, BEC Funding II, LLC and CEC Funding, LLC are VIEs and should continue to be consolidated by NSTAR.

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. 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.

Subsequent to the March 31, 2004 effective date, NSTAR executed purchase power buy-out or 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 or 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. The remaining potential entities that may be considered VIEs are associated with power plants with minimal MW capacity and would not have a material effect on NSTAR’s financial position. 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 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 the first quarter of 2006. NSTAR is currently assessing its valuation options allowed in this Standard but, preliminarily, expects this Standard to impact annual pre-tax earnings by approximately $1.5 million. In addition, the Company will use the Modified Prospective approach and will utilize the Black-Scholes Option pricing model to determine the fair value of its compensation expense for these option grants.

23

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This Standard which is effective January 1, 2006, changes the requirements for the accounting for and reporting of accounting changes and error corrections. The Standard establishes retrospective application as the required method for reporting a change in accounting principle rather than reporting a cumulative effect of change in accounting principle. Retrospective application requires the application of the new accounting principle to prior periods as if that principle had always been used. Accordingly, NSTAR will adopt this Standard.

Rate and Regulatory Proceedings

a. Service Quality Indicators

Service quality indicators (SQI) 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.

NSTAR monitors its service quality continuously to determine its contingent liability. If it is probable that a liability has been incurred and is estimable, a liability is 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.

On March 1, 2005, NSTAR Electric and NSTAR Gas filed their 2004 Service Quality Reports with the MDTE that demonstrated the Companies achieved sufficient levels of reliability and performance; the reports indicate that no penalty was assessable for 2004. On December 30, 2005, the MDTE issued a formal approval of this filing.

As of December 31, 2005, NSTAR has determined that for 2005, two of its electric subsidiaries are in a combined penalty position of approximately $0.4 million relating to their applicable service quality indicators. This penalty position is primarily due to service interruptions caused by the severe winter storms experienced earlier in the year. As a result, NSTAR has recorded a liability for this obligation. Since 2001, NSTAR Electric and NSTAR Gas have not been in a penalty position and therefore, the current performance is not indicative of future results.

In late 2004, the MDTE initiated a proceeding to potentially modify the service quality indicators for all Massachusetts utilities. Until any modification occurs, the current SQI measures will remain in place. NSTAR cannot predict the outcome or timing of this proceeding.

The Settlement Agreement approved by the MDTE on December 30, 2005, established additional performance measures applicable to NSTAR’s rate regulated subsidiaries. NSTAR Gas will establish and submit a service quality measure based on separate leaks per mile metrics for bare-steel mains and unprotected, coated-steel mains. A specific proposal to implement this performance benchmark will be submitted to the MDTE for approval by on or before July 1, 2006 and will be subject to a maximum penalty or incentive of up to $500,000. The Settlement Agreement also establishes, for NSTAR Electric, a performance benchmark relating to poor performing circuits, with a maximum penalty or incentive of up to $500,000.

b. Electric Rates

Electric distribution companies in Massachusetts have been 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 ended on February 28, 2005 and effective March 1, 2005, all customers who had not

24

chosen to receive service from a competitive supplier were provided default service, subsequently renamed “basic service.” Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. As of December 31, 2005, 2004 and 2003, customers of NSTAR Electric had approximately 32%, 24% and 26%, respectively, of their load requirements provided by competitive suppliers.

On December 30, 2005, the MDTE approved a rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners effective January 1, 2006. Refer to the “Rate Settlement Agreement” section of this MD&A.

In December 2005, NSTAR Electric filed proposed transition rate adjustments for 2006, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2005. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2006. The filings are to be updated in February 2006 to reflect final 2005 costs and revenues which are subject to final reconciliation. As part of the rate Settlement Agreement approved by the MDTE on December 30, 2005, transition rates are further impacted by a reduction of $20 million effective January 1, 2006 and by $30 million on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

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

On October 19, 2005, the MDTE approved a settlement agreement between Cambridge Electric, ComElectric and the Attorney General of the Commonwealth of Massachusetts to resolve issues relating to the reconciliation of transition, standard offer and basic service costs for 2003 and 2004. This settlement agreement had no material effect on NSTAR’s consolidated results of operations, cash flows and financial condition for a reporting period. The reconciliation of transmission costs and revenues was not resolved by settlement and will be decided by the MDTE after a hearing if there is no settlement on this issue. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing with respect to Boston Edison’s 2003 and 2004 transmission reconciliation filing. Settlement discussions for the reconciliation of Boston Edison’s 2004 costs for transition, transmission, standard offer and basic service have been delayed and will be decided by the MDTE in a future hearing. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions or adjustments.

c. Wholesale Market and Transmission Changes

Locational Installed Capacity (LICAP)

On March 23, 2005, the FERC unanimously approved an Independent System Operator-New England (ISO-New England) plan to implement LICAP, a new market rule designed to compensate wholesale generators for their capacity with an implementation date of January 1, 2006. FERC subsequently revised this date to no earlier than October 2006. The new LICAP rules require electric load serving entities (LSE), like NSTAR Electric, to utilize capacity within the zones where load is served. The current market structure allows capacity located anywhere in New England to count towards an LSE’s obligation, regardless of load zone. NSTAR Electric’s service territory covers two of the five capacity zones in New England; Northeastern Massachusetts (NEMA) and Rest of Pool (ROP). NEMA is import-constrained and could potentially see higher capacity prices than the ROP. The majority of NSTAR Electric’s customers are in the NEMA load zone. At this point, it is likely that the completion of NSTAR Electric’s 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and ROP to converge. This could ultimately render this locational aspect of LICAP a minimal factor for NSTAR Electric’s customers. However, since the new market rules require that a certain amount of capacity be procured in the NEMA zone, these requirements could impact pricing for capacity in the NEMA zone.

25

Additionally, several generators in the NEMA zone have filed 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 new LICAP rules are likely to increase 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. NSTAR is opposed to LICAP as it will likely increase the price of power to NSTAR Electric’s customers without any assurance that new capacity will be built. As a result, NSTAR (and other parties) have appealed the FERC’s LICAP decision in federal court. Additionally, while LICAP has been approved by FERC, the specific parameters of the capacity pricing mechanism are still being contested at FERC. A final decision on these matters is expected sometime in 2006. On October 21, 2005, FERC issued an Interim Order Regarding Settlement Procedures and Directing Compliance Filing. In this Order, the FERC gives the parties in this proceeding a further opportunity to pursue settlement on an alternative to the LICAP mechanism. FERC further directed that a settlement judge be appointed to manage the process. On January 31, 2006, this Settlement Judge, along with other parties, requested from the FERC an extension to file the Settlement Agreement and accompanying documents within 34 days, by March 6, 2006. NSTAR cannot predict the actual impact these changes will have on NSTAR Electric and its customers, but expects all costs incurred to be fully recoverable. In addition, the Company’s December 30, 2005 rate Settlement Agreement provides an incentive mechanism for the recovery of litigation costs associated with NSTAR’s efforts to reduce wholesale energy and capacity costs and sharing of customer benefits realized from those efforts with the potential for the Company to retain 25% of any resulting savings.

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 joint ROE filing among the Transmission Owners was made concurrently in connection with the proposed formation of an RTO by the Transmission Owners and ISO-NE and is an important and integral component of the agreement to form an RTO for the New England region. Among other things, the filing requested an increase in the base ROE component of regional and local transmission rates to a single ROE of 12.8% for all regional and local transmission rates, a 50 basis point adder to reward RTO participation, and a 100 basis point increase in regional rates as an incentive to build new transmission facilities. FERC accepted the 50 basis point adder for regional rates, and set for hearing the base ROE and the 100 basis point incentive adder for new transmission. Settlement negotiations before an administrative law judge were unsuccessful and hearings were held in early 2005. As a result of these hearings, on May 27, 2005, an initial decision was reached. The judge found that the base ROE should be 10.72% and that the 100 basis point adder for new transmission facilities should only apply to projects where innovative and less expensive technology is used. Appeal briefs by all parties, including the Transmission Owners, were filed with the full Commission on June 27, 2005, and are currently awaiting the FERC’s final decision.

In November 2005, as directed by the Energy Policy Act of 2005, FERC proposed incentives to facilitate the maintenance and expansion of the interstate transmission system. FERC’s proposals are intended to ensure that the return on equity is sufficient to attract new transmission investment and to apply “incentive based” ratemaking that would ultimately accrue to the benefits of customers by ensuring reliability and by reducing the cost of delivered power. The final rulemaking will be issued prior to August 31, 2006.

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.

Cambridge Electric and ComElectric filed proposed changes to their component of the ISO OATT with the FERC on March 30, 2005 to provide for consistent application of the OATT among all NSTAR Electric

26

companies. The new tariffs became effective on June 1, 2005; however, the FERC set issues raised in the proceeding for hearing. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing. NSTAR cannot predict the timing or the ultimate resolution of this proceeding.

d. 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.

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%.

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. NSTAR Gas will purchase financial contracts based upon NYMEX natural gas futures in order to lock in prices for approximately one-third of its projected normal winter gas requirements. NSTAR Gas will not be taking physical delivery of the gas when the financial contracts are executed. NSTAR Gas has commenced to implement this practice after having completed contract negotiations with major financial institutions. All costs incurred or benefits recovered will continue to be included in the CGAC. NSTAR Gas accounts for its gas procurement contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and related interpretations.

Due to fluctuations in wholesale natural gas prices, NSTAR Gas is allowed to recover its gas supply costs from firm sales customers through the CGAC. The 2004-2005 winter season CGAC factor was revised downward from earlier in 2004 to reflect decreases in the cost of gas caused by varying market conditions. NSTAR Gas’ CGAC factor received MDTE approval of $0.9968/therm effective November 1, 2004. On February 1, 2005, an approved rate of $0.8500/therm was established until May 1, 2005 when a rate of $0.7501/therm was approved. On September 1, 2005 and on November 1, 2005, due to rapid increases in natural gas prices, the MDTE approved CGAC factors of $1.2232/therm and $1.4570/therm, respectively.

On December 30, 2005, the MDTE approved the rate Settlement Agreement which provided for a reduction in the CGAC factor from $1.4570/therm to $1.3955/therm effective January 1, 2006.

Prior to 2004-2005, the winter season CGAC factor was revised upward to reflect increases in the cost of gas caused by varying market conditions. The CGAC factor for the winter of 2003-2004 ranged from $0.8121/therm to $0.8925; in the winter of 2002-2003, the CGAC ranged from $0.6139/therm to $0.8936/therm.

Stock Split

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million common shares. The Board of Trustees subsequently approved a two-for-one stock split of NSTAR common shares, in the form of a 100% common share dividend, for shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors.

27

Sale of Properties

On December 28, 2005, ComElectric sold a former electric generation station site in New Bedford, Massachusetts for $12 million. NSTAR anticipates that most of the proceeds from the sale will be applied against ComElectric’s transition charge. The sale and regulatory treatment of the proceeds remains subject to MDTE approval. As a result, this transaction had no impact on current year earnings.

On September 8, 2005, NSTAR sold the assets of its wholly-owned unregulated subsidiary, NSTAR Steam Corporation to a non-affiliated company for $3.5 million, realizing a pre-tax gain on the sale of $2.5 million. Also in September 2005, NSTAR sold a parcel of land in Cambridge Massachusetts for $2 million. No gain was recognized from this land sale, as Cambridge Electric will refund these proceeds to its customers.

On April 7, 2004, Boston Edison sold a parcel of land in the City of Newton, Massachusetts for $15.1 million; the net proceeds from the sale were used to reduce Boston Edison’s transition charge. The sale and the regulatory treatment of the proceeds were approved by the MDTE. As a result, this transaction had no impact on 2004 earnings.

General 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 except for the item disclosed in the Consolidated Financial Statements, Note P, “Environmental Matters.” 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.

RCN Corporation (RCN) Share Abandonment Tax Treatment

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 reflecting the writedown of its investment to zero as of December 31, 2003. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR also 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 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 investment for financial reporting purposes. The requirement for a tax valuation allowance recorded prior to this abandonment, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.

It is NSTAR’s tax accounting policy to not recognize tax benefits associated with an uncertain tax position until it is probable that such tax benefit will ultimately be realized. Since NSTAR is under continuous audit by the Internal Revenue Service (IRS), NSTAR consulted with its independent tax advisors and determined that it could not conclude that it is probable that the tax deduction related to the abandonment of its RCN investment will be sustained. Accordingly, NSTAR accrued a tax reserve so as to not record the tax benefit of the uncertain tax position.

The Company believes it is more likely than not that it is entitled to this ordinary loss deduction, but expects the IRS will review this transaction and it is possible that the IRS will disagree with the Company’s position. In accordance with the Company’s tax policy as it relates to uncertain tax positions, NSTAR established a loss contingency of approximately $44.4 million at December 31, 2003. This amount

28

represents the tax impact to the Company should the ordinary loss ultimately be recharacterized to a capital loss and would be reclassified as a tax valuation allowance. During 2005, the Company recognized approximately $4.7 million in tax benefits related to capital tax gain transactions. As a result, the Company reduced its tax loss contingency by a corresponding amount. Therefore, as of December 31, 2005, the tax loss contingency is approximately $39.7 million. 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.

Results of Operations

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2005, 2004 and 2003 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.

2005 compared to 2004

Executive Summary

Earnings per common share were as follows:

	Years ended December 31,
	2005		2004		% Change
Basic	$	1.84	$	1.77	4.0
Diluted	$	1.83	$	1.76	4.0

Net income was $196.1 million for 2005 compared to $188.5 million for 2004. Factors that contributed to the $7.6 million, or 4%, increase in 2005 earnings include:

• Recognition of incremental incentives as approved by the MDTE for successfully lowering transition charges (approximately $9 million) and incentives related to NSTAR’s demand-side management programs (approximately $0.9 million)

• Higher electric distribution revenues ($16.5 million) that primarily resulted from a 2.9% increase in energy sales. Cooling and heating degree days increased 41.3% and decreased 1.0%, respectively, over 2004.

• Higher electric transmission rates due to FERC approval of the inclusion of 50% transmission CWIP in rate base and additional transmission plant in service ($16.4 million)

• Decreased income tax expense of approximately $9.0 million derived from successful resolution of uncertain tax positions and positive adjustments to NSTAR’s RCN tax loss contingency through a related capital gain transaction

These increases were partially offset by:

• Higher operations and maintenance expense due to costs associated with:

• severe storms (approximately $8.6 million)

• costs associated with facilities consolidation (approximately $3 million)

• incremental costs associated with a work stoppage by union employees ($3 million)

• a net increase of approximately $4.7 million related to an environmental reserve

29

• Lower firm gas revenues due to lower firm gas sales caused by warmer winter weather ($3.6 million)

• Higher short-term debt interest costs due to higher level and rates on debt outstanding ($4.8 million)

• The absence in 2005 of $4.7 million in cost reconciliation adjustments that increased revenues in 2004

In 2005, NSTAR closed on a $674.5 million securitization financing transaction. The net proceeds were used primarily to make liquidation payments required in connection with the termination of obligations under certain purchase power contracts (approximately $554.3 million) and to repay $150 million of outstanding debt at ComElectric.

Net cash used in operations in 2005 was $26.9 million, a level that was significantly lower than 2004, and resulted from the effect of the purchase power agreements buy-out payments of $653.2 million. Certain of these buyout costs ($554.3 million) were financed with the proceeds from NSTAR Electric’s securitization financing. Cash generated from operations was primarily used to fund approximately $383.6 million of net plant expenditures. The Company’s plant expenditures will continue to provide improvements to its operational performance. Net financing activities provided approximately $400.5 million of cash and includes the securitization financing referenced above.

Energy Sales

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

	Years ended December 31,
	2005	2004	% Change
Retail Electric Sales - MWH
Residential	6,773,925	6,564,494	3.2
Commercial	13,117,869	12,693,217	3.3
Industrial	1,624,422	1,651,389	(1.6	)
Other	165,158	168,733	(2.1	)
Total retail sales	21,681,374	21,077,833	2.9
	Years ended December 31,
	2005	2004	% Change
Firm Gas Sales - BBTU
Residential	21,974	23,073	(4.8	)
Commercial	15,416	15,692	(1.8	)
Industrial and other	8,115	8,202	(1.1	)
Total firm sales	45,505	46,967	(3.1	)

Energy sales of electricity in 2006 are expected to grow at a rate of approximately 1%. Firm gas energy sales are expected to grow at a rate of 3%. 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, energy conservation, and other factors. Refer to the “Cautionary Statement” in this section.

Weather Conditions

In terms of customer sector characteristics, industrial sales are less sensitive to weather than residential and commercial sales, which are influenced by temperature fluctuations. The overall warmer weather in 2005 caused residential air conditioning use to rise and significantly contributed to the increase in electric sales. Additionally, the commercial sector has continued to expand and that has resulted in additional energy use. Electric residential and commercial customers represented approximately 31% and 61%, respectively, of NSTAR’s total sales mix

30

for 2005 and provided 43% and 52% 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.

	2005		2004		Normal 30-Year Average
Heating degree-days	6,437		6,500		6,445
Percentage (warmer) colder than prior year	(1.0	)%	(3.1	)%
Percentage (warmer) colder than 30-year average	(0.1	)%	0.3	%
Cooling degree-days	894		632		777
Percentage warmer (cooler) than prior year	41.9	%	(16.3	)%
Percentage warmer (cooler) than 30-year average	15.1	%	(18.7	)%

Weather conditions impact electric and, to a greater extent during the winter, gas sales in NSTAR’s service area. The first quarter of 2005 was 2.6% warmer than the same period in 2004, followed by a change to a cooler spring in the second quarter. The warmer than prior year third quarter resulted in increased air conditioning demand that preceded a slightly colder fourth quarter of 2005. The comparative information above relates to heating and cooling degree-days for 2005 and 2004 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.

Other Events

Impact from Hurricanes

During the summer of 2005, Hurricanes Katrina and Rita impacted natural gas production, processing and transportation assets in the Gulf of Mexico (GOM). None of these facilities are owned by NSTAR; however, NSTAR depends on resources in the GOM for supply of natural gas in addition to storage supplies which were not affected by the storms. One of the facilities impacted is the Tennessee Gas Pipeline (TGP) 500 Line, which is under repair. TGP’s initial assessment is that this pipeline will be out of service for three to six months. NSTAR has approximately 6% of its peak design winter need supplied by the 500 Line. NSTAR has contracted to replace this supply with Canadian supplies. NSTAR is actively involved with other utilities, pipelines, suppliers and regulators in assessing the GOM supplies and will continue to respond as necessary. NSTAR cannot predict the impact GOM may have on supply available during the remainder of this winter heating season.

Energy Prices

It is possible that the recent unprecedented rise in energy prices, resulting from hurricanes Katrina and Rita and global energy conditions, may have a negative impact on electric and gas demand and therefore on NSTAR’s future electric and gas sales. NSTAR can not predict the overall impact resulting from these events on its financial positions, results of operations or cash flows.

31

Operating Revenues

Operating revenues for 2005 increased 9.8% from 2004 as follows:

					Increase/(Decrease)
(in millions)	2005		2004		Amount			Percent
Electric revenues
Retail distribution and transmission	$	867.1	$	852.7	$	14.4		1.7
Energy, transition and other		1,666.7		1,480.6		186.1		12.6
Total retail		2,533.8		2,333.3		200.5		8.6
Wholesale		9.7		16.9		(7.2	)	(42.6	)
Total electric revenues		2,543.5		2,350.2		193.3		8.2
Gas revenues
Firm and transportation		147.5		147.7		(0.2	)	(0.1	)
Energy supply and other		423.7		344.6		79.1		23.0
Total gas revenues		571.2		492.3		78.9		16.0
Unregulated operations revenues		128.4		111.8		16.6		14.8
Total operating revenues	$	3,243.1	$	2,954.3	$	288.8		9.8

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 distribution and transmission revenues reflects a 2.9% increase in retail mWh sales substantially all in the residential and commercial sector and includes an increase in demand revenues from NSTAR’s commercial customers.

NSTAR’s largest earnings sources are the revenues derived from transmission and distribution rates approved by the MDTE and FERC. The level of distribution revenues is affected by weather conditions and the economy. Weather and economic 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 their behalf (basic service) and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. Energy supply contract prices vary among the NSTAR Electric companies. However, the retail revenues related to basic service are fully reconciled to the costs incurred and have no impact on NSTAR’s consolidated net income. Furthermore, 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 $186.1 million increase in energy, transition and other revenues is primarily attributable to energy procurement costs and approximately $12.2 million of MDTE-approved incentive revenue entitlements for successfully lowering transition charges resulting from the securitization financing that closed on March 1, 2005. In addition, NSTAR Electric is permitted to earn a carrying charge on transition deferral balances.

Wholesale revenues relate to electric sales to municipal utilities and certain other governmental authorities. The decrease in 2005 wholesale revenues reflects the expiration of a municipal wholesale power supply contract in

32

the fourth quarter of 2004 that was not renewed and a wholesale power supply contract with a regional airport that expired on October 31, 2005. As of November 1, 2005, NSTAR no longer has wholesale electric supply contracts. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these wholesale supply contracts had no material impact on results of operations or cash flows.

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 impact of warmer winter weather conditions, energy efficiency and conservation efforts and customers switching to alternate fuel sources as a result of energy price concerns, resulted in the decrease in sales volumes of 3.1% during 2005. Firm gas and transportation revenues were nearly unchanged when compared with the prior year.

NSTAR Gas’ sales are positively impacted by colder heating season 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 acquire the natural gas in the marketplace and a charge for recovery gas supplier service costs. The energy supply and other revenue increase of $79.1 million primarily reflects the impact of the higher cost of gas purchased from these suppliers. 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 operating revenues are primarily derived from NSTAR’s unregulated businesses that include district energy operations and telecommunications. Unregulated revenues were $128.4 million in 2005 compared to $111.8 million in 2004, an increase of $16.6 million, or 14.8%. The increase in unregulated revenues is primarily the result of higher steam sales volume and higher electric sales and prices to its Advanced Energy Systems, Inc. Medical Area Total Energy Plant (MATEP) customers. Partially offsetting these revenues was the sale of a portion of NSTAR’s district energy steam assets in September 2005. Refer to the “Sale of Properties” contained within this MD&A section.

Operating Expenses

Purchased power costs were $1,428.4 million for 2005 compared to $1,347.8 million for 2004, an increase of $80.6 million, or 6%. The increase is primarily the result of the higher energy procurement costs of both our regulated and unregulated companies and increased sales. 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.

Cost of gas sold, representing NSTAR Gas’ supply expense, was $388.4 million for 2005 compared to $313.3 million in 2004, an increase of $75.1 million, or 24%. Despite a 3.1% decline in firm gas sales, the expense 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. NSTAR Gas adjusts its rates to collect costs related to gas supply from customers on a fully reconciling basis.

Operations and maintenance expense was $452.6 million in 2005 compared to $421.4 million in 2004, an increase of $31.2 million, or 7%. This increase primarily reflects costs associated with storms (approximately $8.6 million), facilities consolidation (approximately $3 million), incremental costs associated with a work

33

stoppage by union employees (approximately $3 million), a net increase to an environmental cost due to a settlement of an environmental claim and an increase in insurance costs (approximately $6.2 million and $2.5 million, respectively), higher bad debt expense (approximately $6.9 million) and higher employee expenses.

Depreciation and amortization expense was $336.7 million in 2005 compared to $254.9 million in 2004, an increase of $81.8 million or 32%. The increase primarily reflects amortization costs related to transition property regulatory asset ($145.4 million and $70.9 million in 2005 and 2004, respectively) and higher depreciable distribution and transmission plant in service.

DSM and renewable energy programs expense was $68.4 million in 2005 compared to $67.3 million in 2004, 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 $102.4 million in 2005 compared to $103.1 million in 2004, a decrease of $0.7 million, or less than 1%.

Income tax expense attributable to operations were $110.7 million in 2005 compared to $108.3 million in 2004, an increase of $2.4 million, or 2%, primarily reflecting the increase in tax expense resulting from a higher level of taxable income. Offsetting this increase was the recognition of a favorable resolution of uncertain tax positions that decreased tax expense by $4.2 million.

Other income, net

Other income, net was approximately $12.1 million in 2005 compared to $7.3 million in 2004, an increase of $4.8 million. The increase is primarily due to a $2.5 million gain recognized in 2005 from the sale of a portion of NSTAR’s district energy steam assets, recognition of tax benefits resulting from the realization of capital tax gains from sales of property ($4.7 million), offset by the absence in 2005 of proceeds from an executive life insurance policy of $1.2 million and $1 million in employee-related contract fees as a result of the Blackstone Station sale in 2004.

Other deductions, net

Other deductions, net were approximately $2 million in 2005 compared to $1.5 million in 2004. The $0.5 million increase was due to slightly higher charitable donations expenses and higher non-intercompany expenses billed from NSTAR’s services company.

Interest charges

Interest on long-term debt and transition property securitization certificates was $165.7 million in 2005 compared to $147.3 million in 2004, an increase of $18.4 million, or 12%. The increase in interest expense primarily reflects:

• Higher interest costs in 2005 of $4.3 million on Boston Edison’s $300 million ten-year fixed rate 4.875% Debentures issued on April 16, 2004

• Additional interest costs of $17.5 million associated with transition property securitization. Securitization interest represents interest on securitization certificates of BEC Funding, BEC Funding II and CEC Funding collateralized by the future income stream associated primarily with NSTAR’s stranded costs. The future income stream was sold to these companies by Boston Edison and ComElectric.

34

These increases were partially offset by:

• The absence in 2005 of expense of nearly $3 million related to the retirement of Boston Edison’s $181 million 7.80% Debentures on March 15, 2004

• The impact of the March 1, 2005 retirement of $150 million variable rate Note, due in May 2006, at ComElectric with a portion of the proceeds from the sale of CEC Funding LLC’s securitization certificates

Short-term and other interest expense was $5.6 million in 2005 compared to $7.4 million in 2004, a decrease of $1.8 million, or 24%. The decrease is primarily due to lower interest costs of $3.8 million on regulatory deferrals offset by higher short-term debt borrowing costs of $4.8 million primarily reflective of a 199 basis point increase in 2005 weighted average borrowing rates and a higher average level of funds borrowed as compared to 2004. The weighted average short-term interest rates including fees were 3.81% and 1.82% in 2005 and 2004, respectively. The higher rate of borrowing during 2005 includes $117 million in contributions to NSTAR’s postretirement benefit plans and $100 million for the retirement of Boston Edison’s Floating Rate Debentures in October 2005.

Allowance for funds used during construction (AFUDC) increased $2.7 million in 2005 primarily due to higher levels of construction activity primarily related to the on-going construction of NSTAR’s 345 kV transmission line.

2004 compared to 2003

Executive Summary

Earnings per common share were as follows:

	Years ended December 31,
	2004		2003		% Change
Basic	$	1.77	$	1.71	3.5
Diluted	$	1.76	$	1.70	3.5

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.

NSTAR in 2004 generated $429.4 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 plant expenditures contributed to NSTAR’s increased 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.

35

Energy Sales

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	)

Weather Conditions

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.

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	6,500		6,710		6,482
Percentage (warmer) colder than prior year	(3.1	)%	10.5	%
Percentage (warmer) colder than 30-year average	0.3	%	2.6	%
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 2.4% 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

36

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		1,480.6		1,451.1		29.5		2.0
Total retail		2,333.3		2,311.8		21.5		0.9
Wholesale		16.9		21.5		(4.6	)	(21.4	)
Total electric revenues		2,350.2		2,333.3		16.9		0.7
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		111.8		113.2		(1.4	)	(1.2	)
Total operating revenues	$	2,954.3	$	2,911.7	$	42.6		1.5

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.

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. 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 $29.5 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. As of November 1, 2005, NSTAR no longer has wholesale electric supply contracts. Amounts collected from wholesale customers were previously credited to retail customers through the transition charge. Therefore, the expiration of these contracts had no impact on results of operations.

37

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.

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. 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 primarily derived from NSTAR’s businesses that include district energy operations and telecommunications. Unregulated revenues were $111.8 million in 2004 compared to $113.2 million in 2003, a decrease of $1.4 million, or 1%. 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 $254.8 million in 2004 compared to $243.4 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.

38

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 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 tax expense attributable to operations were $108.3 million in 2004 compared to $113.5 million in 2003, a decrease of $5.2 million, or 5%. 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 the 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

39

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. The weighted average short-term interest rates including fees were 1.82% and 1.68% in 2004 and 2003, respectively. 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.

Liquidity, Commitments and Capital Resources

The major factor that effects NSTAR’s cash requirements is the level of plant expenditures. Plant expenditures currently forecasted for 2006 are $408 million. The plant expenditure level over the following four years (2007-2010) is currently forecasted to aggregate to approximately $1.2 billion.

Forecasted plant expenditures in 2006 include remaining costs of $89 million for NSTAR’s 345kV transmission project that is expected to total $220 million.

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)	2006		2007		2008		2009		2010		Years Thereafter		Total
Long-term debt	$	28	$	15	$	17	$	7	$	633	$	952	$	1,652
Interest obligation on long-term debt		109		107		105		104		79		258		762
Transition property securitization		95		151		153		153		119		212		883
Interest obligation on transition property securitization		45		37		30		21		13		14		160
Leases		20		16		15		13		11		36		111
Electric capacity obligations		2		2		2		2		3		21		32
Gas contractual obligations		48		48		47		45		44		67		299
Purchase power buy-out obligations		156		160		162		142		140		206		966
	$	503	$	536	$	531	$	487	$	1,042	$	1,766	$	4,865

Transition property securitization payments reflects securities issued in 1999 by BEC Funding LLC, a subsidiary of Boston Edison and on March 1, 2005, additional transition property securitization bonds issued through BEC Funding II, LLC, a subsidiary of Boston Edison and CEC Funding, LLC, a subsidiary of ComElectric. BEC Funding LLC, BEC Funding, II, LLC and CEC Funding, LLC recover the principal and interest obligations for their transition property securitization bonds from customers of Boston Edison and ComElectric, respectively, through a component of Boston Edison’s and ComElectric’s transition charges and, as a result, these payment obligations do not affect NSTAR’s overall cash flow.

Electric capacity and gas contractual obligations reflect 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. NSTAR Electric recovers these obligations from customers through its transition charge.

40

Current Cash Flow Activity

NSTAR’s primary uses of cash in 2005 included capital expenditures, dividend payments, debt reductions, and liquidation payments under certain purchase power contract buy-out agreements.

Net operating cash flow used in 2005 was $26.9 million and reflects the impact of its obligations related to the purchase power contract buy-outs in 2005. The Company used $370.5 million in its investing activities that consisted of $383.6 million of plant expenditures, which included construction costs related to NSTAR Electric’s 345 kV project and other system reliability and infrastructure improvement projects incurred by NSTAR Electric and NSTAR Gas operations. Additionally, the Company provided $400.5 million (net) from financing activities primarily from the issuance of $674.5 million of transition property securitization certificates used to finance its purchase power contract termination payments.

Operating Activities

The net cash used in 2005 operating activities was significantly impacted by the contract termination payments on certain purchase power contracts in 2005. The payments of approximately $653.2 million created a current tax deduction. As a result, income tax payments were $38.9 million lower in 2005 than in 2004. These tax benefits represent a book/tax timing difference which will reverse as amounts are collected from customers.

Other changes to NSTAR’s working capital primarily reflect the timing of ordinary receipts and disbursements. For 2005 and 2004, NSTAR contributed approximately $117.6 million and $62.7 million, respectively, to its retirement benefit plans.

In 2004 and 2003, NSTAR 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 and NSTAR does not anticipate realizing any further benefit from bonus depreciation.

Investing Activities

The net cash used in investing activities in 2005 of $370.5 million consists primarily of capital expenditures related to infrastructure investments in transmission and distribution systems. Capital expenditures increased $70.2 million from the prior year primarily due to Boston Edison’s 345 kV project. Boston Edison spent nearly $120 million on this project in 2005.

Financing Activities

The net cash provided by financing activities in 2005 of $400.5 million primarily reflects the issuance of $674.5 million of transition property securitization certificates on March 1, 2005 and additional borrowing from short-term debt of $256.1 million. Offsetting the receipt of cash from the securitization financing, NSTAR used cash to make long-term debt redemptions and sinking funds payments of $400.8 million and to pay dividends of $125.7 million.

NSTAR’s banking arrangements provide for daily cash transfers to the Company’s 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 Consolidated Statement of Cash Flows.

In connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, NSTAR has issued approximately 258,000 shares under this registration and received approximately $7.1 million in 2005.

41

Short-Term Financing Activities

NSTAR’s short-term debt increased by $256.1 million to $417.5 million at December 31, 2005 as compared to $161.4 million at December 31, 2004. The increase resulted primarily from additional working capital needs that reflected the significant increase in contributions to NSTAR’s pension and postretirement benefit plans and the financing of the retirement, at maturity, of Boston Edison’s $100 million Variable Rate notes on October 17, 2005.

Long-Term Financing Activities

On March 1, 2005, two wholly owned special purpose subsidiaries, BEC Funding II, LLC and CEC Funding LLC, issued $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently issued a total of $674.5 million of rate reduction certificates to the public. These certificates represent fractional, undivided beneficial interests in the notes issued by BEC Funding II, LLC and CEC Funding, LLC and are secured by a portion of the transition charge assessed on Boston Edison’s and ComElectric’s retail customers as permitted under the 1997 Massachusetts Electric Industry Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison and ComElectric, respectively. The assets and revenues of BEC Funding II, LLC and CEC Funding, LLC, including without limitation, the transition property, are owned solely by BEC Funding II, LLC and CEC Funding, LLC, and are not available to creditors of Boston Edison, ComElectric or NSTAR. The certificates and the related BEC Funding II, LLC and CEC Funding, LLC notes were issued at a weighted average yield of 4.15% in four classes with varying final maturity dates between 2008 and 2015. Scheduled semi-annual principal payments began in September 2005. The net proceeds from this transaction were used to make liquidation payments required in connection with the termination of certain purchase power agreements, and, in the case of ComElectric, to repay outstanding debt.

In 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its purchase power agreements subject to MDTE approval. These agreements constituted approximately 685 MW of the remaining 800 MW of purchased power commitments, and reduced the amount of above-market energy costs that NSTAR Electric will incur and collect from its customers through its transition charges. As of December 31, 2004, four of these agreements received MDTE approval and were 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. These buy-out/restructuring agreements, once completed, provide no economic benefit to NSTAR Electric and, therefore, the agreements’ contract termination costs were recorded on the accompanying Consolidated Financial Statements.

On January 7, 2005, NSTAR Electric received approval from the MDTE for an additional four agreements that were 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 was removed during February 2005, NSTAR recorded the contract termination cost 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 recognized as of December 31, 2005 and 2004 for obligations relating to eight of the twelve contracts is approximately $764 million and $852 million (present valued); approximately $156 million and $145 million are reflected as a component of current liabilities - energy contracts and approximately $608 million and $707 million as a component of Deferred credits - energy contracts on the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. 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 to assets and liabilities.

42

Also in January 2005, the MDTE approved the remaining four contract buy-outs with two suppliers that reduced the overall amount of transition costs to be paid for above-market contracts. These contracts are buy-out arrangements whereby NSTAR Electric has made contract termination payments in full release of its obligation under the purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that sought approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to provide the funds for these 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% and the securitization financing closed on March 1, 2005.

Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the forecasts included in NSTAR’s 2005 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

With the exception of the indemnity agreement, referenced in “Financial and Performance Guarantees” within this MD&A, 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 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, 2005 and 2004. NSTAR’s long-term debt other than the Mortgage Bonds, Notes of NSTAR Gas and of MATEP, a wholly owned subsidiary of NSTAR, is unsecured.

NSTAR has executed a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2005 and 2004, had $66 million and $5 million outstanding, respectively. Under the terms of the 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. Commitment fees must be paid on the total agreement amount. At December 31, 2005 and 2004, NSTAR was in full compliance with the aforementioned covenant as the ratios were 56.7% and 58.3% respectively.

As of December 31, 2005, Boston Edison has $200 million available under its current shelf registration, as approved by the SEC. 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. On December 29, 2005, the MDTE approved Boston Edison’s request to extend the term of its financing plan until June 30, 2006 for the remaining $200 million in securities that have yet to be issued.

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. Boston Edison has 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.

43

At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as backup to Boston Edison’s $350 million commercial paper program that had a $197 million and $46.5 million balance at December 31, 2005 and 2004, respectively. Under the terms of the revolving credit 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. At December 31, 2005 and 2004, Boston Edison was in full compliance with its covenants in connection with its short-term credit facilities as the ratios were 45.9% and 53.1%, respectively.

As of December 31, 2005, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $245 million available under several lines of credit and had $154.5 million and $109.9 million outstanding under these lines of credit at December 31, 2005 and 2004, 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 312,000 and 258,000 shares under this registration and received approximately $7.6 million and $7.1 million in 2004 and 2005, respectively. Additionally, NSTAR issued approximately 172,000 shares as part of its Share Incentive Plan. No cash was received from this issuance.

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.

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.

Performance Assurances from Electricity and Gas Supply Agreements

NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second half of 2006. NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 2006. These agreements are for a term of three to twelve months but could change as a result of NSTAR’s recently approved rate Settlement Agreement. 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 required to secure alternative sources of supply at higher or lower prices than provided under the

44

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. Additionally, the hedging agreements that NSTAR Gas enters into related to its gas purchases have a termination clause for either party in the event the credit rating of the other falls below a stipulated level.

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, 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, 2005, outstanding guarantees totaled $38.1 million as follows:

(in thousands)
Letters of Credit	$	13,100
Surety Bonds		16,200
Other Guarantees		8,800
Total Guarantees	$	38,100

Letters of Credit

In May 2005, Boston Edison issued a $7.5 million standby letter of credit to the general contractor of Boston Edison’s 345kV project. The amount of the standby letter of credit was reduced to $4.5 million on February 1, 2006. The contractor will be able to draw upon the letter of credit if Boston Edison does not comply with the payment terms of the respective executed construction agreement, signed by both parties. NSTAR believes that it is very unlikely that a draw will be made on the standby letter of credit. In addition, NSTAR issued a $5.6 million letter of credit for the benefit of a third party, as trustee in connection with the 6.924% Notes of one of its subsidiaries. The letter of credit is available if the subsidiary has insufficient funds to pay the debt service requirements. As of December 31, 2005, there have been no amounts drawn under these letters of credit.

Surety Bonds

As of December 31, 2005, certain of NSTAR’s subsidiaries have purchased a total of $1.5 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 have purchased approximately $14.7 million in

45

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. On January 3, 2006, NSTAR and certain of its subsidiaries executed indemnity agreements to provide additional financial security to its bond company in the form of a contingent letter of credit to be triggered in the event of a downgrade in the future of NSTAR’s Senior Note rating to below BBB by S&P and/or to below Baa1 by Moody’s. These Indemnity Agreements cover both the performance surety bonds and workers’ compensation bonds.

Other

NSTAR and its subsidiaries have also issued $8.8 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.

Contingencies

Environmental Matters

NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential liability for the majority of these sites.

During the second quarter of 2005, the Massachusetts Supreme Judicial Court (SJC) issued its decision in one of the environmental contamination matters. In 2004, a Superior Court had issued a decision favorable to Boston Edison that put the burden of proof on the plaintiffs to determine Boston Edison’s liability for contamination. The SJC’s decision reversed the Superior Court’s 2004 ruling and held that the plaintiffs in this matter are allowed to seek joint and several liability against the defendants, including Boston Edison. The case was remanded back to the Superior Court for trial. On October 6, 2005, Boston Edison reached a settlement in principle with the plaintiffs in this matter. It is anticipated that the appropriate settlement documents will be finalized in February 2006 and filed with the Superior Court shortly thereafter. The Settlement is subject to a 90-day public comment period at which point we expect the Superior Court to approve and enter final judgment. Boston Edison anticipates paying within 30 days of the final judgment approximately $8.6 million which approximates the amount previously reserved for this matter. Boston Edison will vigorously attempt to recover monies from the other responsible third parties, including recovery from its insurance carrier.

As of December 31, 2005 and 2004, NSTAR had reserves of $10.3 million and $3.9 million, respectively, for all potential environmental sites, including the site specified in the paragraph above. This estimated recorded liability is based on an evaluation of all currently available facts with respect to all of its sites. In addition, based on a legal opinion from the Company’s environmental counsel, it is probable that Boston Edison will recover, at a minimum, approximately $2 million from other parties. As a result, Boston Edison recorded a receivable in the second quarter that will ultimately offset the Company’s obligation. Management believes that the ultimate disposition of this matter will not have a material adverse impact on NSTAR’s results of operation, cash flows or its financial position.

NSTAR Gas is participating in the assessment or remediation of certain 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, 2005 and 2004, NSTAR recorded a liability of approximately $3.6 million and $3.8 million, respectively, as estimates for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset was recorded that reflects the future rate recovery for these costs.

46

Estimates related to environmental remediation costs are reviewed and adjusted 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 or cash flows.

Capital Spending Commitments

In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. To date, this project is approximately 60% complete. This transmission line is expected to ensure continued reliability of electric service and improve power import capability in the Northeast Massachusetts area. This project is expected to be placed in service during the summer of 2006. A substantial portion of the cost of this project will be shared by other utilities in New England based on ISO-New England’s approval and will be recovered by NSTAR through wholesale and retail transmission rates. As of December 31, 2005, NSTAR has contractual construction cost commitments of approximately $17 million related to this project.

Employees and Employee Relations

As of December 31, 2005, NSTAR had approximately 3,050 employees, including approximately 2,150, or 70%, who are represented by three units covered by separate collective bargaining contracts.

NSTAR’s labor contract with Local 369 of the Utility Workers Union of America, AFL-CIO, expired on May 15, 2005. After a brief strike, on May 29, 2005, NSTAR management and union officials agreed upon a new four year contract expiring June 1, 2009. The union members, which represent approximately 1,850 employees, ratified the contract on May 31, 2005. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006. Management and Union officials are currently negotiating a new contract. Management cannot predict the outcome of this negotiation. 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.

Fair Value of Financial Instruments

Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2005 and 2004 were as follows:

	2005				2004
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term indebtedness (including current maturities)	$	2,525,517	$	2,642,190	$	2,250,647	$	2,483,220

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

47

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 basic service or retail gas customers are recovered on a fully reconciling basis.

However, 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 6.03% and 6.23% in 2005 and 2004, respectively.

48

Item 8. Financial Statements and Supplementary Data

NSTAR

Consolidated Statements of Income

	Years ended December 31,
	2005			2004			2003
	(in thousands, except earnings per share)
Operating revenues	$	3,243,120		$	2,954,332		$	2,911,711
Operating expenses:
Purchased power and cost of gas sold		1,816,765			1,661,100			1,614,290
Operations and maintenance		452,558			421,367			443,931
Depreciation and amortization		336,670			254,852			243,424
Demand side management and renewable energy programs		68,441			67,294			66,217
Property and other taxes		102,426			103,061			97,837
Income taxes		110,690			108,330			113,501
Total operating expenses		2,887,550			2,616,004			2,579,200
Operating income		355,570			338,328			332,511
Other income (deductions):
Write-down of RCN investment, net		—			—			(4,450	)
Other income, net		12,120			7,305			14,397
Other deductions, net		(2,032	)		(1,487	)		(1,712	)
Total other income, net		10,088			5,818			8,235
Interest charges:
Long-term debt		119,970			119,164			121,027
Transition property securitization		45,694			28,150			32,715
Short-term debt and other		5,608			7,394			8,043
Allowance for borrowed funds used during construction and capitalized interest		(3,709	)		(1,003	)		(4,573	)
Total interest charges		167,563			153,705			157,212
Preferred stock dividends of subsidiary		1,960			1,960			1,960
Net income	$	196,135		$	188,481		$	181,574
Weighted average common shares outstanding:
Basic		106,756			106,268			106,065
Diluted		107,100			107,292			106,797
Earnings per common share (Note K):
Basic	$	1.84		$	1.77		$	1.71
Diluted	$	1.83		$	1.76		$	1.70

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

49

NSTAR

Consolidated Statements of Comprehensive Income

	Years ended December 31,
	2005			2004			2003
	(in thousands)
Net income	$	196,135		$	188,481		$	181,574
Other comprehensive income, net:
Unrealized gain (loss) on investments		—			—			2,783
Reclassification adjustment for (gain) loss included in net income		—			—			(2,783	)
Additional minimum pension liability		(5,132	)		(5,817	)		1,104
Deferred income taxes (benefit)		2,113			2,414			(389	)
Comprehensive income	$	193,116		$	185,078		$	182,289

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

NSTAR

Consolidated Statements of Retained Earnings

	Years ended December 31,
	2005		2004		2003
	(in thousands)
Balance at the beginning of the year	$	518,252	$	449,114	$	382,886
Add:
Net income		196,135		188,481		181,574
Subtotal		714,387		637,595		564,460
Deduct:
Dividends declared:
Common shares*		92,887		119,343		115,346
Balance at the end of the year	$	621,500	$	518,252	$	449,114

* As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend typically declared in December was approved on January 26, 2006. The dividend payment schedule remains unchanged.

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

50

NSTAR

Consolidated Balance Sheets

	December 31,
	2005					2004
Assets	(in thousands)
Utility plant in service, at original cost	$	4,454,774				$	4,454,774
Less: accumulated depreciation		1,178,259			3,492,800		1,122,810			3,331,964
Construction work in progress					208,957					103,866
Net utility plant					3,701,757					3,435,830
Non-utility property, net					138,222					144,148
Equity investments					13,705					13,887
Other investments					63,441					59,096
Current assets:
Cash and cash equivalents		15,612					12,497
Restricted cash		14,282					10,254
Accounts receivable, net of allowance of $24,504 and $21,804, respectively		305,441					302,194
Accrued unbilled revenues		59,400					53,752
Regulatory assets		446,286					300,238
Inventory, at average cost		120,924					86,397
Income taxes		57,444					21,063
Other		16,894			1,036,283		11,434			797,829
Deferred debits:
Regulatory assets - energy contracts					683,193					1,269,651
Regulatory asset - goodwill					658,538					678,698
Regulatory assets - other					924,693					607,037
Prepaid pension					346,889					297,746
Other					78,843					87,434
Total assets				$	7,645,564				$	7,391,356
Capitalization and Liabilities
Common equity:
Common shares, par value $1 per share, 200,000,000 shares authorized; 106,808,376 shares in 2005 and 106,550,282 shares in 2004 issued and outstanding	$	106,808				$	106,550
Premium on common shares		813,099					819,454
Retained earnings		621,500					518,252
Accumulated other comprehensive loss		(6,392	)		1,535,015		(3,374	)		1,440,882
Cumulative non-mandatory redeemable preferred stock of subsidiary					43,000					43,000
Long-term debt					1,614,411					1,792,654
Transition property securitization					787,966					308,748
Current liabilities:
Long-term debt		28,457					108,197
Transition property securitization		94,683					41,048
Notes payable		417,500					161,400
Deferred income taxes		7,232					8,072
Accounts payable		320,960					239,613
Energy contracts		183,674					171,312
Accrued interest		33,114					33,073
Dividends payable		327					31,227
Accrued expenses		20,729					30,654
Other		62,769			1,169,445		73,346			897,942
Deferred credits:
Accumulated deferred income taxes and unamortized investment tax credits					1,273,456					1,114,588
Energy contracts					683,193					1,269,651
Pension liability					37,351					31,296
Regulatory liability - cost of removal					258,782					258,722
Other					242,945					233,873
Commitments and contingencies
Total capitalization and liabilities				$	7,645,564				$	7,391,356

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

51

NSTAR

Consolidated Statements of Cash Flows

	Years ended December 31,
	2005			2004			2003
	(in thousands)
Operating activities:
Net income	$	196,135		$	188,481		$	181,574
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		337,887			254,271			244,244
Deferred income taxes		158,914			71,662			120,471
Gain on sale of steam assets		(2,500	)		—			—
Loss on write-down of RCN investment		—			—			6,146
Allowance for borrowed funds used during construction/capitalized interest		(3,709	)		(1,003	)		(4,573	)
Net changes in:
Accounts receivable and accrued unbilled revenues		(8,895	)		(3,572	)		(6,526	)
Inventory, at average cost		(34,527	)		(6,812	)		(21,188	)
Other current assets		(187,986	)		(131,711	)		(24,286	)
Accounts payable		55,523			8,014			10,536
Other current liabilities		(8,939	)		139,229			(1,382	)
Effects of purchase power contract buyouts		(653,210	)		(8,935	)		(12,741	)
Deferred debits and credits		144,252			(279,789	)		(83,781	)
Decrease in regulatory asset - pension		—			297,746			—
Net change from other miscellaneous operating activities		(19,831	)		(98,172	)		(3,970	)
Net cash (used in) provided by operating activities		(26,886	)		429,409			404,524
Investing activities:
Plant expenditures (excluding AFUDC/capitalized interest)		(383,556	)		(313,387	)		(307,655	)
(Increase) decrease in restricted cash		(4,028	)		2,890			20,755
Proceeds from sale of property, net		16,321			14,252			17,572
Investments		728			1,070			669
Net cash used in investing activities		(370,535	)		(295,175	)		(268,659	)
Financing activities:
Long-term debt redemptions		(400,847	)		(258,357	)		(242,357	)
Debt issue costs		(6,513	)		(1,851	)		(663	)
Issuance of transition property securitization		674,500			—			—
Issuance of long-term debt		—			300,000			150,000
Net change in notes payable		256,100			(77,700	)		40,500
Change in disbursement accounts		(4,103	)		11,922			(3,747	)
Common stock issuance		7,146			7,558			—
Dividends paid		(125,747	)		(119,835	)		(116,510	)
Net cash provided from (used in) financing activities		400,536			(138,263	)		(172,777	)
Net increase (decrease) in cash and cash equivalents		3,115			(4,029	)		(36,912	)
Cash and cash equivalents at the beginning of the year		12,497			16,526			53,438
Cash and cash equivalents at the end of the year	$	15,612		$	12,497		$	16,526
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized	$	166,853		$	144,762		$	154,956
Income taxes (refund)	$	(4,317	)	$	34,627		$	(4,526	)
Non-cash investing activity:
Non-cash plant additions	$	29,927		$	—		$	—
Non-cash financing activity:
Non-cash common share issuance	$	—		$	4,063		$	—

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

52

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’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 through its Advanced Energy Systems, Inc. subsidiary (AES), 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 2005, 2004 and 2003.

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. Effective September 30, 2005, NSTAR changed its classification of goodwill to a regulatory asset on the accompanying Consolidated Balance Sheets. For more information refer to Note D. Certain other 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 E 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 transmission 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.

53

4. Utility Plant

Utility plant is stated at original cost. The cost of replacements of property units is capitalized. Maintenance and repairs and replacements of certain 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. The following is a summary of utility property and equipment, at cost, at December 31:

(in thousands)	2005		2004
Electric -
Transmission	$	724,393	$	695,031
Distribution		3,136,554		2,966,304
General		199,001		211,643
Electric utility plant		4,059,948		3,872,978
Gas -
Transmission and distribution		537,940		507,630
General		73,171		74,166
Gas Utility Plant		611,111		581,796
Total utility plant in service	$	4,671,059	$	4,454,774

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)	2005			2004
Land	$	15,710		$	15,700
Energy production equipment		132,564			136,929
Telecommunications equipment		40,120			39,287
Buildings and improvements		1,364			2,992
		189,758			194,908
Less: accumulated depreciation		(51,536	)		(51,218	)
		138,222			143,690
Construction work in progress		—			458
	$	138,222		$	144,148

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 3.03%, 3.02% and 3.04% in 2005, 2004 and 2003, respectively. The rates include a cost of removal component, which is collected from customers. Depreciation expense on utility plant for 2005, 2004 and 2003 was $141.4 million, $134 million and $126.8 million, respectively.

54

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 $8.9 million, $9.2 million and $8.3 million for 2005, 2004 and 2003, 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.

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 2005, 2004 and 2003 were 3.75%, 1.72% and 1.60%, respectively, and represented only the costs of short-term debt. The 2005 rate increase is directly related to an increase in short-term borrowing rates.

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 2005 and 2004.

9. Cash, Cash Equivalents and Restricted Cash

Cash, cash equivalents and restricted cash at December 31, 2005 are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the 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 and ComElectric to pay the principal and interest on the transition property securitization.

NSTAR’s banking arrangements provide for daily cash transfers to its disbursement accounts as vendor checks are presented for payment. The balances of the disbursement accounts amount to (in thousands) $22,062 and $26,165 at December 31, 2005 and 2004, 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 Statements of Cash Flows.

55

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, two of which are currently being decommissioned. The third plant site has been decommissioned in accordance with the federal Nuclear Regulatory Commission procedures.

11. Costs to Achieve (CTA)

CTA represent costs incurred to execute the merger that created NSTAR and includes the costs of a voluntary severance program, costs of financial advisors, legal costs, and other transaction and systems integration costs. CTA was being amortized over 10 years at an annual rate of $11.1 million through the completion of the four-year rate freeze period based on the original rate plan and was estimated at $111 million, as approved by the MDTE. Effective upon completion of the rate freeze period on August 25, 2003, the amortization expense was increased to reflect the actual CTA final expenditures incurred. As a result, the total CTA amortization expense for 2005 and 2004 was approximately $16.4 million and reflect the final actual CTA of approximately $143 million.

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. Refer to Item 14, “New Accounting Standards,” within this Note for the impact of changes in accounting for Share-Based Payment effective January 1, 2006.

(in thousands, except earnings per common share amounts)	Years ended December 31,
	2005			2004			2003
Net income	$	196,135		$	188,481		$	181,574
Add: Share grant incentive compensation expense included in reported net income, net of related tax effects		3,347			2,608			2,147
Deduct: Total share grant and stock option compensation expense determined under fair value method for all awards, net of related tax effects		(4,110	)		(3,385	)		(2,870	)
Pro forma net income	$	195,372		$	187,704		$	180,851
Earnings per common share:
Basic - as reported	$	1.84		$	1.77		$	1.71
Basic - pro forma	$	1.83		$	1.77		$	1.71
Diluted - as reported	$	1.83		$	1.76		$	1.70
Diluted - pro forma	$	1.82		$	1.75		$	1.70

56

13. Other Income (Deductions), net

Major components of other income, net were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Equity earnings, dividends and other investment income	$	1,480		$	1,607		$	2,205
Interest and rental income		6,509			4,859			3,244
Sale of unregulated property assets		2,564			1,700			1,386
Tax adjustments		4,735			—			8,485
Miscellaneous other income, (includes applicable income tax expense)		(3,168	)		(861	)		(923	)
	$	12,120		$	7,305		$	14,397

Major components of other deductions, net were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Charitable contributions	$	(2,744	)	$	(2,654	)	$	(1,268	)
Miscellaneous other deductions, (includes applicable income tax benefit (expense))		712			1,167			(444	)
	$	(2,032	)	$	(1,487	)	$	(1,712	)

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 January 1, 2006. 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. In addition, the Company will use the Modified Prospective method and will utilize the Black-Scholes Option - pricing model to determine the fair value of its compensation expense of these option grants.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This Standard is effective January 1, 2006 and it changes the requirements for the accounting for and reporting of accounting changes and error corrections. The Standard establishes retrospective application as the required method for reporting a change in accounting principle rather than reporting a cumulative effect of change in accounting principle. Retrospective application requires the application of the new accounting principle to prior periods as if that principle had always been used. Accordingly, NSTAR will adopt this Standard.

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

During 2004, NSTAR Electric was subject to an agreement whereby all of its energy supply resource entitlements under long-term contracts were transferred to an independent energy supplier, following which NSTAR Electric repurchased its energy resource needs from this independent energy supplier for NSTAR Electric’s ultimate sale to its standard offer customers. This transaction had been recorded as a net purchase of electricity. This agreement expired in December 2004 and most of NSTAR Electric’s remaining long-term contracts were bought-out of in February 2005. Refer to Note O, “Contracts for the Purchase of Energy” for more detail on the buy-out of purchase power contracts.

57

During 2005, as part of its normal business operations, NSTAR Electric entered into transactions to sell energy from all of its remaining long-term energy supply resources to ISO-NE. NSTAR Electric records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense.

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 (non-vested) shares and stock options granted under the NSTAR Share Incentive Plan.

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

(in thousands, except per share amounts)	2005		2004		2003
Net income	$	196,135	$	188,481	$	181,574
Basic EPS	$	1.84	$	1.77	$	1.71
Diluted EPS	$	1.83	$	1.76	$	1.70
Weighted average common shares outstanding for basic EPS		106,756		106,268		106,065
Effect of dilutive shares:
Weighted average dilutive potential common shares		344		1,024		732
Weighted average common shares outstanding for diluted EPS		107,100		107,292		106,797

Note C. Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143” (FIN 47), “Accounting for Asset Retirement Obligations” (SFAS 143). In 2003, NSTAR adopted SFAS No. 143 that established accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation (ARO) 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. FIN 47 clarifies when an entity would be required to recognize a liability for the fair value of an ARO 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 are factored into the measurement of the liability rather than the existence of the liability.

NSTAR adopted FIN 47 at December 31, 2005, as required. The recognition of an ARO within its regulated utility businesses has no impact on NSTAR’s earnings. In accordance with SFAS 71, for its rate-regulated utilities, NSTAR established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO. NSTAR has identified several plant assets in which this condition exists and is related to plant assets containing asbestos materials. As a result, in December 2005, NSTAR recognized an asset retirement cost of $0.4 million as an increase in utility property, an asset retirement liability of $9.4 million and a regulatory asset of $9 million.

For comparative purposes, the pro forma ARO that would have been recognized in accordance with FIN 47 as of December 31, 2004 and January 1, 2004 would have amounted to $8.8 million and $8.4 million, respectively.

58

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, 2005 and 2004, the estimated amount of the cost of removal included in regulatory liabilities was approximately $259 million based on the estimated cost of removal component in current depreciation rates.

Note D. Changes in Classification of Goodwill

Effective September 30, 2005, NSTAR changed its classification of the amount included as Goodwill in the December 31, 2004 Consolidated Balance Sheet of $415.5 million to a Deferred debit - Regulatory asset - goodwill. As a result of this change in classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” the Company recognized $268.2 million of accumulated deferred income taxes along with an offsetting regulatory asset as of September 30, 2005. The new classification of goodwill was adopted to better align with the Company’s recovery of goodwill amortization from its customers. For comparative purposes, NSTAR has adopted the new classification retrospectively to the financial statements of prior periods. The regulatory asset, representing the accumulated deferred income taxes, will be amortized over the remaining life of the regulatory asset - goodwill in accordance with the Company’s merger rate order allowing recovery of goodwill amortization and amounts to approximately $7.9 million annually. This additional amortization expense is entirely offset by a corresponding deferred income tax - benefit.

The Company’s goodwill arose from the merger that created NSTAR in 1999. As a result of a rate order from the MDTE approving the merger, the Company is recovering goodwill from its customers and, therefore, NSTAR has determined that this rate structure allows for amortization of goodwill over the collection period.

This classification change had no effect on prior year earnings and, therefore, there has been no change to previously reported retained earnings.

A summary of the impact of the classification change for the years ended December 31, 2004 and 2003 is as follows: (in thousands)

	Year Ended December 31, 2004
	Previously Reported		As Adjusted		Effect of Change
Consolidated Income Statement
Depreciation and amortization	$	246,944	$	254,852	$	7,908
Income taxes		116,238		108,330		(7,908	)
	Previously Reported		As Adjusted		Effect of Change
Consolidated Statement of Cash Flows
Depreciation and amortization	$	246,363	$	254,271	$	7,908
Deferred Income taxes		79,570		71,662		(7,908	)
	December 31, 2004
	Previously Reported		As Adjusted		Effect of Change
Consolidated Balance Sheet
Goodwill	$	426,870	$	—	$	(426,870	)
Current regulatory asset		280,078		300,238		20,160
Deferred debit regulatory asset - goodwill		—		678,698		678,698
Accumulated deferred income taxes		840,461		1,114,588		274,127
	Year Ended December 31, 2003
	Previously Reported		As Adjusted		Effect of Change
Consolidated Income Statement
Depreciation and amortization	$	235,516	$	243,424	$	7,908
Income taxes		121,409		113,501		(7,908	)

59

	Year Ended December 31, 2003
	Previously Reported		As Adjusted		Effect of Change
Consolidated Statement of Cash Flows
Depreciation and amortization	$	236,336	$	244,244	$	7,908
Deferred income taxes		128,379		120,471		(7,908	)

Note E. 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)	2005		2004
Energy contracts (including Yankee units)	$	866,867	$	1,440,963
Goodwill		678,698		698,858
Regulatory assets - other:
Generation-related costs		909,651		520,481
Merger costs to achieve		60,247		76,680
Income taxes, net		50,058		50,292
Purchased energy costs		44,665		—
Redemption premiums		14,896		16,785
Retiree benefit costs		23,090		34,558
Other		64,538		17,007
Total current and long-term regulatory assets	$	2,712,710	$	2,855,624

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.

Energy contracts

The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants was $102.7 million at December 31, 2005. The Maine Yankee (MY) nuclear unit was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. 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. NSTAR does not earn a return on decommissioning costs, but a return is included in rates charged to NSTAR by the plant operators. Refer to Note P, “Commitments and Contingencies,” for more discussion.

In addition, at December 31, 2004, $472.3 million represents the recognition of four purchase power contracts as derivatives and their above-market value and future recovery through NSTAR Electric’s transition charges. Refer to Note F, “Derivative Instruments - Energy Contracts” for further details. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these four contracts. The remaining balance at December 31, 2005 of $764.2 million represents their future recovery through NSTAR

60

Electric’s transition charges. 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.

For the power contracts that were terminated, NSTAR does not earn a return on this regulatory asset. NSTAR recognized this regulatory asset as a result of recognizing the contract termination liability in accordance with SFAS 146 “Accounting for Costs Associated with the Exit or Disposal Activities.” As a result, NSTAR has not treated this regulatory asset as an investment in which it would be entitled to earn a return. Furthermore, no cash outlay has been incurred by NSTAR to create the regulatory asset. The contracts’ termination payments will occur over time and will be collected from customers through NSTAR’s transition charge over the same time period. The cost recovery of these terminated contracts is through September 2016.

Goodwill

The Company’s goodwill originated from the merger that created NSTAR in 1999. As a result of a rate order from the MDTE approving the merger, the Company is recovering goodwill from its customers and, therefore, NSTAR has determined that this rate structure allows for amortization of goodwill over the collection period.

In the third quarter of 2005, NSTAR changed its classification of the amount included as Goodwill in the December 31, 2004 Consolidated Balance Sheet of $415.5 million to a Deferred debit - Regulatory asset - goodwill. As a result of this change in classification to a regulatory asset and in accordance with the requirements of SFAS 109, “Accounting for Income Taxes,” the Company recognized $268.2 million of accumulated deferred income taxes along with an offsetting regulatory asset as of September 30, 2005. Goodwill along with deferred income taxes is being amortized over 40 years, through 2039, without a carrying charge. Refer to Note D, “Change in Classification of Goodwill” for further details.

Generation-related costs

Costs related to purchase power contract buyouts and 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, 2005 and 2004, $892.4 million and $357.2 million of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by Boston Edison’s subsidiaries, BEC Funding LLC and BEC Funding II, LLC and to ComElectric’s subsidiary, CEC Funding, LLC. The certificates are non-recourse to both Boston Edison and ComElectric.

Merger costs to achieve

An integral part of the merger that created NSTAR was the MDTE-approved rate plan of the retail utility subsidiaries of NSTAR. These costs are collected from all NSTAR Electric and NSTAR Gas distribution customers and exclude a return component. The amortization amount of these costs has 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 and excludes a return component. In addition, approximately $37 million in additional Boston Edison deferred tax reserve deficiencies have been recorded in accordance with an MDTE-approved settlement agreement and excludes a return component. Offsetting these amounts is approximately $16 million of a regulatory liability associated with unamortized investment tax credits relating to NSTAR Electric and NSTAR Gas.

61

Purchased energy costs

The purchased energy costs at December 31, 2005 relate to deferred electric basic service and gas costs. Prior to March 1, 2005, customers had the option of continuing to buy electricity from the retail electric distribution businesses at standard offer prices. Since 1998, NSTAR has been allowed to defer the difference between the standard offer and basic service revenues and the cost to supply the power, plus carrying costs. As of March 1, 2005, basic service is the electricity that is supplied by the local distribution company when a customer has not chosen to receive service from a competitive supplier. The market price for basic service may fluctuate based on the average market price for power. Amounts collected through basic service are recovered on a fully reconciling basis. Deferred gas costs are deferred and are recovered from customers in the future.

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.

Retiree benefit costs

The retiree benefit regulatory asset at December 31, 2005 of $23.1 million is comprised of $18.4 million in carrying charges that will be recovered from customers commencing in 2006 related to its qualified pension and other postretirement benefit obligations. There are $4.7 million of pension and PBOP expenses deferred under the MDTE order through 2005. Deferred pension and PBOP costs are amortized and collected from customers over three years. NSTAR is allowed to recover its qualified pension and PBOP expenses through a reconciling rate mechanism. This reconciling rate mechanism removes the volatility in earnings that may have resulted from requirements of existing accounting standards and provides for an annual filing and rate adjustment with the MDTE.

Other

These amounts primarily consist of deferred transmission costs that are set to be recovered over a subsequent twelve-month period with carrying charges. 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 F. Derivative Instruments

Energy 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 their 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” (SFAS 133) and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting. NSTAR accounts for its energy contracts in accordance with SFAS 133 and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities” (SFAS 149).

62

NSTAR Electric has long-term purchase power agreements that were used primarily to meet its customer obligations. 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 SFAS 133 and DIG interpretations, NSTAR, as of December 31, 2004, had four remaining contracts that were recorded at fair value on the accompanying Consolidated Balance Sheets. On March 1, 2005, NSTAR closed on a securitization financing for $674.5 million to, in part, finance the buy-out of these remaining four contracts that were classified as derivative instruments at December 31, 2004. These four contracts had an aggregate fair value of approximately $472 million at December 31, 2004 and were therefore removed as a derivative instrument from Deferred credits - Energy contracts, along with the offsetting regulatory asset, on the accompanying Consolidated Balance Sheets. The securitization debt obligation was recorded along with an offsetting regulatory asset to reflect the future recovery of the debt obligation through its electric distribution companies’ transition charge. At December 31, 2005, NSTAR does not have any contracts that continue to be classified as derivative instruments. Refer to the accompanying Consolidated Financial Statements, Note O, for more detail on the buy-out of certain purchase power contracts.

Hedging Agreements

On February 28, 2005, the MDTE approved a petition by NSTAR Gas to change a portion of its gas procurement practices. As approved, NSTAR Gas began purchasing financial contracts based upon NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. Ultimately, this will minimize fluctuations in prices to NSTAR firm gas sales customers. NSTAR Gas will not take physical delivery of gas when the financial contracts are executed. These contracts qualify as derivative financial instruments and, specifically, cash flow hedges under SFAS 133, as amended by SFAS 149. Accordingly, the fair value of these instruments will be recognized on the accompanying Consolidated Balance Sheet as a deferred asset or liability representing amounts due from or payable to the counter parties of NSTAR Gas. All costs incurred are included in the firm sales Cost of Gas Adjustment Clause (CGAC). Therefore, NSTAR Gas will record an offsetting regulatory asset or liability. Management has begun to implement this practice with two major financial institutions. Currently, these derivative contracts extend through April 2006. At December 31, 2005, NSTAR has recorded a liability and a corresponding regulatory asset of $0.3 million reflecting the fair value of these contracts.

Note G. Variable Interest Entities

In 2004, the FASB issued its interpretation, “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 three wholly owned special purpose subsidiaries, BEC Funding LLC., established in 1999, BEC Funding II, LLC and CEC Funding, LLC both established in 2004, to undertake the sale of $725 million, $265.5 million and $409 million, respectively, in notes to a special purpose trust created by two Massachusetts state agencies. NSTAR consolidates these entities. As part of NSTAR’s assessment of FIN 46R and, for compliance at December 31, 2003 or 2004, NSTAR reviewed the substance of these entities to determine if it is still proper to consolidate these entities. Based on its review, NSTAR has concluded that BEC Funding LLC, BEC Funding II, LLC and CEC Funding, LLC are VIEs and should continue to be consolidated by NSTAR.

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. In order

63

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.

Subsequent to the March 31, 2004 effective date, NSTAR executed purchase power buy-out or 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 or 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. The remaining potential entities that may be considered VIEs are associated with power plants with minimal MW capacity and would not have a material effect on NSTAR’s financial position. As a result, NSTAR will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.

Note H. 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 $50.1 million and $50.3 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2005 and 2004, 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)	2005		2004
Deferred tax liabilities:
Plant-related	$	560,445	$	555,095
Goodwill		266,219		274,127
Power contracts		188,194		—
Transition costs		123,149		151,015
Other		259,781		263,783
		1,397,788		1,244,020
Deferred tax assets:
Plant-related		46,224		50,864
Investment tax credits		15,428		16,101
Other		78,925		79,588
		140,577		146,553
Net accumulated deferred income taxes		1,257,211		1,097,467
Accumulated unamortized investment tax credits		23,477		25,193
	$	1,280,688	$	1,122,660

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

64

Components of income tax expense were as follows:

(in thousands)	2005			2004			2003
Current (benefit) income tax expense	$	(52,959	)	$	36,668		$	39,188
Deferred income tax expense		165,364			73,378			76,036
Investment tax credit amortization		(1,715	)		(1,716	)		(1,723	)
Income taxes charged to operations		110,690			108,330			113,501
Tax expense (benefit) on other income net:
Current income tax expense (benefit)		3,703			2,989			(54,668	)
Deferred income tax (benefit) expense		(4,735	)		—			46,157
Income tax (benefit) expense on other income, net		(1,032	)		2,989			(8,511	)
Total income tax expense	$	109,658		$	111,319		$	104,990

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:

	2005		2004		2003
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal income tax benefit	4.6		4.0		5.3
Investment tax credits	(0.6	)	(0.6	)	(0.6	)
Other	(1.6	)	(1.3	)	(0.3	)
Effective tax rate before tax adjustments	37.4		37.1		39.4
Tax adjustments	(1.5	)	—		(2.8	)
Effective tax rate	35.9	%	37.1	%	36.6	%

RCN Corporation (RCN) Share Abandonment Tax Treatment

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 reflecting the writedown of its investment to zero as of December 31, 2003. NSTAR determined that the abandonment at that time was the most tax efficient, cost effective and expedient means to exit its RCN investment. NSTAR also 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 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 deferred tax asset recorded on its books that resulted from the previous write-down of this investment for financial reporting purposes. The requirement for a tax valuation allowance recorded prior to this abandonment, therefore, is no longer applicable. Accordingly, the Company reversed this reserve as of December 31, 2003.

It is NSTAR’s tax accounting policy to not recognize tax benefits associated with an uncertain tax position until it is probable that such tax benefit will ultimately be realized. Since NSTAR is under continuous audit by the Internal Revenue Service (IRS), NSTAR consulted with its independent tax advisors and determined that it could not conclude that it is probable that the tax deduction related to the abandonment of its RCN investment will be sustained. Accordingly, NSTAR accrued a tax reserve so as to not record the tax benefit of the uncertain tax position.

65

The Company believes it is more likely than not that it is entitled to this ordinary loss deduction, but expects the IRS will review this transaction and it is possible that the IRS will disagree with the Company’s position. In accordance with the Company’s tax policy as it relates to uncertain tax positions, NSTAR established a loss contingency of approximately $44.4 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 and would be reclassified as a tax valuation allowance. During 2005, the Company recognized approximately $4.7 million in tax benefits relating to capital tax gain transactions. As a result, the Company reduced its tax loss contingency by a corresponding amount. Therefore, as of December 31, 2005, the tax loss contingency is approximately $39.7 million. 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.

Note I. 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 31^st for the measurement date to determine its projected benefit obligation and fair value of plan assets for the purposes of determining the Plan’s funded status and the net periodic benefit costs for the following year.

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

	December 31,
(in thousands)	2005			2004
Change in benefit obligation:
Benefit obligation, beginning of the year	$	1,059,398		$	961,029
Service cost		20,689			19,038
Interest cost		57,634			60,165
Plan participants’ contributions		42			61
Actuarial (gain) loss		(24,664	)		90,693
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(53,815	)		(53,000	)
Benefit obligation, end of the year	$	1,035,558		$	1,059,398
Change in Plan assets:
Fair value of Plan assets, beginning of the year	$	894,754		$	829,126
Actual gain on Plan assets, net		69,812			94,431
Employer contribution		77,546			42,724
Plan participants’ contributions		42			61
Settlement payments		(23,726	)		(18,588	)
Benefits paid		(53,815	)		(53,000	)
Fair value of Plan assets, end of the year	$	964,613		$	894,754

The market-related value of NSTAR’s pension assets is determined based on the actual fair value as of the balance sheet date for all classes of assets. Therefore, the difference between the actual and expected return on Plan assets is reflected as a component of unrecognized actuarial net loss.

66

The Plan’s funded status was as follows:

	December 31,
(in thousands)	2005			2004
Funded status	$	(70,945	)	$	(164,644	)
Unrecognized actuarial net loss		397,149			443,437
Unrecognized prior service cost		(3,228	)		(3,096	)
Net amount recognized	$	322,976		$	275,697

Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:

	December 31,
(in thousands)	2005			2004
Accrued retirement liability	$	(37,351	)	$	(31,297	)
Intangible asset		2,570			3,513
Accumulated other comprehensive income		10,868			5,735
Prepaid pension		346,889			297,746
Net amount recognized	$	322,976		$	275,697

The accumulated benefit obligations for the qualified pension plan as of December 31, 2005 and 2004 were $880,819,000 and $870,730,000, respectively.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the nonqualified retirement plan were $40,596,000, $37,351,000 and $0, respectively, as of December 31, 2005 and were $36,415,000, $31,297,000 and $0, respectively, as of December 31, 2004.

Weighted average assumptions were as follows:

	2005		2004		2003
Discount rate at the end of the year	5.75	%	5.75	%	6.25	%
Expected return on Plan assets for the year (net of expenses)	8.4	%	8.4	%	8.4	%
Rate of compensation increase at the end of the year	4.0	%	4.0	%	4.0	%

The Plans’ discount rates are based on a rate modeling of a bond portfolio which approximates the Plan liabilities. In addition, management considers 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 2005 and 2004.

Components of net periodic benefit cost were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Service cost	$	20,689		$	19,038		$	17,976
Interest cost		57,634			60,165			58,826
Expected return on Plan assets		(74,390	)		(70,794	)		(58,917	)
Amortization of prior service cost		133			133			133
Amortization of transition obligation		—			379			601
Recognized actuarial loss		26,202			26,931			33,514
Net periodic benefit cost	$	30,268		$	35,852		$	52,133

67

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 31^st as well as the Plan’s target percentages and the permissible range:

	Plan Assets				Target Percentages		Permissible Ranges
	2005		2004					Benchmark
Asset Category
Equity securities	51	%	54	%	50	%	45% - 55%	Russell 300 Index
Debt securities	28	%	26	%	25	%	20% - 30%	Lehman Aggregate
Real Estate	7	%	5	%	10	%	5% - 15%	Wilshire NAREIT Index
Other	14	%	15	%	15	%	5% - 15%
Total	100	%	100	%	100	%

Other asset category primarily consists of hedge funds and market neutral securities.

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.

As a result of the significant contributions made in 2005, NSTAR does not anticipate making any contributions to the Plan in 2006.

The estimated benefit payments for the years after 2005 are as follows:

(in thousands)
2006	$	61,271
2007		64,613
2008		65,611
2009		73,870
2010		73,597
2011 - 2015		414,821
Total	$	753,783

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 contribute for postretirement benefits.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was reflected as of January 1, 2004 by NSTAR assuming continuation of prescription drug benefits to retirees that are at least actuarially equivalent to the benefits provided under Medicare Part D. The Act provides for drug benefits for

68

participants over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who continue to provide prescription drug programs for eligible former employees over the age of 65, there are subsidies available that are contained in the Act in the form of direct tax-exempt cash payments.

In May 2004, the FASB provided 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 by approximately $51 million in 2004. 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 the accounting guidance resulted in a reduction to the net periodic postretirement benefit cost of approximately $9.7 million and $7 million in 2005 and 2004, respectively, and is reflected as a component of net periodic postretirement benefits costs. However, as a result of the Company’s pension and other postretirement benefits rate reconciliation adjustment mechanism, these reductions do not have a material impact on reported earnings.

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

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

	December 31,
(in thousands)	2005			2004
Change in benefit obligation:
Benefit obligation, beginning of the year	$	600,430		$	595,483
Service cost		5,733			5,828
Interest cost		33,342			33,395
Plan participants’ contributions		2,204			1,835
Plan amendments		(17,789	)		—
Actuarial loss (gain)		3,002			(6,993	)
Benefits paid		(31,250	)		(29,118	)
Benefit obligation, end of the year	$	595,672		$	600,430
Change in plan assets:
Fair value of plan assets, beginning of the year	$	305,309		$	280,032
Actual gain on plan assets		19,028			32,539
Employer contribution		40,047			20,021
Plan participants’ contributions		2,204			1,835
Benefits paid		(31,250	)		(29,118	)
Fair value of plan assets, end of the year	$	335,338		$	305,309

The plans’ funded status was as follows:

	December 31,
(in thousands)	2005			2004
Funded status	$	(260,334	)	$	(295,121	)
Unrecognized actuarial net loss		205,569			207,786
Unrecognized transition obligation		5,810			14,575
Unrecognized prior service cost		(916	)		9,570
Net amount recognized	$	(49,871	)	$	(63,190	)

69

Weighted average assumptions were as follows:

	2005		2004		2003
Discount rate at the end of the year	5.75	%	5.75	%	6.25	%
Expected return on plan assets for the year	9.0	%	8.0	%	8.0	%

For measurement purposes, a 9.0% weighted annual rate increase in per capita cost of covered medical claims was assumed for 2006. This rate is assumed to decrease gradually to 5% in 2013 and remain at that level thereafter. Dental claims 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 2005	$	6,378	$	(5,041	)
Effect on December 31, 2005 postretirement benefit obligation	$	92,745	$	(74,689	)

Components of net periodic benefit cost were as follows:

	Years ended December 31,
(in thousands)	2005			2004			2003
Service cost	$	5,733		$	5,828		$	7,076
Interest cost		33,342			33,395			35,383
Expected return on plan assets		(25,027	)		(23,759	)		(19,088	)
Amortization of prior service cost		222			1,285			1,285
Amortization of transition obligation		1,241			1,821			1,821
Recognized actuarial loss		11,216			9,598			13,303
Net periodic benefit cost	$	26,727		$	28,168		$	39,780

As a result of the significant contributions made in 2005, NSTAR does not anticipate making any contribution to its other postretirement benefit plans in 2006.

The estimated future benefit payments for the years after 2005 are as follows:

(in thousands)
2006	$	29,767
2007		31,309
2008		32,704
2009		34,311
2010		35,744
2011 - 2015		199,082
Total	$	362,917

The estimated expected cash flows from the Medicare subsidy for the years after 2005 are as follows:

(in thousands)
2006	$	2,236
2007		2,512
2008		2,793
2009		3,050
2010		3,289
2011 - 2015		19,520
Total	$	33,400

70

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

Asset Category	Plan Assets				Target Percentages		Permissible           Ranges	Benchmark
	2005		2004
Equity securities	47	%	50	%	50	%	45% - 55%	Russell 3000 Index
Debt securities	35	%	31	%	30	%	25% - 35%	Lehman Aggregate
Real Estate	9	%	10	%	10	%	5% - 15%	Wilshire NAREIT Index
Other	9	%	9	%	10	%	5% - 15%
Total	100	%	100	%	100	%

Other asset category consists of hedge funds and common/collective trusts.

The assets of NSTAR’s PBOP Plan are held in voluntary employees’ beneficiary association trusts and in the Pension Plan 401(h) account which is a subset of the Pension Plan assets and are not reflected as a component of the PBOP Plan assets.

The plan’s primary investment goal is to outperform the return of the composite benchmark. The portfolio also seeks a level of volatility, which approximates that of the composite benchmark returns.

3. Savings Plan

NSTAR also provides a defined contribution 401(k) plan for substantially all employees. Matching contributions (which are equal to 50% of the employees’ deferral up to 8% of eligible base and cash bonus compensation) included in the accompanying Consolidated Statements of Income amounted to $9 million in 2005, $8 million in 2004 and $9 million in 2003. The plan was amended to allow for increased maximum annual pre-tax contributions and additional “catch-up” pre-tax contributions for participants age 50 or older, acceptance of other types of “roll-over” pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share Fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year in February, May, August and November.

Note J. Stock-Based Compensation

NSTAR’s Share Incentive Plan (the Plan) permits a variety of stock and stock-based awards, including stock options and deferred (non-vested) stock to be granted to key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of common shares that may be awarded under the Plan is four million. As adjusted for the effect of the common stock split that occurred in 2005, there were 2,116,472 unissued shares available under this Plan as of December 31, 2005. The weighted average grant date fair value of the deferred stock issued during 2005, 2004 and 2003 was $29.60, $24.21 and $21.60, respectively. During 2005, 371,419 deferred shares and 586,000 ten-year non-qualified stock options were granted. During 2004, 216,700 deferred shares and 632,000 ten-year non-qualified stock options were granted under the Plan. During 2003, 219,800 deferred shares and 648,000 ten-year non-qualified stock options were granted under the Plan. The options were granted at the full market price of the common shares on the date of the grant. All the awards vest ratably over a three-year period. Refer to the Consolidated Financial Statements, Note A, for more details.

71

Stock option activity of the Plan was as follows:

	2005 Activity		Weighted Average Exercise Price		2004 Activity		Weighted Average Exercise Price		2003 Activity		Weighted Average Exercise Price
Options outstanding at January 1	2,912,338		$	21.73	2,425,538		$	21.01	2,093,738		$	20.07
Options granted	586,000		$	29.60	632,000		$	24.21	648,000		$	21.60
Options exercised	(909,937	)	$	20.18	(145,200	)	$	20.52	(281,334	)	$	15.27
Options forfeited	—			—	—		$	—	(34,866	)	$	21.78
Options outstanding at December 31	2,588,401		$	24.05	2,912,338		$	21.73	2,425,538		$	21.01

Summarized information regarding stock options outstanding at December 31, 2005:

		Options Outstanding			Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Number Outstanding	Weighted Average Exercise Price
$19.88	39,400	2.26	$	19.88	39,400	$	19.88
$22.19	229,000	4.40	$	22.19	229,000	$	22.19
$19.85	170,000	5.40	$	19.85	170,000	$	19.85
$22.06 - $22.67	415,999	6.30	$	22.61	415,999	$	22.61
$21.60	550,666	7.33	$	21.60	368,946	$	21.60
$24.21	597,336	8.33	$	24.21	197,120	$	24.21
$29.60	586,000	9.44	$	29.60	—		—

There were 1,420,465, 1,689,978 and 1,344,946 stock options exercisable on December 31, 2005, 2004 and 2003, respectively. The weighted average exercise price of these options exercisable are $22.09, $20.75 and $20.42, respectively.

The stock options granted during 2005, 2004 and 2003 have a weighted average grant date fair value of $2.74, $3.74 and $3.85, respectively. The fair value was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:

	2005		2004		2003
Expected life (years)	6.0		4.0		4.0
Risk-free interest rate	3.76	%	3.39	%	2.54	%
Volatility	15	%	15	%	18	%
Dividends	4.69	%	4.90	%	4.97	%

Compensation cost recognized in the accompanying Consolidated Statements of Income for deferred share awards in 2005, 2004 and 2003 was $5,507,458, $4,282,561 and $3,530,719, respectively.

Note K. Capital Stock

At NSTAR’s Annual Meeting of Shareholders held on April 28, 2005, shareholders approved an increase in the number of the Company’s authorized shares from 100 million to 200 million. Subsequently, the Board of Trustees approved a two-for-one stock split of NSTAR’s common shares, in the form of a 100% common share dividend, to shareholders of record on May 16, 2005. The new shares were issued on June 3, 2005. The Company’s intent in effecting a stock split in the form of a stock dividend was to increase the number of outstanding common shares and to reduce the per share stock price thereby making it more accessible to investors. Common equity, common shares, and stock option activity for all periods presented have been restated

72

to give retroactive recognition to the stock split. In addition, all references in the financial statements and notes to the financial statements, to weighted average number of basic and diluted shares, and per share amounts of the Company’s common shares have been restated to give retroactive recognition to the stock split.

Dividends declared per common share were $0.87, $1.1225 and $1.0875 in 2005, 2004 and 2003, respectively. As a result of a change in NSTAR’s Board of Trustee meetings schedule in 2005, the fourth quarter dividend, typically declared in December, of $0.3025 per share was approved on January 26, 2006. The dividend payment schedule remains unchanged.

1. Common Shares

Common share issuances and repurchases in 2004 through 2005 were as follows:

(in thousands)	Number of Shares	Total Par Value		Premium on Common Shares
Balance at December 31, 2003	106,066	$	106,066	$	813,188
Share Incentive Plan issuance	172		172		3,891
Share Incentive Plan	—		—		(4,871	)
Dividend Reinvestment and Direct Common Shares Purchase Plan	312		312		7,246
Balance at December 31, 2004	106,550		106,550		819,454
Share Incentive Plan	—		—		(13,243	)
Dividend Reinvestment and Direct Common Shares Purchase Plan	258		258		6,888
Balance at December 31, 2005	106,808	$	106,808	$	813,099

In connection with the NSTAR Dividend Reinvestment and Direct Common Shares Purchase Plan, NSTAR issued approximately 258,000 shares under this registration and received approximately $7.1 million in 2005.

2. Cumulative Preferred Stock of Subsidiary

Non-mandatory redeemable series:

Par value $100 per share, 2,890,000 shares authorized and 430,000 shares issued and outstanding:

(in thousands, except per share amounts)
Series	Current Shares     Outstanding	Redemption Price/Share		December 31, 2005		December 31, 2004
4.25%	180,000	$	103.625	$	18,000	$	18,000
4.78%	250,000	$	102.80		25,000		25,000
Total non-mandatory redeemable series				$	43,000	$	43,000

Boston Edison Company has two outstanding series of non-mandatory redeemable preferred stock. Both series are part of a class of Boston Edison Company’s Cumulative Preferred Stock. Upon any liquidation of Boston Edison Company, holders of the Cumulative Preferred stock are entitled to receive the liquidation preference for their shares before any distribution to the holder of the common stock. The liquidation preference for each outstanding series of Cumulative Preferred Stock is equal to the par value ($100.00 per share), plus accrued and unpaid dividends.

73

Note L. Indebtedness

1. Long-Term Debt

NSTAR’s long-term debt consisted of the following:

	December 31,
(in thousands)	2005			2004
Mortgage Bonds/Notes, collateralized by property of operating subsidiaries:
6.54%, due September 2007	$	2,857		$	4,286
7.04%, due September 2017		25,000			25,000
9.95%, due December 2020		25,000			25,000
7.11%, due December 2033		35,000			35,000
6.924%, due June 2021		103,947			107,548
Notes:
Variable Rate (3.0275% in 2004) due May 2006		—			150,000
7.62%, due November 2006		20,000			20,000
8.70%, due March 2007		5,000			5,000
9.55%, due December 2007		2,857			4,286
7.70%, due March 2008		10,000			10,000
8.0%, due February 2010		500,000			500,000
9.37%, due January 2012		7,368			8,421
7.98%, due March 2013		25,000			25,000
9.53%, due December 2014		10,000			10,000
9.60%, due December 2019		10,000			10,000
8.47%, due March 2023		15,000			15,000
Debentures:
Floating Rate (2.57% in 2004) due October 2005		—			100,000
7.80%, due May 2010		125,000			125,000
4.875%, due October 2012		400,000			400,000
4.875%, due April 2014		300,000			300,000
Sewage facility revenue bonds, due through 2015		14,902			16,591
Massachusetts Industrial Finance Agency (MIFA) bonds:
5.75%, due February 2014		15,000			15,000
Transition Property Securitization Certificates:
6.62%, due March 2005		—			7,296
3.40%, due September 2006		36,836			—
6.91%, due September 2007		108,923			170,876
3.78%, due September 2008		154,018			—
7.03%, due March 2010		171,624			171,624
4.13%, due September 2011		266,477			—
4.40%, due September 2013		144,771			—
		2,534,580			2,260,928
Unamortized debt discount		(9,063	)		(10,281	)
Amounts due within one year		(123,140	)		(149,245	)
Total long-term debt	$	2,402,377		$	2,101,402

On March 1, 2005, ComElectric redeemed its $150 million variable rate notes due May 2006.

On October 17, 2005, Boston Edison redeemed the entire outstanding balance of $100 million aggregate principal amount of its Floating Rate Debentures due on that date.

Sewage facility revenue bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.65 million were made in 2005 and 2004. The interest rate of the bonds was 7.375% for both 2005 and 2004.

The 5.75% tax-exempt unsecured MIFA bonds due 2014 were redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreased to 101% in February 2005 and to par in February 2006.

74

The aggregate principal amounts of NSTAR long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2005 are approximately $123 million in 2006, $166 million in 2007, $170 million in 2008, $160 million in 2009 and $752 million in 2010.

The Transition Property Securitization Certificates held by Boston Edison’s subsidiaries, BEC Funding LLC and BEC Funding II, LLC, are each collaterized with separate securitized regulatory assets with combined balances of $526.1 million and $357.2 million as of December 31, 2005 and 2004, respectively. Boston Edison, as servicing agent for BEC Funding LLC and BEC Funding II, LLC collected $129.2 million in 2005. In addition, the Transition Property Securitization Certificates held by ComElectric’s subsidiary, CEC Funding, LLC, are collaterized with a securitized regulatory asset with a balance of $366.4 million as of December 31, 2005. ComElectric, as servicing agent for CEC Funding, LLC collected $57.7 million in 2005. Funds collected from the companies’ respective customers are transferred to each Funding companies’ Trust on a daily basis. These Certificates are non-recourse to Boston Edison and ComElectric.

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. On December 29, 2005, the MDTE approved Boston Edison’s request to extend the term of its financing plan until June 30, 2006 for the remaining $200 million unissued securities.

2. Financial Covenant Requirements and Lines of Credit

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, 2005 and 2004. 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 NSTAR, is unsecured.

NSTAR has executed a five-year, $175 million revolving credit agreement that expires in November 2009. At December 31, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as a backup to NSTAR’s $175 million commercial paper program that, at December 31, 2005 and 2004, had $66 million and $5 million outstanding, respectively. Under the terms of the 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. Commitment fees must be paid on the total agreement amount. At December 31, 2005 and 2004, NSTAR was in compliance with the aforementioned covenant as the ratios were 56.7% and 58.3% respectively.

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. Boston Edison has 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, 2005 and 2004, there were no amounts outstanding under the revolving credit agreement. This credit facility serves as backup to Boston Edison’s $350 million commercial paper program that had a $197 million and $46.5 million balance at December 31, 2005 and 2004, respectively. Under the terms of the revolving credit 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. At December 31, 2005 and 2004, Boston Edison was in compliance with its covenants in connection with its short-term credit facilities as the ratios were 45.9% and 53.1%, respectively.

75

As of December 31, 2005, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $245 million available under several lines of credit and had $154.5 million and $109.9 million outstanding under these lines of credit at December 31, 2005 and 2004, 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.

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.

Interest rates on the outstanding borrowings generally are money market rates and averaged 3.54% and 1.38% in 2005 and 2004, respectively. In aggregate, short-term borrowings totaled $417.5 million and $161.4 million at December 31, 2005 and 2004, respectively.

Note M. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:

1. Cash and Cash Equivalents

The carrying amounts of $15.6 million and $12.5 million for 2005 and 2004, respectively, approximate fair value due to the short-term nature of these securities.

2. Indebtedness (Excluding Notes Payable)

The fair values of long-term indebtedness are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 2005 and 2004 were as follows:

	2005				2004
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term indebtedness (including current maturities)	$	2,525,517	$	2,642,190	$	2,250,647	$	2,483,220

Note N. Segment and Related Information

For the purpose of providing segment information, NSTAR’s principal operating segments, or its traditional core businesses, are the electric and natural gas utilities that provide energy delivery services in 107 cities and towns in Massachusetts. The unregulated operating segment engages in business activities that include district energy operations, telecommunications and liquefied natural gas service.

Amounts shown on the following table for 2005, 2004 and 2003 include the allocation of NSTAR’s (parent company) results of operations and assets, net of inter-company transactions, and primarily consist of interest charges and investment assets, respectively, to these business segments. The allocation of parent company charges is based on an indirect allocation of the parent company’s investment relating to these various business segments.

The unregulated net income for 2005 as compared to 2004 reflects higher revenues for steam, chilled water and electricity sales offset by the partial absence of NSTAR Steam Corporation which ceased operations in September 2005. The unregulated net income for 2004 as compared to 2003 reflects the absence of operations in 2004 of results of operations from the Blackstone Station due to its sale in 2003 and the resulting impact of decreased income on NSTAR Steam Corporation, offset by a higher gross margin at AES primarily due to increased steam sales and higher demand revenues. In addition, on December 24, 2003, NSTAR abandoned the 11.6 million shares of RCN common stock and recorded a pre-tax charge of $6.8 million including expenses. Offsetting the 2003 RCN abandonment loss is the recognition of $6.8 million of tax benefits resulting from unanticipated capital gain transactions.

76

The unregulated net expenditures for property decreased in 2004 as compared to 2003 primarily due to the absence of construction expenditures for AES’s expansion project that was placed into service in late 2003.

(in thousands)	2005		2004		2003
Operating revenues
Electric utility operations	$	2,543,541	$	2,350,185	$	2,333,235
Gas utility operations		571,199		492,338		465,209
Unregulated operations		128,380		111,809		113,267
Consolidated total	$	3,243,120	$	2,954,332	$	2,911,711
Depreciation and amortization
Electric utility operations	$	299,741	$	218,915	$	209,688
Gas utility operations		22,435		21,310		20,064
Unregulated operations		14,494		14,627		13,672
Consolidated total	$	336,670	$	254,852	$	243,424
Operating income tax expense (benefit)
Electric utility operations	$	92,239	$	90,891	$	96,908
Gas utility operations		13,589		13,979		14,829
Unregulated operations		4,862		3,460		1,764
Consolidated total	$	110,690	$	108,330	$	113,501
Equity income in investments accounted for by the equity method (a)
Electric utility operations	$	1,480	$	1,607	$	2,205
Interest charges
Electric utility operations	$	143,044	$	128,306	$	134,513
Gas utility operations		14,643		15,677		14,203
Unregulated operations		9,876		9,722		8,496
Consolidated total	$	167,563	$	153,705	$	157,212
Segment net income
Electric utility operations	$	157,235	$	156,679	$	150,249
Gas utility operations		25,310		25,801		24,441
Unregulated operations		13,590		6,001		6,884
Consolidated total	$	196,135	$	188,481	$	181,574
Equity Investments
Electric utility operations	$	13,705	$	13,887	$	15,322
Net expenditures for property
Electric utility operations	$	337,519	$	272,794	$	240,699
Gas utility operations		40,361		35,262		30,167
Unregulated operations		5,676		5,331		36,789
Consolidated total	$	383,556	$	313,387	$	307,655
Segment assets
Electric utility operations	$	6,658,805	$	6,494,568	$	5,664,553
Gas utility operations		790,155		695,329		719,706
Unregulated operations		196,604		201,459		229,927
Consolidated total	$	7,645,564	$	7,391,356	$	6,614,186

(a) The equity income from equity investments is included in other income, net on the accompanying Consolidated Statements of Income.

77

Note O. Contracts for the Purchase of Energy

1. NSTAR Electric Purchase Power Agreements

As a Massachusetts distribution company, NSTAR Electric is required to obtain and resell power to retail customers for those who choose not to buy energy from a competitive energy supplier. Standard offer service option for customers ended on February 28, 2005. Therefore, all customers who had not chosen to receive service from a competitive supplier were provided default service, which was designated basic service thereafter. Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for power. For basic service power supply, NSTAR Electric makes periodic market solicitations consistent with MDTE regulations. During 2005, NSTAR Electric entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these large customers, for the second-half of 2006. NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers through March 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers. For 2005, NSTAR Electric entered into agreements ranging in length from three to twelve-months.

In 2004, NSTAR Electric executed agreements to buy-out or restructure twelve of its purchase power agreements that required MDTE approval. These agreements constituted approximately 685 MW of the remaining 800 MW of capacity, and reduced the amount of above-market costs that NSTAR Electric will collect from its customers through its transition charges. As of December 31, 2004, four of these agreements received MDTE approval and were 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. These buy-out/restructuring agreements, once completed, provide no economic benefit to NSTAR Electric and, therefore, the agreements’ contract termination costs were recorded on the accompanying Consolidated Financial Statements.

On January 7, 2005, NSTAR Electric received approval from the MDTE for an additional four agreements that were 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 was removed during February 2005, NSTAR recorded the contract termination cost 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 recognized as of December 31, 2005 and 2004 for obligations relating to eight of the twelve contracts is approximately $764 million and $852 million (present valued); approximately $156 million and $145 million are reflected as a component of current liabilities - energy contracts and approximately $608 million and $707 million as a component of Deferred credits - energy contracts on the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively. 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 to assets and liabilities.

Also in January 2005, the MDTE approved the remaining four contract buy-outs with two suppliers that reduced the overall amount of transition costs to be paid for above-market contracts. These contracts are buy-out arrangements whereby NSTAR Electric has made contract termination payments in full release of its obligation under the purchase power agreements. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that sought approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to provide the funds for these 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% and the securitization financing closed on March 1, 2005.

78

2. NSTAR Gas Firm Transportation and Storage Agreements

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. NSTAR Gas also utilizes contracts for underground storage and liquefied natural gas facilities to meet its winter peaking demands. 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 contracts with storage capacity entitlements of nearly 8 billion cubic feet.

NSTAR Gas has various contractual agreements covering the transportation of natural gas and underground natural gas storage facilities, which are recoverable from customers under the MDTE-approved Cost of Gas Adjustment Clause. These contracts expire at various times from 2006 to 2012. NSTAR Gas’ firm contract demand charges associated with firm pipeline transportation and storage capacity contracts in 2005, 2004 and 2003 were approximately $47.7 million, $48.4 million and $50.5 million, respectively. Refer to Note P, “Commitments and Contingencies,” “Energy Supply” section for NSTAR Gas’ firm contract demand charges at current rates under these contracts for the years after 2005.

Note P. Commitments and Contingencies

1. 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.

NSTAR monitors its service quality continuously to determine its contingent liability. If it is probable that a liability has been incurred and is estimable, a liability is 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.

On March 1, 2005, NSTAR Electric and NSTAR Gas filed their 2004 Service Quality Reports with the MDTE that demonstrated the Companies achieved sufficient levels of reliability and performance; the reports indicate that no penalty was assessable for 2004. On December 30, 2005, the MDTE issued formal approval of this filing.

As of December 31, 2005, NSTAR has determined that for 2005, two of its electric subsidiaries are in a combined penalty position of approximately $0.4 million relating to their applicable service quality indicators. This penalty position is primarily due to service interruptions caused by the severe winter storms experienced earlier in the year. As a result, NSTAR has recorded a liability for this obligation. Since 2001, NSTAR Electric and NSTAR Gas have not been in a penalty position and therefore, the current performance is not indicative of future results.

In late 2004, the MDTE initiated a proceeding to potentially modify the service quality indicators for all Massachusetts utilities. Until any modification occurs, the current SQI measures will remain in place. NSTAR cannot predict the outcome or timing of this proceeding.

The Settlement Agreement approved by the MDTE on December 30, 2005, established additional performance measures applicable to NSTAR’s rate regulated subsidiaries. NSTAR Gas shall establish and submit a service quality measure based on separate leaks per mile metrics for bare-steel mains and unprotected, coated-steel

79

mains. A specific proposal to implement this performance benchmark shall be submitted to the MDTE for approval by on or before July 1, 2006 and shall be subject to a maximum penalty or incentive of up to $500,000. The Settlement Agreement also establishes, for NSTAR Electric, a performance benchmark relating to poor performing circuits, with a maximum penalty or incentive of up to $500,000.

2. Contractual Commitments

Leases

NSTAR also has leases for facilities and equipment. The estimated minimum rental commitments under non-cancellable capital and operating leases for the years after 2005 are as follows:

(in thousands)
2006	$	19,566
2007		16,462
2008		14,703
2009		13,200
2010		11,230
Years thereafter		35,790
	$	110,951

The total expense for both leases and transmission agreements was $28.3 million in 2005, $27.0 million in 2004 and $25.4 million in 2003, net of capitalized expenses of $1.8 million in 2005, $1.5 million in 2004 and $1.9 million in 2003.

Total rent expense for all operating leases, except those with terms of a month or less, amounted to $17.8 million in 2005, $16.3 million in 2004 and $19.9 million in 2003.

Transmission

As a member of ISO-NE, NSTAR Electric is subject to the terms and conditions of the ISO-NE tariff through February 2010. This obligates NSTAR Electric to pay for regional network services through that period to support the pooled transmission facilities requirements of other New England transmission owners whose facilities are used by NSTAR Electric. These payments amounted to $89.6 million, $71.1 million and $62.9 million in 2005, 2004 and 2003, respectively.

Energy Supply

NSTAR Electric has entered into short-term power purchase agreements to meet its entire basic service supply obligation, other than to largest customers, for the period January 1, 2006 through June 30, 2006 and for 50% of its obligation, other than to these largest customers, for the second-half of 2006. NSTAR Electric has entered into a short-term power purchase agreement to meet its entire basic service supply obligation for large customers through March 2006. A request for proposals will be issued quarterly in 2006 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. NSTAR Electric entered into agreements ranging in length from three to twelve-months effective January 1, 2005 through December 31, 2005 with suppliers to provide full basic service energy and ancillary service requirements at contract rates approved by the MDTE. NSTAR Electric is currently recovering payments it is making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect NSTAR Electric from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, an individual NSTAR Electric distribution company receive a credit rating below investment grade, that company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer to Note O, “Contracts for the Purchase of Energy” for a further discussion.

80

The following represents NSTAR’s long-term energy related contractual commitments:

(in millions)	2006		2007		2008		2009		2010		Years Thereafter		Total
Electric capacity obligations	$	2	$	2	$	2	$	2	$	3	$	21	$	32
Gas contractual obligations		48		48		47		45		44		67		299
Purchase power buy-out obligations		156		160		162		142		140		206		966
	$	206	$	210	$	211	$	189	$	187	$	294	$	1,297

Electric capacity obligations represent remaining capacity costs of long-term contracts that reflect NSTAR Electric’s proportionate share of capital and fixed operating costs of certain generating units. In 2005, these costs were attributed to 361.6 MW of capacity purchased. Energy costs are paid to generators based on a price per kWh actually received into NSTAR Electric’s distribution system and are included in the total cost. Total capacity purchased in 2005 was 880.7 MW. These contracts expire at various times from 2006 through 2019.

Gas contractual obligations represent agreements covering the transportation of natural gas and underground natural gas storage facilities that are recoverable from customers under the MDTE approved Cost of Gas Adjustment Clause. These contracts expire at various times from 2006 through 2012.

Purchase power buy-out obligations represent the buy-out/restructuring agreements for contract termination costs that reduce the amount of above-market costs that NSTAR Electric will collect from its customers through its transition charges. These agreements require NSTAR Electric to make net monthly payments through September 2016.

3. Electric Equity Investments and Joint Ownership Interest

NSTAR has an equity investment of approximately 14.5% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, NSTAR is required to guarantee, in addition to each company’s own share, the obligations of those participants who do not meet certain credit criteria. At December 31, 2005, NSTAR’s portion of these guarantees amounted to $8.8 million. New England Hydro-Transmission Electric Company, Inc. (NEH) and New England Hydro-Transmission Corporation (NHH) have agreed to use their best efforts to limit their equity investment to 40% of their total capital during the time NEH and NHH have outstanding debt in their capital structure. In order to meet their best efforts obligations pursuant to the Equity Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in 2005, NEH repurchased a total of 110,000 of its outstanding shares from all equity holders and NHH repurchased a total of 650 outstanding shares from all equity holders. Through December 31, 2005, NSTAR Electric’s reduction of its equity ownership resulting from NEH buy-back of 15,914 shares and NHH buy-back of 94 shares was approximately $0.4 million.

NSTAR Electric collectively has an equity ownership of 14% in Connecticut Yankee Atomic Power Company (CYAPC), 14% in Yankee Atomic Electric Company (YAEC), and 4% in 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) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.

The Maine Yankee nuclear unit (MY) was notified on October 3, 2005 by the U.S. Nuclear Regulatory Commission (NRC) that its former plant site has been decommissioned in accordance with NRC procedures. The NRC has amended MY’s license, reducing the land under the license from approximately 179 acres to the 12 acre Independent Spent Fuel Storage Installation (ISFSI) that includes a dry cask storage facility, and marks the first time a commercial nuclear power plant in the United States has been fully decommissioned with all plant

81

buildings removed. MY’s amended license will continue to apply to the ISFSI where spent nuclear fuel from the plant’s 23 years of operation is stored. MY remains responsible for the security and protection of the ISFSI and is required to maintain a radiation monitoring program at the site.

Based on estimates from the Yankee Companies’ management as of December 31, 2005, the total remaining approximate cost for decommissioning and/or security or protection of each nuclear unit is as follows: $515.7 million for CY, $149.3 million for YA and $242.5 million for MY. Of these amounts, NSTAR Electric is obligated to pay $72.2 million towards the decommissioning of CY, $20.9 million toward YA, and $9.7 million toward MY. These estimates are recorded in the accompanying Consolidated Balance Sheets as Energy contract liabilities with a corresponding Regulatory asset and do not impact the current results of operations and cash flows. 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.

The various decommissioning trusts for which NSTAR or it subsidiaries are responsible through their equity ownership are established pursuant to Federal regulations. The investment of decommissioning funds that have been established, are managed in accordance with these federal guidelines, state jurisdictions and with the applicable Internal Revenue Service requirements. Some of the requirements state that these investments be managed independently by a prudent fund manager and that funds are to be invested in conservative, minimum risk investment securities. Any gains or losses are anticipated to be refunded to or collected from customers, respectively.

CY’s estimated decommissioning costs increased significantly in 2003 which reflected 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 the outcome of a hearing and refund to allow for this recovery.

CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims including 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. On January 27, 2006, the Connecticut Superior Court issued a finding that the real property and the periodic payments were subject to attachment and garnishment, respectively, which is likely result in the implementation of the stipulated escrowing arrangement. CY may appeal the Superior Court finding. Discovery in the termination litigation is drawing to a close and a trial has been scheduled for May 2006. NSTAR Electric NSTAR cannot predict the timing or outcome of the litigation with Bechtel.

On November 22, 2005, FERC’s Administrative Law Judge (ALJ) issued an Initial Decision (ID) that found in favor of CY on all imprudence claims, finding that no disallowance was warranted. The only adjustment the ID would make in CY’s proposed decommissioning charges is with respect to the escalation rate used to factor the effects of inflation into the estimate. Because the ALJ found that CY had dispelled all claims of imprudence, the ALJ did not address any party’s proposed disallowance whether on the grounds of imprudence or under the 2003 Settlement’s budget incentive mechanism.

Under FERC’s rules, the ID becomes final only if no party takes exception to it; if any party does take exception, the full FERC will review the ID, and FERC can reach different conclusions. CY expects that the interveners who unsuccessfully raised imprudence claims before the ALJ will pursue those claims before the full FERC.

82

During the course of carrying out the decommissioning work, YA has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards beyond the levels assumed in the 2003 Estimate. On November 23, 2005, YA submitted a filing to the FERC for revisions to its Rate Schedules to revise the level of collections to recover the costs of completing the decommissioning of YA’s retired nuclear generating plant (the 2005 Estimate). The schedule for the completion of physical work will need to extend until the end of August 2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of the 2003 FERC settlement. Based on this allocation increase, NSTAR Electric is obligated to pay $8.8 million to the decommissioning of YA. Most of the cost increase relates to decommissioning expenditures that will be made during 2006, followed by a significant reduction in those charges during the years 2007 through 2010. On January 31, 2006, FERC issued an order accepting the rates for filing, effective February 1, 2006, subject to hearing and refund. FERC ordered the hearing held in abeyance pending the outcome of settlement procedures. NSTAR Electric cannot predict the timing or the ultimate outcome of these settlement discussions.

4. 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, 2005, outstanding guarantees totaled $38.1 million as follows:

(in thousands)
Letters of Credit	$	13,100
Surety Bonds		16,200
Other Guarantees		8,800
Total Guarantees	$	38,100

Letters of Credit

There is a $5.6 million letter of credit 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. There have been no amounts drawn under this letter of credit. In addition, during May 2005, NSTAR issued a $7.5 million letter of credit for the benefit of the general contractor on NSTAR’s 345 kV Transmission project. The letter of credit is available if NSTAR’s subsidiary is unable to meet its obligations. As of December 31, 2005, no amounts have been drawn under this letter of credit. The amount of the standby letter of credit was reduced to $4.5 million on February 1, 2006.

Surety Bonds

As of December 31, 2005, certain of NSTAR’s subsidiaries have purchased a total of $1.5 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 have 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. On January 3, 2006, NSTAR and certain of its subsidiaries executed indemnity agreements to provide additional financial security to its bond company in the form of a contingent letter of credit to be triggered in the event of a downgrade in the future of NSTAR’s Senior Note rating to below BBB by S&P and/or to below Baa1 by Moody’s. These Indemnity Agreements cover both the performance surety bonds and workers’ compensation bonds.

83

Other

NSTAR and its subsidiaries have also issued $8.8 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.

5. Environmental Matters

NSTAR subsidiaries face possible liabilities as a result of involvement in several multi-party disposal sites, state-regulated sites or third party claims associated with contamination remediation. NSTAR generally expects to have only a small percentage of the total potential liability for the majority of these sites.

During the second quarter of 2005, the Massachusetts Supreme Judicial Court (SJC) issued its decision in one of the environmental contamination matters. In 2004, a Superior Court had issued a decision favorable to Boston Edison that put the burden of proof on the plaintiffs to determine Boston Edison’s liability for contamination. The SJC’s decision reversed the Superior Court’s 2004 ruling and held that the plaintiffs in this matter are allowed to seek joint and several liability against the defendants, including Boston Edison. The case was remanded back to the Superior Court for trial. On October 6, 2005, Boston Edison reached a settlement in principle with the plaintiffs in this matter. It is anticipated that the appropriate settlement documents will be finalized in February 2006 and filed with the Superior Court shortly thereafter. The Settlement is subject to a 90-day public comment period as which point we expect the Superior Court to approve and enter final judgment. Boston Edison anticipates paying within 30 days of the final judgment approximately $8.6 million which is within the amount previously reserved for this matter. Boston Edison will vigorously attempt to recover monies from the other responsible third parties, including recovery from its insurance carrier.

As of December 31, 2005 and 2004, NSTAR had reserves of $10.3 million and $3.9 million, respectively, for all potential environmental sites, including the site specified in the paragraph above. This estimated recorded liability is based on an evaluation of all currently available facts with respect to all of its sites. In addition, based on a legal opinion from the Company’s environmental counsel, it is probable that Boston Edison will recover, at a minimum, approximately $2 million from other parties. As a result, Boston Edison recorded a receivable in the second quarter that will ultimately offset the Company’s obligation. Management believes that the ultimate disposition of this matter will not have a material adverse impact on NSTAR’s results of operation, cash flows or its financial position.

NSTAR Gas is participating in the assessment or remediation of certain 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, 2005 and 2004, NSTAR recorded a liability of approximately $3.6 million and $3.8 million, respectively, as estimates for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a potentially responsible party. A corresponding regulatory asset was recorded that reflects the future rate recovery for these costs.

Estimates related to environmental remediation costs are reviewed and adjusted 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 or cash flows.

84

6. Regulatory and Legal Proceedings

a. Regulatory proceedings

On December 30, 2005, the MDTE approved a multi-year rate Settlement Agreement between the Attorney General of Massachusetts, NSTAR and several interveners, for adjustments to NSTAR Electric’s transition and distribution rates effective January 1, 2006 and May 1, 2006, respectively. Effective with the January 1^st date adjustment, NSTAR Electric will freeze its total transition and distribution rates through 2012. Additionally, the Settlement Agreement establishes a performance-based distribution rate increases (PBR) beginning January 1, 2007. The PBR will result in annual inflation-adjusted distribution rates increases that will be offset by a decrease in transition rates through 2012.

In December 2005, NSTAR Electric filed proposed transition rate adjustments for 2006, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2005. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2006. The filings are to be updated in February 2006 to reflect final 2005 costs and revenues which are subject to final reconciliation. As part of the rate Settlement Agreement approved by the MDTE on December 30, 2005, transition rates are further impacted by a reduction of $20 million effective January 1, 2006 and by $30 million on May 1, 2006 and are deferred with carrying charges at a rate of 10.88%.

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

On October 19, 2005, the MDTE approved a settlement agreement between Cambridge Electric, ComElectric and the Attorney General of the Commonwealth of Massachusetts to resolve issues relating to the reconciliation of transition, standard offer and basic service costs for 2003 and 2004. This settlement agreement had no material effect on NSTAR’s consolidated results of operations, cash flows and financial condition for a reporting period. The reconciliation of transmission costs and revenues was not resolved by settlement and will be decided by the MDTE after a hearing. Settlement discussions with an intervener and the Attorney General of the Commonwealth of Massachusetts are ongoing with respect to Boston Edison’s 2003 and 2004 transmission reconciliation filing. Settlement discussions with the MDTE for the reconciliation of Boston Edison’s 2004 costs for transition, standard offer and basic service have been delayed and will be decided by the MDTE in a future hearing. NSTAR Electric cannot predict the timing or the ultimate out come of these Settlement discussions.

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.

Cambridge Electric and ComElectric filed proposed changes to their OATT with the FERC on March 30, 2005 to provide for consistent application of the OATT among all NSTAR Electric companies. The new tariffs became effective on June 1, 2005; however, the FERC set issues raised in the proceeding for hearing. Settlement discussions with interveners, the Attorney General of Massachusetts, are ongoing. NSTAR cannot predict the timing or ultimate resolution of this proceeding.

b. 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,

85

settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance except for the item disclosed in the Consolidated Financial Statements, Note P, “Commitments and Contingencies.” 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.

7. Capital Expenditures and Financings

The most recent estimates of capital expenditures and long-term debt maturities for the years 2006 and 2007-2010 are as follows:

(in thousands)	2006		2007-2010
Capital expenditures	$	408,000	$	1,200,000
Long-term debt	$	123,140	$	1,247,857

Capital expenditures for 2006 include the remaining costs related to NSTAR’s 345kV transmission project that amounts to $89 million. The total cost of this project is estimated at approximately $220 million. A significant portion of these costs ($120 million) was incurred in 2005 and the remaining balance will be expended in 2006. In the second quarter of 2005, NSTAR began construction of a switching station in Stoughton, Massachusetts and a 345kV transmission line that will connect the switching station to South Boston. As of December 31, 2005, construction that is part of this project is also in progress on the expansion of two existing substations. To date, this project is approximately 60% complete. This transmission line is expected to ensure continued reliability of electric service and improve power import capability in the Northeast Massachusetts area. This project is expected to be placed in service during the summer of 2006. A substantial portion of the cost of this project will be shared by other utilities in New England based on ISO-New England’s approval and will be recovered by NSTAR through wholesale and retail transmission rates. As of December 31, 2005, NSTAR has contractual construction cost commitments of approximately $17 million related to this project.

As part of NSTAR’s Settlement Agreement approved by the MDTE on December 30, 2005, NSTAR Electric has provided the MDTE with a list of potential capital projects that that are designed to improve reliability and safety. The list is limited to incremental capital additions and operations and maintenance expenses related to programs for stray-voltage inspection survey and remediation, double pole inspection, replacement/restoration and transfer and manhole inspection, repair and upgrade. NSTAR Electric has agreed to spend at least $10 million in 2006 on these programs.

86

Report of Independent Registered Public Accounting Firm

To Shareholders and Trustees of NSTAR:

We have completed integrated audits of NSTAR’s December 31, 2005 and December 31, 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)2 present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2005 and December 31, 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

87

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

/s/ PRICEWATERHOUSECOOPERS LLP

Boston, Massachusetts

February 17, 2006

88

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

No event that would be described in response to this item 9 has occurred with respect to NSTAR or its subsidiaries.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rules 13a-15(f). A system of internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Under the supervision and with the participation of management, including the principal executive officer and the principal financial officer, NSTAR management has evaluated the effectiveness of its internal control over financial reporting as of December 31, 2005 based on the criteria established in a report entitled Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, NSTAR management has evaluated and concluded that NSTAR’s internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of NSTAR’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm that audited NSTAR’s consolidated financial statements included herewith in the Form 10-K.

Item 9B. Other Information

None

89

Part III

The information called for by Part III (Items 10(a), 11, 12, and 14) will be included in NSTAR’s 2006 Proxy Statement (as specified below) to be filed in connection with the Annual Meeting of Shareholders to be held on May 4, 2006 and is incorporated herein by reference. Such Proxy Statement will be filed with the Securities and Exchange Commission on or about March 31, 2006.

Item 10. Trustees and Executive Officers of the Registrant

(a) Identification of Trustees

The information required by this Item is incorporated herein by reference to the sections included in the Company’s 2006 Proxy Statement entitled “Information about the NSTAR Board, Nominees and Incumbent Trustees.”

The information required by this Item with regard to NSTAR’s Corporate Governance Guidelines is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Governance of the Company.”

The information required by the Item with regard to compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Section 16(a) Beneficial Ownership Reporting Compliance.”

Audit, Finance and Risk Management Committee Financial Expert

The NSTAR Board of Trustees has made a determination that Mr. Daniel Dennis, CPA, an independent trustee and a member of NSTAR’s Audit, Finance and Risk Management Committee, is an “audit committee financial expert” as that term is defined in the SEC’s regulations.

(b) Identification of Officers

Information required by this item is included in Item 4A of this Form 10-K.

Item 11. Executive Compensation

The information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Executive Compensation.”

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information required by this item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Trustee Compensation,” “Common Share Ownership by Trustees and Executive Officers,” and “Change in Control Agreements.”

Item 13. Certain Relationships and Related Transactions

The information required by this Item is not applicable to NSTAR.

Item 14. Principal Accountant Fees and Services

The information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “2005-2004 Audit and Related Fees.”

With regard to the Audit, Finance and Risk Management Committee’s policy to pre-approve all audit and non-audit services by the Company’s independent public accountants, the information required by this Item is incorporated herein by reference to the section included in the Company’s 2006 Proxy Statement entitled “Audit, Finance and Risk Management Committee Report.”

90

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Form 10-K:

1. Financial Statements:

	Page
Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	49
Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003	50
Consolidated Statements of Retained Earnings for the years ended December 31, 2005, 2004 and 2003	50
Consolidated Balance Sheets as of December 31, 2005 and 2004	51
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	52
Notes to Consolidated Financial Statements	53
Selected Consolidated Quarterly Financial Data (Unaudited)	15
Report of Independent Registered Public Accounting Firm	87
2.      Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and 2003	95
3.      Exhibits:
Refer to the exhibits listing beginning below.

91

Incorporated herein by reference unless designated otherwise:

NSTAR and its subsidiaries

Exhibit 3	Articles of Incorporation and By-Laws
3.1	Declaration of Trust of NSTAR (dated as of April 20, 1999, as amended April 28, 2005)(NSTAR Form 10-Q for the quarter ended June 30, 2005, File No. 1-14768)
3.2	Bylaws of NSTAR (Annex E to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78285))
3.3	Boston Edison Restated Articles of Organization (Form 10-Q for the quarter ended June 30, 1994, File No. 1-2301)
3.4	Boston Edison Company Bylaws dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988, and November 22, 1989 (Form 10-Q for the quarter ended June 30, 1990, File No. 1-2301)
Exhibit 4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)
4.2	Votes of the Board of Trustees of NSTAR, dated January 27, 2000, supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
4.3	Votes of the Board of Trustees of NSTAR, dated September 28, 2000 supplementing the Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N. A. (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
4.4	Boston Edison Company Revolving Credit Agreement dated November 15, 2002 (Boston Edison Form 10-Q for the quarter ended March 31, 2003, File No. 1-2301)
4.5	Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Form 10-Q for the quarter ended September 30, 1988, File No. 1-2301)
4.6	Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 (Form 10-K for the year ended December 31, 1995, File No. 1-2301)
4.7	Votes of the Board of Directors of Boston Edison Company taken October 8, 2002 re $500 million aggregate principal amount of unsecured debentures ($400 million, 4.875% due in 2012 and $100 million, Floating rate due in 2005)(Form 8-K dated October 11, 2002, File No. 1-2301)
	Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of NSTAR and its subsidiaries defining the rights of holders of any long-term debt whose authorization does not exceed 10% of total assets.
Exhibit 10	Material Contracts
10.1	NSTAR Excess Benefit Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.2	NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.3	Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)

92

10.4	Executive Retirement Plan Agreement between NSTAR and Werner J. Schweiger dated as of February 25, 2002, regarding Supplemental Executive Retirement Plan (NSTAR Form 10-K for the year ended December 31, 2004, File No. 1-14768)
10.5	Amended and Restated Change in Control Agreement between NSTAR and Thomas J. May dated October 23, 2003 (NSTAR Form 10-K for the year ended December 31, 2003, File No. 1-14768)
10.6	NSTAR Deferred Compensation Plan (Restated Effective August 25, 1999) (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768)
10.7	NSTAR 1997 Share Incentive Plan, as amended June 30, 1999 and assumed by NSTAR effective August 28, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.7.1	NSTAR 1997 Share Incentive Plan, as amended January 24, 2002 (NSTAR Form 10-K for the year ended December 31, 2002, File No. 1-14768)
10.8	Amended and Restated Change in Control Agreement between James J. Judge and NSTAR, November 1, 2001. (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.9	NSTAR Trustee’s Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.10	Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768)
10.11	Amended and Restated Change in Control Agreement between Douglas S. Horan and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.12	Amended and Restated Change in Control Agreement between Joseph R. Nolan, Jr. and NSTAR dated November 1, 2001 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.13	Amended and Restated Change in Control Agreement between Werner J. Schweiger and NSTAR dated March 1, 2002 (NSTAR Form 10-K for the year ended December 31, 2001, File No. 1-14768)
10.14	Amended and Restated NSTAR Annual Incentive Plan as of January 1, 2003 (NSTAR Form 10-K for the year ended December 31, 2004, File No. 1-14768)
10.15	Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998 (Form 10-K for the year ended December 31, 1999, File No. 1-2301)
10.16	Boston Edison Company Restructuring Settlement Agreement dated July 1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301)
10.17	Agreement and Plan of Merger, as Amended, between BEC Energy and Commonwealth Energy System (Annex A to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78385))
10.18	Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (filed herewith)
10.19	Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (filed herewith)
10.20	Amended and Restated Power Purchase Agreement (CECO 1 PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L.P. (filed herewith)
10.21	Amended and Restated Power Purchase Agreement (CECO 2 PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L.P. (filed herewith)
10.22	The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison and ComElectric and Northeast Energy Associates L.P. (filed herewith)

93

10.23	Purchase and Sale Agreement, dated June 23, 2004, between Boston Edison and Transcanada Energy Ltd. (Ocean State Power Contract) (filed herewith)
10.24	Termination Agreement, dated June 2, 2004, by and between Cambridge Electric and Pittsfield Generating Company, L. P. (f/k/a Altresco Pittsfield, L.P.) (filed herewith)
10.25	Termination Agreement, dated June 2, 2004, by and between ComElectric and Pittsfield Generating company, L. P. (f/k/a Altresco Pittsfield, L.P.)(filed herewith)
	Transmission Agreements
10.2.1	New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for Cambridge Electric, Canal, ComElectric; Boston Edison Company and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association’s Form S-16 (April 1980), File No. 2-64731)
10.2.1.1	Second Restated NEPOOL Agreement among Boston Edison, Cambridge Electric, Canal and ComElectric and various other electric utilities operating in New England, dated August 16, 2004 (filed herewith)
10.2.1.2	Transmission Operating Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric and various other electric transmission providers in New England and ISO New England Inc., dated February 1, 2005 (filed herewith)
10.2.1.3	Market Participants Service Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric, various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005 (filed herewith)
10.2.1.4	Rate Design and Funds Disbursement Agreement among Boston Edison, Cambridge Electric, Canal, ComElectric and various other electric transmission providers in New England, dated February 1, 2005 (filed herewith)
Exhibit 21	Subsidiaries of the Registrant
21.1	(filed herewith)
Exhibit 23	Consent of Independent Accountants
23.1	(filed herewith)
Exhibit 31	Rule 13a - 15/15d-15(e) Certifications (filed herewith)
31.1	Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibit 32	Section 1350 Certifications (filed herewith)
32.1	Certification Statement of Chief Executive Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification Statement of Chief Financial Officer of NSTAR pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99	Additional Exhibits
99.1	Annual Reports on Form 11-K for certain employee savings plans for the years ended December 31, 2004, 2003, 2002, 2001 and 2000, as dated June 28, 2005, June 25, 2004, June 30, 2003, June 28, 2002 and June 29, 2001, respectively, (File No. 1-14768)
99.2	MDTE Order approving Settlement Agreement dated December 31, 2005 (NSTAR Form8-K for the event reported December 30, 2005, dated January 4, 2006, File No. 1-14768).

94

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

(In Thousands)

			Additions
Description	Balance at Beginning of Year		Provisions Charged to Operations		Recoveries		Deductions Accounts Written Off		Balance At End of Year
Allowance for Doubtful Accounts
Year Ended December 31, 2005	$	21,804	$	28,585	$	8,215	$	34,100	$	24,504
Year Ended December 31, 2004	$	23,424	$	24,569	$	7,371	$	33,560	$	21,804
Year Ended December 31, 2003	$	24,379	$	20,509	$	5,949	$	27,413	$	23,424
Tax Valuation Allowance
Year Ended December 31, 2005	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2004	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2003	$	52,897	$	—	$	—	$	52,897	$	—

95

FORM 10-K NSTAR DECEMBER 31, 2005

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		NSTAR
		(Registrant)
Date February 17, 2006	By:	/s/    ROBERT J. WEAFER, JR.
		Robert J. Weafer, Jr.
		Vice President, Controller and
		Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of the 17th day of February 2006.

Signature	Title
/s/    THOMAS J. MAY         Thomas J. May	Chairman, President, Chief Executive Officer and Trustee
/s/    JAMES J. JUDGE         James J. Judge	Senior Vice President, Treasurer and Chief Financial Officer
/s/    G. L. Countryman         Gary L. Countryman	Trustee
/s/    DANIEL DENNIS         Daniel Dennis	Trustee
/s/    THOMAS G. DIGNAN, JR.         Thomas G. Dignan, Jr.	Trustee
/s/    CHARLES K. GIFFORD         Charles K. Gifford	Trustee
/s/    MATINA S. HORNER         Matina S. Horner	Trustee
/s/    PAUL A. LA CAMERA         Paul A. La Camera	Trustee
/s/    SHERRY H. PENNEY         Sherry H. Penney	Trustee
/s/    WILLIAM C. VAN FAASEN         William C. Van Faasen	Trustee
/s/    G. L. WILSON         Gerald L. Wilson	Trustee

96

EX-10.18

EXHIBIT 10.18

AMENDED AND RESTATED POWER PURCHASE AGREEMENT

THIS AMENDED AND RESTATED POWER PURCHASE AGREEMENT (the “Agreement”) is entered into as of August 19, 2004 (the “Agreement Date”), by and between Boston Edison Company, a Massachusetts corporation (“BECO”) and Northeast Energy Associates Limited Partnership, a Massachusetts limited partnership (“NEA”). BECO and NEA are individually referred to herein as a “Party” and are collectively referred to herein as the “Parties”.

WHEREAS, NEA owns a nominal 300 MW natural gas-fired electricity and steam generating plant located in Bellingham, Massachusetts (the “Facility”);

WHEREAS, BECO and NEA are parties to a certain Power Purchase Agreement dated April 1, 1986, as amended to date (the “Existing NEA A PPA”), pursuant to which BECO purchases from NEA a portion of the Facility’s capacity and associated energy;

WHEREAS, BECO and NEA desire to amend and restate the Existing NEA A PPA as provided for herein; and

WHEREAS, such amendment and restatement of the Existing NEA A PPA is consistent with BECO’s invitation, dated October 17, 2003, to submit proposals regarding the transfer of entitlements to certain power purchase agreements and NEA’s response, dated December 3, 2003, related to the restructuring of four (4) power purchase agreements (including the Existing NEA A PPA) existing between NEA and each of BECO and Commonwealth Electric Company (“CECO”) (the four (4) existing agreements, the “Existing Agreements”, are set forth at Exhibit A).

NOW, THEREFORE, in consideration of the premises and of the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1. DEFINITIONS

In addition to terms defined in the recitals hereto, the following terms shall have the meanings set forth below.

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries’ controls, is controlled by, or is under common control with, such first Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall have the meaning set forth in the first paragraph of this Agreement.

“Agreement Date” shall have the meaning set forth in the first paragraph of this Agreement.

“Approved Capacity Buyer” shall mean any of the Persons set forth on Schedule 4.1(c) hereto.

“BECO Reorganization Event” shall mean (a) any consolidation, merger or other form of combination of BECO with any other Person, (b) the acquisition of a majority of the outstanding shares of BECO by any Person or (c) the sale, conveyance, lease, transfer or other disposition, in one transaction or a series of related transactions, including without limitation the transfer or “spin-off” of shares of a subsidiary (collectively, a “Transfer”), affecting all or substantially all of the assets of BECO existing on the Agreement Date or hereafter acquired. For purposes of this definition, the transfer, sale or other disposition of all or substantially all of the transmission and/or distribution assets of BECO, will, in either case, constitute a “BECO Reorganization Event.”

“BECO Termination Payment” shall mean, with respect to this Agreement and NEA, an amount payable by BECO to NEA equal to the sum of the Losses (including, without limitation, the adverse financial impact, if any, of NEA being caused to forego its ability to reduce the Energy Bank balance by performing its obligations under this Agreement, but net of Gains) and Costs, expressed in U.S. Dollars, which NEA incurs as a result of the termination of this Agreement pursuant to Section 8.2(a)(i) hereof. The BECO Termination Payment shall be net of any amounts then owed to BECO in the Energy Bank.

“Business Day” shall mean any day that is not a Saturday, Sunday, or NERC Holiday.

“Capacity” shall mean “Unforced Capacity” as presently defined in the NEPOOL Manual for Definitions and Abbreviations (and, throughout the Term, any successor product thereto).

“Capacity Payment” with respect to any given time period, shall mean the product of (a) the Capacity Price and (b) Capacity Requirement, for such period.

“Capacity Price” with respect to any month, shall mean (a) the Negotiated Capacity Price or (b) in the event that the Parties fail to agree upon a Negotiated Capacity Price on or before the Contract UCAP Transfer Deadline, the price for UCAP for such month established pursuant to the next UCAP Monthly Supply Auction; provided, however, if no price for UCAP is established in the next UCAP Monthly Supply Auction, the price to be used is that established pursuant to the last UCAP Monthly Supply Auction in which UCAP was transacted.

“Capacity Receipt Shortfall” shall have the meaning set forth in Section 3.8(c) hereof.

“Capacity Replacement Damages” shall have the meaning ascribed thereto in Section 3.8(b) herein.

“Capacity Replacement Price” with respect to any portion of the Capacity Requirement that NEA fails to deliver to BECO hereunder, shall mean (a) the price at which BECO, acting in a commercially reasonable manner, purchases Capacity in lieu of such portion of the Capacity Requirement, plus transaction and other administrative costs reasonably incurred by BECO in purchasing such Capacity, or (b) to the extent BECO has not purchased Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

- 2 -

“Capacity Requirement,” shall mean for the applicable month, for so long as NEA is the owner of the Facility during the Term hereof, the lesser of (a) 100 MW or (b) 50% of the Capacity recognized by the ISO as attributable to the Facility. Upon the sale, assignment or transfer by NEA of its interest in the Facility during the Term hereof, Capacity Requirement shall be fixed at the Capacity Requirement in effect on the date immediately prior to such sale, assignment or transfer.

“Capacity Resale Damages” shall have the meaning ascribed thereto in Section 3.8(c) herein.

“Capacity Resale Price” with respect to any portion of the Capacity Requirement that BECO fails to accept delivery from NEA hereunder, shall mean (a) the price at which NEA, acting in a commercially reasonable manner, re-sells Capacity in lieu of such portion of the Capacity Requirement, less transaction and other administrative costs reasonably incurred by NEA in selling such Capacity or (b) to the extent NEA has not sold Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Supply Shortfall” shall have the meaning set forth in Section 3.8(b) hereof.

“Change in Law or Market Structure” shall mean any of the following events that has a material adverse economic effect on one or both of the Parties: (a) the adoption, promulgation, modification, repeal or reinterpretation by any Governmental Entity of any Law which (or the effects of which) amends or conflicts with the Laws established or in effect as of the Agreement Date, (b) the adoption, promulgation, modification, repeal or reinterpretation by ISO of the ISO Policies which (or the effect of which) amends or conflicts with the ISO Policies established or in effect as of the Agreement Date or (c) the adoption or promulgation of a market structure that differs from the market structure reflected in the ISO Policies established or in effect as of the Agreement Date. For avoidance of doubt, a Change in Law or Market Structure shall include any event described in clauses (a), (b) or (c) above that results in BECO not being able to sell the Contract Energy purchased hereunder at a price greater than or equal to the Energy Payment prices (excluding the Support Payment) paid to NEA hereunder.

“Claiming Party” shall have the meaning set forth in Section 9.2(b) hereof.

“Contract Energy” shall have the meaning set forth in Section 3.1 hereof.

“Contract UCAP Transfer Deadline” with respect to any month, shall mean 5 PM Eastern Prevailing Time on the Business Day preceding the day by which final bids into the NEPOOL ISO Supply Auction must be submitted to be considered timely under the NEPOOL Practices and Market Rules and Procedures governing suppliers’ participation in the UCAP Monthly Supply Auction.

“Costs” shall mean brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred in terminating this Agreement; and all reasonable attorneys’ fees and expenses incurred in connection with the termination of this Agreement.

“Cover Damages” shall have the meaning set forth in Section 3.6 hereof.

“Credit Support” shall have the meaning set forth in Section 8.2(a)(i)(B) hereof.

- 3 -

“Day-Ahead Energy Market” or “DAM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Delivery Point” shall mean the Facility Bus; provided, however, that (a) if a LMP is not established for a node at the Facility Bus, or during periods of Force Majeure, NEA may deliver Contract Energy to an alternate node within the ISO control area that has a published LMP price and (b) NEA may deliver to any other delivery point mutually agreed to by the Parties.

“Delivery Shortfall” shall have the meaning set forth in Section 3.6 hereof.

“DTE” shall mean the Massachusetts Department of Telecommunications and Energy or its successor state regulatory agency.

“Eastern Prevailing Time” shall mean either Eastern Standard Time or Eastern Daylight Savings Time, as in effect from time to time.

“Effective Date” shall have the meaning set forth in Section 2.1 hereof.

“Energy Bank” shall mean that certain account described in Article 9A of the Existing NEA PPA.

“Energy Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Event of Default” shall have the meaning set forth in Section 8.1 hereof.

“Existing Agreements” shall have the meaning set forth in the Recitals.

“Execution Agreement” shall mean the Execution Agreement by and among NEA, Commonwealth Electric Company and BECO dated as of August 19, 2004.

“Existing NEA A PPA” shall have the meaning set forth in the Recitals.

“Facility” shall have the meaning set forth in the Recitals.

“Facility Bus” shall mean the point of interconnection between the Facility and the NEPOOL transmission system, which as of the Agreement Date is the UN.Bellinghm 13.2 NEA bus.

“FERC” shall mean the United States Federal Energy Regulatory Commission, and shall include its successors.

“Force Majeure” shall have the meaning set forth in Section 9.1(a) hereof.

- 4 -

“Gains” shall mean an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic benefit, if any (exclusive of Costs) resulting from the termination of this Agreement, determined in a commercially reasonable manner.

“Governmental Entity” shall mean any federal, state or local governmental agency, authority, department, instrumentality or regulatory body, and any court or tribunal, with jurisdiction over NEA, BECO or the Facility.

“IBT Containers” shall have the meaning as set forth in Section 3.3(a) hereof.

“Indemnified Party” shall have the meaning set forth in Section 12.1 hereof.

“Indemnifying Party” shall have the meaning set forth in Section 12.1 hereof.

“Internal Bilateral Transaction” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO” or ISO-NE” shall mean the ISO New England, Inc., the independent system operator established in accordance with the NEPOOL Agreement, or its successor.

“ISO Policies” shall mean the Market Rules and Procedures, NEPOOL Agreement, NEPOOL Manual for Definitions and Abbreviations and NEPOOL Practices.

“ISO Settlement Market System” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO UCAP Transfer Deadline” with respect to any month, shall mean the latest date upon which Capacity for that month may be transferred under an Internal Bilateral Transaction in accordance with ISO rules.

“Late Payment Rate” shall have the meaning set forth in Section 4.3 hereof.

“Law” shall mean all federal, state and local statutes, regulations, rules, orders, executive orders, decrees, policies, judicial decisions and notifications.

“Lead Participant” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“LMP” shall mean, for any ISO nodal point for any hour on any day, the “Day Ahead LMP” or “Real Time LMP” ($/MWh) at such ISO nodal point calculated in accordance with Section 2 of Market Rule 1, as reported on the ISO website at www.iso-ne.com on the “Data & Reports” page, “Hourly Markets Data” subpage and “Selectable Hourly LMP Data” category, for such nodal point on such date and time. If such price should ever cease to be published, then the LMP shall be a regularly published comparable substitute price, as agreed to by the Parties in writing.

“Losses” shall mean, with respect to any Party, an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic loss to it, if any (exclusive of Costs), resulting from termination of this Agreement, determined in a commercially reasonable manner.

- 5 -

“Market Rules and Procedures” shall mean the Market Rules, Manuals and Procedures adopted by the ISO and/or members of NEPOOL, as may be amended from time to time, and as administered by the ISO to govern the operation of the NEPOOL markets, and any applicable successor rules, manuals and procedures.

“Moody’s” shall mean Moody’s Investors Service, Inc., and any successor thereto.

“MW” shall mean a megawatt.

“MWh” shall mean a megawatt-hour (one MWh shall equal 1,000 kWh).

“NEA Termination Payment” shall mean, with respect to this Agreement and BECO, an amount payable by NEA to BECO equal to the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which BECO incurs as a result of the termination of this Agreement pursuant to Section 8.2 (a)(ii) hereof plus the balance then due BECO under the Energy Bank.

“Negotiated Capacity Price” shall mean the price for Capacity as agreed to by the Parties pursuant to Section 4.1(b) herein.

“NEPOOL” shall mean the New England Power Pool, or its successor.

“NEPOOL Agreement” shall mean that certain Restated New England Power Pool Agreement, as restated by an amendment dated as of December 1, 1996, as amended and restated from time to time, and any applicable successor agreement.

“NEPOOL ISO Supply Auction” shall mean the auction currently defined as the “Supply Auction” in the Market Rules and Procedures, or any successor to such auction.

“NEPOOL Manual for Definitions and Abbreviations” shall mean that certain Manual for Definitions and Abbreviations prepared by ISO-NE, as may be amended from time to time, and any applicable successor manual.

“NEPOOL Practices” shall mean the NEPOOL practices and procedures for delivery and transmission of electricity and capacity and capacity testing in effect from time to time and shall include, without limitation, applicable requirements of the NEPOOL Agreement, and any applicable successor practices and procedures.

“NERC Holiday” shall mean New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day, and any other day declared a holiday by NERC.

“Ownership Share” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

- 6 -

“Party” and “Parties” shall have the meaning set forth in the first paragraph of this Agreement.

“Performance Assurance” shall mean collateral in the form of either cash, letter(s) of credit, or other security acceptable to the requesting Party.

“Person” shall mean an individual, partnership, corporation, limited liability company, limited liability partnership, limited partnership, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof.

“PURPA” shall mean the Public Utility Regulatory Policies Act of 1978, as amended.

“QF” shall have the meaning set forth in Section 6.3(a)(i) hereof.

“Quote Period” shall have the meaning set forth in Section 4.1(b) herein.

“Real-Time Energy Market” or “RTM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Rejected Power” shall have the meaning set forth in Section 3.7 hereof.

“Replacement Power” shall mean electricity purchased by BECO and delivered to the Delivery Point as replacement for any Delivery Shortfall. Replacement Power shall not include Contract Energy delivered to BECO on behalf of NEA pursuant to Section 3.1 hereof.

“Replacement Price” shall mean the lesser of (a) the price at which BECO, acting in a commercially reasonable manner, purchases Replacement Power, plus (i) transaction and other administrative costs reasonably incurred by BECO in purchasing such Replacement Power and (ii) additional transmission charges, if any, reasonably incurred by BECO to transmit Replacement Power to the Delivery Point, or (b) the locational marginal pricing at the Delivery Point for such Replacement Power; provided, however, that in no event shall the Replacement Price include any penalties, ratcheted demand or similar charges, nor shall BECO be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize NEA’s liability.

“Resale Damages” shall have the meaning set forth in Section 3.7 hereof.

“Resale Price” shall mean the higher of (a) the price at which NEA, acting in a commercially reasonable manner, sells or is paid for Rejected Power, plus transaction and other administrative costs reasonably incurred by NEA in re-selling such Rejected Power; or (b) the LMP at the Delivery Point for such Rejected Power; provided, however, that in no event shall such price include any penalties, ratcheted demand or similar charges, and further provided that in no event shall NEA be required to utilize or change its utilization of the Facility or its other assets or market positions in order to minimize BECO’s liability for Rejected Power.

“Schedule or Scheduling” shall mean the actions of NEA or BECO and/or their designated representatives, including each Party’s Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity of Contract Energy to be delivered on any given day or days (or in any given hour or hours) during the Term at the Delivery Point.

- 7 -

“S&P” shall mean Standard & Poor’s Ratings Group, a division of McGraw Hill, Inc., and any successor thereto.

“Support Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Term” shall have the meaning set forth in Section 2.2 hereof.

“Third-Party Quote” with respect to any Capacity Requirement, shall mean a firm offer by an Approved Capacity Buyer to purchase Capacity from BECO in a volume and for a time period equal to such Capacity Requirement.

“Transmission Provider” shall mean (a) ISO, its respective successor or Affiliates; (b) NEPOOL; (c) BECO; or (d) such other third parties from whom transmission services are necessary for NEA to fulfill its performance obligations to BECO hereunder.

“UCAP” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“UCAP Monthly Supply Auction” shall mean the auction currently defined as the “UCAP Monthly Auction” in the NEPOOL Manual for Definitions and Abbreviations, or any successor to such auction that establishes a price for UCAP or its successor product.

2. EFFECTIVE DATE; CONDITIONS; TERM

2.1 Effective Date. The “Effective Date” of this Agreement shall be the Closing Date as established under the Execution Agreement.

2.2 Term.

(a) The “Term” of this Agreement shall mean the period from and including 11:59 p.m. (Eastern Prevailing Time) on the Effective Date through and including 11:59 p.m. (Eastern Prevailing Time) on September 15, 2016, unless this Agreement is sooner terminated in accordance with the provisions hereof.

(b) At the expiration of the Term, the Parties shall no longer be bound by the terms and provisions hereof (including, without limitation, any payment obligation hereunder), except (i) to the extent necessary to provide invoices and make payments or refunds with respect to Contract Energy or Capacity delivered prior to such expiration or termination, (ii) to the extent necessary to enforce the rights and the obligations of the Parties arising under this Agreement before such expiration or termination and (iii) the obligations of the Parties hereunder with respect to confidentiality and indemnification shall survive the expiration or termination of this Agreement and shall continue for a period of two (2) calendar years following such expiration or termination.

- 8 -

3. DELIVERY OF CONTRACT ENERGY AND CAPACITY

3.1 Obligation to Sell and Purchase Contract Energy. During each hour of the Term, NEA shall sell and deliver at the Delivery Point, and BECO shall purchase and receive at the Delivery Point, electricity in the amounts set forth in Section 3.3 and otherwise in accordance with the terms and conditions of this Agreement (“Contract Energy”). NEA shall be permitted to satisfy its obligation to deliver Contract Energy from any source of supply available to NEA. Contract Energy delivered to BECO by NEA or on behalf of NEA by NEA’s suppliers, designees or any other Person engaged by NEA to deliver Contract Energy shall be deemed delivered by NEA hereunder and NEA shall be solely responsible for any costs payable to its suppliers for such delivery. The aforementioned obligations for NEA to sell and deliver the Energy and for BECO to purchase and receive the Energy shall be firm and subject to adjustment only to reflect performance interruptions excused by this Agreement.

3.2 Characteristics. Contract Energy delivered by NEA to BECO at the Delivery Point shall be in the form of three (3)-phase, sixty (60) hertz, alternating current and otherwise in the form required by Market Rules and Procedures.

3.3 Scheduling.

(a) NEA shall Schedule deliveries of Contract Energy delivered hereunder with ISO in equal hourly quantities in accordance with all NEPOOL Practices and Market Rules and Procedures applicable thereto as set forth in Schedule 3.3. Furthermore, Contract Energy will be sold and delivered for purchase by BECO in the form of Internal Bilateral Transactions (“IBTs”) and NEA will use commercially reasonable efforts to transfer Contract Energy in the DAM; provided, however, that if such transfer cannot be made in the DAM, the Contract Energy shall be transferred in the RTM. All Contract Energy will be delivered to a specific node and not a zone. NEA will submit IBT Containers, as defined below, and notify BECO that the IBT Containers have been submitted into the ISO Settlement Market System.

Subject to the satisfaction of NEA’s obligations in this Section 3.3, BECO will confirm the IBT Container in the ISO Settlement Market System. For purposes of this Agreement, “IBT Container” shall mean the form of electronic contract submittal, as implemented in the ISO Settlement Market System effective March 1, 2003 as amended from time to time, that requires BECO to confirm the general parameters of the IBT. IBTs shall be submitted and confirmed for the longest term permitted by the ISO. NEA shall be responsible for any inaccuracies in any schedules and shall correct such schedules upon notification by BECO; provided, however, BECO shall cooperate with NEA in connection with any such Scheduling and bidding and in complying with all NEPOOL Practices and shall promptly provide information reasonably requested by NEA for the purpose of assisting NEA with its Scheduling obligations hereunder. Notwithstanding the agreement to Schedule all Contract Energy in the DAM, the Energy Payment made by BECO to NEA shall be as calculated pursuant to Section 4.1(a) hereof.

(b) The Parties agree to use commercially reasonable efforts to comply with all applicable ISO Policies in connection with the Scheduling and delivery of Contract Energy hereunder. For administrative convenience, the Parties agree that all Contract Energy deliveries and receipts made pursuant to this Agreement and any other power purchase agreement between the Parties may be provided for in a single Schedule. Penalties or similar charges assessed by a Transmission Provider and caused by a Party’s noncompliance with the Scheduling obligations set forth in this Section 3.3 shall be the responsibility of the Party whose action or inaction caused the penalty.

- 9 -

3.4 Lead Participant: Ownership Share. NEA, or any entity so identified by NEA, shall be the Lead Participant of the Facility and BECO shall use commercially reasonable efforts to transfer such designation to NEA or the entity so identified by NEA. BECO shall use commercially reasonable efforts to transfer to NEA, or any entity so identified by NEA, the Ownership Share now held by BECO relating to the Facility.

3.5 Sales for Resale. All Contract Energy delivered by NEA to BECO hereunder shall be sales for resale, with BECO reselling such Contract Energy. BECO shall provide NEA with any certificates reasonably requested by NEA to evidence that the deliveries of Contract Energy hereunder are sales for resale. Nothing in this Agreement shall be construed to prohibit or restrict such resale by BECO.

3.6 Failure of NEA to Deliver Scheduled Contract Energy: Cover Damages.

Subject to Section 8.1(g) hereof, in the event NEA fails to deliver Contract Energy it is obligated to deliver hereunder and such failure is not excused under the terms of this Agreement (such undelivered Contract Energy to be referred to herein as the “Delivery Shortfall”), then NEA shall pay BECO, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Delivery Shortfall equal to the Cover Damages. “Cover Damages” means an amount equal to (i) the amount, if any, by which (A) the Replacement Price ($/MWh) multiplied by the quantity (in MWh) of the Delivery Shortfall, exceeds (B) the Energy Payment that would have been paid pursuant to Section 4.1 hereof had the Delivery Shortfall been delivered, plus (ii) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against BECO as a direct result of NEA’s failure to deliver such Contract Energy; provided, however, BECO shall use commercially reasonable efforts to purchase replacement power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(g) and 8.2 hereof, the damages provided in this Section 3.6 shall be the sole and exclusive remedy of BECO for any failure of NEA to deliver Contract Energy that it is obligated to deliver hereunder. The invoice for the amount payable pursuant to this Section 3.6 shall include a written statement explaining in reasonable detail the calculation of such amount.

3.7 Failure by BECO to Accept Delivery of Contract Energy; Resale Damages. If BECO fails to accept all or part of the Contract Energy it is obligated to accept hereunder and such failure to accept is not excused under the terms of this Agreement (such Contract Energy is referred to herein as “Rejected Power”), then BECO shall pay NEA, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Rejected Power equal to the Resale Damages. “Resale Damages” means an amount equal to (a) the amount, if any, by which (i) the Energy Payment that would have been paid pursuant to Section 4.1 (a) hereof for such Rejected Power, had it been accepted, exceeds (ii) the Resale Price ($/MWh) multiplied by the quantity (in MWh) of Rejected Power resold by NEA, plus (b) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of BECO’s failure to accept such Contract Energy; provided, however, NEA shall use commercially reasonable efforts to sell such Rejected Power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(h) and 8.2 hereof, the damages provided in this Section 3.7 shall be the sole and exclusive remedy of NEA for any failure of BECO to accept delivery of Contract Energy that it is obligated to accept hereunder. The invoice for the amount payable pursuant to this Section 3.7 shall include a written statement explaining in reasonable detail the calculation of such amount.

- 10 -

3.8 Obligation to Sell and Purchase Capacity Requirements.

(a) During the Term, NEA shall sell to BECO and BECO shall purchase from NEA the Capacity Requirement. In the event there is no longer a market for Capacity in New England, NEA shall not be obligated to sell and BECO shall not be obligated to purchase the Capacity Requirement.

(i) For so long as NEA is the owner of the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement only from the Facility. In the event that NEA sells, assigns or transfers its interests in the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement from any source of supply available to NEA. Nothing in this Agreement shall be construed to restrict or bar NEA from any sale, assignment or transfer of its interests in the Facility.

(ii) The Parties acknowledge that as of the Agreement Date, the Market Rules and Procedures do not impose any locational requirement with respect to Capacity. In the event that, at any time during the Term, the Market Rules and Procedures do impose a zonal, nodal or other geographic locational requirement, the Capacity Requirement will be fulfilled for the zone, node or other geographic area in which the Facility is located.

(b) If NEA fails to provide BECO with all or part of the Capacity Requirement it is required to provide pursuant to Section 3.8(a) hereof (a “Capacity Supply Shortfall”) and such failure is not excused under the terms of this Agreement, then the Capacity Replacement Damages associated with such Capacity Supply Shortfall shall be deducted from amounts payable by BECO hereunder for the next succeeding month or paid by NEA to BECO, at BECO’s election. “Capacity Replacement Damages,” with respect to any portion of the Capacity Requirement that NEA fails to deliver to BECO hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Replacement Price exceeds the Capacity Price, multiplied by the Capacity Supply Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against BECO as a direct result of NEA’s failure to deliver the Capacity Requirement in accordance with Section 3.8(a) hereof. Subject to Section 8.1(g) hereof, the damages provided in this Section 3.8(b) shall be the sole and exclusive remedy of BECO for any failure of NEA to deliver the Capacity Requirement hereunder. With respect to any calendar month during the Term, NEA will be deemed to have failed to deliver the Capacity Requirement for such calendar month if it has not scheduled a bilateral transfer of the Capacity Requirement (or otherwise effected delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

(c) If BECO fails to accept delivery of all or part of the Capacity Requirement it is required to purchase pursuant to Section 3.8(a) hereof (a “Capacity Receipt Shortfall”), and such failure is not excused under the terms of this Agreement, then the Capacity Resale Damages associated with such Capacity Receipt Shortfall shall be payable by BECO on the date payment would otherwise be due in respect of the month in which the failure occurred. “Capacity Resale Damages,” with respect to any portion of the Capacity Requirement that BECO fails to accept delivery of from NEA hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Price exceeds the Capacity Resale Price, multiplied by the Capacity Receipt Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of BECO’s failure to accept delivery of the Capacity Requirement

- 11 -

in accordance with Section 3.8(a) hereof. Subject to Section 8.1(h) hereof, the damages provided in this Section 3.8(c) shall be the sole and exclusive remedy of NEA for any failure of BECO to accept delivery of the Capacity Requirement hereunder and there shall be no adjustment of the Energy Payment or Support Payment as a result of BECO’s failure to accept delivery of such Capacity Requirement. With respect to any calendar month during the Term, BECO will be deemed to have failed to accept delivery of the Capacity Requirement for such calendar month if it has not confirmed a schedule (or an equivalent commitment instrument) entered by NEA for bilateral transfer of the Capacity Requirement (or otherwise effected acceptance of delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

3.9 Delivery Point.

(a) All Contract Energy shall be delivered hereunder by NEA to BECO at the Delivery Point.

(b) Except as provided for in Section 3.3(b) herein, NEA shall be responsible for all transmission and distribution charges, including applicable ancillary service charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission incurred, in each case, in connection with the delivery of Contract Energy to the Delivery Point.

(c) Except as provided for in Section 3.3(b) herein, BECO shall be responsible for all transmission charges, ancillary services charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission, incurred, in each case, in connection with the transmission of Contract Energy delivered under this Agreement from and after the Delivery Point.

4. PAYMENTS FOR CONTRACT ENERGY AND CAPACITY REQUIREMENTS

4.1 Payment for Contract Energy and Capacity Requirements.

(a) All Contract Energy delivered to BECO under this Agreement shall be purchased by BECO for an amount calculated pursuant to this Section 4.1(a).

(i) Beginning on the Effective Date and continuing for the Term, BECO shall pay NEA a monthly energy payment (the “Energy Payment”) equal to the sum of: (A) the product of (I) the Contract Energy (in MWhs) delivered to BECO hereunder during each hour during such month that cleared in the DAM and (II) the hourly DAM LMP Price for such hour at the Delivery Point for MWhs that cleared in the DAM for such month, plus (B) the product of (I) the Contract Energy (in MWhs) delivered to BECO hereunder during each hour during such month that cleared in the RTM and (II) the hourly RTM LMP Price for such hour at the Delivery Point for MWhs that cleared in the RTM for such month, plus (C) a support payment (the “Support Payment”) equal to the product of (I) the lesser of: the total Contract Energy (in MWhs) delivered to BECO hereunder during such month or the MWh quantity for the applicable month, as set forth in Schedule 4.1 (a), and (II) the $/MWh price (the “Monthly Support Payment Price”) for the applicable month, as set forth in Schedule 4.1 (a). Notwithstanding anything in this Agreement to the contrary, no exercise by NEA of its right under Section 8.2 to reduce Contract Energy delivered to BECO as a result of BECO’s failure to timely pay for such Contract Energy shall have the effect of reducing the Support Payment as calculated pursuant to this Section.

- 12 -

(ii) BECO’s sole payment obligation, including without limitation any Support Payment obligation, with respect to Contract Energy is limited to the payment of the Energy Payment for Contract Energy delivered in accordance with the terms of this Agreement by or on behalf of NEA to the Delivery Point.

(b) All Capacity delivered to BECO under this Agreement shall be purchased by BECO at the Capacity Price. BECO’s sole payment obligation with respect to Capacity is limited to the payment of the Capacity Payment for the Capacity Requirement actually provided to BECO in accordance with the terms of this Agreement by or on behalf of NEA. The Parties will negotiate in good faith and in a commercially reasonable manner towards agreement upon a negotiated price for Capacity (the “Negotiated Capacity Price”) for each month of the Term in accordance with the terms and provisions of this Section 4.1(b). At any time during the Term, NEA may request BECO to provide it with an indicative quote for the Capacity Requirement for one month or any period of months (the “Quote Period”) as set forth in such request. Within six (6) Business Days after BECO’s receipt of such request, BECO will provide NEA with an indicative quote for a purchase price of such Capacity Requirement for the Quote Period which BECO in its commercially reasonable judgment believes reflects the fair market value for such Capacity Requirement. Within one Business Day after its receipt of such indicative quote, NEA will inform BECO as to whether NEA accepts or rejects the indicative quote.

(i) In the event that NEA accepts the indicative quote, the pricing reflected in such indicative quote will be established as the Negotiated Capacity Price for such Capacity Requirement unless BECO notifies NEA, within one Business Day after NEA’s acceptance, that BECO retracts the indicative quote. BECO may retract the indicative quote only in the event that BECO, in its commercially reasonable judgment, believes that the fair market value of the Capacity Requirement has materially declined since BECO delivered the indicative quote to NEA. In the event that BECO retracts the indicative quote, NEA may, at its election, (A) provide Third-Party Quotes to BECO for the applicable Capacity Requirement, provided that NEA does so within two (2) Business Days after BECO’s retraction of the indicative quote (and, in which event, the procedures set forth in Section 4.1(b)(ii) will be followed to determine the Negotiated Capacity Price), or (B) request a new indicative quote from BECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(ii) In the event that NEA rejects such indicative quote, NEA may, at its election, provide one or more Third-Party Quotes to BECO for the Capacity Requirement, provided that NEA does so within two (2) Business Days after NEA’s rejection of the indicative quote. In the event that NEA so delivers one or more Third-Party Quotes to BECO, BECO will, within one Business Day after delivery of the Third-Party Quotes, either (A) agree to establish any one of the Third-Party Quotes as the Negotiated Capacity Price or (B) sell Capacity (in an amount equal to the Capacity Requirement and for the Quote Period) to any of the Approved Capacity Buyers cited in the Third-Party Quotes at a different price, in which case such different price will be established as the Negotiated Capacity Price. Notwithstanding the foregoing, if, by the close of business on the Business Day immediately following NEA’s delivery of Third-Party Quotes, BECO, after making commercially reasonable efforts, is able to neither consummate a transaction as described in clause (B) of the immediately preceding sentence, nor confirm to its reasonable satisfaction the validity and firmness of at least one of the Third Party Quotes, then no Negotiated Capacity Price will be deemed to have been established for the applicable Capacity Requirement. In such event (or in the event that NEA does not deliver any Third-Party Quotes to BECO within two (2) Business Days after

- 13 -

its rejection of the indicative quote), NEA may request a new indicative quote from BECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(c) If, despite their good faith efforts, the Parties are not able to agree upon a Negotiated Capacity price prior to the Contract UCAP Transfer Deadline then the Capacity Requirement shall be purchased by BECO from NEA on a bilateral basis and the Capacity Price paid by BECO to NEA shall be the settlement price set at the UCAP Monthly Supply Auction.

4.2 Payment and Netting.

(a) Billing Period. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments). On or before the third (3^rd) day following the end of each month, NEA will render to BECO an invoice for the Energy Payment and Capacity Payment obligations incurred hereunder during the preceding month.

(b) Timeliness of Payment. BECO shall use its reasonable efforts to pay all NEA invoices under this Agreement on the fifteenth (15th) day after receipt of the invoice; provided, however, unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with each Party’s invoice instructions on or before the later of thirty (30) days following the receipt of such invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Late Payment Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

(c) Disputes and Adjustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Late Payment Rate from and including the due date but excluding the date paid. Inadvertent overpayments shall be reimbursed or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Late Payment Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment, as directed by the other party. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 4.2 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance is waived.

- 14 -

(d) Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other under this Agreement on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Contract Energy during the monthly billing period under this Agreement, including any related damages calculated pursuant to this Agreement, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, such Party shall pay such sum in full when due. The Parties agree to provide each other with reasonable detail of such net payment or net payment request.

4.3 Interest on Late Payment. If a payment is not received when due under this Agreement, the delinquent Party shall pay to the other Party interest on such unpaid amount which shall accrue from the due date until the date upon which payment in full is made at the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published) (the “Late Payment Rate”).

5. ENERGY BANK

The Parties acknowledge that in order to enhance the economic viability of the Facility, the Existing NEA A PPA provided an Energy Bank for the purpose of tracking the difference between the Floor Price Amount paid by BECO to NEA and an Energy Bank Amount calculated each month by BECO (as such terms are defined in the Existing NEA A PPA). A positive balance in the Energy Bank represented a debt owed by NEA to BECO. The Energy Bank also provided a methodology whereby positive balances will be reduced and the Energy Bank would be paid off over time and eliminated. It is hereby agreed by the Parties that the provisions in the Existing NEA A PPA related to the Energy Bank, including, without limitation, Articles 9A and 9B (such Articles 9A and 9B are reproduced and attached hereto as Schedule 5(a)) be incorporated herein by reference; provided, the Parties agree that the amortization schedule attached hereto at Schedule 5(b) reflects accurately the current Energy Bank balance and the monthly amount by which such balance is being reduced. Such amortization schedule shall be adjusted to reflect the Energy Bank balance as of the Effective Date to reflect deliveries under the Existing NEA A PPA for the period from the Agreement Date through and including the Effective Date.

6. REPRESENTATIONS, WARRANTIES, COVENANTS AND ACKNOWLEDGEMENTS

6.1 Representations and Warranties of BECO. BECO hereby represents and warrants to NEA as of the Effective Date as follows:

(a) Organization and Good Standing: Power and Authority. BECO is a corporation duly incorporated, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. BECO has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery by BECO of this Agreement, and the performance by BECO of its obligations hereunder, have been duly authorized by all

- 15 -

necessary actions on the part of BECO and do not and, under existing facts and law, will not: (i) contravene its restated certificate of incorporation or any other governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of BECO and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of BECO, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting BECO or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which BECO reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) BECO’s ability to perform its obligations under this Agreement.

(e) Consents and Approvals. The execution, delivery and performance by BECO of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of BECO.

6.2 Representations and Warranties of NEA. NEA hereby represents and warrants to BECO as of the Effective Date as follows:

(a) Organization and Good Standing: Power and Authority. NEA is a limited partnership, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. NEA has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery by NEA of this Agreement, and the performance by NEA of its obligations hereunder, have been duly authorized by all necessary actions on the part of NEA and do not and, under existing facts and law, will not: (i) contravene any of its governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory

- 16 -

approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of NEA and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of NEA, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting NEA or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which NEA reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) NEA’s ability to perform its obligations under this Agreement.

(e) Consents and Approvals. The execution, delivery and performance by NEA of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non- appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of NEA.

(g) Other Agreements. NEA has not entered into any (i) agreements for the sale of energy or capacity other than (A) the Existing Agreements and (B) that certain Power Purchase Agreement between NEA and Montaup Electric Company dated October 17, 1986 (the “Montaup PPA”), and (ii) amendment or modification of the Montaup PPA other than as set forth in Schedule 6.2(g).

6.3 PURPA Acknowledgements.

(a) The Parties acknowledge and agree that:

(i) Under the Existing NEA A PPA, NEA was entitled to all rights afforded to a “qualifying facility” (as defined in 18 C.F.R. Part 292) (“QF”) under applicable law, including, but not limited to, PURPA, for as long as the Facility maintained its status as a QF, and

(ii) The consideration for NEA’s agreement to amend and restate the Existing NEA A PPA and to waive its rights under PURPA, as provided in Section 6.3(c) below, is the execution and delivery of this Agreement by BECO.

(b) It is the express intent of the Parties that this Agreement shall be deemed a successor to, replacement of and substitute for the Existing NEA A PPA, which is being amended and restated in its entirety as of the Effective Date.

- 17 -

(c) As of the Effective Date, NEA forever relinquishes and waives any rights it may have or may have in the future under PURPA or any federal or state regulation, act or order implementing PURPA, to require BECO or any of its affiliates to purchase electricity and or capacity generated at the Facility. NEA shall cause any third party successor to NEA’s rights and interest in the Facility to agree to be bound by the foregoing waiver. NEA shall indemnify, defend and hold BECO and its partners, shareholders, members, directors, officers, employees and agents harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever suffered or incurred by BECO arising out of any failure by NEA to comply with the waiver of PURPA rights set forth in this Section 6.3(c).

(d) As of the Effective Date and continuing throughout the Term, each Party hereby irrevocably waives its right to seek or support, and agrees not to seek or support, in any way, including, but not limited to, seeking or supporting through application, complaint, petition, motion, filing before any Governmental Entity (including, without limitation, DTE and FERC), rule, regulation or statute: (i) reconsideration by DTE of its approval of this Agreement; (ii) modification or invalidation of this Agreement or any term or condition contained herein (including, without limitation, any pricing provision herein); or (iii) disallowance or impairment, in whole or in part, of BECO’s right to fully and timely recover from its customers its costs of purchasing electricity and capacity pursuant to this Agreement.

(e) Nothing contained herein shall be deemed or construed as (i) a waiver by either Party of any right to challenge any attempt by DTE, FERC or any other Governmental Entity to disallow rate recovery or modify, amend or supplement this Agreement or (ii) an acknowledgment by any such Party that DTE, FERC or any other Governmental Entity would have such authority if it so attempted.

(f) As of the Effective Date, NEA’s and BECO’s obligations under this Agreement are expressly not conditioned on the maintenance of the QF status of the Facility under PURPA, and this Agreement shall remain binding upon the Parties without regard to whether the Facility or any other source of power delivered to BECO under this Agreement is, was or remains a QF. Each Party shall obtain and maintain all permits or licenses necessary for it to perform its obligations under this Agreement.

(g) The Parties acknowledge and agree that, to the extent this Agreement is or becomes subject to review pursuant to the Federal Power Act, the standard of review for any change or modification to the pricing provisions of this Agreement proposed by any Person who is not a party hereto or FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “Mobile-Sierra” doctrine).

6.4 Release. The Parties agree to each release the other of all obligations, liabilities and costs arising under the Existing NEA A PPA as of the Effective Date, and to further release each other regarding potential claims against one another and related to differing interpretations of the Existing NEA A PPA (the “PPA and Related Potential Claims”). Such claims include, without limitation, the obligations to deliver, sell, receive and purchase energy and capacity under the Existing NEA A PPA, and disputes related to: (a) the payment for Capacity and Associated Energy (as such terms are defined in the Existing NEA A PPA) delivered by NEA and received by BECO in excess of the Company’s Entitlement (as such term is defined in the Existing NEA A PPA); (b) the application of Article 21, Other Terms to Third Parties, as set forth in the Existing NEA A PPA; (c) the allocation of certain congestion charges/credits imposed by the ISO; and

- 18 -

(d) the calculation of the Qualifying Facility Power Purchase Rate (as such term is defined in the Existing NEA A PPA). The Parties agree that it is in their mutual best interests to waive such PPA and Related Potential Claims and to release each other from liability thereunder. Therefore, as of the Effective Date, the Parties, intending to be legally bound on behalf of themselves and their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives ABSOLUTELY, IRREVOCABLY, AND UNCONDITIONALLY, FULLY AND FOREVER ACQUIT, RELEASE, AND DISCHARGE AND COVENANT NOT TO SUE each other and any and all of their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives, from any and all claims, causes of action, demands, obligations, charges, complaints, controversies, damages, liabilities, costs, expenses, judgments, guarantees, agreements, or defaults of every and any nature, relating to or arising out of the PPA and Related Potential Claims, whether in law or equity and whether arising in contract (including breach), tort or otherwise, and irrespective of fault, negligence or strict liability, which a Party may have had, or may now have, prior to the Effective Date.

7. RESERVED

8. BREACHES; REMEDIES

8.1 Events of Default; Cure Rights. It shall constitute an event of default (“Event of Default”) hereunder if:

(a) Representation or Warranty. Any representation or warranty set forth herein is not accurate and complete in all material respects as of the date made, unless such inaccuracy or incompleteness is capable of cure by the payment of money and is cured within thirty (30) days after written notice thereof is given by the non-defaulting Party to the defaulting Party, or unless such inaccuracy or incompleteness is not capable of cure by the payment of money, but is otherwise capable of cure, and the Party in default promptly begins and diligently and continuously pursues such cure activity.

(b) Payment Obligations. Any undisputed payment due and payable hereunder is not made on the date due, and such failure continues for more than five (5) Business Days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(c) Other Covenants. Subject to Sections 3.6, 3.7, 3.8, 8.1(g) and 8.1(h) hereof, a Party fails to perform, observe or otherwise to comply with any obligation hereunder and such failure continues for more than thirty (30) days after notice thereof is given by the non-defaulting Party to the defaulting Party, or if such default is not capable of cure within thirty (30) days, the Party in default promptly begins such cure activity within such thirty (30) day period and diligently and continuously pursues the cure activity such that the failure is cured within ninety (90) days after notice thereof is given by the non- defaulting Party to the defaulting Party.

- 19 -

(d) BECO Bankruptcy. BECO (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against BECO under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize BECO pursuant to 11 U.S.C. § 101 or any similar statute applicable to BECO, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of BECO, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of BECO or of a major part of its property.

(e) NEA Bankruptcy. NEA (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against NEA under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize NEA pursuant to 11 U.S.C. § 101 or any similar statute applicable to NEA, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of NEA, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of NEA or of a major part of its property.

(f) Consolidation. A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party.

(g) Continuing Failure by NEA to Deliver Contract Energy or Satisfy the Capacity Requirement. NEA (i) fails to deliver and sell Contract Energy hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by BECO to NEA, or if such failure is not capable of cure within five (5) days, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by BECO to NEA or (ii) fails to satisfy the Capacity Requirement hereunder for a period of one (1) calendar month during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than two (2) calendar months after written notice thereof is given by BECO to NEA, or if such failure is not capable of cure within two (2) calendar months, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by BECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect NEA’s obligation to pay Cover Damages or Capacity Replacement Damages for any day on which NEA fails to deliver Contract Energy or satisfy the Capacity Requirement.

(h) Continuing Failure by BECO to Accept Delivery of Contract Energy or the Capacity Requirement. BECO fails to accept delivery of Contract Energy or the Capacity Requirement hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by NEA to BECO, or if such failure is not capable of cure within five (5) days, BECO promptly begins such cure activity within such five (5) day period and diligently and continuously pursues the cure activity such that the failure is cured within thirty (30) days after notice thereof is given by BECO to NEA; provided,

- 20 -

however, the foregoing shall not be construed to limit or otherwise affect BECO’s obligation to pay Resale Damages or Capacity Resale Damages for any day on which BECO fails to accept Contract Energy or the Capacity Requirement.

8.2 Remedies.

(a) Declaration of an Early Termination Date and Calculation of Termination Payments.

(i) BECO Termination Payment.

(A) If an Event of Default with respect to BECO shall have occurred and be continuing, NEA shall have the right (I) to designate a day on which this Agreement will terminate (the “BECO Early Termination Date”), (II) withhold any payments due to BECO under this Agreement and (III) suspend performance. NEA shall calculate, in a commercially reasonable manner, a BECO Termination Payment as of the BECO Early Termination Date. As soon as practicable after termination, notice shall be given by NEA to BECO of the amount of the BECO Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. BECO shall make the BECO Termination Payment within two (2) Business Days after such notice is effective. If BECO disputes NEA’s calculation of the BECO Termination Payment, in whole or in part, BECO shall, within two (2) Business Days of receipt of the calculation of the BECO Termination Payment, provide to NEA a detailed written explanation of the basis for such dispute; provided, however, BECO shall first transfer Performance Assurance to NEA in an amount equal to the BECO Termination Payment as calculated by NEA.

(B) Notwithstanding the provisions of Section 8.2(a)(i)(A), if on the first occasion that an Event of Default by BECO pursuant to Section 8.1(b) shall have occurred and be continuing, and NEA has exercised its rights under Section 8.2(a)(i)(A) to designate a BECO Early Termination Date, which date shall be no less than twenty (20) Business Days from the date NEA provides BECO with the notice of default under Section 8.1(b), BECO may, within twenty (20) Business Days of such notice, provide NEA with any amounts then due, plus credit support in an amount equal to the aggregate of the payments to be made by BECO pursuant to Article 4 hereof for the subsequent three (3) month period, as calculated in good faith by NEA (and disregarding any suspension of performance by NEA under Section 8.2(a)(i)) (“Credit Support”) in any of the following forms: (I) a letter of credit with an initial term of at least six (6) months issued by a bank or other financial institution reasonably acceptable to NEA, which will allow NEA to draw on the letter of credit up to the full amount upon a subsequent Event of Default by BECO, or (II) such other credit support proposed by BECO that is reasonably acceptable to NEA. If BECO makes such payments and provides such Credit Support, then NEA’s rights under Section 8.2(a)(i) shall no longer be in effect and, if NEA has suspended performance under Section 8.2(a)(i), NEA shall recommence such performance.

(C) In the event of either (I) a subsequent Event of Default by BECO pursuant to Section 8.1(b) and a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B) or (II) a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B), NEA will have all rights as set forth in Section 8.2(a)(i).

- 21 -

(D) BECO shall be relieved of the obligation to maintain such Credit Support to the extent that each of the following shall have occurred: (I) for at least six (6) months BECO shall have provided and maintained the Credit Support in accordance with Section 8.2(a)(i)(B) and there shall have been no drawdown by NEA under such Credit Support on account of a subsequent Event of Default by BECO; (II) BECO’s senior secured Credit Rating, not supported by third party credit enhancements, is at or above BBB-/Stable Outlook from S&P and at or above Baa3, Stable Outlook from Moody’s (or in the event BECO does not have, or no longer has, a senior secured credit rating, its issuer and/or long term debt rating shall be referenced); and (III) no other Event of Default has occurred and is continuing, including an event of Default under Section 8.1(b).

(ii) NEA Termination Payment. If an Event of Default with respect to NEA shall have occurred and be continuing, BECO shall have the right (A) to designate a day on which this Agreement will terminate (the “NEA Early Termination Date”), (B) withhold any payments due to NEA under this Agreement and (C) suspend performance. BECO shall calculate, in a commercially reasonable manner, a NEA Termination Payment as of the NEA Early Termination Date. As soon as practicable after termination, notice shall be given by BECO to NEA of the amount of the NEA Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. NEA shall make the NEA Termination Payment within two (2) Business Days after such notice is effective. If NEA disputes BECO’s calculation of the NEA Termination Payment, in whole or in part, NEA shall, within two (2) Business Days of receipt of the calculation of the NEA Termination Payment, provide to BECO a detailed written explanation of the basis for such dispute; provided, however, NEA shall first transfer Performance Assurance to BECO in an amount equal to the NEA Termination Payment as calculated by BECO.

(b) Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER (REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT

- 22 -

REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

9. FORCE MAJEURE

9.1 Force Majeure.

(a) The term “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under this Agreement, which event or circumstance was not anticipated as of the date this Agreement was agreed to, which is not within the control of, or the result of the negligence of, the Claiming Party or its agents, contractors, suppliers or Affiliates, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided, including storms, floods, earthquakes, tornados, fires, explosions, wars, riots or other civil disturbances, acts of war or acts of a public enemy, strikes, lockout, work stoppage or other industrial disturbances, labor or material shortage, and failure of the plant or plant equipment resulting from such force majeure events. Force Majeure shall not be based on (i) the loss of BECO’s markets; (ii) BECO’s inability economically to use or resell the Contract Energy purchased hereunder; (iii) the loss or failure of NEA’s supply; or (iv) NEA’s ability to sell the Contract Energy at a price greater than the amount provided for in Section 4.1(a).

(b) Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Contract Energy to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in Section 9.1(a) has occurred.

9.2 Notice and Excuse of Performance.

(a) Following a Force Majeure event, if either Party believes that such event will, or is reasonably likely to, adversely affect the performance of its obligations under this Agreement, then as early as commercially practicable but in no event later than two (2) Business Days after the initial occurrence of such event and for contingency planning purposes, such Party shall provide preliminary telephonic notice of the occurrence of a Force Majeure to the other Party promptly followed by written notice on or before the tenth (10th) Business Day after the initial occurrence of such event. Such written notice shall specify the nature and, if known, cause of the Force Majeure, its anticipated effect on the ability of such Party to perform obligations under this Agreement and the estimated duration of any interruption in service or other adverse effects resulting from such Force Majeure and shall be updated or supplemented as necessary to keep the other Party advised of the effect and remedial measures being undertaken to overcome the Force Majeure.

- 23 -

(b) To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under this Agreement and such Party (the “Claiming Party”) gives notice and details of the Force Majeure to the other Party as soon as practicable, then the Claiming Party shall be excused from the performance of its obligations with respect to such obligations (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.

10. DISPUTE RESOLUTION

In the event of any dispute, controversy or claim between the Parties arising out of or relating to this Agreement (collectively, a “Dispute”), the Parties shall attempt in the first instance to resolve such Dispute through friendly consultations between the Parties. If such consultations do not result in a resolution of the Dispute within fifteen (15) Days after notice of the Dispute has been delivered to either Party, then such Dispute shall be referred to the senior management of the Parties for resolution. If the Dispute has not been resolved within fifteen (15) Days after such referral to the senior management of the Parties, then either Party may pursue all of its remedies available hereunder. The Parties agree to attempt to resolve all Disputes promptly, equitably and in a good faith manner. In the event a dispute hereunder is resolved pursuant to arbitration or judicial proceedings, the Party whose position does not prevail in such proceedings shall reimburse all of the other Party’s third party costs (including reasonable attorney’s fees) incurred to prosecute or defend (as the case may be) such proceedings.

11. CONFIDENTIALITY

11.1 Nondisclosure. BECO and NEA each agree not to disclose to any Person and to keep confidential, and to cause and instruct its Affiliates, officers, directors, employees, partners and representatives not to disclose to any Person and to keep confidential, any and all of the following non- public information relating to the terms and provisions of this Agreement; any financial, pricing or supply quantity information relating to the Contract Energy to be supplied by NEA hereunder, the Facility or NEA and any information that is clearly marked or identified as “Confidential”. Notwithstanding the foregoing, any such information may be disclosed: (a) to the extent required by applicable laws and regulations or by any subpoena or similar legal process of any court or agency of federal, state or local government so long as the receiving Party gives the non-disclosing Party written notice at least three (3) Business Days prior to such disclosure, if practicable; (b) to lenders and potential lenders to BECO or to lenders to NEA or other Person(s) in connection with the implementation of this Agreement and to financial advisors, rating agencies, and any other Persons involved in the acquisition, marketing or sale or placement of such debt; (c) to agents, trustees, advisors and accountants of the Parties or their Affiliates involved in the financings described in clause (b) above, (d) to potential assignees of BECO or NEA or other Persons in connection with such proposed assignment and to financial advisors, rating agencies, and any other Persons involved in the marketing, placement or rating of such assignment, (e) to agents, trustees, advisors and accountants of the Parties or their Affiliates or agents, trustees, advisors and accountants of Persons involved in the potential assignment described in clause (d) above or (f) to the extent the non-disclosing Party shall have consented in writing prior to any such disclosure.

- 24 -

11.2 Public Statements. No public statement, press release or other voluntary publication regarding this Agreement shall be made or issued without the prior consent of the other Party, which consent shall not be unreasonably withheld.

12. INDEMNIFICATION AND INDEMNIFICATION PROCEDURES

12.1 Indemnification. Each Party (“Indemnifying Party”) shall indemnify, defend and hold the other Party (“Indemnified Party”) and its partners, shareholders, partners, directors, officers, employees and agents (including, but not limited to, Affiliates and contractors and their employees), harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever related to this Agreement suffered or incurred by such Indemnified Party arising out of the Indemnifying Party’s gross negligence or willful misconduct (including, without limitation, any breach of this Agreement resulting from gross negligence or willful misconduct). In the event injury or damage results from the joint or concurrent grossly negligent or willful misconduct of the Parties, each Party shall be liable under this indemnification in proportion to its relative degree of fault. Such duty to indemnify shall not apply to any claims which arise or are first asserted more than two (2) years after the termination of this Agreement. Such indemnity shall not include or compensate for indirect, punitive, exemplary, incidental or consequential damages incurred by either Party.

12.2 Indemnification Procedures. Each Indemnified Party shall promptly notify the Indemnifying Party of any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12. Such notice shall be given as soon as is reasonably practicable after the Indemnified Party becomes aware of each claim; provided, however, that failure to give prompt notice shall not adversely affect any claim for indemnification hereunder except to the extent the Indemnifying Party’s ability to contest any claim by any third party is materially adversely affected. The Indemnifying Party shall have the right, but not the obligation, at its expense, to contest, defend, litigate and settle, and to control the contest, defense, litigation and/or settlement of, any claim by any third party alleged or asserted against any Indemnified Party arising out of any matter in respect of which such Indemnified Party is entitled to be indemnified hereunder. The Indemnifying Party shall promptly notify such Indemnified Party of its intention to exercise such right set forth in the immediately preceding sentence and shall reimburse the Indemnified Party for the reasonable costs and expenses paid or incurred by it prior to the assumption of such contest, defense or litigation by the Indemnifying Party. The Indemnifying Party shall have the right to select legal counsel to defend a claim for which the Indemnified Party is seeking indemnification pursuant to this Section 12.2, subject to the consent of the Indemnified Party, which shall not be unreasonably delayed or withheld. If the Indemnifying Party exercises such right in accordance with the provisions of this Article 12 and any Indemnified Party notifies the Indemnifying Party that it desires to retain separate counsel in order to participate in or proceed independently with such contest, defense or litigation, such Indemnified Party may do so at its own expense. If the Indemnifying Party fails to exercise it rights set forth in the third sentence of this Section 12.2, then the Indemnifying Party will reimburse the Indemnified Party for its reasonable costs and expenses incurred in connection with the contest, defense or litigation of such claim. No Indemnified Party shall settle or compromise any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12 without the prior written consent of the Indemnifying Party; provided, however, that such consent shall not be unreasonably withheld by the Indemnifying Party.

- 25 -

13. ASSIGNMENT

13.1 Prohibition on Assignment. Except as provided in Section 13.2 hereof, this Agreement may not be assigned by either Party without the prior written consent of the other Party, which may not be unreasonably withheld. Any attempted or purported assignment of this Agreement that is not expressly permitted pursuant to Section 13.2 hereof shall be null and void and shall have no effect on or with respect to the rights and obligations of the Parties hereunder.

13.2 Permitted Assignment.

(a) NEA shall have the right to assign all or any portion of its rights or obligations under this Agreement without the consent of BECO solely for financing purposes to existing and any future lenders secured, in whole or in part, by interests in the Facility, NEA’s contractual rights, or NEA or Affiliates of NEA. Such assignment to lenders shall not operate to relieve NEA of any duty or obligation under this Agreement. In connection with the exercise of remedies under the security documents relating to such financing(s), the lender(s) or trustee(s) shall be entitled to assign this Agreement to any third-party transferee designated by such lender(s) or trustee(s), provided that BECO determines, in BECO’s reasonable discretion, that such proposed transferee or assignee is qualified and capable to satisfy NEA’s obligations hereunder.

(b) BECO shall have the right to assign this Agreement in connection with a BECO Reorganization Event to any assignee without the consent of NEA so long as (i) the proposed assignee serves load in NEPOOL and (ii) the proposed assignee’s credit rating as established by Moody’s or S&P is equal to or better than that of BECO at the time of the proposed assignment (provided, that any such rating that is on “watch” for downgrading shall not satisfy the credit rating criteria described in clause (ii)).

(c) If either Party assigns this Agreement as provided in this Section 13.2, then such Party shall cause to be delivered to the other Party an assumption agreement (in form and substance reasonably satisfactory to the non-assigning Party) of all of the obligations of the assigning Party hereunder by such assignee.

(d) An assignment of this Agreement pursuant to this Section 13.2 shall not release or discharge the assignor from its obligations hereunder unless the assignee executes a written assumption agreement in accordance with Section 13.2(c) hereof.

14. NOTICES

Any notice or communication given pursuant hereto shall be in writing and (1) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (2) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); (3) e-mailed (e-mailed notices shall be deemed given upon actual receipt) or (4) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designed by either Party to the other in writing:

- 26 -

If to BECO:

Boston Edison Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

Copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

With a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

15. WAIVER AND MODIFICATION

This Agreement may be amended and its provisions and the effects thereof waived only by a writing executed by the Parties, and no subsequent conduct of any Party or course of dealings between the Parties shall effect or be deemed to effect any such amendment or waiver. No waiver of any of the

- 27 -

provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. The failure of either Party to enforce any provision of this Agreement shall not be construed as a waiver of or acquiescence in or to such provision.

16. INTERPRETATION

16.1 Choice of Law. Interpretation and performance of this Agreement shall be in accordance with, and shall be controlled by, the laws of the Commonwealth of Massachusetts (without regard to its principles of conflicts of law).

16.2 Headings. Article and Section headings are for convenience only and shall not affect the interpretation of this Agreement. References to articles, sections and appendices, and schedules are, unless the context otherwise requires, references to articles, sections, appendices, and schedules of this Agreement. The words “hereof” and “hereunder” shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

17. COUNTERPARTS

Any number of counterparts of this Agreement may be executed, and each shall have the same force and effect as an original.

18. NO DUTY TO THIRD PARTIES

Except as provided in any consent to assignment of this Agreement, nothing in this Agreement nor any action taken hereunder shall be construed to create any duty, liability or standard of care to any Person not a Party to this Agreement.

19. SEVERABILITY

If any term or provision of this Agreement or the interpretation or application of any term or provision to any prior circumstance is held to be unenforceable, illegal or invalid by a court or agency of competent jurisdiction, the remainder of this Agreement and the interpretation or application of all other terms or provisions to Persons or circumstances other than those which are unenforceable, illegal or invalid shall not be affected thereby, and each term and provision shall be valid and be enforced to the fullest extent permitted by law.

20. ENTIRE AGREEMENT

Upon the Effective Date, this Agreement, together with the agreements executed or delivered on the Effective Date in connection herewith, shall constitute the entire agreement and understanding between the Parties hereto and shall supersede all prior agreements including, without limitation, the Existing NEA A PPA and understandings relating to the subject matter hereof.

- 28 -

21. CHANGE IN LAW OR MARKET STRUCTURE

The Parties acknowledge that this Agreement is based on the Laws, ISO Policies and market structure in effect as of the Agreement Date. In the event of a Change in Law or Market Structure, the Parties shall make such amendments to this Agreement as are necessary to accommodate such Change in Law or Market Structure, provided that any such amendments shall preserve the economic and business arrangements embodied or referenced in this Agreement.

- 29 -

IN WITNESS WHEREOF, each of BECO and NEA has caused this Agreement to be duly executed on its behalf as of the date first above written.

Boston Edison Company
By:	Ellen K. Angley
Name:	Ellen K. Angley
Title:	VP Energy Supply & Transmission
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:	Nathan E. Hanson
	Nathan E. Hanson
	Authorized Representative

- 30 -

SCHEDULE 4.1(a)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

- 31 -

Month Ending	No. of Days	MWh/hr BECO A	MWhs BECO A	Monthly Support Payment Price ($/MWh) BECO A
04/30/04	30	140.0000	100,800.0000
05/31/04	31	100.0000	74,400.0000
06/30/04	30	120.0000	86,400.0000
07/31/04	31	130.0000	96,720.0000
08/31/04	31	130.0000	96,720.0000
09/30/04	30	130.0000	93,600.0000
10/31/04	31	130.0000	96,720.0000
11/30/04	30	110.0000	79,200.0000
12/31/04	31	140.0000	104,160.0000
01/31/05	31	150.0000	111,600.0000
02/28/05	28	150.0000	100,800.0000
03/31/05	31	140.0000	104,160.0000
04/30/05	30	140.0000	100,800.0000
05/31/05	31	100.0000	74,400.0000
06/30/05	30	120.0000	86,400.0000
07/31/05	31	130.0000	96,720.0000
08/31/05	31	130.0000	96,720.0000
09/30/05	30	130.0000	93,600.0000
10/31/05	31	130.0000	96,720.0000
11/30/05	30	110.0000	79,200.0000
12/31/05	31	140.0000	104,160.0000
01/31/06	31	150.0000	111,600.0000
02/28/06	28	150.0000	100,800.0000
03/31/06	31	140.0000	104,160.0000
04/30/06	30	140.0000	100,800.0000
05/31/06	31	100.0000	74,400.0000
06/30/06	30	120.0000	86,400.0000
07/31/06	31	130.0000	96,720.0000
08/31/06	31	130.0000	96,720.0000
09/30/06	30	130.0000	93,600.0000
10/31/06	31	130.0000	96,720.0000
11/30/06	30	110.0000	79,200.0000
12/31/06	31	140.0000	104,160.0000
01/31/07	31	150.0000	111,600.0000
02/28/07	28	150.0000	100,800.0000
03/31/07	31	140.0000	104,160.0000
04/30/07	30	140.0000	100,800.0000
05/31/07	31	100.0000	74,400.0000
06/30/07	30	120.0000	86,400.0000
07/31/07	31	130.0000	96,720.0000
08/31/07	31	130.0000	96,720.0000
09/30/07	30	130.0000	93,600.0000
10/31/07	31	130.0000	96,720.0000
11/30/07	30	110.0000	79,200.0000
12/31/07	31	140.0000	104,160.0000
01/31/08	31	150.0000	111,600.0000
02/29/08	29	150.0000	104,400.0000
03/31/08	31	140.0000	104,160.0000
04/30/08	30	140.0000	100,800.0000
05/31/08	31	100.0000	74,400.0000
06/30/08	30	120.0000	86,400.0000

- 32 -

Month Ending	No. of Days	MWh/hr BECO A	MWhs BECO A	Monthly Support Payment Price ($/MWh) BECO A
07/31/08	31	130.0000	96,720.0000
08/31/08	31	130.0000	96,720.0000
09/30/08	30	130.0000	93,600.0000
10/31/08	31	130.0000	96,720.0000
11/30/08	30	110.0000	79,200.0000
12/31/08	31	140.0000	104,160.0000
01/31/09	31	150.0000	111,600.0000
02/28/09	28	150.0000	100,800.0000
03/31/09	31	140.0000	104,160.0000
04/30/09	30	140.0000	100,800.0000
05/31/09	31	100.0000	74,400.0000
06/30/09	30	120.0000	86,400.0000
07/31/09	31	130.0000	96,720.0000
08/31/09	31	130.0000	96,720.0000
09/30/09	30	130.0000	93,600.0000
10/31/09	31	130.0000	96,720.0000
11/30/09	30	110.0000	79,200.0000
12/31/09	31	140.0000	104,160.0000
01/31/10	31	150.0000	111,600.0000
02/28/10	28	150.0000	100,800.0000
03/31/10	31	140.0000	104,160.0000
04/30/10	30	140.0000	100,600.0000
05/31/10	31	100.0000	74,400.0000
06/30/10	30	120.0000	86,400.0000
07/31/10	31	130.0000	96,720.0000
08/31/10	31	130.0000	96,720.0000
09/30/10	30	130.0000	93,600.0000
10/31/10	31	130.0000	96,720.0000
11/30/10	30	110.0000	79,200.0000
12/31/10	31	140.0000	104,160.0000
01/31/11	31	150.0000	111,600.0000
02/28/11	28	150.0000	100,800.0000
03/31/11	31	140.0000	104,160.0000
04/30/11	30	140.0000	100,800.0000
05/31/11	31	100.0000	74,400.0000
06/30/11	30	120.0000	86,400.0000
07/31/11	31	130.0000	96,720.0000
08/31/11	31	130.0000	96,720.0000
09/30/11	30	130.0000	93,600.0000
10/31/11	31	130.0000	96,720.0000
11/30/11	30	110.0000	79,200.0000
12/31/11	31	140.0000	104,160.0000
01/31/12	31	150.0000	111,600.0000
02/29/12	29	150.0000	104,400.0000
03/31/12	31	140.0000	104,160.0000
04/30/12	30	140.0000	100,800.0000
05/31/12	31	100.0000	74,400.0000
06/30/12	30	120.0000	86,400.0000
07/31/12	31	130.0000	96,720.0000
08/31/12	31	130.0000	96,720.0000
09/30/12	30	130.0000	93,600.0000

- 33 -

Month Ending	No. of Days	MWh/hr BECO A	MWhs BECO A	Monthly Support Payment Price ($/MWh) BECO A
10/31/12	31	130.0000	96,720.0000
11/30/12	30	110.0000	79,200.0000
12/31/12	31	140.0000	104,160.0000
01/31/13	31	150.0000	111,600.0000
02/28/13	28	150.0000	100,800.0000
03/31/13	31	140.0000	104,160.0000
04/30/13	30	140.0000	100,800.0000
05/31/13	31	100.0000	74,400.0000
06/30/13	30	120.0000	86,400.0000
07/31/13	31	130.0000	96,720.0000
08/31/13	31	130.0000	96,720.0000
09/30/13	30	130.0000	93,600.0000
10/31/13	31	130.0000	96,720.0000
11/30/13	30	110.0000	79,200.0000
12/31/13	31	140.0000	104,160.0000
01/31/14	31	150.0000	111,600.0000
02/28/14	28	150.0000	100,800.0000
03/31/14	31	140.0000	104,160.0000
04/30/14	30	140.0000	100,800.0000
05/31/14	31	100.0000	74,400.0000
06/30/14	30	120.0000	86,400.0000
07/31/14	31	130.0000	96,720.0000
08/31/14	31	130.0000	96,720.0000
09/30/14	30	130.0000	93,600.0000
10/31/14	31	130.0000	96,720.0000
11/30/14	30	110.0000	79,200.0000
12/31/14	31	140.0000	104,160.0000
01/31/15	31	150.0000	111,600.0000
02/28/15	28	150.0000	100,800.0000
03/31/15	31	140.0000	104,160.0000
04/30/15	30	140.0000	100,800.0000
05/31/15	31	100.0000	74,400.0000
06/30/15	30	120.0000	86,400.0000
07/31/15	31	130.0000	96,720.0000
08/31/15	31	130.0000	96,720.0000
09/30/15	30	130.0000	93,600.0000
10/31/15	31	130.0000	96,720.0000
11/30/15	30	110.0000	79,200.0000
12/31/15	31	140.0000	104,160.0000
01/31/16	31	150.0000	111,600.0000
02/29/16	29	150.0000	104,400.0000
03/31/16	31	140.0000	104,160.0000
04/30/16	30	140.0000	100,800.0000
05/31/16	31	100.0000	74,400.0000
06/30/16	30	120.0000	86,400.0000
07/31/16	31	130.0000	96,720.0000
08/31/16	31	130.0000	96,720.0000
09/30/16	15	130.0000	46,800.0000

- 34 -

SCHEDULE 4.1(c)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

LIST OF APPROVED CAPACITY BUYERS

Constellation Power Source, Inc.

J Aron & Company

Morgan Stanley Group Capital

PP&L Energy Plus, LLC

PSE&G Energy Resources & Trading, LLC

Select Energy, Inc.

Sempra Energy Trading Corp.

TransCanada Power Marketing Ltd.

- 35 -

EX-10.19

EXHIBIT 10.19

AMENDED AND RESTATED POWER PURCHASE AGREEMENT

THIS AMENDED AND RESTATED POWER PURCHASE AGREEMENT (the “Agreement”) is entered into as of August 19, 2004 (the “Agreement Date”), by and between Boston Edison Company, a Massachusetts corporation (“BECO”) and Northeast Energy Associates Limited Partnership, a Massachusetts limited partnership (“NEA”). BECO and NEA are individually referred to herein as a “Party” and are collectively referred to herein as the “Parties”.

WHEREAS, NEA owns a nominal 300 MW natural gas-fired electricity and steam generating plant located in Bellingham, Massachusetts (the “Facility”);

WHEREAS, BECO and NEA are parties to a certain Power Purchase Agreement dated January 28, 1988, as amended to date (the “Existing NEA B PPA”), pursuant to which BECO purchases from NEA a portion of the Facility’s capacity and associated energy;

WHEREAS, BECO and NEA desire to amend and restate the Existing NEA B PPA as provided for herein; and

WHEREAS, such amendment and restatement of the Existing NEA B PPA is consistent with BECO’s invitation, dated October 17, 2003, to submit proposals regarding the transfer of entitlements to certain power purchase agreements and NEA’s response, dated December 3, 2003, related to the restructuring of four (4) power purchase agreements (including the Existing NEA B PPA) existing between NEA and each of BECO and Commonwealth Electric Company (“CECO”) (the four (4) existing agreements, the “Existing Agreements”, are set forth at Exhibit A).

NOW, THEREFORE, in consideration of the premises and of the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1. DEFINITIONS

In addition to terms defined in the recitals hereto, the following terms shall have the meanings set forth below.

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries’ controls, is controlled by, or is under common control with, such first Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall have the meaning set forth in the first paragraph of this Agreement.

“Agreement Date” shall have the meaning set forth in the first paragraph of this Agreement.

“Approved Capacity Buyer” shall mean any of the Persons set forth on Schedule 4.1(c) hereto.

“BECO Reorganization Event” shall mean (a) any consolidation, merger or other form of combination of BECO with any other Person, (b) the acquisition of a majority of the outstanding shares of BECO by any Person or (c) the sale, conveyance, lease, transfer or other disposition, in one transaction or a series of related transactions, including without limitation the transfer or “spin-off” of shares of a subsidiary (collectively, a Transfer”), affecting all or substantially all of the assets of BECO existing on the Agreement Date or hereafter acquired. For purposes of this definition, the transfer, sale or other disposition of all or substantially all of the transmission and/or distribution assets of BECO, will, in either case, constitute a “BECO Reorganization Event.”

“BECO Termination Payment” shall mean, with respect to this Agreement and NEA, an amount payable by BECO to NEA equal to the sum of the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which NEA incurs as a result of the termination of this Agreement pursuant to Section 8.2(a)(i) hereof.

“Business Day” shall mean any day that is not a Saturday, Sunday, or NERC Holiday.

“Capacity” shall mean “Unforced Capacity” as presently defined in the NEPOOL Manual for Definitions and Abbreviations (and, throughout the Term, any successor product thereto).

“Capacity Payment” with respect to any given time period, shall mean the product of (a) the Capacity Price and (b) Capacity Requirement, for such period.

“Capacity Price” with respect to any month, shall mean (a) the Negotiated Capacity Price or (b) in the event that the Parties fail to agree upon a Negotiated Capacity Price on or before the Contract UCAP Transfer Deadline, the price for UCAP for such month established pursuant to the next UCAP Monthly Supply Auction; provided, however, if no price for UCAP is established in the next UCAP Monthly Supply Auction, the price to be used is that established pursuant to the last UCAP Monthly Supply Auction in which UCAP was transacted.

“Capacity Receipt Shortfall” shall have the meaning set forth in Section 3.8(c) hereof.

“Capacity Replacement Damages” shall have the meaning ascribed thereto in Section 3.8(b) herein.

“Capacity Replacement Price” with respect to any portion of the Capacity Requirement that NEA fails to deliver to BECO hereunder, shall mean (a) the price at which BECO, acting in a commercially reasonable manner, purchases Capacity in lieu of such portion of the Capacity Requirement, plus transaction and other administrative costs reasonably incurred by BECO in purchasing such Capacity, of (b) to the extent BECO has not purchased Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Requirement,” shall mean for the applicable month, for so long as NEA is the owner of the Facility during the Term hereof, the lesser of (a) 60 MW or (b) 30% of the Capacity recognized by the ISO as attributable to the Facility. Upon the sale, assignment or transfer by NEA of its interest in the Facility during the Term hereof, Capacity Requirement shall be fixed at the Capacity Requirement in effect on the date immediately prior to such sate, assignment or transfer.

- 2 -

“Capacity Resale Damages” shall have the meaning ascribed thereto in Section 3.8(c) herein.

“Capacity Resale Price” with respect to any portion of the Capacity Requirement that BECO fails to accept delivery from NEA hereunder, shall mean (a) the price at which NEA, acting in a commercially reasonable manner, re-sells Capacity in lieu of such portion of the Capacity Requirement, less transaction and other administrative costs reasonably incurred by NEA in selling such Capacity or (b) to the extent NEA has not sold Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Supply Shortfall” shall have the meaning set forth in Section 3.8(b) hereof.

“Change in Law or Market Structure” shall mean any of the following events that has a material adverse economic effect on one or both of the Parties: (a) the adoption, promulgation, modification, repeal or reinterpretation by any Governmental Entity of any Law which (or the effects of which) amends or conflicts with the Laws established or in effect as of the Agreement Date, (b) the adoption, promulgation, modification, repeal or reinterpretation by ISO of the ISO Policies which (or the effect of which) amends or conflicts with the ISO Policies established or in effect as of the Agreement Date or (c) the adoption or promulgation of a market structure that differs from the market structure reflected in the ISO Policies established or in effect as of the Agreement Date. For avoidance of doubt, a Change in Law or Market Structure shall include any event described in clauses (a), (b) or (c) above that results in BECO not being able to sell the Contract Energy purchased hereunder at a price greater than or equal to the Energy Payment prices (excluding the Support Payment) paid to NEA hereunder.

“Claiming Party” shall have the meaning set forth in Section 9.2(b) hereof.

“Contract Energy” shall have the meaning set forth in Section 3.1 hereof.

“Contract UCAP Transfer Deadline” with respect to any month, shall mean 5 PM Eastern Prevailing Time on the Business Day preceding the day by which final bids into the NEPOOL ISO Supply Auction must be submitted to be considered timely under the NEPOOL Practices and Market Rules and Procedures governing suppliers’ participation in the UCAP Monthly Supply Auction.

“Costs” shall mean brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred in terminating this Agreement; and all reasonable attorneys’ fees and expenses incurred in connection with the termination of this Agreement.

“Cover Damages” shall have the meaning set forth in Section 3.6 hereof.

“Credit Support” shall have the meaning set forth in Section 8.2(a)(i)(B) hereof.

“Day-Ahead Energy Market” or “DAM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

- 3 -

“Delivery Point” shall mean the Facility Bus; provided, however, that (a) if a LMP is not established for a node at the Facility Bus, or during periods of Force Majeure, NEA may deliver Contract Energy to an alternate node within the ISO control area that has a published LMP price and (b) NEA may deliver to any other delivery point mutually agreed to by the Parties.

“Delivery Shortfall” shall have the meaning set forth in Section 3.6 hereof.

“DTE” shall mean the Massachusetts Department of Telecommunications and Energy or its successor state regulatory agency.

“Eastern Prevalling Time” shall mean either Eastern Standard Time or Eastern Daylight Savings Time, as in effect from time to time.

“Effective Date” shall have the meaning set forth in Section 2.1 hereof.

“Energy Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Event of Default” shall have the meaning set forth in Section 8.1 hereof.

“Existing Agreements” shall have the meaning set forth in the Recitals.

“Execution Agreement” shall mean the Execution Agreement by and among NEA, Commonwealth Electric Company and BECO dated as of August 19, 2004.

“Existing NEA B PPA” shall have the meaning set forth in the Recitals.

“Facility” shall have the meaning set forth in the Recitals.

“Facility Bus” shall mean the point of interconnection between the Facility and the NEPOOL transmission system, which as of the Agreement Date is the UN.Bellinghm 13.2 NEA bus.

“FERC” shall mean the United States Federal Energy Regulatory Commission, and shall include its successors.

“Force Majeure” shall have the meaning set forth in Section 9.1(a) hereof.

“Gains” shall mean an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic benefit if any (exclusive of Costs) resulting from the termination of this Agreement, determined in a commercially reasonable manner.

“Governmental Entity” shall mean any federal, state or local governmental agency, authority, department, instrumentality or regulatory body, and any court or tribunal, with jurisdiction over NEA, BECO or the Facility.

“IBT Containers” shall have the meaning as set forth in Section 3.3(a) hereof.

- 4 -

“Indemnified Party” shall have the meaning set forth in-Section 12.1 hereof.

“Indemnifying Party” shall have the meaning set forth in Section 12.1 hereof.

“Internal Bilateral Transaction” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO” or ISO-NE” shall mean the ISO New England, Inc., the independent system operator established in accordance with the NEPOOL Agreement, or its successor.

“ISO Policies” shall mean the Market Rules and Procedures, NEPOOL Agreement, NEPOOL Manual for Definitions and Abbreviations and NEPOOL Practices.

“ISO Settlement Market System” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO UCAP Transfer Deadline” with respect to any month, shall mean the latest date upon which Capacity for that month may be transferred under an Internal Bilateral Transaction in accordance with ISO rules.

“Late Payment Rate” shall have the meaning set forth in Section 4.3 hereof.

“Law” shall mean all federal, state and local statutes, regulations, rules, orders, executive orders, decrees, policies, judicial decisions and notifications.

“Lead Participant” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“LMP” shall mean, for any ISO nodal point for any hour on any day, the “Day Ahead LMP” or “Real Time LMP” ($/MWh) at such ISO nodal point calculated in accordance with Section 2 of Market Rule 1, as reported on the ISO website at www.iso-ne.com on the “Data & Reports” page, “Hourly Markets Data” subpage and “Selectable Hourly LMP Data” category, for such nodal point on such date and time. If such price should ever cease to be published, then the LMP shall be a regularly published comparable substitute price, as agreed to by the Parties in writing.

“Losses” shall mean, with respect to any Party, an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic loss to it, if any (exclusive of Costs), resulting from termination of this Agreement, determined in a commercially reasonable manner.

“Market Rules and Procedures” shall mean the Market Rules, Manuals and Procedures adopted by the ISO and/or members of NEPOOL, as may be amended from time to time, and as administered by the ISO to govern the operation of the NEPOOL markets, and any applicable successor rules, manuals and procedures.

“Moody’s” shall mean Moody’s Investors Service, Inc., and any successor thereto.

“MW” shall mean a megawatt.

- 5 -

“MWh” shall mean a megawatt-hour (one MWh shall equal 1,000 kWh).

“NEA Termination Payment” shall mean, with respect to this Agreement and BECO, an amount payable by NEA to BECO equal to the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which BECO incurs as a result of the termination of this Agreement pursuant to Section 8.2(a)(ii) hereof.

“Negotiated Capacity Price” shall mean the price for Capacity as agreed to by the Parties pursuant to Section 4.1(b) herein.

“NEPOOL” shall mean the New England Power Pool, or its successor.

“NEPOOL Agreement” shall mean that certain Restated New England Power Pool Agreement, as restated by an amendment dated as of December 1, 1996, as amended and restated from time to time, and any applicable successor agreement.

“NEPOOL ISO Supply Auction” shall mean the auction currently defined as the “Supply Auction” in the Market Rules and Procedures, or any successor to such auction.

“NEPOOL Manual for Definitions and Abbreviations” shall mean that certain Manual for Definitions and Abbreviations prepared by ISO-NE, as may be amended from time to time, and any applicable successor manual.

“NEPOOL Practices” shall mean the NEPOOL practices and procedures for delivery and transmission of electricity and capacity and capacity testing in effect from time to time and shall include, without limitation, applicable requirements of the NEPOOL Agreement, and any applicable successor practices and procedures.

“NERC Holiday” shall mean New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day, and any other day declared a holiday by NERC.

“Ownership Share” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Party” and “Parties” shall have the meaning set forth in the first paragraph of this Agreement.

“Performance Assurance” shall mean collateral in the form of either cash, letter(s) of credit, or other security acceptable to the requesting Party.

“Person” shall mean an individual, partnership, corporation, limited liability company, limited liability partnership, limited partnership, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof.

“PURPA” shall mean the Public Utility Regulatory Policies Act of 1978, as amended.

“QF” shall have the meaning set forth in Section 6.3(a)(i) hereof.

- 6 -

“Quote Period” shall have the meaning set forth in Section 4.1(b) herein.

“Real-Time Energy Market” or “RTM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Rejected Power” shall have the meaning set forth in Section 3.7 hereof.

“Replacement Power” shall mean electricity purchased by BECO and delivered to the Delivery Point as replacement for any Delivery Shortfall. Replacement Power shall not include Contract Energy delivered to BECO on behalf of NEA pursuant to Section 3.1 hereof.

“Replacement Price” shall mean the lesser of (a) the price at which BECO, acting in a commercially reasonable manner, purchases Replacement Power, plus (i) transaction and other administrative costs reasonably incurred by BECO in purchasing such Replacement Power and (ii) additional transmission charges, if any, reasonably incurred by BECO to transmit Replacement Power to the Delivery Point, or (b) the locational marginal pricing at the Delivery Point for such Replacement Power; provided, however, that in no event shall the Replacement Price include any penalties, ratcheted demand or similar charges, nor shall BECO be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize NEA’s liability.

“Resale Damages” shall have the meaning set forth in Section 3.7 hereof.

“Resale Price” shall mean the higher of (a) the price at which NEA, acting in a commercially reasonable manner, sells or is paid for Rejected Power, plus transaction and other administrative costs reasonably incurred by NEA in re-selling such Rejected Power; or (b) the LMP at the Delivery Point for such Rejected Power; provided, however, that in no event shall such price include any penalties, ratcheted demand or similar charges, and further provided that in no event shall NEA be required to utilize or change its utilization of the Facility or its other assets or market positions in order to minimize BECO’s liability for Rejected Power.

“Schedule or Scheduling” shall mean the actions of NEA or BECO and/or their designated representatives, including each Party’s Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity of Contract Energy to be delivered on any given day or days (or in any given hour or hours) during the Term at the Delivery Point.

“S&P” shall mean Standard & Poor’s Ratings Group, a division of McGraw Hill, Inc., and any successor thereto.

“Support Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Term” shall have the meaning set forth in Section 2.2 hereof.

“Third-Party Quote” with respect to any Capacity Requirement, shall mean a firm offer by an Approved Capacity Buyer to purchase Capacity from BECO in a volume and for a time period equal to such Capacity Requirement.

- 7 -

“Transmission Provider” shall mean (a) ISO, its respective successor or Affiliates; (b) NEPOOL; (c) BECO; or (d) such other third parties from whom transmission services are necessary for NEA to fulfill its performance obligations to BECO hereunder.

“UCAP” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“UCAP Monthly Supply Auction” shall mean the auction currently defined as the “UCAP Monthly Auction” in the NEPOOL Manual for Definitions and Abbreviations, or any successor to such auction that establishes a price for UCAP or its successor product.

2. EFFECTIVE DATE; CONDITIONS; TERM

2.1 Effective Date. The “Effective Date” of this Agreement shall be the Closing Date as established under the Execution Agreement.

2.2 Term.

(a) The “Term” of this Agreement shall mean the period from and including 11:59 p.m. (Eastern Prevailing Time) on the Effective Date through and including 11:59 p.m. (Eastern Prevailing Time) on September 15, 2011, unless this Agreement is sooner terminated in accordance with the provisions hereof.

(b) At the expiration of the Term, the Parties shall no longer be bound by the terms and provisions hereof (including, without limitation, any payment obligation hereunder), except (i) to the extent necessary to provide invoices and make payments or refunds with respect to Contract Energy or Capacity delivered prior to such expiration or termination, (ii) to the extent necessary to enforce the rights and the obligations of the Parties arising under this Agreement before such expiration or termination and (iii) the obligations of the Parties hereunder with respect to confidentiality and indemnification shall survive the expiration or termination of this Agreement and shall continue for a period of two (2) calendar years following such expiration or termination.

- 8 -

3. DELIVERY OF CONTRACT ENERGY AND CAPACITY

3.1 Obligation to Sell and Purchase Contract Energy. During each hour of the Term, NEA shall sell and deliver at the Delivery Point, and BECO shall purchase and receive at the Delivery Point, electricity in the amounts set forth in Section 3.3 and otherwise in accordance with the terms and conditions of this Agreement (“Contract Energy”). NEA shall be permitted to satisfy its obligation to deliver Contract Energy from any source of supply available to NEA. Contract Energy delivered to BECO by NEA or on behalf of NEA by NEA’s suppliers, designees or any other Person engaged by NEA to deliver Contract Energy shall be deemed delivered by NEA hereunder and NEA shall be solely responsible for any costs payable to its suppliers for such delivery. The aforementioned obligations for NEA to sell and deliver the Energy and for BECO to purchase and receive the Energy shall be firm and subject to adjustment only to reflect performance interruptions excused by this Agreement.

3.2 Characteristics. Contract Energy delivered by NEA to BECO at the Delivery Point shall be in the form of three (3)-phase, sixty (60) hertz, alternating current and otherwise in the form required by Market Rules and Procedures.

3.3 Scheduling.

(a) NEA shall Schedule deliveries of Contract Energy delivered hereunder with ISO in equal hourly quantities in accordance with all NEPOOL Practices and Market Rules and Procedures applicable thereto as set forth in Schedule 3.3. Furthermore, Contract Energy will be sold and delivered for purchase by BECO in the form of Internal Bilateral Transactions (“IBTs”) and NEA will use commercially reasonable efforts to transfer Contract Energy in the DAM; provided, however, that if such transfer cannot be made in the DAM, the Contract Energy shall be transferred in the RTM. All Contract Energy will be delivered to a specific node and not a zone. NEA will submit IBT Containers, as defined below, and notify BECO that the IBT Containers have been submitted into the ISO Settlement Market System.

Subject to the satisfaction of NEA’s obligations in this Section 3.3, BECO will confirm the IBT Container in the ISO Settlement Market System. For purposes of this Agreement, “IBT Container” shall mean the form of electronic contract submittal, as implemented in the ISO Settlement Market System effective March 1, 2003 as amended from time to time, that requires BECO to confirm the general parameters of the IBT. IBTs shall be submitted and confirmed for the longest term permitted by the ISO. NEA shall be responsible for any inaccuracies in any schedules and shall correct such schedules upon notification by BECO; provided, however, BECO shall cooperate with NEA in connection with any such Scheduling and bidding and in complying with all NEPOOL Practices and shall promptly provide information reasonably requested by NEA for the purpose of assisting NEA with its Scheduling obligations hereunder. Notwithstanding the agreement to Schedule all Contract Energy in the DAM, the Energy Payment made by BECO to NEA shall be as calculated pursuant to Section 4.1(a) hereof.

(b) The Parties agree to use commercially reasonable efforts to comply with all applicable ISO Policies in connection with the Scheduling and delivery of Contract Energy hereunder. For administrative convenience, the Parties agree that all Contract Energy deliveries and receipts made pursuant to this Agreement and any other power purchase agreement between the Parties may be provided for in a single Schedule. Penalties or similar charges assessed by a Transmission Provider and caused by a Party’s noncompliance with the Scheduling obligations set forth in this Section 3.3 shall be the responsibility of the Party whose action or inaction caused the penalty.

- 9 -

3.4 Lead Participant; Ownership Share. NEA, or any entity so identified by NEA, shall be the Lead Participant of the Facility and BECO shall use commercially reasonable efforts to transfer such designation to NEA or the entity so identified by NEA. BECO shall use commercially reasonable efforts to transfer to NEA, or any entity so identified by NEA, the Ownership Share now held by BECO relating to the Facility.

3.5 Sales for Resale. All Contract Energy delivered by NEA to BECO hereunder shall be sales for resale, with BECO reselling such Contract Energy. BECO shall provide NEA with any certificates reasonably requested by NEA to evidence that the deliveries of Contract Energy hereunder are sales for resale. Nothing in this Agreement shall be construed to prohibit or restrict such resale by BECO.

3.6 Failure of NEA to Deliver Scheduled Contract Energy; Cover Damages.

Subject to Section 8.1(g) hereof, in the event NEA fails to deliver Contract Energy it is obligated to deliver hereunder and such failure is not excused under the terms of this Agreement (such undelivered Contract Energy to be referred to herein as the “Delivery Shortfall”), then NEA shall pay BECO, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Delivery Shortfall equal to the Cover Damages. “Cover Damages” means an amount equal to (i) the amount, if any, by which (A) the Replacement Price ($/MWh) multiplied by the quantity (in MWh) of the Delivery Shortfall, exceeds (B) the Energy Payment that would have been paid pursuant to Section 4.1 hereof had the Delivery Shortfall been delivered, plus (ii) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against BECO as a direct result of NEA’s failure to deliver such Contract Energy; provided, however, BECO shall use commercially reasonable efforts to purchase replacement power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(g) and 8.2 hereof, the damages provided in this Section 3.6 shall be the sole and exclusive remedy of BECO for any failure of NEA to deliver Contract Energy that it is obligated to deliver hereunder. The invoice for the amount payable pursuant to this Section 3.6 shall include a written statement explaining in reasonable detail the calculation of such amount.

3.7 Failure by BECO to Accept Delivery of Contract Energy; Resale Damages. If BECO fails to accept all or part of the Contract Energy it is obligated to accept hereunder and such failure to accept is not excused under the terms of this Agreement (such Contract Energy is referred to herein as “Rejected Power”), then BECO shall pay NEA, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Rejected Power equal to the Resale Damages. “Resale Damages” means an amount equal to (a) the amount, if any, by which (i) the Energy Payment that would have been paid pursuant to Section 4.1(a) hereof for such Rejected Power, had it been accepted, exceeds (ii) the Resale Price ($/MWh) multiplied by the quantity (in MWh) of Rejected Power resold by NEA, plus (b) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of BECO’s failure to accept such Contract Energy; provided, however, NEA shall use commercially reasonable efforts to sell such Rejected Power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(h) and 8.2 hereof, the damages provided in this Section 3.7 shall be the sole and exclusive remedy of NEA for any failure of BECO to accept delivery of Contract Energy that it is obligated to accept hereunder. The invoice for the amount payable pursuant to this Section 3.7 shall include a written statement explaining in reasonable detail the calculation of such amount.

- 10 -

3.8 Obligation to Sell and Purchase Capacity Requirements.

(a) During the Term, NEA shall sell to BECO and BECO shall purchase from NEA the Capacity Requirement. In the event there is no longer a market for Capacity in New England, NEA shall not be obligated to sell and BECO shall not be obligated to purchase the Capacity Requirement.

(i) For so long as NEA is the owner of the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement only from the Facility. In the event that NEA sells, assigns or transfers its interests in the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement from any source of supply available to NEA. Nothing in this Agreement shall be construed to restrict or bar NEA from any sale, assignment or transfer of its interests in the Facility.

(ii) The Parties acknowledge that as of the Agreement Date, the Market Rules and Procedures do not impose any locational requirement with respect to Capacity. In the event that, at any time during the Term, the Market Rules and Procedures do impose a zonal, nodal or other geographic locational requirement, the Capacity Requirement will be fulfilled for the zone, node or other geographic area in which the Facility is located.

(b) If NEA fails to provide BECO with all or part of the Capacity Requirement it is required to provide pursuant to Section 3.8(a) hereof (a “Capacity Supply Shortfall”) and such failure is not excused under the terms of this Agreement, then the Capacity Replacement Damages associated with such Capacity Supply Shortfall shall be deducted from amounts payable by BECO hereunder for the next succeeding month or paid by NEA to BECO, at BECO’s election. “Capacity Replacement Damages,” with respect to any portion of the Capacity Requirement that NEA fails to deliver to BECO hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Replacement Price exceeds the Capacity Price, multiplied by the Capacity Supply Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against BECO as a direct result of NEA’s failure to deliver the Capacity Requirement in accordance with Section 3.8(a) hereof. Subject to Section 8.1(g) hereof, the damages provided in this Section 3.8(b) shall be the sole and exclusive remedy of BECO for any failure of NEA to deliver the Capacity Requirement hereunder. With respect to any calendar month during the Term, NEA will be deemed to have failed to deliver the Capacity Requirement for such calendar month if it has not scheduled a bilateral transfer of the Capacity Requirement (or otherwise effected delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

(c) If BECO fails to accept delivery of all or part of the Capacity Requirement it is required to purchase pursuant to Section 3.8(a) hereof (a “Capacity Receipt Shortfall”), and such failure is not excused under the terms of this Agreement, then the Capacity Resale Damages associated with such Capacity Receipt Shortfall shall be payable by BECO on the date payment would otherwise be due in respect of the month in which the failure occurred. “Capacity Resale Damages,” with respect to any portion of the Capacity Requirement that BECO fails to accept delivery of from NEA hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Price exceeds the Capacity Resale Price, multiplied by the Capacity Receipt Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of BECO’s failure to accept delivery of the Capacity Requirement

- 11 -

in accordance with Section 3.8(a) hereof. Subject to Section 8.1(h) hereof, the damages provided in this Section 3.8(c) shall be the sole and exclusive remedy of NEA for any failure of BECO to accept delivery of the Capacity Requirement hereunder and there shall be no adjustment of the Energy Payment or Support Payment as a result of BECO’s failure to accept delivery of such Capacity Requirement. With respect to any calendar month during the Term, BECO will be deemed to have failed to accept delivery of the Capacity Requirement for such calendar month if it has not confirmed a schedule (or an equivalent commitment instrument) entered by NEA for bilateral transfer of the Capacity Requirement (or otherwise effected acceptance of delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

3.9 Delivery Point.

(a) All Contract Energy shall be delivered hereunder by NEA to BECO at the Delivery Point.

(b) Except as provided for in Section 3.3(b) herein, NEA shall be responsible for all transmission and distribution charges, including applicable ancillary service charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission incurred, in each case, in connection with the delivery of Contract Energy to the Delivery Point.

(c) Except as provided for in Section 3.3(b) herein, BECO shall be responsible for all transmission charges, ancillary services charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission, incurred, in each case, in connection with the transmission of Contract Energy delivered under this Agreement from and after the Delivery Point.

4. PAYMENTS FOR CONTRACT ENERGY AND CAPACITY REQUIREMENTS

4.1 Payment for Contract Energy and Capacity Requirements.

(a) All Contract Energy delivered to BECO under this Agreement shall be purchased by BECO for an amount calculated pursuant to this Section 4.1(a).

(i) Beginning on the Effective Date and continuing for the Term, BECO shall pay NEA a monthly energy payment (the “Energy Payment”) equal to the sum of: (A) the product of (I) the Contract Energy (in MWhs) delivered to BECO hereunder during each hour during such month that cleared in the DAM and (II) the hourly DAM LMP Price for such hour at the Delivery Point for MWhs that cleared in the DAM for such month, plus (B) the product of (I) the Contract Energy (in MWhs) delivered to BECO hereunder during each hour during such month that cleared in the RTM and (II) the hourly RTM LMP Price for such hour at the Delivery Point for MWhs that cleared in the RTM for such month, plus (C) a support payment (the “Support Payment”) equal to the product of (I) the lesser of: the total Contract Energy (in MWhs) delivered to BECO hereunder during such month or the MWh quantity for the applicable month, as set forth in Schedule 4.1(a), and (II) the $/MWh price (the “Monthly Support Payment Price”) for the applicable month, as set forth in Schedule 4.1(a). Notwithstanding anything in this Agreement to the contrary, no exercise by NEA of its right under Section 8.2 to reduce Contract Energy delivered to BECO as a result of BECO’s failure to timely pay for such Contract Energy shall have the effect of reducing the Support Payment as calculated pursuant to this Section.

- 12 -

(ii) BECO’s sole payment obligation, including without limitation any Support Payment obligation, with respect to Contract Energy is limited to the payment of the Energy Payment for Contract Energy delivered in accordance with the terms of this Agreement by or on behalf of NEA to the Delivery Point.

(b) All Capacity delivered to BECO under this Agreement shall be purchased by BECO at the Capacity Price. BECO’s sole payment obligation with respect to Capacity is limited to the payment of the Capacity Payment for the Capacity Requirement actually provided to BECO in accordance with the terms of this Agreement by or on behalf of NEA. The Parties will negotiate in good faith and in a commercially reasonable manner towards agreement upon a negotiated price for Capacity (the “Negotiated Capacity Price”) for each month of the Term in accordance with the terms and provisions of this Section 4.1(b). At any time during the Term, NEA may request BECO to provide it with an indicative quote for the Capacity Requirement for one month or any period of months (the “Quote Period”) as set forth in such request. Within six (6) Business Days after BECO’s receipt of such request, BECO will provide NEA with an indicative quote for a purchase price of such Capacity Requirement for the Quote Period which BECO in its commercially reasonable judgment believes reflects the fair market value for such Capacity Requirement. Within one Business Day after its receipt of such indicative quote, NEA will inform BECO as to whether NEA accepts or rejects the indicative quote.

(i) In the event that NEA accepts the indicative quote, the pricing reflected in such indicative quote will be established as the Negotiated Capacity Price for such Capacity Requirement unless BECO notifies NEA, within one Business Day after NEA’s acceptance, that BECO retracts the indicative quote. BECO may retract the indicative quote only in the event that BECO, in its commercially reasonable judgment, believes that the fair market value of the Capacity Requirement has materially declined since BECO delivered the indicative quote to NEA. In the event that BECO retracts the indicative quote, NEA may, at its election, (A) provide Third-Party Quotes to BECO for the applicable Capacity Requirement, provided that NEA does so within two (2) Business Days after BECO’s retraction of the indicative quote (and, in which event, the procedures set forth in Section 4.1(b)(ii) will be followed to determine the Negotiated Capacity Price), or (B) request a new indicative quote from BECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(ii) In the event that NEA rejects such indicative quote, NEA may, at its election, provide one or more Third-Party Quotes to BECO for the Capacity Requirement, provided that NEA does so within two (2) Business Days after NEA’s rejection of the indicative quote. In the event that NEA so delivers one or more Third-Party Quotes to BECO, BECO will, within one Business Day after delivery of the Third-Party Quotes, either (A) agree to establish any one of the Third-Party Quotes as the Negotiated Capacity Price or (B) sell Capacity (in an amount equal to the Capacity Requirement and for the Quote Period) to any of the Approved Capacity Buyers cited in the Third-Party Quotes at a different price, in which case such different price will be established as the Negotiated Capacity Price. Notwithstanding the foregoing, if, by the close of business on the Business Day immediately following NEA’s delivery of Third-Party Quotes, BECO, after making commercially reasonable efforts, is able to neither consummate a transaction as described in clause (B) of the immediately preceding sentence, nor confirm to its reasonable satisfaction the validity and firmness of at least one of the Third Party Quotes, then no Negotiated Capacity Price will be deemed to have been established for the applicable Capacity Requirement. In such event (or in the event that NEA does not deliver any Third-Party Quotes to BECO within two (2) Business Days after

- 13 -

its rejection of the indicative quote), NEA may request a new indicative quote from BECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(c) If, despite their good faith efforts, the Parties are not able to agree upon a Negotiated Capacity price prior to the Contract UCAP Transfer Deadline then the Capacity Requirement shall be purchased by BECO from NEA on a bilateral basis and the Capacity Price paid by BECO to NEA shall be the settlement price set at the UCAP Monthly Supply Auction.

4.2 Payment and Netting.

(a) Billing Period. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments). On or before the third (3^rd) day following the end of each month, NEA will render to BECO an invoice for the Energy Payment and Capacity Payment obligations incurred hereunder during the preceding month.

(b) Timeliness of Payment. BECO shall use its reasonable efforts to pay all NEA invoices under this Agreement on the fifteenth (15th) day after receipt of the invoice; provided, however, unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with each Party’s invoice instructions on or before the later of thirty (30) days following the receipt of such invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Late Payment Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

(c) Disputes and Adjustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Late Payment Rate from and including the due date but excluding the date paid. Inadvertent overpayments shall be reimbursed or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Late Payment Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment, as directed by the other party. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 4.2 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance is waived.

- 14 -

(d) Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other under this Agreement on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Contract Energy during the monthly billing period under this Agreement, including any related damages calculated pursuant to this Agreement, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, such Party shall pay such sum in full when due. The Parties agree to provide each other with reasonable detail of such net payment or net payment request.

4.3 Interest on Late Payment. If a payment is not received when due under this Agreement, the delinquent Party shall pay to the other Party interest on such unpaid amount which shall accrue from the due date until the date upon which payment in full is made at the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published) (the “Late Payment Rate”).

5. RESERVED

6. REPRESENTATIONS, WARRANTIES, COVENANTS AND ACKNOWLEDMENTS

6.1 Representations and Warranties of BECO. BECO hereby represents and warrants to NEA as of the Effective Date as follows:

(a) Organization and Good Standing: Power and Authority. BECO is a corporation duly incorporated, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. BECO has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization: No Conflicts. The execution and delivery by BECO of this Agreement, and the performance by BECO of its obligations hereunder, have been duly authorized by all necessary actions on the part of BECO and do not and, under existing facts and law, will not: (i) contravene its restated certificate of incorporation or any other governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of BECO and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of BECO, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

- 15 -

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting BECO or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which BECO reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) BECO’s ability to perform its obligations under this Agreement.

(e) Consents and Approvals. The execution, delivery and performance by BECO of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non- appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of BECO.

6.2 Representations and Warranties of NEA. NEA hereby represents and warrants to BECO as of the Effective Date as follows:

(a) Organization and Good Standing; Power and Authority. NEA is a limited partnership, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. NEA has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization: No Conflicts. The execution and delivery by NEA of this Agreement, and the performance by NEA of its obligations hereunder, have been duly authorized by all necessary actions on the part of NEA and do not and, under existing facts and law, will not: (i) contravene any of its governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of NEA and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of NEA, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting NEA or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which NEA reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) NEA’s ability to perform its obligations under this Agreement.

- 16 -

(e) Consents and Approvals. The execution, delivery and performance by NEA of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non- appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of NEA.

(g) Other Agreements. NEA has not entered into any (i) agreements for the sale of energy or capacity other than (A) the Existing Agreements and (B) that certain Power Purchase Agreement between NEA and Montaup Electric Company dated October 17, 1986 (the “Montaup PPA”), and (ii) amendment or modification of the Montaup PPA other than as set forth in Schedule 6.2(g).

6.3 PURPA Acknowledgements.

(a) The Parties acknowledge and agree that:

(i) Under the Existing NEA B PPA, NEA was entitled to all rights afforded to a “qualifying facility” (as defined in 18 C.F.R. Part 292) (“QF”) under applicable law, including, but not limited to, PURPA, for as long as the Facility maintained its status as a QF, and

(ii) The consideration for NEA’s agreement to amend and restate the Existing NEA B PPA and to waive its rights under PURPA, as provided in Section 6.3(c) below, is the execution and delivery of this Agreement by BECO.

(b) It is the express intent of the Parties that this Agreement shall be deemed a successor to, replacement of and substitute for the Existing NEA B PPA, which is being amended and restated in its entirety as of the Effective Date.

(c) As of the Effective Date, NEA forever relinquishes and waives any rights it may have or may have in the future under PURPA or any federal or state regulation, act or order implementing PURPA, to require BECO or any of its affiliates to purchase electricity and or capacity generated at the Facility. NEA shall cause any third party successor to NEA’s rights and interest in the Facility to agree to be bound by the foregoing waiver. NEA shall indemnify, defend and hold BECO and its partners, shareholders, members, directors, officers, employees and agents harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever suffered or incurred by BECO arising out of any failure by NEA to comply with the waiver of PURPA rights set forth in this Section 6.3(c).

(d) As of the Effective Date and continuing throughout the Term, each Party hereby irrevocably waives its right to seek or support, and agrees not to seek or support, in any way, including, but not limited to, seeking or supporting through application, complaint, petition, motion, filing before any Governmental Entity (including, without limitation, DTE and FERC), rule, regulation or statute: (i)

- 17 -

reconsideration by DTE of its approval of this Agreement; (ii) modification or invalidation of this Agreement or any term or condition contained herein (including, without limitation, any pricing provision herein); or (iii) disallowance or impairment, in whole or in part, of BECO’s right to fully and timely recover from its customers its costs of purchasing electricity and capacity pursuant to this Agreement.

(e) Nothing contained herein shall be deemed or construed as (i) a waiver by either Party of any right to challenge any attempt by DTE, FERC or any other Governmental Entity to disallow rate recovery or modify, amend or supplement this Agreement or (ii) an acknowledgment by any such Party that DTE, FERC or any other Governmental Entity would have such authority if it so attempted.

(f) As of the Effective Date, NEA’s and BECO’s obligations under this Agreement are expressly not conditioned on the maintenance of the QF status of the Facility under PURPA, and this Agreement shall remain binding upon the Parties without regard to whether the Facility or any other source of power delivered to BECO under this Agreement is, was or remains a QF. Each Party shall obtain and maintain all permits or licenses necessary for it to perform its obligations under this Agreement.

(g) The Parties acknowledge and agree that, to the extent this Agreement is or becomes subject to review pursuant to the Federal Power Act, the standard of review for any change or modification to the pricing provisions of this Agreement proposed by any Person who is not a party hereto or FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “Mobile-Sierra” doctrine).

6.4 Release. The Parties agree to each release the other of all obligations, liabilities and costs arising under the Existing NEA B PPA as of the Effective Date, and to further release each other regarding potential claims against one another and related to differing interpretations of the Existing NEA B PPA (the “PPA and Related Potential Claims”). Such claims include, without limitation, the obligations to deliver, sell, receive and purchase energy and capacity under the Existing NEA B PPA, and disputes related to: (a) the payment for Capacity and Associated Energy (as such terms are defined in the Existing NEA B PPA) delivered by NEA and received by BECO in excess of the Company’s Entitlement (as such term is defined in the Existing NEA B PPA); (b) the application of Article 16(a), as set forth in the Existing NEA B PPA; (c) the allocation of certain congestion charges/credits imposed by the ISO; and (d) the calculation of the Qualifying Facility Power Purchase Rate (as such term is defined in the Existing NEA B PPA). The Parties agree that it is in their mutual best interests to waive such PPA and Related Potential Claims and to release each other from liability thereunder. Therefore, as of the Effective Date, the Parties, intending to be legally bound on behalf of themselves and their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives ABSOLUTELY, IRREVOCABLY, AND UNCONDITIONALLY, FULLY AND FOREVER ACQUIT, RELEASE, AND DISCHARGE AND COVENANT NOT TO SUE each other and any and all of their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives, from any and all claims, causes of action, demands, obligations, charges, complaints, controversies, damages, liabilities, costs, expenses, judgments, guarantees, agreements, or defaults of every and any nature, relating to or arising out of the PPA and Related Potential Claims, whether in law or equity and whether arising in contract (including breach), tort or otherwise, and irrespective of fault, negligence or strict liability, which a Party may have had, or may now have, prior to the Effective Date.

- 18 -

7. RESERVED

8. BREACHES; REMEDIES

8.1 Events of Default: Cure Rights. It shall constitute an event of default (“Event of Default”) hereunder if:

(a) Representation or Warranty. Any representation or warranty set forth herein is not accurate and complete in all material respects as of the date made, unless such inaccuracy or incompleteness is capable of cure by the payment of money and is cured within thirty (30) days after written notice thereof is given by the non-defaulting Party to the defaulting Party, or unless such inaccuracy or incompleteness is not capable of cure by the payment of money, but is otherwise capable of cure, and the Party in default promptly begins and diligently and continuously pursues such cure activity.

(b) Payment Obligations. Any undisputed payment due and payable hereunder is not made on the date due, and such failure continues for more than five (5) Business Days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(c) Other Covenants. Subject to Sections 3.6, 3.7, 3.8, 8.1(g) and 8.1(h) hereof, a Party fails to perform, observe or otherwise to comply with any obligation hereunder and such failure continues for more than thirty (30) days after notice thereof is given by the non-defaulting Party to the defaulting Party, or if such default is not capable of cure within thirty (30) days, the Party in default promptly begins such cure activity within such thirty (30) day period and diligently and continuously pursues the cure activity such that the failure is cured within ninety (90) days after notice thereof is given by the non- defaulting Party to the defaulting Party.

(d) BECO Bankruptcy. BECO (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against BECO under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize BECO pursuant to 11 U.S.C. § 101 or any similar statute applicable to BECO, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of BECO, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of BECO or of a major part of its property.

(e) NEA Bankruptcy. NEA (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against NEA under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize NEA pursuant to 11 U.S.C. § 101 or any similar statute applicable to NEA, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of NEA, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of NEA or of a major part of its property.

- 19 -

(f) Consolidation. A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party.

(g) Continuing Failure by NEA to Deliver Contract Energy or Satisfy the Capacity Requirement. NEA (i) fails to deliver and sell Contract Energy hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by BECO to NEA, or if such failure is not capable of cure within five (5) days, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by BECO to NEA or (ii) fails to satisfy the Capacity Requirement hereunder for a period of one (1) calendar month during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than two (2) calendar months after written notice thereof is given by BECO to NEA, or if such failure is not capable of cure within two (2) calendar months, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by BECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect NEA’s obligation to pay Cover Damages or Capacity Replacement Damages for any day on which NEA fails to deliver Contract Energy or satisfy the Capacity Requirement.

(h) Continuing Failure by BECO to Accept Delivery of Contract Energy or the Capacity Requirement. BECO fails to accept delivery of Contract Energy or the Capacity Requirement hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by NEA to BECO, or if such failure is not capable of cure within five (5) days, BECO promptly begins such cure activity within such five (5) day period and diligently and continuously pursues the cure activity such that the failure is cured within thirty (30) days after notice thereof is given by BECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect BECO’s obligation to pay Resale Damages or Capacity Resale Damages for any day on which BECO fails to accept Contract Energy or the Capacity Requirement.

8.2 Remedies.

(a) Declaration of an Early Termination Date and Calculation of Termination Payments.

(i) BECO Termination Payment.

(A) If an Event of Default with respect to BECO shall have occurred and be continuing, NEA shall have the right (I) to designate a day on which this Agreement will terminate (the “BECO Early Termination Date”), (II) withhold any payments due to BECO under this Agreement and (III) suspend performance. NEA shall calculate, in a commercially reasonable manner, a BECO Termination Payment as of the BECO Early Termination Date. As soon as practicable after termination, notice shall be given by NEA to BECO of the amount of the BECO Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. BECO shall

- 20 -

make the BECO Termination Payment within two (2) Business Days after such notice is effective. If BECO disputes NEA’s calculation of the BECO Termination Payment, in whole or in part, BECO shall, within two (2) Business Days of receipt of the calculation of the BECO Termination Payment, provide to NEA a detailed written explanation of the basis for such dispute; provided, however, BECO shall first transfer Performance Assurance to NEA in an amount equal to the BECO Termination Payment as calculated by NEA.

(B) Notwithstanding the provisions of Section 8.2(a)(i)(A), if on the first occasion that an Event of Default by BECO pursuant to Section 8.1(b) shall have occurred and be continuing, and NEA has exercised its rights under Section 8.2(a)(i)(A) to designate a BECO Early Termination Date, which date shall be no less than twenty (20) Business Days from the date NEA provides BECO with the notice of default under Section 8.1(b), BECO may, within twenty (20) Business Days of such notice, provide NEA with any amounts then due, plus credit support in an amount equal to the aggregate of the payments to be made by BECO pursuant to Article 4 hereof for the subsequent three (3) month period, as calculated in good faith by NEA (and disregarding any suspension of performance by NEA under Section 8.2(a)(i)) (“Credit Support”) in any of the following forms: (I) a letter of credit with an initial term of at least six (6) months issued by a bank or other financial institution reasonably acceptable to NEA, which will allow NEA to draw on the letter of credit up to the full amount upon a subsequent Event of Default by BECO, or (II) such other credit support proposed by BECO that is reasonably acceptable to NEA. If BECO makes such payments and provides such Credit Support, then NEA’s rights under Section 8.2(a)(i) shall no longer be in effect and, if NEA has suspended performance under Section 8.2(a)(i), NEA shall recommence such performance.

(C) In the event of either (I) a subsequent Event of Default by BECO pursuant to Section 8.1(b) and a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B) or (II) a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B), NEA will have all rights as set forth in Section 8.2(a)(i).

(D) BECO shall be relieved of the obligation to maintain such Credit Support to the extent that each of the following shall have occurred: (I) for at least six (6) months BECO shall have provided and maintained the Credit Support in accordance with Section 8.2(a)(i)(B) and there shall have been no drawdown by NEA under such Credit Support on account of a subsequent Event of Default by BECO; (II) BECO’s senior secured Credit Rating, not supported by third party credit enhancements, is at or above BBB-/Stable Outlook from S&P and at or above Baa3, Stable Outlook from Moody’s (or in the event BECO does not have, or no longer has, a senior secured credit rating, its issuer and/or long term debt rating shall be referenced); and (III) no other Event of Default has occurred and is continuing, including an event of Default under Section 8.1(b).

(ii) NEA Termination Payment. If an Event of Default with respect to NEA shall have occurred and be continuing, BECO shall have the right (A) to designate a day on which this Agreement will terminate (the “NEA Early Termination Date”), (B) withhold any payments due to NEA under this Agreement and (C) suspend performance. BECO shall calculate, in a commercially reasonable manner, a NEA Termination Payment as of the NEA Early Termination Date. As soon as practicable after termination, notice shall be

- 21 -

given by BECO to NEA of the amount of the NEA Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. NEA shall make the NEA Termination Payment within two (2) Business Days after such notice is effective. If NEA disputes BECO’s calculation of the NEA Termination Payment, in whole or in part, NEA shall, within two (2) Business Days of receipt of the calculation of the NEA Termination Payment, provide to BECO a detailed written explanation of the basis for such dispute; provided, however, NEA shall first transfer Performance Assurance to BECO in an amount equal to the NEA Termination Payment as calculated by BECO.

(b) Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND All IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

- 22 -

9. FORCE MAJEURE

9.1 Force Majeure.

(a) The term “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under this Agreement, which event or circumstance was not anticipated as of the date this Agreement was agreed to, which is not within the control of, or the result of the negligence of, the Claiming Party or its agents, contractors, suppliers or Affiliates, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided, including storms, floods, earthquakes, tomados, fires, explosions, wars, riots or other civil disturbances, acts of war or acts of a public enemy, strikes, lockout, work stoppage or other industrial disturbances, labor or material shortage, and failure of the plant or plant equipment resulting from such force majeure events. Force Majeure shall not be based on (i) the loss of BECO’s markets; (ii) BECO’s inability economically to use or resell the Contract Energy purchased hereunder; (iii) the loss or failure of NEA’s supply; or (iv) NEA’s ability to sell the Contract Energy at a price greater than the amount provided for in Section 4.1(a).

(b) Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Contract Energy to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in Section 9.1(a) has occurred.

9.2 Notice and Excuse of Performance.

(a) Following a Force Majeure event, if either Party believes that such event will, or is reasonably likely to, adversely affect the performance of its obligations under this Agreement, then as early as commercially practicable but in no event later than two (2) Business Days after the initial occurrence of such event and for contingency planning purposes, such Party shall provide preliminary telephonic notice of the occurrence of a Force Majeure to the other Party promptly followed by written notice on or before the tenth (10th) Business Day after the initial occurrence of such event. Such written notice shall specify the nature and, if known, cause of the Force Majeure, its anticipated effect on the ability of such Party to perform obligations under this Agreement and the estimated duration of any interruption in service or other adverse effects resulting from such Force Majeure and shall be updated or supplemented as necessary to keep the other Party advised of the effect and remedial measures being undertaken to overcome the Force Majeure.

(b) To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under this Agreement and such Party (the “Claiming Party”) gives notice and details of the Force Majeure to the other Party as soon as practicable, then the Claiming Party shall be excused from the performance of its obligations with respect to such obligations (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.

- 23 -

10. DISPUTE RESOLUTION

In the event of any dispute, controversy or claim between the Parties arising out of or relating to this Agreement (collectively, a “Dispute”), the Parties shall attempt in the first instance to resolve such Dispute through friendly consultations between the Parties. If such consultations do not result in a resolution of the Dispute within fifteen (15) Days after notice of the Dispute has been delivered to either Party, then such Dispute shall be referred to the senior management of the Parties for resolution. If the Dispute has not been resolved within fifteen (15) Days after such referral to the senior management of the Parties, then either Party may pursue all of its remedies available hereunder. The Parties agree to attempt to resolve all Disputes promptly, equitably and in a good faith manner. In the event a dispute hereunder is resolved pursuant to arbitration or judicial proceedings, the Party whose position does not prevail in such proceedings shall reimburse all of the other Party’s third party costs (including reasonable attorney’s fees) incurred to prosecute or defend (as the case may be) such proceedings.

11. CONFIDENTIALITY

11.1 Nondisclosure. BECO and NEA each agree not to disclose to any Person and to keep confidential, and to cause and instruct its Affiliates, officers, directors, employees, partners and representatives not to disclose to any Person and to keep confidential, any and all of the following non-public information relating to the terms and provisions of this Agreement; any financial, pricing or supply quantity information relating to the Contract Energy to be supplied by NEA hereunder, the Facility or NEA and any information that is clearly marked or identified as “Confidential”. Notwithstanding the foregoing, any such information may be disclosed: (a) to the extent required by applicable laws and regulations or by any subpoena or similar legal process of any court or agency of federal, state or local government so long as the receiving Party gives the non-disclosing Party written notice at least three (3) Business Days prior to such disclosure, if practicable; (b) to lenders and potential lenders to BECO or to lenders to NEA or other Person(s) in connection with the implementation of this Agreement and to financial advisors, rating agencies, and any other Persons involved in the acquisition, marketing or sale or placement of such debt; (c) to agents, trustees, advisors and accountants of the Parties or their Affiliates involved in the financings described in clause (b) above, (d) to potential assignees of BECO or NEA or other Persons in connection with such proposed assignment and to financial advisors, rating agencies, and any other Persons involved in the marketing, placement or rating of such assignment, (e) to agents, trustees, advisors and accountants of the Parties or their Affiliates or agents, trustees, advisors and accountants of Persons involved in the potential assignment described in clause (d) above or (f) to the extent the non-disclosing Party shall have consented in writing prior to any such disclosure.

11.2 Public Statements. No public statement, press release or other voluntary publication regarding this Agreement shall be made or issued without the prior consent of the other Party, which consent shall not be unreasonably withheld.

- 24 -

12. INDEMNIFICATION AND INDEMNIFICATION PROCEDURES

12.1 Indemnification. Each Party (“Indemnifying Party”) shall indemnify, defend and hold the other Party (“Indemnified Party”) and its partners, shareholders, partners, directors, officers, employees and agents (including, but not limited to, Affiliates and contractors and their employees), harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever related to this Agreement suffered or incurred by such Indemnified Party arising out of the Indemnifying Party’s gross negligence or willful misconduct (including, without limitation, any breach of this Agreement resulting from gross negligence or willful misconduct). In the event injury or damage results from the joint or concurrent grossly negligent or willful misconduct of the Parties, each Party shall be liable under this indemnification in proportion to its relative degree of fault. Such duty to indemnify shall not apply to any claims which arise or are first asserted more than two (2) years after the termination of this Agreement. Such indemnity shall not include or compensate for indirect, punitive, exemplary, incidental or consequential damages incurred by either Party.

12.2 Indemnification Procedures. Each Indemnified Party shall promptly notify the Indemnifying Party of any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12. Such notice shall be given as soon as is reasonably practicable after the Indemnified Party becomes aware of each claim; provided, however, that failure to give prompt notice shall not adversely affect any claim for indemnification hereunder except to the extent the Indemnifying Party’s ability to contest any claim by any third party is materially adversely affected. The Indemnifying Party shall have the right, but not the obligation, at its expense, to contest, defend, litigate and settle, and to control the contest, defense, litigation and/or settlement of, any claim by any third party alleged or asserted against any Indemnified Party arising out of any matter in respect of which such Indemnified Party is entitled to be indemnified hereunder. The Indemnifying Party shall promptly notify such Indemnified Party of its intention to exercise such right set forth in the immediately preceding sentence and shall reimburse the Indemnified Party for the reasonable costs and expenses paid or incurred by it prior to the assumption of such contest, defense or litigation by the Indemnifying Party. The Indemnifying Party shall have the right to select legal counsel to defend a claim for which the Indemnified Party is seeking indemnification pursuant to this Section 12.2, subject to the consent of the Indemnified Party, which shall not be unreasonably delayed or withheld. If the Indemnifying Party exercises such right in accordance with the provisions of this Article 12 and any Indemnified Party notifies the Indemnifying Party that it desires to retain separate counsel in order to participate in or proceed independently with such contest, defense or litigation, such Indemnified Party may do so at its own expense. If the Indemnifying Party fails to exercise it rights set forth in the third sentence of this Section 12.2, then the Indemnifying Party will reimburse the Indemnified Party for its reasonable costs and expenses incurred in connection with the contest, defense or litigation of such claim. No Indemnified Party shall settle or compromise any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12 without the prior written consent of the Indemnifying Party; provided, however, that such consent shall not be unreasonably withheld by the Indemnifying Party.

- 25 -

13. ASSIGNMENT

13.1 Prohibition on Assignment. Except as provided in Section 13.2 hereof, this Agreement may not be assigned by either Party without the prior written consent of the other Party, which may not be unreasonably withheld. Any attempted or purported assignment of this Agreement that is not expressly permitted pursuant to Section 13.2 hereof shall be null and void and shall have no effect on or with respect to the rights and obligations of the Parties hereunder.

13.2 Permitted Assignment.

(a) NEA shall have the right to assign all or any portion of its rights or obligations under this Agreement without the consent of BECO solely for financing purposes to existing and any future lenders secured, in whole or in part, by interests in the Facility, NEA’s contractual rights, or NEA or Affiliates of NEA. Such assignment to lenders shall not operate to relieve NEA of any duty or obligation under this Agreement. In connection with the exercise of remedies under the security documents relating to such financing(s), the lender(s) or trustee(s) shall be entitled to assign this Agreement to any third-party transferee designated by such lender(s) or trustee(s), provided that BECO determines, in BECO’s reasonable discretion, that such proposed transferee or assignee is qualified and capable to satisfy NEA’s obligations hereunder.

(b) BECO shall have the right to assign this Agreement in connection with a BECO Reorganization Event to any assignee without the consent of NEA so long as (i) the proposed assignee serves toad in NEPOOL and (ii) the proposed assignee’s credit rating as established by Moody’s or S&P is equal to or better than that of BECO at the time of the proposed assignment (provided, that any such rating that is on “watch” for downgrading shall not satisfy the credit rating criteria described in clause (ii)).

(c) If either Party assigns this Agreement as provided in this Section 13.2, then such Party shall cause to be delivered to the other Party an assumption agreement (in form and substance reasonably satisfactory to the non-assigning Party) of all of the obligations of the assigning Party hereunder by such assignee.

(d) An assignment of this Agreement pursuant to this Section 13.2 shall not release or discharge the assignor from its obligations hereunder unless the assignee executes a written assumption agreement in accordance with Section 13.2(c) hereof.

14. NOTICES

Any notice or communication given pursuant hereto shall be in writing and (1) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (2) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); (3) e-mailed (e-mailed notices shall be deemed given upon actual receipt) or (4) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designed by either Party to the other in writing:

- 26 -

If to BECO:

Boston Edison Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

Copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

With a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

15. WAIVER AND MODIFICATION

This Agreement may be amended and its provisions and the effects thereof waived only by a writing executed by the Parties, and no subsequent conduct of any Party or course of dealings between the Parties shall effect or be deemed to effect any such amendment or waiver. No waiver of any of the

- 27 -

provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. The failure of either Party to enforce any provision of this Agreement shall not be construed as a waiver of or acquiescence in or to such provision.

16. INTERPRETATION

16.1 Choice of Law. Interpretation and performance of this Agreement shall be in accordance with, and shall be controlled by, the laws of the Commonwealth of Massachusetts (without regard to its principles of conflicts of law).

16.2 Headings. Article and Section headings are for convenience only and shall not affect the interpretation of this Agreement. References to articles, sections and appendices, and schedules are, unless the context otherwise requires, references to articles, sections, appendices, and schedules of this Agreement. The words “hereof” and “hereunder” shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

17. COUNTERPARTS

Any number of counterparts of this Agreement may be executed, and each shall have the same force and effect as an original.

18. NO DUTY TO THIRD PARTIES

Except as provided in any consent to assignment of this Agreement, nothing in this Agreement nor any action taken hereunder shall be construed to create any duty, liability or standard of care to any Person not a Party to this Agreement.

19. SEVERABILITY

If any term or provision of this Agreement or the interpretation or application of any term or provision to any prior circumstance is held to be unenforceable, illegal or invalid by a court or agency of competent jurisdiction, the remainder of this Agreement and the interpretation or application of all other terms or provisions to Persons or circumstances other than those which are unenforceable, illegal or invalid shall not be affected thereby, and each term and provision shall be valid and be enforced to the fullest extent permitted by law.

20. ENTIRE AGREEMENT

Upon the Effective Date, this Agreement, together with the agreements executed or delivered on the Effective Date in connection herewith, shall constitute the entire agreement and understanding between the Parties hereto and shall supersede all prior agreements including, without limitation, the Existing NEA B PPA and understandings relating to the subject matter hereof.

21. CHANGE IN LAW OR MARKET STRUCTURE

The Parties acknowledge that this Agreement is based on the Laws, ISO Policies and market structure in effect as of the Agreement Date. In the event of a Change in Law or Market Structure, the Parties shall make such amendments to this Agreement as are necessary to accommodate such Change in Law or Market Structure, provided that any such amendments shall preserve the economic and business arrangements embodied or referenced in this Agreement.

- 28 -

IN WITNESS WHEREOF, each of BECO and NEA has caused this Agreement to be duly executed on its behalf as of the data first above written.

Boston Edison Company
By:	/s/ Ellen K. Angley
Name:	Ellen K. Angley
Tite:	VP Energy Supply & Transmission
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General, Partner
By:	/s/ Nathan E. HANSON
	Authorized Representative
	Nathan E. Hanson

- 29 -

SCHEDULE 3.3

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

DELIVERY SCHEDULE FOR CONTRACT ENERGY

Month	MWh/h
January	90.0000
February	90.0000
March	90.0000
April	90.0000
May	60.0000
June	60.0000
July	70.0000
August	70.0000
September	70.0000
October	90.0000
November	80.0000
December	80.0000

- 30 -

SCHEDULE 4.1(a)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

- 31 -

Month Ending	No. of Days	MWh/hr BECO B	MWhs BECO B	Monthly Support Payment Price ($/MWh) BECO B
04/30/04	30	90.0000	64,800.0000
05/31/04	31	60.0000	44,640.0000
06/30/04	30	60.0000	43,200.0000
07/31/04	31	70.0000	52,080.0000
08/31/04	31	70.0000	52,080.0000
09/30/04	30	70.0000	50,400.0000
10/31/04	31	90.0000	66,960.0000
11/30/04	30	80.0000	57,600.0000
12/31/04	31	80.0000	59,520.0000
01/31/05	31	90.0000	66,960.0000
02/28/05	28	90.0000	60,480.0000
03/31/05	31	90.0000	66,960.0000
04/30/05	30	90.0000	64,800.0000
05/31/05	31	60.0000	44,640.0000
06/30/05	30	60.0000	43,200.0000
07/31/05	31	70.0000	52,080.0000
08/31/05	31	70.0000	52,080.0000
09/30/05	30	70.0000	60,400.0000
10/31/05	31	90.0000	66,960.0000
11/30/05	30	80.0000	57,600.0000
12/31/05	31	80.0000	59,520.0000
01/31/06	31	90.0000	66,960.0000
02/28/06	28	90.0000	60,480.0000
03/31/06	31	90.0000	66,960.0000
04/30/06	30	90.0000	64,800.0000
05/31/06	31	60.0000	44,640.0000
06/30/06	30	60.0000	43,200.0000
07/31/06	31	70.0000	52,080.0000
08/31/06	31	70.0000	52,080.0000
09/30/06	30	70.0000	60,400.0000
10/31/06	31	90.0000	66,960.0000
11/30/06	30	80.0000	57,600.0000
12/31/06	31	80.0000	59,520.0000
01/31/07	31	90.0000	66,960.0000
02/28/07	28	90.0000	60,480.0000
03/31/07	31	90.0000	66,960.0000
04/30/07	30	90.0000	64,800.0000
05/31/07	31	60.0000	44,640.0000
06/30/07	30	60.0000	43,200.0000
07/31/07	31	70.0000	52,080.0000
08/31/07	31	70.0000	52,080.0000
09/30/07	30	70.0000	50,400.0000
10/31/07	31	90.0000	66,960.0000
11/30/07	30	80.0000	57,600.0000
12/31/07	31	80.0000	59,520.0000
01/31/08	31	90.0000	66,960.0000
02/29/08	29	90.0000	62,640.0000
03/31/08	31	90.0000	66,960.0000
04/30/08	30	90.0000	64,800.0000
05/31/08	31	60.0000	44,640.0000
06/30/08	30	60.0000	43,200.0000

- 32 -

Month Ending	No. of Days	MWh/hr BECO B	MWhs BECO B	Monthly Support Payment Price ($/MWh) BECO B
07/31/08	31	70.0000	52,080.0000
08/31/08	31	70.0000	52,080.0000
09/30/08	30	70.0000	50,400.0000
10/31/08	31	90.0000	66,960.0000
11/30/08	30	80.0000	57,600.0000
12/31/08	31	80.0000	59,520.0000
01/31/09	31	90.0000	66,960.0000
02/28/09	28	90.0000	60,480.0000
03/31/09	31	90.0000	66,960.0000
04/30/09	30	90.0000	64,800.0000
05/31/09	31	60.0000	44,640.0000
06/30/09	30	60.0000	43,200.0000
07/31/09	31	70.0000	52,080.0000
08/31/09	31	70.0000	52,080.0000
09/30/09	30	70.0000	50,400.0000
10/31/09	31	90.0000	66,960.0000
11/30/09	30	80.0000	57,600.0000
12/31/09	31	80.0000	59,520.0000
01/31/10	31	90.0000	66,960.0000
02/28/10	28	90.0000	60,480.0000
03/31/10	31	90.0000	66,960.0000
04/30/10	30	90.0000	64,800.0000
05/31/10	31	60.0000	44,640.0000
06/30/10	30	60.0000	43,200.0000
07/31/10	31	70.0000	52,080.0000
08/31/10	31	70.0000	52,080.0000
09/30/10	30	70.0000	50,400.0000
10/31/10	31	90.0000	66,960.0000
11/30/10	30	80.0000	57,600.0000
12/31/10	31	80.0000	59,520.0000
01/31/11	31	90.0000	66,960.0000
02/28/11	28	90.0000	60,480.0000
03/31/11	31	90.0000	66,960.0000
04/30/11	30	90.0000	64,800.0000
05/31/11	31	60.0000	44,640.0000
06/30/11	30	60.0000	43,200.0000
07/31/11	31	70.0000	52,080.0000
08/31/11	31	70.0000	52,080.0000
09/30/11	15	70.0000	25,200.0000
10/31/11	31	0.0000	0.0000

- 33 -

SCHEDULE 4.1(c)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

LIST OF APPROVED CAPACITY BUYERS

Constellation Power Source, Inc.

J Aron & Company

Morgan Stanley Group Capital

PP&L Energy Plus, LLC

PSE&G Energy Resources & Trading, LLC

Select Energy, Inc.

Sempra Energy Trading Corp.

TransCanada Power Marketing Ltd.

- 34 -

EX-10.20

EXHIBIT 10.20

AMENDED AND RESTATED POWER PURCHASE AGREEMENT

THIS AMENDED AND RESTATED POWER PURCHASE AGREEMENT (the “Agreement”) is entered into as of August 19, 2004 (the “Agreement Date”), by and between Commonwealth Electric Company, a Massachusetts corporation (“CECO”) and Northeast Energy Associates Limited Partnership, a Massachusetts limited partnership (“NEA”). CECO and NEA are individually referred to herein as a “Party” and are collectively referred to herein as the “Parties”.

WHEREAS, NEA owns a nominal 300 MW natural gas-fired electricity and steam generating plant located in Bellingham, Massachusetts (the “Facility”);

WHEREAS, CECO and NEA are parties to a certain Power Purchase Agreement dated November 26, 1986, as amended to date (the “Existing CECO 1 PPA”), pursuant to which CECO purchases from NEA a portion of the Facility’s capacity and associated energy;

WHEREAS, CECO and NEA desire to amend and restate the Existing CECO 1 PPA as provided form herein; and

WHEREAS, such amendment and restatement of the Existing CECO 1 PPA is consistent with CECO’s invitation, dated October 17, 2003, to submit proposals regarding the transfer of entitlements to certain power purchase agreements and NEA’s response, dated December 3, 2003, related to the restructuring of four (4) power purchase agreements (including the Existing CECO 1 PPA) existing between NEA and each of CECO and Boston Edison Company (“BECO”) (the four (4) existing agreements, the “Existing Agreements”, are set forth at Exhibit A).

NOW, THEREFORE, in consideration of the premises and of the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1. DEFINITIONS

In addition to terms defined in the recitals hereto, the following terms shall have the meanings set forth below.

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries’ controls, is controlled by, or is under common control with, such first Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall have the meaning set forth in the first paragraph of this Agreement.

“Agreement Date” shall have the meaning set forth in the first paragraph of this Agreement.

“Approved Capacity Buyer” shall mean any of the Persons set forth on Schedule 4.1(c) hereto.

“Business Day” shall mean any day that is not a Saturday, Sunday, or NERC Holiday.

“Capacity” shall mean “Unforced Capacity” as presently defined in the NEPOOL Manual for Definitions and Abbreviations (and, throughout the Term, any successor product thereto).

“Capacity Payment” with respect to any given time period, shall mean the product of (a) the Capacity Price and (b) Capacity Requirement, for such period.

“Capacity Price” with respect to any month, shall mean (a) the Negotiated Capacity Price or (b) in the event that the Parties fail to agree upon a Negotiated Capacity Price on or before the Contract UCAP Transfer Deadline, the price for UCAP for such month established pursuant to the next UCAP Monthly Supply Auction; provided, however, if no price for UCAP is established in the next UCAP Monthly Supply Auction, the price to be used is that established pursuant to the last UCAP Monthly Supply Auction in which UCAP was transacted.

“Capacity Receipt Shortfall” shall have the meaning set forth in Section 3.8(c) hereof.

“Capacity Replacement Damages” shall have the meaning ascribed thereto in Section 3.8(b) herein.

“Capacity Replacement Price” with respect to any portion of the Capacity Requirement that NEA fails to deliver to CECO hereunder, shall mean (a) the price at which CECO, acting in a commercially reasonable manner, purchases Capacity in lieu of such portion of the Capacity Requirement, plus transaction and other administrative costs reasonably incurred by CECO in purchasing such Capacity, or (b) to the extent CECO has not purchased Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Requirement” shall mean for the applicable month, for so long as NEA is the owner of the Facility during the Term hereof, the lesser of (a) 20 MW or (b) 10% of the Capacity recognized by the ISO as attributable to the Facility. Upon the sale, assignment or transfer by NEA of its interest in the Facility during the Term hereof, Capacity Requirement shall be fixed at the Capacity Requirement in effect on the date immediately prior to such sale, assignment or transfer.

“Capacity Resale Damages” shall have the meaning ascribed thereto in Section 3.8(c) herein.

“Capacity Resale Price” with respect to any portion of the Capacity Requirement that CECO fails to accept delivery from NEA hereunder, shall mean (a) the price at which NEA, acting in a commercially reasonable manner, re-sells Capacity in lieu of such portion of the Capacity Requirement, less transaction and other administrative costs reasonably incurred by NEA in selling such Capacity or (b) to the extent NEA has not sold Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Supply Shortfall” shall have the meaning set forth in Section 3.8(b) hereof.

- 2 -

“CECO Reorganization Event” shall mean (a) any consolidation, merger or other form of combination of CECO with any other Person, (b) the acquisition of a majority of the outstanding shares of CECO by any Person or (c) the sale, conveyance, lease, transfer or other disposition, in one transaction or a series of related transactions, including without limitation the transfer or “spin-off” of shares of a subsidiary (collectively, a “Transfer”), affecting all or substantially all of the assets of CECO existing on the Agreement Date or hereafter acquired. For purposes of this definition, the transfer, sale or other disposition of all or substantially all of the transmission and/or distribution assets of CECO, will, in either case, constitute a “CECO Reorganization Event.”

“CECO Termination Payment” shall mean, with respect to this Agreement and NEA, an amount payable by CECO to NEA equal to the sum of the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which NEA incurs as a result of the termination of this Agreement pursuant to Section 8.2 (a)(i) hereof.

“Change in Law or Market Structure” shall mean any of the following events that has a material adverse economic effect on one or both of the Parties: (a) the adoption, promulgation, modification, repeal or reinterpretation by any Governmental Entity of any Law which (or the effects of which) amends or conflicts with the Laws established or in effect as of the Agreement Date, (b) the adoption, promulgation, modification, repeal or reinterpretation by ISO of the ISO Policies which (or the effect of which) amends or conflicts with the ISO Policies established or in effect as of the Agreement Date or (c) the adoption or promulgation of a market structure that differs from the market structure reflected in the ISO Policies established or in effect as of the Agreement Date. For avoidance of doubt, a Change in Law or Market Structure shall include any event described in clauses (a), (b) or (c) above that results in CECO not being able to sell the Contract Energy purchased hereunder at a price greater than or equal to the Energy Payment prices (excluding the Support Payment) paid to NEA hereunder.

“Claiming Party” shall have the meaning set forth in Section 9.2(b) hereof.

“Contract Energy” shall have the meaning set forth in Section 3.1 hereof.

“Contract UCAP Transfer Deadline” with respect to any month, shall mean 5 PM Eastern Prevailing Time on the Business Day preceding the day by which final bids into the NEPOOL ISO Supply Auction must be submitted to be considered timely under the NEPOOL Practices and Market Rules and Procedures governing suppliers” participation in the UCAP Monthly Supply Auction.

“Costs” shall mean brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred in terminating this Agreement; and all reasonable attorneys’ fees and expenses incurred in connection with the termination of this Agreement.

“Cover Damages” shall have the meaning set forth in Section 3.6 hereof.

“Credit Support” shall have the meaning set forth in Section 8.2(a)(i)(B) hereof.

“Day-Ahead Energy Market” or “DAM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

- 3 -

“Delivery Point” shall mean the Facility Bus; provided, however, that (a) if a LMP is not established for a node at the Facility Bus, or during periods of Force Majeure, NEA may deliver Contract Energy to an alternate node within the ISO control area that has a published LMP price and (b) NEA may deliver to any other delivery point mutually agreed to by the Parties.

“Delivery Shortfall” shall have the meaning set forth in Section 3.6 hereof.

“DTE” shall mean the Massachusetts Department of Telecommunications and Energy or its successor state regulatory agency.

“Eastern Prevailing Time” shall mean either Eastern Standard Time or Eastern Daylight Savings Time, as in effect from time to time.

“Effective Date” shall have the meaning set forth in Section 2.1 hereof.

“Energy Payment” shall have the meaning set forth in Section 4.1 (a)(i) hereof.

“Event of Default” shall have the meaning set forth in Section 8.1 hereof.

“Existing Agreements” shall have the meaning set forth in the Recitals.

“Execution Agreement” shall mean the Execution Agreement by and among NEA, BECO and CECO dated as of August 19, 2004.

“Existing CECO 1 PPA” shall have the meaning set forth in the Recitals.

“Facility” shall have the meaning set forth in the Recitals.

“Facility Bus” shall mean the point of interconnection between the Facility and the NEPOOL transmission system, which as of the Agreement Date is the UN.Bellinghm 13.2 NEA bus.

“FERC” shall mean the United States Federal Energy Regulatory Commission, and shall include its successors.

“Force Majeure” shall have the meaning set forth in Section 9.1(a) hereof.

“Gains” shall mean an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic benefit, if any (exclusive of Costs) resulting from the termination of this Agreement, determined in a commercially reasonable manner.

“Governmental Entity” shall mean any federal, state or local governmental agency, authority, department, instrumentality or regulatory body, and any court or tribunal, with jurisdiction over NEA, CECO or the Facility.

“IBT Containers” shall have the meaning as set forth in Section 3.3(a) hereof.

- 4 -

“Indemnified Party” shall have the meaning set forth in Section 12.1 hereof.

“Indemnifying Party” shall have the meaning set forth in Section 12.1 hereof.

“Internal Bilateral Transaction” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO” or ISO-NE” shall mean the ISO New England, Inc., the independent system operator established in accordance with the NEPOOL Agreement, or its successor.

“ISO Policies” shall mean the Market Rules and Procedures, NEPOOL Agreement, NEPOOL Manual for Definitions and Abbreviations and NEPOOL Practices.

“ISO Settlement Market System” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO UCAP Transfer Deadline” with respect to any month, shall mean the latest date upon which Capacity for that month may be transferred under an Internal Bilateral Transaction in accordance with ISO rules.

“Late Payment Rate” shall have the meaning set forth in Section 4.3 hereof.

“Law” shall mean all federal, state and local statutes, regulations, rules, orders, executive orders, decrees, policies, judicial decisions and notifications.

“Lead Participant” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“LMP” shall mean, for any ISO nodal point for any hour on any day, the “Day Ahead LMP” or “Real Time LMP” ($/MWh) at such ISO nodal point calculated in accordance with Section 2 of Market Rule 1, as reported on the ISO website at www.iso-ne.com on the “Data & Reports” page, “Hourly Markets Data” subpage and “Selectable Hourly LMP Data” category, for such nodal point on such date and time. If such price should ever cease to be published, then the LMP shall be a regularly published comparable substitute price, as agreed to by the Parties in writing.

“Losses” shall mean, with respect to any Party, an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic loss to it, if any (exclusive of Costs), resulting from termination of this Agreement, determined in a commercially reasonable manner.

“Market Rules and Procedures” shall mean the Market Rules, Manuals and Procedures adopted by the ISO and/or members of NEPOOL, as may be amended from time to time, and as administered by the ISO to govern the operation of the NEPOOL markets, and any applicable successor rules, manuals and procedures.

“Moody’s” shall mean Moody’s Investors Service, Inc., and any successor thereto.

“MW” shall mean a megawatt.

- 5 -

“MWh” shall mean a megawatt-hour (one MWh shall equal 1,000 kWh).

“NEA Termination Payment” shall mean, with respect to this Agreement and CECO, an amount payable by NEA to CECO equal to the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which CECO incurs as a result of the termination of this Agreement pursuant to Section 8.2 (a)(ii) hereof.

“Negotiated Capacity Price” shall mean the price for Capacity as agreed to by the Parties pursuant to Section 4.1(b) herein.

“NEPOOL” shall mean the New England Power Pool, or its successor.

“NEPOOL Agreement” shall mean that certain Restated New England Power Pool Agreement, as restated by an amendment dated as of December 1, 1996, as amended and restated from time to time, and any applicable successor agreement.

“NEPOOL ISO Supply Auction” shall mean the auction currently defined as the “Supply Auction” in the Market Rules and Procedures, or any successor to such auction.

“NEPOOL Manual for Definitions and Abbreviations” shall mean that certain Manual for Definitions and Abbreviations prepared by ISO-NE, as may be amended from time to time, and any applicable successor manual.

“NEPOOL Practices” shall mean the NEPOOL practices and procedures for delivery and transmission of electricity and capacity and capacity testing in effect from time to time and shall include, without limitation, applicable requirements of the NEPOOL Agreement, and any applicable successor practices and procedures.

“NERC Holiday” shall mean New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day, and any other day declared a holiday by NERC.

“Ownership Share” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Party” and “Parties” shall have the meaning set forth in the first paragraph of this Agreement.

“Performance Assurance” shall mean collateral in the form of either cash, letter(s) of credit, or other security acceptable to the requesting Party.

“Person” shall mean an individual, partnership, corporation, limited liability company, limited liability partnership, limited partnership, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof.

“PURPA” shall mean the Public Utility Regulatory Policies Act of 1978, as amended.

“QF” shall have the meaning set forth in Section 6.3(a)(i) hereof.

- 6 -

“Quote Period” shall have the meaning set forth in Section 4.1(b) herein.

“Real-Time Energy Market” or “RTM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Rejected Power” shall have the meaning set forth in Section 3.7 hereof.

“Replacement Power” shall mean electricity purchased by CECO and delivered to the Delivery Point as replacement for any Delivery Shortfall. Replacement Power shall not include Contract Energy delivered to CECO on behalf of NEA pursuant to Section 3.1 hereof.

“Replacement Price” shall mean the lesser of (a) the price at which CECO, acting in a commercially reasonable manner, purchases Replacement Power, plus (i) transaction and other administrative costs reasonably incurred by CECO in purchasing such Replacement Power and (ii) additional transmission charges, if any, reasonably incurred by CECO to transmit Replacement Power to the Delivery Point, or (b) the locational marginal pricing at the Delivery Point for such Replacement Power; provided, however, that in no event shall the Replacement Price include any penalties; ratcheted demand or similar charges, nor shall CECO be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize NEA’s liability.

“Resale Damages” shall have the meaning set forth in Section 3.7 hereof.

“Resale Price” shall mean the higher of (a) the price at which NEA, acting in a commercially reasonable manner, sells or is paid for Rejected Power, plus transaction and other administrative costs reasonably incurred by NEA in re-selling such Rejected Power; or (b) the LMP at the Delivery Point for such Rejected Power; provided, however, that in no event shall such price include any penalties, ratcheted demand or similar charges, and further provided that in no event shall NEA be required to utilize or change its utilization of the Facility or its other assets or market positions in order to minimize CECO’s liability for Rejected Power.

“Schedule or Scheduling” shall mean the actions of NEA or CECO and/or their designated representatives, including each Party’s Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity of Contract Energy to be delivered on any given day or days (or in any given hour or hours) during the Term at the Delivery Point.

“S&P” shall mean Standard & Poor’s Ratings Group, a division of McGraw Hill, Inc., and any successor thereto.

“Support Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Term” shall have the meaning set forth in Section 2.2 hereof.

“Third-Party Quote” with respect to any Capacity Requirement, shall mean a firm offer by an Approved Capacity Buyer to purchase Capacity from CECO in a volume and for a time period equal to such Capacity Requirement.

- 7 -

“Transmission Provider” shall mean (a) ISO, its respective successor or Affiliates; (b) NEPOOL; (c) CECO; or (d) such other third parties from whom transmission services are necessary for NEA to fulfill its performance obligations to CECO hereunder.

“UCAP” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“UCAP Monthly Supply Auction” shall mean the auction currently defined as the “UCAP Monthly Auction” in the NEPOOL Manual for Definitions and Abbreviations, or any successor to such auction that establishes a price for UCAP or its successor product.

2. EFFECTIVE DATE; CONDITIONS; TERM

2.1 Effective Date. The “Effective Date” of this Agreement shall be the Closing Date as established under the Execution Agreement.

2.2 Term.

(a) The “Term” of this Agreement shall mean the period from and including 11:59 p.m. (Eastern Prevailing Time) on the Effective Date through and including 11:59 p.m. (Eastern Prevailing Time) on September 15, 2016, unless this Agreement is sooner terminated in accordance with the provisions hereof.

(b) At the expiration of the Term, the Parties shall no longer be bound by the terms and provisions hereof (including, without limitation, any payment obligation hereunder), except (i) to the extent necessary to provide invoices and make payments or refunds with respect to Contract Energy or Capacity delivered prior to such expiration or termination, (ii) to the extent necessary to enforce the rights and the obligations of the Parties arising under this Agreement before such expiration or termination and (iii) the obligations of the Parties hereunder with respect to confidentiality and indemnification shall survive the expiration or termination of this Agreement and shall continue for a period of two (2) calendar years following such expiration or termination.

- 8 -

3. DELIVERY OF CONTRACT ENERGY AND CAPACITY

3.1 Obligation to Sell and Purchase Contract Energy. During each hour of the Term, NEA shall sell and deliver at the Delivery Point, and CECO shall purchase and receive at the Delivery Point, electricity in the amounts set forth in Section 3.3 and otherwise in accordance with the terms and conditions of this Agreement (“Contract Energy”). NEA shall be permitted to satisfy its obligation to deliver Contract Energy from any source of supply available to NEA. Contract Energy delivered to CECO by NEA or on behalf of NEA by NEA’s suppliers, designees or any other Person engaged by NEA to deliver Contract Energy shall be deemed delivered by NEA hereunder and NEA shall be solely responsible for any costs payable to its suppliers for such delivery. The aforementioned obligations for NEA to sell and deliver the Energy and for CECO to purchase and receive the Energy shall be firm and subject to adjustment only to reflect performance interruptions excused by this Agreement.

3.2 Characteristics. Contract Energy delivered by NEA to CECO at the Delivery Point shall be in the form of three (3)-phase, sixty (60) hertz, alternating current and otherwise in the form required by Market Rules and Procedures.

3.3 Scheduling.

(a) NEA shall Schedule deliveries of Contract Energy delivered hereunder with ISO in equal hourly quantities in accordance with all NEPOOL Practices and Market Rules and Procedures applicable thereto as set forth in Schedule 3.3. Furthermore, Contract Energy will be sold and delivered for purchase by CECO in the form of Internal Bilateral Transactions (“IBTs”) and NEA will use commercially reasonable efforts to transfer Contract Energy in the DAM; provided, however, that if such transfer cannot be made in the DAM, the Contract Energy shall be transferred in the RTM. All Contract Energy will be delivered to a specific node and not a zone. NEA will submit IBT Containers, as defined below, and notify CECO that the IBT Containers have been submitted into the ISO Settlement Market System. Subject to the satisfaction of NEA’s obligations in this Section 3.3, CECO will confirm the IBT Container in the ISO Settlement Market System. For purposes of this Agreement, “IBT Container” shall mean the form of electronic contract submittal, as implemented in the ISO Settlement Market System effective March 1, 2003 as amended from time to time, that requires CECO to confirm the general parameters of the IBT. IBTs shall be submitted and confirmed for the longest term permitted by the ISO. NEA shall be responsible for any inaccuracies in any schedules and shall correct such schedules upon notification by CECO; provided, however, CECO shall cooperate with NEA in connection with any such Scheduling and bidding and in complying with all NEPOOL Practices and shall promptly provide information reasonably requested by NEA for the purpose of assisting NEA with its Scheduling obligations hereunder. Notwithstanding the agreement to Schedule all Contract Energy in the DAM, the Energy Payment made by CECO to NEA shall be as calculated pursuant to Section 4.1(a) hereof.

(b) The Parties agree to use commercially reasonable efforts to comply with all applicable ISO Policies in connection with the Scheduling and delivery of Contract Energy hereunder. For administrative convenience, the Parties agree that all Contract Energy deliveries and receipts made pursuant to this Agreement and any other power purchase agreement between the Parties may be provided for in a single Schedule. Penalties or similar charges assessed by a Transmission Provider and caused by a Party’s noncompliance with the Scheduling obligations set forth in this Section 3.3 shall be the responsibility of the Party whose action or inaction caused the penalty.

- 9 -

3.4 Lead Participant; Ownership Share. NEA, or any entity so identified by NEA, shall be the Lead Participant of the Facility and CECO shall use commercially reasonable efforts to transfer such designation to NEA or the entity so identified by NEA. CECO shall use commercially reasonable efforts to transfer to NEA, or any entity so identified by NEA, the Ownership Share now held by CECO relating to the Facility.

3.5 Sales for Resale. All Contract Energy delivered by NEA to CECO hereunder shall be sales for resale, with CECO reselling such Contract Energy. CECO shall provide NEA with any certificates reasonably requested by NEA to evidence that the deliveries of Contract Energy hereunder are sales for resale. Nothing in this Agreement shall be construed to prohibit or restrict such resale by CECO.

3.6 Failure of NEA to Deliver Scheduled Contract Energy; Cover Damages.

Subject to Section 8.1(g) hereof, in the event NEA fails to deliver Contract Energy it is obligated to deliver hereunder and such failure is not excused under the terms of this Agreement (such undelivered Contract Energy to be referred to herein as the “Delivery Shortfall”), then NEA shall pay CECO, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Delivery Shortfall equal to the Cover Damages. “Cover Damages” means an amount equal to (i) the amount, if any, by which (A) the Replacement Price ($/MWh) multiplied by the quantity (in MWh) of the Delivery Shortfall, exceeds (B) the Energy Payment that would have been paid pursuant to Section 4.1 hereof had the Delivery Shortfall been delivered, plus (ii) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against CECO as a direct result of NEA’s failure to deliver such Contract Energy; provided, however, CECO shall use commercially reasonable efforts to purchase replacement power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(g) and 8.2 hereof, the damages provided in this Section 3.6 shall be the sole and exclusive remedy of CECO for any failure of NEA to deliver Contract Energy that it is obligated to deliver hereunder. The invoice for the amount payable pursuant to this Section 3.6 shall include a written statement explaining in reasonable detail the calculation of such amount.

3.7 Failure by CECO to Accept Delivery of Contract Energy; Resale Damages. If CECO fails to accept all or part of the Contract Energy it is obligated to accept hereunder and such failure to accept is not excused under the terms of this Agreement (such Contract Energy is referred to herein as “Rejected Power”), then CECO shall pay NEA, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Rejected Power equal to the Resale Damages. “Resale Damages” means an amount equal to (a) the amount, if any, by which (i) the Energy Payment that would have been paid pursuant to Section 4.1(a) hereof for such Rejected Power, had it been accepted, exceeds (ii) the Resale Price ($/MWh) multiplied by the quantity (in MWh) of Rejected Power resold by NEA, plus (b) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of CECO’s failure to accept such Contract Energy; provided, however, NEA shall use commercially reasonable efforts to sell such Rejected Power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(h) and 8.2 hereof, the damages provided in this Section 3.7 shall be the sole and exclusive remedy of NEA for any failure of CECO to accept delivery of Contract Energy that it is obligated to accept hereunder. The invoice for the amount payable pursuant to this Section 3.7 shall include a written statement explaining in reasonable detail the calculation of such amount.

- 10 -

3.8 Obligation to Sell and Purchase Capacity Requirements.

(a) During the Term, NEA shall sell to CECO and CECO shall purchase from NEA the Capacity Requirement. In the event there is no longer a market for Capacity in New England, NEA shall not be obligated to sell and CECO shall not be obligated to purchase the Capacity Requirement.

(i) For so long as NEA is the owner of the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement only from the Facility. In the event that NEA sells, assigns or transfers its interests in the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement from any source of supply available to NEA. Nothing in this Agreement shall be construed to restrict or bar NEA from any sale, assignment or transfer of its interests in the Facility.

(ii) The Parties acknowledge that as of the Agreement Date, the Market Rules and Procedures do not impose any locational requirement with respect to Capacity. In the event that, at any time during the Term, the Market Rules and Procedures do impose a zonal, nodal or other geographic locational requirement, the Capacity Requirement will be fulfilled for the zone, node or other geographic area in which the Facility is located.

(b) If NEA fails to provide CECO with all or part of the Capacity Requirement it is required to provide pursuant to Section 3.8 (a) hereof (a “Capacity Supply Shortfall”) and such failure is not excused under the terms of this Agreement, then the Capacity Replacement Damages associated with such Capacity Supply Shortfall shall be deducted from amounts payable by CECO hereunder for the next succeeding month or paid by NEA to CECO, at CECO’s election. “Capacity Replacement Damages,” with respect to any portion of the Capacity Requirement that NEA fails to deliver to CECO hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Replacement Price exceeds the Capacity Price, multiplied by the Capacity Supply Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against CECO as a direct result of NEA’s failure to deliver the Capacity Requirement in accordance with Section 3.8 (a) hereof. Subject to Section 8.1(g) hereof, the damages provided in this Section 3.8(b) shall be the sole and exclusive remedy of CECO for any failure of NEA to deliver the Capacity Requirement hereunder. With respect to any calendar month during the Term, NEA will be deemed to have failed to deliver the Capacity Requirement for such calendar month if it has not scheduled a bilateral transfer of the Capacity Requirement (or otherwise effected delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

(c) If CECO fails to accept delivery of all or part of the Capacity Requirement it is required to purchase pursuant to Section 3.8 (a) hereof (a “Capacity Receipt Shortfall”), and such failure is not excused under the terms of this Agreement, then the Capacity Resale Damages associated with such Capacity Receipt Shortfall shall be payable by CECO on the date payment would otherwise be due in respect of the month in which the failure occurred. “Capacity Resale Damages,” with respect to any portion of the Capacity Requirement that CECO fails to accept delivery of from NEA hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Price exceeds the Capacity Resale Price, multiplied by the Capacity Receipt Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of CECO’s failure to accept delivery of the Capacity Requirement

- 11 -

in accordance with Section 3.8(a) hereof. Subject to Section 8.1(h) hereof, the damages provided in this Section 3.8(c) shall be the sole and exclusive remedy of NEA for any failure of CECO to accept delivery of the Capacity Requirement hereunder and there shall be no adjustment of the Energy Payment or Support Payment as a result of CECO’s failure to accept delivery of such Capacity Requirement. With respect to any calendar month during the Term, CECO will be deemed to have failed to accept delivery of the Capacity Requirement for such calendar month if it has not confirmed a schedule (or an equivalent commitment instrument) entered by NEA for bilateral transfer of the Capacity Requirement (or otherwise effected acceptance of delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

3.9 Delivery Point.

(a) All Contract Energy shall be delivered hereunder by NEA to CECO at the Delivery Point.

(b) Except as provided for in Section 3.3(b) herein, NEA shall be responsible for all transmission and distribution charges, including applicable ancillary service charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission incurred, in each case, in connection with the delivery of Contract Energy to the Delivery Point.

(c) Except as provided for in Section 3.3(b) herein, CECO shall be responsible for all transmission charges, ancillary services charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission, incurred, in each case, in connection with the transmission of Contract Energy delivered under this Agreement from and after the Delivery Point.

4. PAYMENTS FOR CONTRACT ENERGY AND CAPACITY REQUIREMENTS

4.1 Payment for Contract Energy and Capacity Requirements.

(a) All Contract Energy delivered to CECO under this Agreement shall be purchased by CECO for an amount calculated pursuant to this Section 4.1(a).

(i) Beginning on the Effective Date and continuing for the Term, CECO shall pay NEA a monthly energy payment (the “Energy Payment”) equal to the sum of: (A) the product of (I) the Contract Energy (in MWhs) delivered to CECO hereunder during each hour during such month that cleared in the DAM and (II) the hourly DAM LMP Price for such hour at the Delivery Point for MWhs that cleared in the DAM for such month, plus (B) the product of (I) the Contract Energy (in MWhs) delivered to CECO hereunder during each hour during such month that cleared in the RTM and (II) the hourly RTM LMP Price for such hour at the Delivery Point for MWhs that cleared in the RTM for such month, plus (C) a support payment (the “Support Payment”) equal to the product of (I) the lesser of: the total Contract Energy (in MWhs) delivered to CECO hereunder during such month or the MWh quantity for the applicable month, as set forth in Schedule 4.1(a), and (II) the $/MWh price (the “Monthly Support Payment Price”) for the applicable month, as set forth in Schedule 4.1(a). Notwithstanding anything in this Agreement to the contrary, no exercise by NEA of its right under Section 8.2 to reduce Contract Energy delivered to CECO as a result of CECO’s failure to timely pay for such Contract Energy shall have the effect of reducing the Support Payment as calculated pursuant to this Section.

- 12 -

(ii) CECO’s sole payment obligation, including without limitation any Support Payment obligation, with respect to Contract Energy is limited to the payment of the Energy Payment for Contract Energy delivered in accordance with the terms of this Agreement by or on behalf of NEA to the Delivery Point.

(b) All Capacity delivered to CECO under this Agreement shall be purchased by CECO at the Capacity Price. CECO’s sole payment obligation with respect to Capacity is limited to the payment of the Capacity Payment for the Capacity Requirement actually provided to CECO in accordance with the terms of this Agreement by or on behalf of NEA. The Parties will negotiate in good faith and in a commercially reasonable manner towards agreement upon a negotiated price for Capacity (the “Negotiated Capacity Price”) for each month of the Term in accordance with the terms and provisions of this Section 4.1(b). At any time during the Term, NEA may request CECO to provide it with an indicative quote for the Capacity Requirement for one month or any period of months (the “Quote Period”) as set forth in such request. Within six (6) Business Days after CECO’s receipt of such request, CECO will provide NEA with an indicative quote for a purchase price of such Capacity Requirement for the Quote Period which CECO in its commercially reasonable judgment believes reflects the fair market value for such Capacity Requirement. Within one Business Day after its receipt of such indicative quote, NEA will inform CECO as to whether NEA accepts or rejects the indicative quote.

(i) In the event that NEA accepts the indicative quote, the pricing reflected in such indicative quote will be established as the Negotiated Capacity Price for such Capacity Requirement unless CECO notifies NEA, within one Business Day after NEA’s acceptance, that CECO retracts the indicative quote. CECO may retract the indicative quote only in the event that CECO, in its commercially reasonable judgment, believes that the fair market value of the Capacity Requirement has materially declined since CECO delivered the indicative quote to NEA. In the event that CECO retracts the indicative quote, NEA may, at its election, (A) provide Third-Party Quotes to CECO for the applicable Capacity Requirement, provided that NEA does so within two (2) Business Days after CECO’s retraction of the indicative quote (and, in which event, the procedures set forth in Section 4.1(b)(ii) will be followed to determine the Negotiated Capacity Price), or (B) request a new indicative quote from CECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(ii) In the event that NEA rejects such indicative quote, NEA may, at its election, provide one or more Third-Party Quotes to CECO for the Capacity Requirement, provided that NEA does so within two (2) Business Days after NEA’s rejection of the indicative quote. In the event that NEA so delivers one or more Third-Party Quotes to CECO, CECO will, within one Business Day after delivery of the Third-Party Quotes, either (A) agree to establish any one of the Third-Party Quotes as the Negotiated Capacity Price or (B) sell Capacity (in an amount equal to the Capacity Requirement and for the Quote Period) to any of the Approved Capacity Buyers cited in the Third-Party Quotes at a different price, in which case such different price will be established as the Negotiated Capacity Price. Notwithstanding the foregoing, if, by the close of business on the Business Day immediately following NEA’s delivery of Third-Party Quotes, CECO, after making commercially reasonable efforts, is able to neither consummate a transaction as described in clause (B) of the immediately preceding sentence, nor confirm to its reasonable satisfaction the validity and firmness of at least one of the Third Party Quotes, then no Negotiated Capacity Price will be deemed to have been established for the applicable Capacity Requirement. In such event (or in the event that NEA does not deliver any Third-Party Quotes to CECO within two (2) Business Days after

- 13 -

its rejection of the indicative quote), NEA may request a new indicative quote from CECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(c) If, despite their good faith efforts, the Parties are not able to agree upon a Negotiated Capacity price prior to the Contract UCAP Transfer Deadline then the Capacity Requirement shall be purchased by CECO from NEA on a bilateral basis and the Capacity Price paid by CECO to NEA shall be the settlement price set at the UCAP Monthly Supply Auction.

4.2 Payment and Netting.

(a) Billing Period. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments). On or before the third (3^rd) day following the end of each month, NEA will render to CECO an invoice for the Energy Payment and Capacity Payment obligations incurred hereunder during the preceding month.

(b) Timeliness of Payment. CECO shall use its reasonable efforts to pay all NEA invoices under this Agreement on the fifteenth (15th) day after receipt of the invoice; provided, however, unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with each Party’s invoice instructions on or before the later of thirty (30) days following the receipt of such invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Late Payment Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

(c) Disputes and Adjustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Late Payment Rate from and including the due date but excluding the date paid. Inadvertent overpayments shall be reimbursed or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Late Payment Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment, as directed by the other party. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 4.2 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance waived.

- 14 -

(d) Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other under this Agreement on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Contract Energy during the monthly billing period under this Agreement, including any related damages calculated pursuant to this Agreement, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, such Party shall pay such sum in full when due. The Parties agree to provide each other with reasonable detail of such net payment or net payment request.

4.3 Interest on Late Payment. If a payment is not received when due under this Agreement, the delinquent Party shall pay to the other Party interest on such unpaid amount which shall accrue from the due date until the date upon which payment in full is made at the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published) (the “Late Payment Rate”).

5. RESERVED

6. REPRESENTATIONS, WARRANTIES, COVENANTS AND ACKNOWLEDMENTS

6.1 Representations and Warranties of CECO. CECO hereby represents and warrants to NEA as of the Effective Date as follows:

(a) Organization and Good Standing; Power and Authority. CECO is a corporation duly incorporated, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. CECO has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery, by CECO of this Agreement, and the performance by CECO of its obligations hereunder, have been duly authorized by all necessary actions on the part of CECO and do not and, under existing facts and law, will not: (i) contravene its restated certificate of incorporation or any other governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of CECO and, assuming the due execution hereof and performance hereunder by NEA, consititutes a legal, valid and binding obligation of CECO, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

- 15 -

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting CECO or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which CECO reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) CECO’s ability to perform its obligations under this Agreement.

(e) Consents and Approvals. The execution, delivery and performance by CECO of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of CECO.

6.2 Representations and Warranties of NEA. NEA hereby represents and warrants to CECO as of the Effective Date as follows:

(a) Organization and Good Standing; Power and Authority. NEA is a limited partnership, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. NEA has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery by NEA of this Agreement, and the performance by NEA of its obligations hereunder, have been duly authorized by all necessary actions on the part of NEA and do not and, under existing facts and law, will not: (i) contravene any of its governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of NEA and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of NEA, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting NEA or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which NEA reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) NEA’s ability to perform its obligations under this Agreement.

- 16 -

(e) Consents and Approvals. The execution, delivery and performance by NEA of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of NEA.

(g) Other Agreements. NEA has not entered into any (i) agreements for the sale of energy or capacity other than (A) the Existing Agreements and (B) that certain Power Purchase Agreement between NEA and Montaup Electric Company dated October 17, 1986 (the “Montaup PPA”), and (ii) amendment or modification of the Montaup PPA other than as set forth in Schedule 6.2(g).

6.3 PURPA Acknowledgements.

(a) The Parties acknowledge and agree that:

(i) Under the Existing CECO 2 PPA, NEA was entitled to all rights afforded to a “qualifying facility” (as defined in 18 C.F.R. Part 292) (“QF”) under applicable law, including, but not limited to, PURPA, for as long as the Facility maintained its status as a QF, and

(ii) The consideration for NEA’s agreement to amend and restate the Existing CECO 2 PPA and to waive its rights under PURPA, as provided in Section 6.3(c) below, is the execution and delivery of this Agreement by CECO.

(b) It is the express intent of the Parties that this Agreement shall be deemed a successor to, replacement of and substitute for the Existing CECO 2 PPA, which is being amended and restated in its entirety as of the Effective Date.

(c) As of the Effective Date, NEA forever relinquishes and waives any rights it may have or may have in the future under PURPA or any federal or state regulation, act or order implementing PURPA, to require CECO or any of its affiliates to purchase electricity and or capacity generated at the Facility. NEA shall cause any third party successor to NEA’s rights and interest in the Facility to agree to be bound by the foregoing waiver. NEA shall indemnify, defend and hold CECO and its partners, shareholders, members, directors, officers, employees and agents harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever suffered or incurred by CECO arising out of any failure by NEA to comply with the waiver of PURPA rights set forth in this Section 6.3 (c).

(d) As of the Effective Date and continuing throughout the Term, each Party hereby irrevocably waives its right to seek or support, and agrees not to seek or support, in any way, including, but not limited to, seeking or supporting through application, complaint, petition, motion, filing before any Governmental Entity (including, without limitation, DTE and FERC), rule, regulation or statute: (i)

- 17 -

reconsideration by DTE of its approval of this Agreement; (ii) modification or invalidation of this Agreement or any term or condition contained herein (including, without limitation, any pricing provision herein); or (iii) disallowance or impairment, in whole or in part, of CECO’s right to fully and timely recover from its customers its costs of purchasing electricity and capacity pursuant to this Agreement.

(e) Nothing contained herein shall be deemed or construed as (i) a waiver by either Party of any right to challenge any attempt by DTE, FERC or any other Governmental Entity to disallow rate recovery or modify, amend or supplement this Agreement or (ii) an acknowledgment by any such Party that DTE, FERC or any other Governmental Entity would have such authority if it so attempted.

(f) As of the Effective Date, NEA’s and CECO’s obligations under this Agreement are expressly not conditioned on the maintenance of the QF status of the Facility under PURPA, and this Agreement shall remain binding upon the Parties without regard to whether the Facility or any other source of power delivered to CECO under this Agreement is, was or remains a QF. Each Party shall obtain and maintain all permits or licenses necessary for it to perform its obligations under this Agreement.

(g) The Parties acknowledge and agree that, to the extent this Agreement is or becomes subject to review pursuant to the Federal Power Act, the standard of review for any change or modification to the pricing provisions of this Agreement proposed by any Person who is not a party hereto or FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “Mobile-Sierra” doctrine).

6.4 Release. The Parties agree to each release the other of all obligations, liabilities and costs arising under the Existing CECO 2 PPA as of the Effective Date, and to further release each other regarding potential claims against one another and related to differing interpretations of the Existing CECO 2 PPA (the “PPA and Related Potential Claims”). Such claims include, without limitation, the obligations to deliver, sell, receive and purchase energy and capacity under the Existing CECO 2 PPA, and disputes related to: (a) the payment for Delivered Energy (as such term is defined in the Existing CECO 2 PPA) delivered by NEA and received by CECO in excess of CECO’s entitlement; (b) the application of Article X(i), as set forth in the Existing CECO 2 PPA; (c) the allocation of certain congestion charges/credits imposed by the ISO; and (d) the pricing for the full term of the Existing CECO 2 PPA. The Parties agree that it is in their mutual best interests to waive such PPA and Related Potential Claims and to release each other from liability thereunder. Therefore, as of the Effective Date, the Parties, intending to be legally bound on behalf of themselves and their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives ABSOLUTELY, IRREVOCABLY, AND UNCONDITIONALLY, FULLY AND FOREVER ACQUIT, RELEASE, AND DISCHARGE AND COVENANT NOT TO SUE each other and any and all of their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives, from any and all claims, causes of action, demands, obligations, charges, complaints, controversies, damages, liabilities, costs, expenses, judgments, guarantees, agreements, or defaults of every and any nature, relating to or arising out of the PPA and Related Potential Claims, whether in law or equity and whether arising in contract (including breach), tort or otherwise, and irrespective of fault, negligence or strict liability, which a Party may have had, or may now have, prior to the Effective Date.

- 18 -

7. RESERVED

8. BREACHES; REMEDIES

8.1 Events of Default; Cure Rights. It shall constitute an event of default (“Event of Default”) hereunder if:

(a) Representation or Warranty. Any representation or warranty set forth herein is not accurate and complete in all material respects as of the date made, unless such inaccuracy or incompleteness is capable of cure by the payment of money and is cured within thirty (30) days after written notice thereof is given by the non-defaulting Party to the defaulting Party, or unless such inaccuracy or incompleteness is not capable of cure by the payment of money, but is otherwise capable of cure, and the Party in default promptly begins and diligently and continuously pursues such cure activity.

(b) Payment Obligations. Any undisputed payment due and payable hereunder is not made on the date due, and such failure continues for more than five (5) Business Days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(c) Other Covenants. Subject to Sections 3.6, 3.7, 3.8, 8.1(g) and 8.1(h) hereof, a Party fails to perform, observe or otherwise to comply with any obligation hereunder and such failure continues for more than thirty (30) days after notice thereof is given by the non-defaulting Party to the defaulting Party, or if such default is not capable of cure within thirty (30) days, the Party in default promptly begins such cure activity within such thirty (30) day period and diligently and continuously pursues the cure activity such that the failure is cured within ninety (90) days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(d) CECO Bankruptcy. CECO (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against CECO under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize CECO pursuant to 11 U.S.C. § 101 or any similar statute applicable to CECO, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of CECO, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of CECO or of a major part of its property.

(e) NEA Bankruptcy. NEA (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against NEA under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize NEA pursuant to 11 U.S.C. § 101 or any similar statute applicable to NEA, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of NEA, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of NEA or of a major part of its property.

- 19 -

(f) Consolidation. A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party.

(g) Continuing Failure by NEA to Deliver Contract Energy or Satisfy the Capacity Requirement. NEA (i) fails to deliver and sell Contract Energy hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by CECO to NEA, or if such failure is not capable of cure within five (5) days, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by CECO to NEA or (ii) fails to satisfy the Capacity Requirement hereunder for a period of one (1) calendar month during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than two (2) calendar months after written notice thereof is given by CECO to NEA, or if such failure is not capable of cure within two (2) calendar months, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by CECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect NEA’s obligation to pay Cover Damages or Capacity Replacement Damages for any day on which NEA fails to deliver Contract Energy or satisfy the Capacity Requirement.

(h) Continuing Failure by CECO to Accept Delivery of Contract Energy or the Capacity Requirement. CECO fails to accept delivery of Contract Energy or the Capacity Requirement hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by NEA to CECO, or if such failure is not capable of cure within five (5) days, CECO promptly begins such cure activity within such five (5) day period and diligently and continuously pursues the cure activity such that the failure is cured within thirty (30) days after notice thereof is given by CECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect CECO’s obligation to pay Resale Damages or Capacity Resale Damages for any day on which CECO fails to accept Contract Energy or the Capacity Requirement.

8.2 Remedies.

(a) Declaration of an Early Termination Date and Calculation of Termination Payments.

(i) CECO Termination Payment.

(A) If an Event of Default with respect to CECO shall have occurred and be continuing, NEA shall have the right (I) to designate a day on which this Agreement will terminate (the “CECO Early Termination Date”), (II) withhold any payments due to CECO under this Agreement and (III) suspend performance. NEA shall calculate, in a commercially reasonable manner, a CECO Termination Payment as of the CECO Early Termination Date. As soon as practicable after termination, notice shall be given by NEA to CECO of the amount of the CECO Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. CECO

- 20 -

shall make the CECO Termination Payment within two (2) Business Days after such notice is effective. If CECO disputes NEA’s calculation of the CECO Termination Payment, in whole or in part, CECO shall, within two (2) Business Days of receipt of the calculation of the CECO Termination Payment, provide to NEA a detailed written explanation of the basis for such dispute; provided, however, CECO shall first transfer Performance Assurance to NEA in an amount equal to the CECO Termination Payment as calculated by NEA.

(B) Notwithstanding the provisions of Section 8.2(a)(i)(A), if on the first occasion that an Event of Default by CECO pursuant to Section 8.1(b) shall have occurred and be continuing, and NEA has exercised its rights under Section 8.2(a)(i)(A) to designate a CECO Early Termination Date, which date shall be no less than twenty (20) Business Days from the date NEA provides CECO with the notice of default under Section 8.1(b), CECO may, within twenty (20) Business Days of such notice, provide NEA with any amounts then due, plus credit support in an amount equal to the aggregate of the payments to be made by CECO pursuant to Article 4 hereof for the subsequent three (3) month period, as calculated in good faith by NEA (and disregarding any suspension of performance by NEA under Section 8.2(a)(i)) (“Credit Support”) in any of the following forms: (I) a letter of credit with an initial term of at least six (6) months issued by a bank or other financial institution reasonably acceptable to NEA, which will allow NEA to draw on the letter of credit up to the full amount upon a subsequent Event of Default by CECO, or (II) such other credit support proposed by CECO that is reasonably acceptable to NEA. If CECO makes such payments and provides such Credit Support, then NEA’s rights under Section 8.2(a)(i) shall no longer be in effect and, if NEA has suspended performance under Section 8.2(a)(i), NEA shall recommence such performance.

(C) In the event of either (I) a subsequent Event of Default by BECO pursuant to Section 8.1(b) and a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B) or (II) a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B), NEA will have all rights as set forth in Section 8.2(a)(i).

(D) CECO shall be relieved of the obligation to maintain such Credit Support to the extent that each of the following shall have occurred: (I) for at least six (6) months CECO shall have provided and maintained the Credit Support in accordance with Section 8.2(a)(i)(B) and there shall have been no drawdown by NEA under such Credit Support on account of a subsequent Event of Default by CECO; (II) CECO’s senior secured Credit Rating, not supported by third party credit enhancements, is at or above BBB-/Stable Outlook from S&P and at or above Baa3, Stable Outlook from Moody’s (or in the event CECO does not have, or no longer has, a senior secured credit rating, its issuer and/or long term debt rating shall be referenced); and (III) no other Event of Default has occurred and is continuing, including an event of Default under Section 8.1(b).

(ii) NEA Termination Payment. If an Event of Default with respect to NEA shall have occurred and be continuing, CECO shall have the right (A) to designate a day on which this Agreement will terminate (the “NEA Early Termination Date”), (B) withhold any payments due to NEA under this Agreement and (C) suspend performance. CECO shall calculate, in a commercially reasonable manner, a NEA Termination Payment as of the NEA Early Termination Date. As soon as practicable after termination, notice shall be

- 21 -

given by CECO to NEA of the amount of the NEA Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. NEA shall make the NEA Termination Payment within two (2) Business Days after such notice is effective. If NEA disputes CECO’s calculation of the NEA Termination Payment, in whole or in part, NEA shall, within two (2) Business Days of receipt of the calculation of the NEA Termination Payment, provide to CECO a detailed written explanation of the basis for such dispute; provided, however, NEA shall first transfer Performance Assurance to CECO in an amount equal to the NEA Termination Payment as calculated by CECO.

(b) Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

- 22 -

9. FORCE MAJEURE

9.1 Force Majeure.

(a) The term “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under this Agreement, which event or circumstance was not anticipated as of the date this Agreement was agreed to, which is not within the control of, or the result of the negligence of, the Claiming Party or its agents, contractors, suppliers or Affiliates, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided, including storms, floods, earthquakes, tornados, fires, explosions, wars, riots or other civil disturbances, acts of war or acts of a public enemy, strikes, lockout, work stoppage or other industrial disturbances, labor or material shortage, and failure of the plant or plant equipment resulting from such force majeure events. Force Majeure shall not be based on (i) the loss of CECO’s markets; (ii) CECO’s inability economically to use or resell the Contract Energy purchased hereunder; (iii) the loss or failure of NEA’s supply; or (iv) NEA’s ability to sell the Contract Energy at a price greater than the amount provided for in Section 4.1(a).

(b) Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Contract Energy to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in Section 9.1(a) has occurred.

9.2 Notice and Excuse of Performance.

(a) Following a Force Majeure event, if either Party believes that such event will, or is reasonably likely to, adversely affect the performance of its obligations under this Agreement, then as early as commercially practicable but in no event later than two (2) Business Days after the initial occurrence of such event and for contingency planning purposes, such Party shall provide preliminary telephonic notice of the occurrence of a Force Majeure to the other Party promptly followed by written notice on or before the tenth (10th) Business Day after the initial occurrence of such event. Such written notice shall specify the nature and, if known, cause of the Force Majeure, its anticipated effect on the ability of such Party to perform obligations under this Agreement and the estimated duration of any interruption in service or other adverse effects resulting from such Force Majeure and shall be updated or supplemented as necessary to keep the other Party advised of the effect and remedial measures being undertaken to overcome the Force Majeure.

(b) To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under this Agreement and such Party (the “Claiming Party”) gives notice and details of the Force Majeure to the other Party as soon as practicable, then the Claiming Party shall be excused from the performance of its obligations with respect to such obligations (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.

- 23 -

10. DISPUTE RESOLUTION

In the event of any dispute, controversy or claim between the Parties arising out of or relating to this Agreement (collectively, a “Dispute”), the Parties shall attempt in the first instance to resolve such Dispute through friendly consultations between the Parties. If such consultations do not result in a resolution of the Dispute within fifteen (15) Days after notice of the Dispute has been delivered to either Party, then such Dispute shall be referred to the senior management of the Parties for resolution. If the Dispute has not been resolved within fifteen (15) Days after such referral to the senior management of the Parties, then either Party may pursue all of its remedies available hereunder. The Parties agree to attempt to resolve all Disputes promptly, equitably and in a good faith manner. In the event a dispute hereunder is resolved pursuant to arbitration or judicial proceedings, the Party whose position does not prevail in such proceedings shall reimburse all of the other Party’s third party costs (including reasonable attorney’s fees) incurred to prosecute or defend (as the case may be) such proceedings.

11. CONFIDENTIALITY

11.1 Nondisclosure. CECO and NEA each agree not to disclose to any Person and to keep confidential, and to cause and instruct its Affiliates, officers, directors, employees, partners and representatives not to disclose to any Person and to keep confidential, any and all of the following non-public information relating to the terms and provisions of this Agreement; any financial, pricing or supply quantity information relating to the Contract Energy to be supplied by NEA hereunder, the Facility or NEA and any information that is clearly marked or identified as “Confidential”. Notwithstanding the foregoing, any such information may be disclosed: (a) to the extent required by applicable laws and regulations or by any subpoena or similar legal process of any court or agency of federal, state or local government so long as the receiving Party gives the non-disclosing Party written notice at least three (3) Business Days prior to such disclosure, if practicable; (b) to lenders and potential lenders to CECO or to lenders to NEA or other Person(s) in connection with the implementation of this Agreement and to financial advisors, rating agencies, and any other Persons involved in the acquisition, marketing or sale or placement of such debt; (c) to agents, trustees, advisors and accountants of the Parties or their Affiliates involved in the financings described in clause (b) above, (d) to potential assignees of CECO or NEA or other Persons in connection with such proposed assignment and to financial advisors, rating agencies, and any other Persons involved in the marketing, placement or rating of such assignment, (e) to agents, trustees, advisors and accountants of the Parties or their Affiliates or agents, trustees, advisors and accountants of Persons involved in the potential assignment described in clause (d) above or (f) to the extent the non-disclosing Party shall have consented in writing prior to any such disclosure.

11.2 Public Statements. No public statement, press release or other voluntary publication regarding this Agreement shall be made or issued without the prior consent of the other Party, which consent shall not be unreasonably withheld.

- 24 -

12. INDEMNIFICATION AND INDEMNIFICATION PROCEDURES

12.1 Indemnification. Each Party (“Indemnifying Party”) shall indemnify, defend and hold the other Party (“Indemnified Party”) and its partners, shareholders, partners, directors, officers, employees and agents (including, but not limited to, Affiliates and contractors and their employees), harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever related to this Agreement suffered or incurred by such Indemnified Party arising out of the Indemnifying Party’s gross negligence or willful misconduct (including, without limitation, any breach of this Agreement resulting from gross negligence or willful misconduct). In the event injury or damage results from the joint or concurrent grossly negligent or willful misconduct of the Parties, each Party shall be liable under this indemnification in proportion to its relative degree of fault. Such duty to indemnify shall not apply to any claims which arise or are first asserted more than two (2) years after the termination of this Agreement. Such indemnity shall not include or compensate for indirect, punitive, exemplary, incidental or consequential damages incurred by either Party.

12.2 Indemnification Procedures. Each Indemnified Party shall promptly notify the Indemnifying Party of any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12. Such notice shall be given as soon as is reasonably practicable after the Indemnified Party becomes aware of each claim; provided, however, that failure to give prompt notice shall not adversely affect any claim for indemnification hereunder except to the extent the Indemnifying Party’s ability to contest any claim by any third party is materially adversely affected. The Indemnifying Party shall have the right, but not the obligation, at its expense, to contest, defend, litigate and settle, and to control the contest, defense, litigation and/or settlement of, any claim by any third party alleged or asserted against any Indemnified Party arising out of any matter in respect of which such Indemnified Party is entitled to be indemnified hereunder. The Indemnifying Party shall promptly notify such Indemnified Party of its intention to exercise such right set forth in the immediately preceding sentence and shall reimburse the Indemnified Party for the reasonable costs and expenses paid or incurred by it prior to the assumption of such contest, defense or litigation by the Indemnifying Party. The Indemnifying Party shall have the right to select legal counsel to defend a claim for which the Indemnified Party is seeking indemnification pursuant to this Section 12.2, subject to the consent of the Indemnified Party, which shall not be unreasonably delayed or withheld. If the Indemnifying Party exercises such right in accordance with the provisions of this Article 12 and any Indemnified Party notifies the Indemnifying Party that it desires to retain separate counsel in order to participate in or proceed independently with such contest, defense or litigation, such Indemnified Party may do so at its own expense. If the Indemnifying Party fails to exercise it rights set forth in the third sentence of this Section 12.2, then the Indemnifying Party will reimburse the Indemnified Party for its reasonable costs and expenses incurred in connection with the contest, defense or litigation of such claim. No Indemnified Party shall settle or compromise any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12 without the prior written consent of the Indemnifying Party; provided, however, that such consent shall not be unreasonably withheld by the Indemnifying Party.

- 25 -

13. ASSIGNMENT

13.1 Prohibition on Assignment. Except as provided in Section 13.2 hereof, this Agreement may not be assigned by either Party without the prior written consent of the other Party, which may not be unreasonably withheld. Any attempted or purported assignment of this Agreement that is not expressly permitted pursuant to Section 13.2 hereof shall be null and void and shall have no effect on or with respect to the rights and obligations of the Parties hereunder.

13.2 Permitted Assignment.

(a) NEA shall have the right to assign all or any portion of its rights or obligations under this Agreement without the consent of CECO solely for financing purposes to existing and any future lenders secured, in whole or in part, by interests in the Facility, NEA’s contractual rights, or NEA or Affiliates of NEA. Such assignment to lenders shall not operate to relieve NEA of any duty or obligation under this Agreement. In connection with the exercise of remedies under the security documents relating to such financing(s), the lender(s) or trustee(s) shall be entitled to assign this Agreement to any third-party transferee designated by such lender(s) or trustee(s), provided that CECO determines, in CECO’s reasonable discretion, that such proposed transferee or assignee is qualified and capable to satisfy NEA’s obligations hereunder.

(b) CECO shall have the right to assign this Agreement in connection with a CECO Reorganization Event to any assignee without the consent of NEA so long as (i) the proposed assignee serves load in NEPOOL and (ii) the proposed assignee’s credit rating as established by Moody’s or S&P is equal to or better than that of CECO at the time of the proposed assignment (provided, that any such rating that is on “watch” for downgrading shall not satisfy the credit rating criteria described in clause (ii)).

(c) If either Party assigns this Agreement as provided in this Section 13.2, then such Party shall cause to be delivered to the other Party an assumption agreement (in form and substance reasonably satisfactory to the non-assigning Party) of all of the obligations of the assigning Party hereunder by such assignee.

(d) An assignment of this Agreement pursuant to this Section 13.2 shall not release or discharge the assignor from its obligations hereunder unless the assignee executes a written assumption agreement in accordance with Section 13.2(c) hereof.

14. NOTICES

Any notice or communication given pursuant hereto shall be in writing and (1) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (2) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); (3) e-mailed (e-mailed notices shall be deemed given upon actual receipt) or (4) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designed by either Party to the other in writing:

- 26 -

If to CECO:

Commonwealth Electric Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

Copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

With a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

15. WAIVER AND MODIFICATION

This Agreement may be amended and its provisions and the effects thereof waived only by a writing executed by the Parties, and no subsequent conduct of any Party or course of dealings between the Parties shall effect or be deemed to effect any such amendment or waiver. No waiver of any of the

- 27 -

provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. The failure of either Party to enforce any provision of this Agreement shall not be construed as a waiver of or acquiescence in or to such provision.

16. INTERPRETATION

16.1 Choice of Law. Interpretation and performance of this Agreement shall be in accordance with, and shall be controlled by, the laws of the Commonwealth of Massachusetts (without regard to its principles of conflicts of law).

16.2 Headings. Article and Section headings are for convenience only and shall not affect the interpretation of this Agreement. References to articles, sections and appendices, and schedules are, unless the context otherwise requires, references to articles, sections, appendices, and schedules of this Agreement. The words “hereof” and “hereunder” shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

17. COUNTERPARTS

Any number of counterparts of this Agreement may be executed, and each shall have the same force and effect as an original.

18. NO DUTY TO THIRD PARTIES

Except as provided in any consent to assignment of this Agreement, nothing in this Agreement nor any action taken hereunder shall be construed to create any duty, liability or standard of care to any Person not a Party to this Agreement.

19. SEVERABILITY

If any term or provision of this Agreement or the interpretation or application of any term or provision to any prior circumstance is held to be unenforceable, illegal or invalid by a court or agency of competent jurisdiction, the remainder of this Agreement and the interpretation or application of all other terms or provisions to Persons or circumstances other than those which are unenforceable, illegal or invalid shall not be affected thereby, and each term and provision shall be valid and be enforced to the fullest extent permitted by law.

20. ENTIRE AGREEMENT

Upon the Effective Date, this Agreement, together with the agreements executed or delivered on the Effective Date in connection herewith, shall constitute the entire agreement and understanding between the Parties hereto and shall supersede all prior agreements including, without limitation, the Existing CECO 1 PPA and understandings relating to the subject matter hereof.

- 28 -

21. CHANGE IN LAW OR MARKET STRUCTURE

The Parties acknowledge that this Agreement is based on the Laws, ISO Policies and market structure in effect as of the Agreement Date. In the event of a Change in Law or Market Structure, the Parties shall make such amendments to this Agreement as are necessary to accommodate such Change in Law or Market Structure, provided that any such amendments shall preserve the economic and business arrangements embodied or referenced in this Agreement.

- 29 -

CECO 1

IN WITNESS WHEREOF, each of CECO and NEA has caused this Agreement to be duly executed on its behalf as of the date first above written.

Commonwealth Electric Company
By:	/s/ Ellen K. Angley
Name:	Ellen K. Angley
Title:	Vice President Energy Supply & Transmission

NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:	/s/ Nathan E. Hanson
	Nathan E. Hanson
	Authorized Representative

- 30 -

SCHEDULE 3.3

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

DELIVERY SCHEDULE FOR CONTRACT ENERGY

Month	MWh/h
January	30.0000
February	30.0000
March	30.0000
April	30.0000
May	20.0000
June	20.0000
July	20.0000
August	20.0000
September	30.0000
October	30.0000
November	20.0000
December	30.0000

- 31 -

SCHEDULE 4.1(a)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

- 32 -

Month Ending	No. of Days	MWh/hr CECo 1	MWhs CECo 1	Monthly Support Payment Price ($/MWh) CECo 1
04/30/04	30	30.0000	21,600.0000
05/31/04	31	20.0000	14,880.0000
06/30/04	30	20.0000	14,400.0000
07/31/04	31	20.0000	14,880.0000
08/31/04	31	20.0000	14,880.0000
09/30/04	30	30.0000	21,600.0000
10/31/04	31	30.0000	22,320.0000
11/30/04	30	20.0000	14,400.0000
12/31/04	31	30.0000	22,320.0000
01/31/05	31	30.0000	22,320.0000
02/28/05	28	30.0000	20,160.0000
03/31/05	31	30.0000	22,320.0000
04/30/05	30	30.0000	21,600.0000
05/31/05	31	20.0000	14,880.0000
06/30/05	30	20.0000	14,400.0000
07/31/05	31	20.0000	14,880.0000
08/31/05	31	20.0000	14,880.0000
09/30/05	30	30.0000	21,600.0000
10/31/05	31	30.0000	22,320.0000
11/30/05	30	20.0000	14,400.0000
12/31/05	31	30.0000	22,320.0000
01/31/06	31	30.0000	22,320.0000
02/28/06	28	30.0000	20,160.0000
03/31/06	31	30.0000	22,320.0000
04/30/06	30	30.0000	21,600.0000
05/31/06	31	20.0000	14,880.0000
06/30/06	30	20.0000	14,400.0000
07/31/06	31	20.0000	14,880.0000
08/31/06	31	20.0000	14,880.0000
09/30/06	30	30.0000	21,600.0000
10/31/06	31	30.0000	22,320.0000
11/30/06	30	20.0000	14,400.0000
12/31/06	31	30.0000	22,320.0000
01/31/07	31	30.0000	22,320.0000
02/28/07	28	30.0000	20,160.0000
03/31/07	31	30.0000	22,320.0000
04/30/07	30	30.0000	21,600.0000
05/31/07	31	20.0000	14,880.0000
06/30/07	30	20.0000	14,400.0000
07/31/07	31	20.0000	14,880.0000
08/31/07	31	20.0000	14,880.0000
09/30/07	30	30.0000	21,600.0000
10/31/07	31	30.0000	22,320.0000
11/30/07	30	20.0000	14,400.0000
12/31/07	31	30.0000	22,320.0000
01/31/08	31	30.0000	22,320.0000
02/29/08	29	30.0000	20,880.0000
03/31/08	31	30.0000	22,320.0000
04/30/08	30	30.0000	21,600.0000
05/31/08	31	20.0000	14,880.0000
06/30/08	30	20.0000	14,400.0000

- 33 -

Month Ending	No. of Days	MWh/hr CECo 1	MWhs CECo 1	Monthly Support Payment Price ($/MWh) CECo 1
07/31/08	31	20.0000	14,880.0000
08/31/08	31	20.0000	14,880.0000
09/30/08	30	30.0000	21,600.0000
10/31/08	31	30.0000	22,320.0000
11/30/08	30	20.0000	14,400.0000
12/31/08	31	30.0000	22,320.0000
01/31/09	31	30.0000	22,320.0000
02/28/09	28	30.0000	20,180.0000
03/31/09	31	30.0000	22,320.0000
04/30/09	30	30.0000	21,600.0000
05/31/09	31	20.0000	14,880.0000
06/30/09	30	20.0000	14,400.0000
07/31/09	31	20.0000	14,880.0000
08/31/09	31	20.0000	14,880.0000
09/30/09	30	30.0000	21,600.0000
10/31/09	31	30.0000	22,320.0000
11/30/09	30	20.0000	14,400.0000
12/31/09	31	30.0000	22,320,0000
01/31/10	31	30.0000	22,320.0000
02/28/10	28	30.0000	20,160.0000
03/31/10	31	30.0000	22,320.0000
04/30/10	30	30.0000	21,600.0000
05/31/10	31	20.0000	14,880.0000
06/30/10	30	20.0000	14,400.0000
07/31/10	31	20.0000	14,880.0000
08/31/10	31	20.0000	14,880.0000
09/30/10	30	30.0000	21,600.0000
10/31/10	31	30.0000	22,320.0000
11/30/10	30	20.0000	14,400.0000
12/31/10	31	30.0000	22,320.0000
01/31/11	31	30.0000	22,320.0000
02/28/11	28	30.0000	20,160.0000
03/31/11	31	30.0000	22,320.0000
04/30/11	30	30.0000	21,600.0000
05/31/11	31	20.0000	14,880.0000
06/30/11	30	20.0000	14,400.0000
07/31/11	31	20.0000	14,880.0000
08/31/11	31	20.0000	14,880.0000
09/30/11	30	30.0000	21,600.0000
10/31/11	31	30.0000	22,320.0000
11/30/11	30	20.0000	14,400.0000
12/31/11	31	30.0000	22,320.0000
01/31/12	31	30.0000	22,320.0000
02/29/12	29	30.0000	20,880.0000
03/31/12	31	30.0000	22,320.0000
04/30/12	30	30.0000	21,600.0000
05/31/12	31	20.0000	14,880.0000
06/30/12	30	20.0000	14,400.0000
07/31/12	31	20.0000	14,880.0000
08/31/12	31	20.0000	14,880.0000
09/30/12	30	30.0000	21,600.0000

- 34 -

Month Ending	No. of Days	MWh/hr CECo 1	MWhs CECo 1	Monthly Support Payment Price ($/MWh) CECo 1
10/31/12	31	30.0000	22,320.0000
11/30/12	30	20.0000	14,400.0000
12/31/12	31	30.0000	22,320.0000
01/31/13	31	30.0000	22,320.0000
02/28/13	28	30.0000	20,160.0000
03/31/13	31	30.0000	22,320.0000
04/30/13	30	30.0000	21,600.0000
05/31/13	31	20.0000	14,880.0000
06/30/13	30	20.0000	14,400.0000
07/31/13	31	20.0000	14,880.0000
08/31/13	31	20.0000	14,880.0000
09/30/13	30	30.0000	21,600.0000
10/31/13	31	30.0000	22,320.0000
11/30/13	30	20.0000	14,400.0000
12/31/13	31	30.0000	22,320.0000
01/31/14	31	30.0000	22,320.0000
02/28/14	28	30.0000	20,160.0000
03/31/14	31	30.0000	22,320.0000
04/30/14	30	30.0000	21,600.0000
05/31/14	31	20.0000	14,880.0000
06/30/14	30	20.0000	14,400.0000
07/31/14	31	20.0000	14,880.0000
08/31/14	31	20.0000	14,880.0000
09/30/14	30	30.0000	21,600.0000
10/31/14	31	30.0000	22,320.0000
11/30/14	30	20.0000	14,400.0000
12/31/14	31	30.0000	22,320.0000
01/31/15	31	30.0000	22,320.0000
02/28/15	28	30.0000	20,160.0000
03/31/15	31	30.0000	22,320.0000
04/30/15	30	30.0000	21,600.0000
05/31/15	31	20.0000	14,880.0000
06/30/15	30	20.0000	14,400.0000
07/31/15	31	20.0000	14,880.0000
08/31/15	31	20.0000	14,880.0000
09/30/15	30	30.0000	21,600.0000
10/31/15	31	30.0000	22,320.0000
11/30/15	30	20.0000	14,400.0000
12/31/15	31	30.0000	22,320.0000
01/31/16	31	30.0000	22,320.0000
02/29/16	29	30.0000	20,880.0000
03/31/16	31	30.0000	22,320.0000
04/30/16	30	30.0000	21,600.0000
05/31/16	31	20.0000	14,880.0000
06/30/16	30	20.0000	14,400.0000
07/31/16	31	20.0000	14,880.0000
08/31/16	31	20.0000	14,880.0000
09/30/16	15	30.0000	10,800.0000

- 35 -

SCHEDULE 4.1(c)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

LIST OF APPROVED CAPACITY BUYERS

Constellation Power Source, Inc.

J Aron & Company

Morgan Stanley Group Capital

PP&L Energy Plus, LLC

PSE&G Energy Resources & Trading, LLC

Select Energy, Inc.

Sempra Energy Trading Corp.

TransCanada Power Marketing Ltd.

- 36 -

SCHEDULE 6.2(g)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

MONTAUP PPA AMENDMENTS OR MODIFICATIONS

First Amendment dated as of June 28, 1989

Agreement dated May 11,1992

Agreement dated December 18, 2001

Agreement dated March 31, 2003

- 37 -

EX-10.21

EXHIBIT 10.21

AMENDED AND RESTATED POWER PURCHASE AGREEMENT

THIS AMENDED AND RESTATED POWER PURCHASE AGREEMENT (the “Agreement” is entered into as of August 19, 2004 (the “Agreement Date”), by and between Commonwealth Electric Company, a Massachusetts corporation (“CECO”) and Northeast Energy Associates Limited Partnership, a Massachusetts limited partnership (“NEA”). CECO and NEA are individually referred to herein as a “Party” and are collectively referred to herein as the “Parties”.

WHEREAS, NEA owns a nominal 300 MW natural gas-fired electricity and steam generating plant located in Bellingham, Massachusetts (the “Facility”);

WHEREAS, CECO and NEA are parties to a certain Power Purchase Agreement dated August 15, 1988, as amended to date (the “Existing CECO 2 PPA”). pursuant to which CECO purchases from NEA a portion of the Facility’s capacity and associated energy;

WHEREAS, CECO and NEA desire to amend and restate the Existing CECO 2 PPA as provided for herein; and

WHEREAS, such amendment and restatement of the Existing CECO 2 PPA is consistent with CECO’s Invitation, dated October 17, 2003, to submit proposals regarding the transfer of entitlements to certain power purchase agreements and NEA’s response, dated December 3, 2003, related to the restructuring of four (4) power purchase agreements (including the Existing CECO 2 PPA) existing between NEA and each of CECO and Boston Edison Company (“BECO”) (the four (4) existing agreements, the “Existing Agreements”, are set forth at Exhibit A).

NOW, THEREFORE, in consideration of the premises and of the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1. DEFINITIONS

In addition to terms defined in the recitals hereto, the following terms shall have the meanings set forth below.

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries’ controls, is controlled by, or is under common control with, such first Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall have the meaning set forth in the first paragraph of this Agreement.

“Agreement Date” shall have the meaning set forth in the first paragraph of this Agreement.

“Approved Capacity Buyer” shall mean any of the Persons set forth on Schedule 4.1(c) hereto.

“Business Day” shall mean any day that is not a Saturday, Sunday, or NERC Holiday.

“Capacity” shall mean “Unforced Capacity” as presently defined in the NEPOOL Manual for Definitions and Abbreviations (and, throughout the Term, any successor product thereto).

“Capacity Payment” with respect to any given time period, shall mean the product of (a) the Capacity Price and (b) Capacity Requirement, for such period.

“Capacity Price” with respect to any month, shall mean (a) the Negotiated Capacity Price or (b) in the event that the Parties fail to agree upon a Negotiated Capacity Price on or before the Contract UCAP Transfer Deadline, the price for UCAP for such month established pursuant to the next UCAP Monthly Supply Auction; provided, however, if no price for UCAP is established in the next UCAP Monthly Supply Auction, the price to be used is that established pursuant to the last UCAP Monthly Supply Auction in which UCAP was transacted.

“Capacity Receipt Shortfall” shall have the meaning set forth in Section 3.8(c) hereof.

“Capacity Replacement Damages” shall have the meaning ascribed thereto in Section 3.8(b) herein.

“Capacity Replacement Price” with respect to any portion of the Capacity Requirement that NEA fails to deliver to CECO hereunder, shall mean (a) the price at which CECO, acting in a commercially reasonable manner, purchases Capacity in lieu of such portion of the Capacity Requirement, plus transaction and other administrative costs reasonably incurred by CECO in purchasing such Capacity, or (b) to the extent CECO has not purchased Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Requirement” shall mean for the applicable month, for so long as NEA is the owner of the Facility during the Term hereof, the lesser of (a) 20 MW or (b) 10% of the Capacity recognized by the ISO as attributable to the Facility. Upon the sale, assignment or transfer by NEA of its interest in the Facility during the Term hereof, Capacity Requirement shall be fixed at the Capacity Requirement in effect on the date immediately prior to such sale, assignment or transfer.

“Capacity Resale Damages” shall have the meaning ascribed thereto in Section 3.8(c) herein.

“Capacity Resale Price” with respect to any portion of the Capacity Requirement that CECO fails to accept delivery from NEA hereunder, shall mean (a) the price at which NEA, acting in a commercially reasonable manner, re-sells Capacity in lieu of such portion of the Capacity Requirement, less transaction and other administrative costs reasonably incurred by NEA in selling such Capacity or (b) to the extent NEA has not sold Capacity in lieu of such portion of the Capacity Requirement, the market price for such portion of the Capacity Requirement determined in a commercially reasonable manner.

“Capacity Supply Shortfall” shall have the meaning set forth in Section 3.8(b) hereof.

- 2 -

“CECO Reorganization Event” shall mean (a) any consolidation, merger or other form of combination of CECO with any other Person, (b) the acquisition of a majority of the outstanding shares of CECO by any Person or (c) the sale, conveyance, lease, transfer or other disposition, in one transaction or a series of related transactions, including without limitation the transfer or “spin-off” of shares of a subsidiary (collectively, a “Transfer”), affecting all or substantially all of the assets of CECO existing on the Agreement Date or hereafter acquired. For purposes of this definition, the transfer, sale or other disposition of all or substantially all of the transmission and/or distribution assets of CECO, will, in either case, constitute a “CECO Reorganization Event.”

“CECO Termination Payment” shall mean, with respect to this Agreement and NEA, an amount payable by CECO to NEA equal to the sum of the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which NEA incurs as a result of the termination of this Agreement pursuant to Section 8.2 (a)(i) hereof.

“Change in Law or Market Structure” shall mean any of the following events that has a material adverse economic effect on one or both of the Parties: (a) the adoption, promulgation, modification, repeal or reinterpretation by any Governmental Entity of any Law which (or the effects of which) amends or conflicts with the Laws established or in effect as of the Agreement Date, (b) the adoption, promulgation, modification, repeal or reinterpretation by ISO of the ISO Policies which (or the effect of which) amends or conflicts with the ISO Policies established or in effect as of the Agreement Date or (c) the adoption or promulgation of a market structure that differs from the market structure reflected in the ISO Policies established or in effect as of the Agreement Date. For avoidance of doubt, a Change in Law or Market Structure shall include any event described in clauses (a), (b) or (c) above that results in CECO not being able to sell the Contract Energy purchased hereunder at a price greater than or equal to the Energy Payment prices (excluding the Support Payment) paid to NEA hereunder.

“Claiming Party” shall have the meaning set forth in Section 9.2(b) hereof.

“Contract Energy” shall have the meaning set forth in Section 3.1 hereof.

“Contract UCAP Transfer Deadline” with respect to any month, shall mean 5 PM Eastern Prevailing Time on the Business Day preceding the day by which final bids into the NEPOOL ISO Supply Auction must be submitted to be considered timely under the NEPOOL Practices and Market Rules and Procedures governing suppliers’ participation in the UCAP Monthly Supply Auction.

“Costs” shall mean brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred in terminating this Agreement; and all reasonable attorneys’ fees and expenses incurred in connection with the termination of this Agreement.

“Cover Damages” shall have the meaning set forth in Section 3.6 hereof.

“Credit Support” shall have the meaning set forth in Section 8.2(a)(i)(B) hereof.

“Day-Ahead Energy Market” or “DAM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

- 3 -

“Delivery Point” shall mean the Facility Bus; provided, however, that (a) if a LMP is not established for a node at the Facility Bus, or during periods of Force Majeure, NEA may deliver Contract Energy to an alternate node within the ISO control area that has a published LMP price and (b) NEA may deliver to any other delivery point mutually agreed to by the Parties.

“Delivery Shortfall” shall have the meaning set forth in Section 3.6 hereof.

“DTE” shall mean the Massachusetts Department of Telecommunications and Energy or its successor state regulatory agency.

“Eastern Prevailing Time” shall mean either Eastern Standard Time or Eastern Daylight Savings Time, as in effect from time to time.

“Effective Date” shall have the meaning set forth in Section 2.1 hereof.

“Energy Payment” shall have the meaning set forth in Section 4.1 (a)(i) hereof.

“Event of Default” shall have the meaning set forth in Section 8.1 hereof.

“Existing Agreements” shall have the meaning set forth in the Recitals.

“Execution Agreement” shall mean the Execution Agreement by and among NEA, BECO and CECO dated as of August 19, 2004.

“Existing CECO 2 PPA” shall have the meaning set forth in the Recitals.

“Facility” shall have the meaning set forth in the Recitals.

“Facility Bus” shall mean the point of interconnection between the Facility and the NEPOOL transmission system, which as of the Agreement Date is the UN.Bellinghm 13.2 NEA bus.

“FERC” shall mean the United States Federal Energy Regulatory Commission, and shall include its successors.

“Force Majeure” shall have the meaning set forth in Section 9.1(a) hereof.

“Gains” shall mean an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic benefit, if any (exclusive of Costs) resulting from the termination of this Agreement, determined in a commercially reasonable manner.

“Governmental Entity” shall mean any federal, state or local governmental agency, authority, department, instrumentality or regulatory body, and any court or tribunal, with jurisdiction over NEA, CECO or the Facility.

“IBT Containers” shall have the meaning as set forth in Section 3.3(a) hereof.

- 4 -

“Indemnified Party” shall have the meaning set forth in Section 12.1 hereof.

“Indemnifying Party” shall have the meaning set forth in Section 12.1 hereof.

“Internal Bilateral Transaction” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO” or ISO-NE” shall mean the ISO New England, Inc., the independent system operator established in accordance with the NEPOOL Agreement, or its successor.

“ISO Policies” shall mean the Market Rules and Procedures, NEPOOL Agreement, NEPOOL Manual for Definitions and Abbreviations and NEPOOL Practices.

“ISO Settlement Market System” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“ISO UCAP Transfer Deadline” with respect to any month, shall mean the latest date upon which Capacity for that month may be transferred under an Internal Bilateral Transaction in accordance with ISO rules.

“Late Payment Rate” shall have the meaning set forth in Section 4.3 hereof.

“Law” shall mean all federal, state and local statutes, regulations, rules, orders, executive orders, decrees, policies, judicial decisions and notifications.

“Lead Participant” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“LMP” shall mean, for any ISO nodal point for any hour on any day, the “Day Ahead LMP” or “Real Time LMP” ($/MWh) at such ISO nodal point calculated in accordance with Section 2 of Market Rule 1, as reported on the ISO website at www.iso-ne.com on the “Data & Reports” page, “Hourly Markets Data” subpage and “Selectable Hourly LMP Data” category, for such nodal point on such date and time. If such price should ever cease to be published, then the LMP shall be a regularly published comparable substitute price, as agreed to by the Parties in writing.

“Losses” shall mean, with respect to any Party, an amount equal to the present value, at an eight point one percent (8.1%) discount rate, of the economic loss to it, if any (exclusive of Costs), resulting from termination of this Agreement, determined in a commercially reasonable manner.

“Market Rules and Procedures” shall mean the Market Rules, Manuals and Procedures adopted by the ISO and/or members of NEPOOL, as may be amended from time to time, and as administered by the ISO to govern the operation of the NEPOOL markets, and any applicable successor rules, manuals and procedures.

“Moody’s” shall mean Moody’s Investors Service, Inc., and any successor thereto.

“MW” shall mean a megawatt.

- 5 -

“MWh” shall mean a megawatt-hour (one MWh shall equal 1,000 kWh).

“NEA Termination Payment” shall mean, with respect to this Agreement and CECO, an amount payable by NEA to CECO equal to the Losses (net of Gains) and Costs, expressed in U.S. Dollars, which CECO incurs as a result of the termination of this Agreement pursuant to Section 8.2 (a)(ii) hereof.

“Negotiated Capacity Price” shall mean the price for Capacity as agreed to by the Parties pursuant to Section 4.1(b) herein.

“NEPOOL” shall mean the New England Power Pool, or its successor.

“NEPOOL Agreement” shall mean that certain Restated New England Power Pool Agreement, as restated by an amendment dated as of December 1, 1996, as amended and restated from time to time, and any applicable successor agreement.

“NEPOOL ISO Supply Auction” shall mean the auction currently defined as the “Supply Auction” in the Market Rules and Procedures, or any successor to such auction.

“NEPOOL Manual for Definitions and Abbreviations” shall mean that certain Manual for Definitions and Abbreviations prepared by ISO-NE, as may be amended from time to time, and any applicable successor manual.

“NEPOOL Practices” shall mean the NEPOOL practices and procedures for delivery and transmission of electricity and capacity and capacity testing in effect from time to time and shall include, without limitation, applicable requirements of the NEPOOL Agreement, and any applicable successor practices and procedures.

“NERC Holiday” shall mean New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day, and any other day declared a holiday by NERC.

“Ownership Share” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Party” and “Parties” shall have the meaning set forth in the first paragraph of this Agreement.

“Performance Assurance” shall mean collateral in the form of either cash, letter(s) of credit, or other security acceptable to the requesting Party.

“Person” shall mean an individual, partnership, corporation, limited liability company, limited liability partnership, limited partnership, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof.

“PURPA” shall mean the Public Utility Regulatory Policies Act of 1978, as amended.

“QF” shall have the meaning set forth in Section 6.3(a)(i) hereof.

- 6 -

“Quote Period” shall have the meaning set forth in Section 4.1(b) herein.

“Real-Time Energy Market” or “RTM” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“Rejected Power” shall have the meaning set forth in Section 3.7 hereof.

“Replacement Power” shall mean electricity purchased by CECO and delivered to the Delivery Point as replacement for any Delivery Shortfall. Replacement Power shall not include Contract Energy delivered to CECO on behalf of NEA pursuant to Section 3.1 hereof.

“Replacement Price” shall mean the lesser of (a) the price at which CECO, acting in a commercially reasonable manner, purchases Replacement Power, plus (i) transaction and other administrative costs reasonably incurred by CECO in purchasing such Replacement Power and (ii) additional transmission charges, if any, reasonably incurred by CECO to transmit Replacement Power to the Delivery Point, or (b) the locational marginal pricing at the Delivery Point for such Replacement Power; provided, however, that in no event shall the Replacement Price include any penalties, ratcheted demand or similar charges, nor shall CECO be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize NEA’s liability.

“Resale Damages” shall have the meaning set forth in Section 3.7 hereof.

“Resale Price” shall mean the higher of (a) the price at which NEA, acting in a commercially reasonable manner, sells or is paid for Rejected Power, plus transaction and other administrative costs reasonably incurred by NEA in re-selling such Rejected Power; or (b) the LMP at the Delivery Point for such Rejected Power; provided, however, that in no event shall such price include any penalties, ratcheted demand or similar charges, and further provided that in no event shall NEA be required to utilize or change its utilization of the Facility or its other assets or market positions in order to minimize CECO’s liability for Rejected Power.

“Schedule or Scheduling” shall mean the actions of NEA or CECO and/or their designated representatives, including each Party’s Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity of Contract Energy to be delivered on any given day or days (or in any given hour or hours) during the Term at the Delivery Point.

“S&P” shall mean Standard & Poor’s Ratings Group, a division of McGraw Hill, Inc., and any successor thereto.

“Support Payment” shall have the meaning set forth in Section 4.1(a)(i) hereof.

“Term” shall have the meaning set forth in Section 2.2 hereof.

“Third-Party Quote” with respect to any Capacity Requirement, shall mean a firm offer by an Approved Capacity Buyer to purchase Capacity from CECO in a volume and for a time period equal to such Capacity Requirement.

- 7 -

“Transmission Provider” shall mean (a) ISO, its respective successor or Affiliates; (b) NEPOOL; (c) CECO; or (d) such other third parties from whom transmission services are necessary for NEA to fulfill its performance obligations to CECO hereunder.

“UCAP” shall have the meaning as set forth in the NEPOOL Manual for Definitions and Abbreviations.

“UCAP Monthly Supply Auction” shall mean the auction currently defined as the “UCAP Monthly Auction” in the NEPOOL Manual for Definitions and Abbreviations, or any successor to such auction that establishes a price for UCAP or its successor product.

2. EFFECTIVE DATE; CONDITIONS; TERM

2.1 Effective Date. The “Effective Date” of this Agreement shall be the Closing Date as established under the Execution Agreement.

2.2 Term.

(a) The “Term” of this Agreement shall mean the period from and including 11:59 p.m. (Eastern Prevailing Time) on the Effective Date through and including 11:59 p.m. (Eastern Prevailing Time) on September 15, 2016, unless this Agreement is sooner terminated in accordance with the provisions hereof.

(b) At the expiration of the Term, the Parties shall no longer be bound by the terms and provisions hereof (including, without limitation, any payment obligation hereunder), except (i) to the extent necessary to provide invoices and make payments or refunds with respect to Contract Energy or Capacity delivered prior to such expiration or termination, (ii) to the extent necessary to enforce the rights and the obligations of the Parties arising under this Agreement before such expiration or termination and (iii) the obligations of the Parties hereunder with respect to confidentiality and indemnification shall survive the expiration or termination of this Agreement and shall continue for a period of two (2) calendar years following such expiration or termination.

- 8 -

3. DELIVERY OF CONTRACT ENERGY AND CAPACITY

3.1 Obligation to Sell and Purchase Contract Energy. During each hour of the Term, NEA shall sell and deliver at the Delivery Point, and CECO shall purchase and receive at the Delivery Point, electricity in the amounts set forth in Section 3.3 and otherwise in accordance with the terms and conditions of this Agreement (“Contract Energy”). NEA shall be permitted to satisfy its obligation to deliver Contract Energy from any source of supply available to NEA. Contract Energy delivered to CECO by NEA or on behalf of NEA by NEA’s suppliers, designees or any other Person engaged by NEA to deliver Contract Energy shall be deemed delivered by NEA hereunder and NEA shall be solely responsible for any costs payable to its suppliers for such delivery. The aforementioned obligations for NEA to sell and deliver the Energy and for CECO to purchase and receive the Energy shall be firm and subject to adjustment only to reflect performance interruptions excused by this Agreement.

3.2 Characteristics. Contract Energy delivered by NEA to CECO at the Delivery Point shall be in the form of three (3)-phase, sixty (60) hertz, alternating current and otherwise in the form required by Market Rules and Procedures.

3.3 Scheduling.

(a) NEA shall Schedule deliveries of Contract Energy delivered hereunder with ISO in equal hourly quantities in accordance with all NEPOOL Practices and Market Rules and Procedures applicable thereto as set forth in Schedule 3.3. Furthermore, Contract Energy will be sold and delivered for purchase by CECO in the form of Internal Bilateral Transactions (“IBTs”) and NEA will use commercially reasonable efforts to transfer Contract Energy in the DAM; provided, however, that if such transfer cannot be made in the DAM, the Contract Energy shall be transferred in the RTM. All Contract Energy will be delivered to a specific node and not a zone. NEA will submit IBT Containers, as defined below, and notify CECO that the IBT Containers have been submitted into the ISO Settlement Market System. Subject to the satisfaction of NEA’s obligations in this Section 3.3, CECO will confirm the IBT Container in the ISO Settlement Market System. For purposes of this Agreement, “IBT Container” shall mean the form of electronic contract submittal, as implemented in the ISO Settlement Market System effective March 1, 2003 as amended from time to time, that requires CECO to confirm the general parameters of the IBT. IBTs shall be submitted and confirmed for the longest term permitted by the ISO. NEA shall be responsible for any inaccuracies in any schedules and shall correct such schedules upon notification by CECO; provided, however, CECO shall cooperate with NEA in connection with any such Scheduling and bidding and in complying with all NEPOOL Practices and shall promptly provide information reasonably requested by NEA for the purpose of assisting NEA with its Scheduling obligations hereunder. Notwithstanding the agreement to Schedule all Contract Energy in the DAM, the Energy Payment made by CECO to NEA shall be as calculated pursuant to Section 4.1(a) hereof.

(b) The Parties agree to use commercially reasonable efforts to comply with all applicable ISO Policies in connection with the Scheduling and delivery of Contract Energy hereunder. For administrative convenience, the Parties agree that all Contract Energy deliveries and receipts made pursuant to this Agreement and any other power purchase agreement between the Parties may be provided for in a single Schedule. Penalties or similar charges assessed by a Transmission Provider and caused by a Party’s noncompliance with the Scheduling obligations set forth in this Section 3.3 shall be the responsibility of the Party whose action or inaction caused the penalty.

- 9 -

3.4 Lead Participant; Ownership Share. NEA, or any entity so identified by NEA, shall be the Lead Participant of the Facility and CECO shall use commercially reasonable efforts to transfer such designation to NEA or the entity so identified by NEA. CECO shall use commercially reasonable efforts to transfer to NEA, or any entity so identified by NEA, the Ownership Share now held by CECO relating to the Facility.

3.5 Sales for Resale. All Contract Energy delivered by NEA to CECO hereunder shall be sales for resale, with CECO reselling such Contract Energy. CECO shall provide NEA with any certificates reasonably requested by NEA to evidence that the deliveries of Contract Energy hereunder are sales for resale. Nothing in this Agreement shall be construed to prohibit or restrict such resale by CECO.

3.6 Failure of NEA to Deliver Scheduled Contract Energy; Cover Damages.

Subject to Section 8.1(g) hereof, in the event NEA fails to deliver Contract Energy it is obligated to deliver hereunder and such failure is not excused under the terms of this Agreement (such undelivered Contract Energy to be referred to herein as the “Delivery Shortfall”), then NEA shall pay CECO, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Delivery Shortfall equal to the Cover Damages. “Cover Damages” means an amount equal to (i) the amount, if any, by which (A) the Replacement Price ($/MWh) multiplied by the quantity (in MWh) of the Delivery Shortfall, exceeds (B) the Energy Payment that would have been paid pursuant to Section 4.1 hereof had the Delivery Shortfall been delivered, plus (ii) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against CECO as a direct result of NEA’s failure to deliver such Contract Energy; provided, however, CECO shall use commercially reasonable efforts to purchase replacement power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(g) and 8.2 hereof, the damages provided in this Section 3.6 shall be the sole and exclusive remedy of CECO for any failure of NEA to deliver Contract Energy that it is obligated to deliver hereunder. The invoice for the amount payable pursuant to this Section 3.6 shall include a written statement explaining in reasonable detail the calculation of such amount.

3.7 Failure by CECO to Accept Delivery of Contract Energy; Resale Damages. If CECO fails to accept all or part of the Contract Energy it is obligated to accept hereunder and such failure to accept is not excused under the terms of this Agreement (such Contract Energy is referred to herein as “Rejected Power”), then CECO shall pay NEA, on the date payment would otherwise be due in respect of the month in which the failure occurred, an amount for such Rejected Power equal to the Resale Damages. “Resale Damages” means an amount equal to (a) the amount, if any, by which (i) the Energy Payment that would have been paid pursuant to Section 4.1(a) hereof for such Rejected Power, had it been accepted, exceeds (ii) the Resale Price ($/MWh) multiplied by the quantity (in MWh) of Rejected Power resold by NEA, plus (b) any applicable penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of CECO’s failure to accept such Contract Energy; provided, however, NEA shall use commercially reasonable efforts to sell such Rejected Power or otherwise mitigate such damages, penalties and related costs and charges wherever possible pursuant to applicable NEPOOL, ISO-NE or any other party’s tariffs and operating procedures then in effect. Except as otherwise provided in Section 8.1(h) and 8.2 hereof, the damages provided in this Section 3.7 shall be the sole and exclusive remedy of NEA for any failure of CECO to accept delivery of Contract Energy that it is obligated to accept hereunder. The invoice for the amount payable pursuant to this Section 3.7 shall include a written statement explaining in reasonable detail the calculation of such amount.

- 10 -

3.8 Obligation to Sell and Purchase Capacity Requirements.

(a) During the Term, NEA shall sell to CECO and CECO shall purchase from NEA the Capacity Requirement. In the event there is no longer a market for Capacity in New England, NEA shall not be obligated to sell and CECO shall not be obligated to purchase the Capacity Requirement.

(i) For so long as NEA is the owner of the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement only from the Facility. In the event that NEA sells, assigns or transfers its interests in the Facility, NEA shall be permitted to satisfy its obligation to deliver the Capacity Requirement from any source of supply available to NEA. Nothing in this Agreement shall be construed to restrict or bar NEA from any sale, assignment or transfer of its interests in the Facility.

(ii) The Parties acknowledge that as of the Agreement Date, the Market Rules and Procedures do not impose any locational requirement with respect to Capacity. In the event that, at any time during the Term, the Market Rules and Procedures do impose a zonal, nodal or other geographic locational requirement, the Capacity Requirement will be fulfilled for the zone, node or other geographic area in which the Facility is located.

(b) If NEA fails to provide CECO with all or part of the Capacity Requirement it is required to provide pursuant to Section 3.8 (a) hereof (a “Capacity Supply Shortfall”) and such failure is not excused under the terms of this Agreement, then the Capacity Replacement Damages associated with such Capacity Supply Shortfall shall be deducted from amounts payable by CECO hereunder for the next succeeding month or paid by NEA to CECO, at CECO’s election. “Capacity Replacement Damages,” with respect to any portion of the Capacity Requirement that NEA fails to deliver to CECO hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Replacement Price exceeds the Capacity Price, multiplied by the Capacity Supply Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against CECO as a direct result of NEA’s failure to deliver the Capacity Requirement in accordance with Section 3.8 (a) hereof. Subject to Section 8.1(g) hereof, the damages provided in this Section 3.8(b) shall be the sole and exclusive remedy of CECO for any failure of NEA to deliver the Capacity Requirement hereunder. With respect to any calendar month during the Term, NEA will be deemed to have failed to deliver the Capacity Requirement for such calendar month if it has not scheduled a bilateral transfer of the Capacity Requirement (or otherwise effected delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

(c) If CECO fails to accept delivery of all or part of the Capacity Requirement it is required to purchase pursuant to Section 3.8 (a) hereof (a “Capacity Receipt Shortfall”), and such failure is not excused under the terms of this Agreement, then the Capacity Resale Damages associated with such Capacity Receipt Shortfall shall be payable by CECO on the date payment would otherwise be due in respect of the month in which the failure occurred. “Capacity Resale Damages,” with respect to any portion of the Capacity Requirement that CECO fails to accept delivery of from NEA hereunder, means an amount equal to: (i) the amount, if any, by which the Capacity Price exceeds the Capacity Resale Price, multiplied by the Capacity Receipt Shortfall, plus (ii) any penalties assessed by NEPOOL, ISO-NE or any other party against NEA as a direct result of CECO’s failure to accept delivery of the Capacity Requirement

- 11 -

in accordance with Section 3.8 (a) hereof. Subject to Section 8.1(h) hereof, the damages provided in this Section 3.8(c) shall be the sole and exclusive remedy of NEA for any failure of CECO to accept delivery of the Capacity Requirement hereunder and there shall be no adjustment of the Energy Payment or Support Payment as a result of CECO’s failure to accept delivery of such Capacity Requirement. With respect to any calendar month during the Term, CECO will be deemed to have failed to accept delivery of the Capacity Requirement for such calendar month if it has not confirmed a schedule (or an equivalent commitment instrument) entered by NEA for bilateral transfer of the Capacity Requirement (or otherwise effected acceptance of delivery in accordance with applicable Market Rules and Procedures as in effect at any time during the Term) on or before the Contract UCAP Transfer Deadline.

3.9 Delivery Point.

(a) All Contract Energy shall be delivered hereunder by NEA to CECO at the Delivery Point.

(b) Except as provided for in Section 3.3(b) herein, NEA shall be responsible for all transmission and distribution charges, including applicable ancillary service charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission incurred, in each case, in connection with the delivery of Contract Energy to the Delivery Point.

(c) Except as provided for in Section 3.3(b) herein, CECO shall be responsible for all transmission charges, ancillary services charges, line losses, congestion charges and other NEPOOL or applicable system costs or charges associated with transmission, incurred, in each case, in connection with the transmission of Contract Energy delivered under this Agreement from and after the Delivery Point.

4. PAYMENTS FOR CONTRACT ENERGY AND CAPACITY REQUIREMENTS

4.1 Payment for Contract Energy and Capacity Requirements.

(a) All Contract Energy delivered to CECO under this Agreement shall be purchased by CECO for an amount calculated pursuant to this Section 4.1(a).

(i) Beginning on the Effective Date and continuing for the Term, CECO shall pay NEA a monthly energy payment (the “Energy Payment”) equal to the sum of: (A) the product of (I) the Contract Energy (in MWhs) delivered to CECO hereunder during each hour during such month that cleared in the DAM and (II) the hourly DAM LMP Price for such hour at the Delivery Point for MWhs that cleared in the DAM for such month, plus (B) the product of (I) the Contract Energy (in MWhs) delivered to CECO hereunder during each hour during such month that cleared in the RTM and (II) the hourly RTM LMP Price for such hour at the Delivery Point for MWhs that cleared in the RTM for such month, plus (C) a support payment (the “Support Payment”) equal to the product of (I) the lesser of: the total Contract Energy (in MWhs) delivered to CECO hereunder during such month or the MWh quantity for the applicable month, as set forth in Schedule 4.1(a), and (II) the $/MWh price (the “Monthly Support Payment Price”) for the applicable month, as set forth in Schedule 4.1(a). Notwithstanding anything in this Agreement to the contrary, no exercise by NEA of its right under Section 8.2 to reduce Contract Energy delivered to CECO as a result of CECO’s failure to timely pay for such Contract Energy shall have the effect of reducing the Support Payment as calculated pursuant to this Section.

- 12 -

(ii) CECO’s sole payment obligation, including without limitation any Support Payment obligation, with respect to Contract Energy is limited to the payment of the Energy Payment for Contract Energy delivered in accordance with the terms of this Agreement by or on behalf of NEA to the Delivery Point.

(b) All Capacity delivered to CECO under this Agreement shall be purchased by CECO at the Capacity Price. CECO’s sole payment obligation with respect to Capacity is limited to the payment of the Capacity Payment for the Capacity Requirement actually provided to CECO in accordance with the terms of this Agreement by or on behalf of NEA. The Parties will negotiate in good faith and in a commercially reasonable manner towards agreement upon a negotiated price for Capacity (the “Negotiated Capacity Price”) for each month of the Term in accordance with the terms and provisions of this Section 4.1(b). At any time during the Term, NEA may request CECO to provide it with an indicative quote for the Capacity Requirement for one month or any period of months (the “Quote Period”) as set forth in such request. Within six (6) Business Days after CECO’s receipt of such request, CECO will provide NEA with an indicative quote for a purchase price of such Capacity Requirement for the Quote Period which CECO in its commercially reasonable judgment believes reflects the fair market value for such Capacity Requirement. Within one Business Day after its receipt of such indicative quote, NEA will inform CECO as to whether NEA accepts or rejects the indicative quote.

(i) In the event that NEA accepts the indicative quote, the pricing reflected in such indicative quote will be established as the Negotiated Capacity Price for such Capacity Requirement unless CECO notifies NEA, within one Business Day after NEA’s acceptance, that CECO retracts the indicative quote. CECO may retract the indicative quote only in the event that CECO, in its commercially reasonable judgment, believes that the fair market value of the Capacity Requirement has materially declined since CECO delivered the indicative quote to NEA. In the event that CECO retracts the indicative quote, NEA may, at its election, (A) provide Third-Party Quotes to CECO for the applicable Capacity Requirement, provided that NEA does so within two (2) Business Days after CECO’s retraction of the indicative quote (and, in which event, the procedures set forth in Section 4.1(b)(ii) will be followed to determine the Negotiated Capacity Price), or (B) request a new indicative quote from CECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(ii) In the event that NEA rejects such indicative quote, NEA may, at its election, provide one or more Third-Party Quotes to CECO for the Capacity Requirement, provided that NEA does so within two (2) Business Days after NEA’s rejection of the indicative quote. In the event that NEA so delivers one or more Third-Party Quotes to CECO, CECO will, within one Business Day after delivery of the Third-Party Quotes, either (A) agree to establish any one of the Third-Party Quotes as the Negotiated Capacity Price or (B) sell Capacity (in an amount equal to the Capacity Requirement and for the Quote Period) to any of the Approved Capacity Buyers cited in the Third-Party Quotes at a different price, in which case such different price will be established as the Negotiated Capacity Price. Notwithstanding the foregoing, if, by the close of business on the Business Day immediately following NEA’s delivery of Third-Party Quotes, CECO, after making commercially reasonable efforts, is able to neither consummate a transaction as described in clause (B) of the immediately preceding sentence, nor confirm to its reasonable satisfaction the validity and firmness of at least one of the Third Party Quotes, then no Negotiated Capacity Price will be deemed to have been established for the applicable Capacity Requirement. In such event (or in the event that NEA does not deliver any Third-Party Quotes to CECO within two (2) Business Days after

- 13 -

its rejection of the indicative quote), NEA may request a new indicative quote from CECO (which request may be for the same or a different period), in which event the negotiation process set forth in this Section 4.1(b) will be repeated with respect to such request.

(c) If, despite their good faith efforts, the Parties are not able to agree upon a Negotiated Capacity price prior to the Contract UCAP Transfer Deadline then the Capacity Requirement shall be purchased by CECO from NEA on a bilateral basis and the Capacity Price paid by CECO to NEA shall be the settlement price set at the UCAP Monthly Supply Auction.

4.2 Payment and Netting.

(a) Billing Period. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments). On or before the third (3^rd) day following the end of each month, NEA will render to CECO an invoice for the Energy Payment and Capacity Payment obligations incurred hereunder during the preceding month.

(b) Timeliness of Payment. CECO shall use its reasonable efforts to pay all NEA invoices under this Agreement on the fifteenth (15th) day after receipt of the invoice; provided, however, unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with each Party’s invoice instructions on or before the later of thirty (30) days following the receipt of such invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Late Payment Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

(c) Disputes and Adjustments of Invoices. A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Late Payment Rate from and including the due date but excluding the date paid. Inadvertent overpayments shall be reimbursed or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Late Payment Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment, as directed by the other party. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 4.2 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance occurred, the right to payment for such performance is waived.

- 14 -

(d) Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other under this Agreement on the same date through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Contract Energy during the monthly billing period under this Agreement, including any related damages calculated pursuant to this Agreement, interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, such Party shall pay such sum in full when due. The Parties agree to provide each other with reasonable detail of such net payment or net payment request.

4.3 Interest on Late Payment. If a payment is not received when due under this Agreement, the delinquent Party shall pay to the other Party interest on such unpaid amount which shall accrue from the due date until the date upon which payment in full is made at the prime lending rate as may from time to time be published in The Wall Street Journal under “Money Rates” on such day (or if not published on such day on the most recent preceding day on which published) (the “Late Payment Rate”).

5. RESERVED

6. REPRESENTATIONS, WARRANTIES, COVENANTS AND ACKNOWLEDMENTS

6.1 Representations and Warranties of CECO. CECO hereby represents and warrants to NEA as of the Effective Date as follows:

(a) Organization and Good Standing; Power and Authority. CECO is a corporation duly incorporated, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. CECO has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery by CECO of this Agreement, and the performance by CECO of its obligations hereunder, have been duly authorized by all necessary actions on the part of CECO and do not and, under existing facts and law, will not: (i) contravene its restated certificate of incorporation or any other governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of CECO and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of CECO, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

- 15 -

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting CECO or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which CECO reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) CECO’s ability to perform its obligations under this Agreement.

(e) Consents and Approvals. The execution, delivery and performance by CECO of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of CECO.

6.2 Representations and Warranties of NEA. NEA hereby represents and warrants to CECO as of the Effective Date as follows:

(a) Organization and Good Standing; Power and Authority. NEA is a limited partnership, validly existing and in good standing under the laws of the Commonwealth of Massachusetts. NEA has all requisite power and authority to execute, deliver, and perform its obligations under this Agreement.

(b) Due Authorization; No Conflicts. The execution and delivery by NEA of this Agreement, and the performance by NEA of its obligations hereunder, have been duly authorized by all necessary actions on the part of NEA and do not and, under existing facts and law, will not: (i) contravene any of its governing documents; (ii) conflict with, result in a breach of, or constitute a default under any note, bond, mortgage, indenture, deed of trust, license, contract or other agreement to which it is a party or by which any of its properties may be bound or affected; (iii) assuming receipt of the requisite regulatory approvals, violate any order, writ, injunction, decree, judgment, award, statute, law, rule, regulation or ordinance of any Governmental Entity or agency applicable to it or any of its properties; or (iv) result in the creation of any lien, charge or encumbrance upon any of its properties pursuant to any of the foregoing.

(c) Binding Agreement. This Agreement has been duly executed and delivered on behalf of NEA and, assuming the due execution hereof and performance hereunder by NEA, constitutes a legal, valid and binding obligation of NEA, enforceable against it in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(d) No Proceedings. There are no actions, suits or other proceedings, at law or in equity, by or before any Governmental Entity or agency or any other body pending or, to the best of its knowledge, threatened against or affecting NEA or any of its properties (including, without limitation, this Agreement) which relate in any manner to this Agreement or any transaction contemplated hereby, or which NEA reasonably expects to lead to a material adverse effect on (i) the validity or enforceability of this Agreement or (ii) NEA’s ability to perform its obligations under this Agreement.

- 16 -

(e) Consents and Approvals. The execution, delivery and performance by NEA of its obligations under this Agreement does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any Person which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(f) Negotiations. The terms and provisions of this Agreement are the result of arm’s length and good faith negotiations on the part of NEA.

(g) Other Agreements. NEA has not entered into any (i) agreements for the sale of energy or capacity other than (A) the Existing Agreements and (B) that certain Power Purchase Agreement between NEA and Montaup Electric Company dated October 17, 1986 (the “Montaup PPA”), and (ii) amendment or modification of the Montaup PPA other than as set forth in Schedule 6.2(g).

6.3 PURPA Acknowledgements.

(a) The Parties acknowledge and agree that:

(i) Under the Existing CECO 2 PPA, NEA was entitled to all rights afforded to a “qualifying facility” (as defined in 18 C.F.R. Part 292) (“QF”) under applicable law, including, but not limited to, PURPA, for as long as the Facility maintained its status as a QF, and

(ii) The consideration for NEA’s agreement to amend and restate the Existing CECO 2 PPA and to waive its rights under PURPA, as provided in Section 6.3(c) below, is the execution and delivery of this Agreement by CECO.

(b) It is the express intent of the Parties that this Agreement shall be deemed a successor to, replacement of and substitute for the Existing CECO 2 PPA, which is being amended and restated in its entirety as of the Effective Date.

(c) As of the Effective Date, NEA forever relinquishes and waives any rights it may have or may have in the future under PURPA or any federal or state regulation, act or order implementing PURPA, to require CECO or any of its affiliates to purchase electricity and or capacity generated at the Facility. NEA shall cause any third party successor to NEA’s rights and interest in the Facility to agree to be bound by the foregoing waiver. NEA shall indemnify, defend and hold CECO and its partners, shareholders, members, directors, officers, employees and agents harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever suffered or incurred by CECO arising out of any failure by NEA to comply with the waiver of PURPA rights set forth in this Section 6.3 (c).

(d) As of the Effective Date and continuing throughout the Term, each Party hereby irrevocably waives its right to seek or support, and agrees not to seek or support, in any way, including, but not limited to, seeking or supporting through application, complaint, petition, motion, filing before any Governmental Entity (including, without limitation, DTE and FERC), rule, regulation or statute: (i)

- 17 -

reconsideration by DTE of its approval of this Agreement; (ii) modification or invalidation of this Agreement or any term or condition contained herein (including, without limitation, any pricing provision herein); or (iii) disallowance or impairment, in whole or in part, of CECO’s right to fully and timely recover from its customers its costs of purchasing electricity and capacity pursuant to this Agreement.

(e) Nothing contained herein shall be deemed or construed as (i) a waiver by either Party of any right to challenge any attempt by DTE, FERC or any other Governmental Entity to disallow rate recovery or modify, amend or supplement this Agreement or (ii) an acknowledgment by any such Party that DTE, FERC or any other Governmental Entity would have such authority if it so attempted.

(f) As of the Effective Date, NEA’s and CECO’s obligations under this Agreement are expressly not conditioned on the maintenance of the QF status of the Facility under PURPA, and this Agreement shall remain binding upon the Parties without regard to whether the Facility or any other source of power delivered to CECO under this Agreement is, was or remains a QF. Each Party shall obtain and maintain all permits or licenses necessary for it to perform its obligations under this Agreement.

(g) The Parties acknowledge and agree that, to the extent this Agreement is or becomes subject to review pursuant to the Federal Power Act, the standard of review for any change or modification to the pricing provisions of this Agreement proposed by any Person who is not a party hereto or FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “Mobile-Sierra” doctrine).

6.4 Release. The Parties agree to each release the other of all obligations, liabilities and costs arising under the Existing CECO 2 PPA as of the Effective Date, and to further release each other regarding potential claims against one another and related to differing interpretations of the Existing CECO 2 PPA (the “PPA and Related Potential Claims”). Such claims include, without limitation, the obligations to deliver, sell, receive and purchase energy and capacity under the Existing CECO 2 PPA, and disputes related to: (a) the payment for Delivered Energy (as such term is defined in the Existing CECO 2 PPA) delivered by NEA and received by CECO in excess of CECO’s entitlement; (b) the application of Article X(i), as set forth in the Existing CECO 2 PPA; (c) the allocation of certain congestion charges/credits imposed by the ISO; and (d) the pricing for the full term of the Existing CECO 2 PPA. The Parties agree that it is in their mutual best interests to waive such PPA and Related Potential Claims and to release each other from liability thereunder. Therefore, as of the Effective Date, the Parties, intending to be legally bound on behalf of themselves and their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives ABSOLUTELY, IRREVOCABLY, AND UNCONDITIONALLY, FULLY AND FOREVER ACQUIT, RELEASE, AND DISCHARGE AND COVENANT NOT TO SUE each other and any and all of their past, present and future parents, subsidiaries, affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, insurers, employees, stockholders, members, partners and representatives, from any and all claims, causes of action, demands, obligations, charges, complaints, controversies, damages, liabilities, costs, expenses, judgments, guarantees, agreements, or defaults of every and any nature, relating to or arising out of the PPA and Related Potential Claims, whether in law or equity and whether arising in contract (including breach), tort or otherwise, and irrespective of fault, negligence or strict liability, which a Party may have had, or may now have, prior to the Effective Date.

- 18 -

7. RESERVED

8. BREACHES; REMEDIES

8.1 Events of Default; Cure Rights. It shall constitute an event of default (“Event of Default”) hereunder if:

(a) Representation or Warranty. Any representation or warranty set forth herein is not accurate and complete in all material respects as of the date made, unless such inaccuracy or incompleteness is capable of cure by the payment of money and is cured within thirty (30) days after written notice thereof is given by the non-defaulting Party to the defaulting Party, or unless such inaccuracy or incompleteness is not capable of cure by the payment of money, but is otherwise capable of cure, and the Party in default promptly begins and diligently and continuously pursues such cure activity.

(b) Payment Obligations. Any undisputed payment due and payable hereunder is not made on the date due, and such failure continues for more than five (5) Business Days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(c) Other Covenants. Subject to Sections 3.6, 3.7, 3.8, 8.1(g) and 8.1(h) hereof, a Party fails to perform, observe or otherwise to comply with any obligation hereunder and such failure continues for more than thirty (30) days after notice thereof is given by the non-defaulting Party to the defaulting Party, or if such default is not capable of cure within thirty (30) days, the Party in default promptly begins such cure activity within such thirty (30) day period and diligently and continuously pursues the cure activity such that the failure is cured within ninety (90) days after notice thereof is given by the non-defaulting Party to the defaulting Party.

(d) CECO Bankruptcy. CECO (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against CECO under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize CECO pursuant to 11 U.S.C. § 101 or any similar statute applicable to CECO, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of CECO, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of CECO or of a major part of its property.

(e) NEA Bankruptcy. NEA (i) is adjudged bankrupt or files a petition in voluntary bankruptcy under any provision of any bankruptcy law or consents to the filing of any bankruptcy or reorganization petition against NEA under any such law, or (without limiting the generality of the foregoing) files a petition to reorganize NEA pursuant to 11 U.S.C. § 101 or any similar statute applicable to NEA, as now or hereinafter in effect, (ii) makes an assignment for the benefit of creditors, or admits in writing an inability to pay its debts generally as they become due, or consents to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of NEA, or (iii) is subject to an order of a court of competent jurisdiction appointing a receiver or liquidator or custodian or trustee of NEA or of a major part of its property.

- 19 -

(f) Consolidation. A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party.

(g) Continuing Failure by NEA to Deliver Contract Energy or Satisfy the Capacity Requirement. NEA (i) fails to deliver and sell Contract Energy hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by CECO to NEA, or if such failure is not capable of cure within five (5) days, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by CECO to NEA or (ii) fails to satisfy the Capacity Requirement hereunder for a period of one (1) calendar month during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than two (2) calendar months after written notice thereof is given by CECO to NEA, or if such failure is not capable of cure within two (2) calendar months, NEA shall cure such failure as soon as commercially practicable but not later than six (6) months after notice thereof is given by CECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect NEA’s obligation to pay Cover Damages or Capacity Replacement Damages for any day on which NEA falls to deliver Contract Energy or satisfy the Capacity Requirement.

(h) Continuing Failure by CECO to Accept Delivery of Contract Energy or the Capacity Requirement. CECO fails to accept delivery of Contract Energy or the Capacity Requirement hereunder for a period of ten (10) continuous days during the Term hereof and such failure is not excused for reasons set forth in this Agreement and such failure continues for more than five (5) days after written notice thereof is given by NEA to CECO, or if such failure is not capable of cure within five (5) days, CECO promptly begins such cure activity within such five (5) day period and diligently and continuously pursues the cure activity such that the failure is cured within thirty (30) days after notice thereof is given by CECO to NEA; provided, however, the foregoing shall not be construed to limit or otherwise affect CECO’s obligation to pay Resale Damages or Capacity Resale Damages for any day on which CECO fails to accept Contract Energy or the Capacity Requirement.

8.2 Remedies.

(a) Declaration of an Early Termination Date and Calculation of Termination Payments.

(i) CECO Termination Payment.

(A) If an Event of Default with respect to CECO shall have occurred and be continuing, NEA shall have the right (I) to designate a day on which this Agreement will terminate (the “CECO Early Termination Date”), (II) withhold any payments due to CECO under this Agreement and (III) suspend performance. NEA shall calculate, in a commercially reasonable manner, a CECO Termination Payment as of the CECO Early Termination Date. As soon as practicable after termination, notice shall be given by NEA to CECO of the amount of the CECO Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. CECO

- 20 -

shall make the CECO Termination Payment within two (2) Business Days after such notice is effective. If CECO disputes NEA’s calculation of the CECO Termination Payment, in whole or in part, CECO shall, within two (2) Business Days of receipt of the calculation of the CECO Termination Payment, provide to NEA a detailed written explanation of the basis for such dispute; provided, however, CECO shall first transfer Performance Assurance to NEA in an amount equal to the CECO Termination Payment as calculated by NEA.

(B) Notwithstanding the provisions of Section 8.2(a)(i)(A), if on the first occasion that an Event of Default by CECO pursuant to Section 8.1(b) shall have occurred and be continuing, and NEA has exercised its rights under Section 8.2(a)(i)(A) to designate a CECO Early Termination Date, which date shall be no less than twenty (20) Business Days from the date NEA provides CECO with the notice of default under Section 8.1(b), CECO may, within twenty (20) Business Days of such notice, provide NEA with any amounts then due, plus credit support in an amount equal to the aggregate of the payments to be made by CECO pursuant to Article 4 hereof for the subsequent three (3) month period, as calculated in good faith by NEA (and disregarding any suspension of performance by NEA under Section 8.2(a)(i)) (“Credit Support”) in any of the following forms: (I) a letter of credit with an initial term of at least six (6) months issued by a bank or other financial institution reasonably acceptable to NEA, which will allow NEA to draw on the letter of credit up to the full amount upon a subsequent Event of Default by CECO, or (II) such other credit support proposed by CECO that is reasonably acceptable to NEA. If CECO makes such payments and provides such Credit Support, then NEA’s rights under Section 8.2(a)(i) shall no longer be in effect and, if NEA has suspended performance under Section 8.2(a)(i), NEA shall recommence such performance.

(C) In the event of either (I) a subsequent Event of Default by BECO pursuant to Section 8.1(b) and a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B) or (II) a failure by BECO to maintain Credit Support as required under Section 8.2(a)(i)(B), NEA will have all rights as set forth in Section 8.2(a)(i).

(D) CECO shall be relieved of the obligation to maintain such Credit Support to the extent that each of the following shall have occurred: (I) for at least six (6) months CECO shall have provided and maintained the Credit Support in accordance with Section 8.2(a)(i)(B) and there shall have been no drawdown by NEA under such Credit Support on account of a subsequent Event of Default by CECO; (II) CECO’s senior secured Credit Rating, not supported by third party credit enhancements, is at or above BBB-/Stable Outlook from S&P and at or above Baa3, Stable Outlook from Moody’s (or in the event CECO does not have, or no longer has, a senior secured credit rating, its issuer and/or long term debt rating shall be referenced); and (III) no other Event of Default has occurred and is continuing, including an event of Default under Section 8.1(b).

(ii) NEA Termination Payment. If an Event of Default with respect to NEA shall have occurred and be continuing, CECO shall have the right (A) to designate a day on which this Agreement will terminate (the “NEA Early Termination Date”), (B) withhold any payments due to NEA under this Agreement and (C) suspend performance. CECO shall calculate, in a commercially reasonable manner, a NEA Termination Payment as of the NEA Early Termination Date. As soon as practicable after termination, notice shall be

- 21 -

given by CECO to NEA of the amount of the NEA Termination Payment. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. NEA shall make the NEA Termination Payment within two (2) Business Days after such notice is effective. If NEA disputes CECO’s calculation of the NEA Termination Payment, in whole or in part, NEA shall, within two (2) Business Days of receipt of the calculation of the NEA Termination Payment, provide to CECO a detailed written explanation of the basis for such dispute; provided, however, NEA shall first transfer Performance Assurance to CECO in an amount equal to the NEA Termination Payment as calculated by CECO.

(b) Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT “SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

- 22 -

9. FORCE MAJEURE

9.1 Force Majeure.

(a) The term “Force Majeure” means an event or circumstance which prevents one Party from performing its obligations under this Agreement, which event or circumstance was not anticipated as of the date this Agreement was agreed to, which is not within the control of, or the result of the negligence of, the Claiming Party or its agents, contractors, suppliers or Affiliates, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided, including storms, floods, earthquakes, tomados, fires, explosions, wars, riots or other civil disturbances, acts of war or acts of a public enemy, strikes, lockout, work stoppage or other industrial disturbances, labor or material shortage, and failure of the plant or plant equipment resulting from such force majeure events. Force Majeure shall not be based on (i) the loss of CECO’s markets; (ii) CECO’s inability economically to use or resell the Contract Energy purchased hereunder; (iii) the loss or failure of NEA’s supply; or (iv) NEA’s ability to sell the Contract Energy at a price greater than the amount provided for in Section 4.1(a).

(b) Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Contract Energy to be delivered to or received at the Delivery Point and (ii) such curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the Transmission Provider’s tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in Section 9.1(a) has occurred.

9.2 Notice and Excuse of Performance.

(a) Following a Force Majeure event, if either Party believes that such event will, or is reasonably likely to, adversely affect the performance of its obligations under this Agreement, then as early as commercially practicable but in no event later than two (2) Business Days after the initial occurrence of such event and for contingency planning purposes, such Party shall provide preliminary telephonic notice of the occurrence of a Force Majeure to the other Party promptly followed by written notice on or before the tenth (10th) Business Day after the initial occurrence of such event. Such written notice shall specify the nature and, if known, cause of the Force Majeure, its anticipated effect on the ability of such Party to perform obligations under this Agreement and the estimated duration of any interruption in service or other adverse effects resulting from such Force Majeure and shall be updated or supplemented as necessary to keep the other Party advised of the effect and remedial measures being undertaken to overcome the Force Majeure.

(b) To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under this Agreement and such Party (the “Claiming Party”) gives notice and details of the Force Majeure to the other Party as soon as practicable, then the Claiming Party shall be excused from the performance of its obligations with respect to such obligations (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.

- 23 -

10. DISPUTE RESOLUTION

In the event of any dispute, controversy or claim between the Parties arising out of or relating to this Agreement (collectively, a “Dispute”), the Parties shall attempt in the first instance to resolve such Dispute through friendly consultations between the Parties. If such consultations do not result in a resolution of the Dispute within fifteen (15) Days after notice of the Dispute has been delivered to either Party, then such Dispute shall be referred to the senior management of the Parties for resolution. If the Dispute has not been resolved within fifteen (15) Days after such referral to the senior management of the Parties, then either Party may pursue all of its remedies available hereunder. The Parties agree to attempt to resolve all Disputes promptly, equitably and in a good faith manner. In the event a dispute hereunder is resolved pursuant to arbitration or judicial proceedings, the Party whose position does not prevail in such proceedings shall reimburse all of the other Party’s third party costs (including reasonable attorney’s fees) incurred to prosecute or defend (as the case may be) such proceedings.

11. CONFIDENTIALITY

11.1 Nondisclosure. CECO and NEA each agree not to disclose to any Person and to keep confidential, and to cause and instruct its Affiliates, officers, directors, employees, partners and representatives not to disclose to any Person and to keep confidential, any and all of the following non-public information relating to the terms and provisions of this Agreement; any financial, pricing or supply quantity information relating to the Contract Energy to be supplied by NEA hereunder, the Facility or NEA and any information that is clearly marked or identified as “Confidential”. Notwithstanding the foregoing, any such information may be disclosed: (a) to the extent required by applicable laws and regulations or by any subpoena or similar legal process of any court or agency of federal, state or local government so long as the receiving Party gives the non-disclosing Party written notice at least three (3) Business Days prior to such disclosure, if practicable; (b) to lenders and potential lenders to CECO or to lenders to NEA or other Person(s) in connection with the implementation of this Agreement and to financial advisors, rating agencies, and any other Persons involved in the acquisition, marketing or sale or placement of such debt; (c) to agents, trustees, advisors and accountants of the Parties or their Affiliates involved in the financings described in clause (b) above, (d) to potential assignees of CECO or NEA or other Persons in connection with such proposed assignment and to financial advisors, rating agencies, and any other Persons involved in the marketing, placement or rating of such assignment, (e) to agents, trustees, advisors and accountants of the Parties or their Affiliates or agents, trustees, advisors and accountants of Persons involved in the potential assignment described in clause (d) above or (f) to the extent the non-disclosing Party shall have consented in writing prior to any such disclosure.

11.2 Public Statements. No public statement, press release or other voluntary publication regarding this Agreement shall be made or issued without the prior consent of the other Party, which consent shall not be unreasonably withheld.

- 24 -

12. INDEMNIFICATION AND INDEMNIFICATION PROCEDURES

12.1 Indemnification. Each Party (“Indemnifying Party”) shall indemnify, defend and hold the other Party (“Indemnified Party”) and its partners, shareholders, partners, directors, officers, employees and agents (including, but not limited to, Affiliates and contractors and their employees), harmless from and against all liabilities, damages, losses, penalties, claims, demands, suits and proceedings of any nature whatsoever related to this Agreement suffered or incurred by such Indemnified Party arising out of the Indemnifying Party’s gross negligence or willful misconduct (including, without limitation, any breach of this Agreement resulting from gross negligence or willful misconduct). In the event injury or damage results from the joint or concurrent grossly negligent or willful misconduct of the Parties, each Party shall be liable under this indemnification in proportion to its relative degree of fault. Such duty to indemnify shall not apply to any claims which arise or are first asserted more than two (2) years after the termination of this Agreement. Such indemnity shall not include or compensate for indirect, punitive, exemplary incidental or consequential damages incurred by either Party.

12.2 Indemnification Procedures. Each Indemnified Party shall promptly notify the Indemnifying Party of any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12. Such notice shall be given as soon as is reasonably practicable after the Indemnified Party becomes aware of each claim; provided, however, that failure to give prompt notice shall not adversely affect any claim for indemnification hereunder except to the extent the Indemnifying Party’s ability to contest any claim by any third party is materially adversely affected. The Indemnifying Party shall have the right, but not the obligation, at its expense, to contest, defend, litigate and settle, and to control the contest, defense, litigation and/or settlement of, any claim by any third party alleged or asserted against any Indemnified Party arising out of any matter in respect of which such Indemnified Party is entitled to be indemnified hereunder. The Indemnifying Party shall promptly notify such Indemnified Party of its intention to exercise such right set forth in the immediately preceding sentence and shall reimburse the Indemnified Party for the reasonable costs and expenses paid or incurred by it prior to the assumption of such contest, defense or litigation by the Indemnifying Party. The Indemnifying Party shall have the right to select legal counsel to defend a claim for which the Indemnified Party is seeking indemnification pursuant to this Section 12.2, subject to the consent of the Indemnified Party, which shall not be unreasonably delayed or withheld. If the Indemnifying Party exercises such right in accordance with the provisions of this Article 12 and any Indemnified Party notifies the Indemnifying Party that it desires to retain separate counsel in order to participate in or proceed independently with such contest, defense or litigation, such Indemnified Party may do so at its own expense. If the Indemnifying Party fails to exercise it rights set forth in the third sentence of this Section 12.2, then the Indemnifying Party will reimburse the Indemnified Party for its reasonable costs and expenses incurred in connection with the contest, defense or litigation of such claim. No Indemnified Party shall settle or compromise any claim in respect of which the Indemnified Party is entitled to be indemnified under this Article 12 without the prior written consent of the Indemnifying Party; provided, however, that such consent shall not be unreasonably withheld by the Indemnifying Party.

- 25 -

13. ASSIGNMENT

13.1 Prohibition on Assignment. Except as provided in Section 13.2 hereof, this Agreement may not be assigned by either Party without the prior written consent of the other Party, which may not be unreasonably withheld. Any attempted or purported assignment of this Agreement that is not expressly permitted pursuant to Section 13.2 hereof shall be null and void and shall have no effect on or with respect to the rights and obligations of the Parties hereunder.

13.2 Permitted Assignment.

(a) NEA shall have the right to assign all or any portion of its rights or obligations under this Agreement without the consent of CECO solely for financing purposes to existing and any future lenders secured, in whole or in part, by interests in the Facility, NEA’s contractual rights, or NEA or Affiliates of NEA. Such assignment to lenders shall not operate to relieve NEA of any duty or obligation under this Agreement. In connection with the exercise of remedies under the security documents relating to such financing(s), the lender(s) or trustee(s) shall be entitled to assign this Agreement to any third-party transferee designated by such lender(s) or trustee(s), provided that CECO determines, in CECO’s reasonable discretion, that such proposed transferee or assignee is qualified and capable to satisfy NEA’s obligations hereunder.

(b) CECO shall have the right to assign this Agreement in connection with a CECO Reorganization Event to any assignee without the consent of NEA so long as (i) the proposed assignee serves load in NEPOOL and (ii) the proposed assignee’s credit rating as established by Moody’s or S&P is equal to or better than that of CECO at the time of the proposed assignment (provided, that any such rating that is on “watch” for downgrading shall not satisfy the credit rating criteria described in clause (ii)).

(c) If either Party assigns this Agreement as provided in this Section 13.2, then such Party shall cause to be delivered to the other Party an assumption agreement (in form and substance reasonably satisfactory to the non-assigning Party) of all of the obligations of the assigning Party hereunder by such assignee.

(d) An assignment of this Agreement pursuant to this Section 13.2 shall not release or discharge the assignor from its obligations hereunder unless the assignee executes a written assumption agreement in accordance with Section 13.2(c) hereof.

14. NOTICES

Any notice or communication given pursuant hereto shall be in writing and (1) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (2) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); (3) e-mailed (e-mailed notices shall be deemed given upon actual receipt) or (4) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designed by either Party to the other in writing:

- 26 -

If to CECO:

Commonwealth Electric Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

Copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

With a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

15. WAIVER AND MODIFICATION

This Agreement may be amended and its provisions and the effects thereof waived only by a writing executed by the Parties, and no subsequent conduct of any Party or course of dealings between the Parties shall effect or be deemed to effect any such amendment or waiver. No waiver of any of the

- 27 -

provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. The failure of either Party to enforce any provision of this Agreement shall not be construed as a waiver of or acquiescence in or to such provision.

16. INTERPRETATION

16.1 Choice of Law. Interpretation and performance of this Agreement shall be in accordance with, and shall be controlled by, the laws of the Commonwealth of Massachusetts (without regard to its principles of conflicts of law).

16.2 Headings. Article and Section headings are for convenience only and shall not affect the interpretation of this Agreement. References to articles, sections and appendices, and schedules are, unless the context otherwise requires, references to articles, sections, appendices, and schedules of this Agreement. The words “hereof and “hereunder” shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

17. COUNTERPARTS

Any number of counterparts of this Agreement may be executed, and each shall have the same force and effect as an original.

18. NO DUTY TO THIRD PARTIES

Except as provided in any consent to assignment of this Agreement, nothing in this Agreement nor any action taken hereunder shall be construed to create any duty, liability or standard of care to any Person not a Party to this Agreement.

19. SEVERABILITY

If any term or provision of this Agreement or the interpretation or application of any term or provision to any prior circumstance is held to be unenforceable, illegal or invalid by a court or agency of competent jurisdiction, the remainder of this Agreement and the interpretation or application of all other terms or provisions to Persons or circumstances other than those which are unenforceable, illegal or invalid shall not be affected thereby, and each term and provision shall be valid and be enforced to the fullest extent permitted by law.

20. ENTIRE AGREEMENT

Upon the Effective Date, this Agreement, together with the agreements executed or delivered on the Effective Date in connection herewith, shall constitute the entire agreement and understanding between the Parties hereto and shall supersede all prior agreements including, without limitation, the Existing CECO 2 PPA and understandings relating to the subject matter hereof.

- 28 -

21. CHANGE IN LAW OR MARKET STRUCTURE

The Parties acknowledge that this Agreement is based on the Laws, ISO Policies and market structure in effect as of the Agreement Date. In the event of a Change in Law or Market Structure, the Parties shall make such amendments to this Agreement as are necessary to accommodate such Change in Law or Market Structure, provided that any such amendments shall preserve the economic and business arrangements embodied or referenced in this Agreement.

- 29 -

CECO 2

IN WITNESS WHEREOF, each of CECO and NEA has caused this Agreement to be duly executed on its behalf as of the date first above written.

Commonwealth Electric Company
By:	/s/ Ellen K. Angley
Name:	Ellen K. Angley
Title:	Vice President Energy Supply & Transmission
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:	/s/ Nathan E. Hanson
	Nathan E. Hanson
	Authorized Representative

- 30 -

SCHEDULE 3.3

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

DELIVERY SCHEDULE FOR CONTRACT ENERGY

Month	MWh/h
January	20.0000
February	20.0000
March	20.0000
April	20.0000
May	20.0000
June	20.0000
July	20.0000
August	20.0000
September	20.0000
October	20.0000
November	20.0000
December	20.0000

- 31 -

SCHEDULE 4.1(a)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

- 32 -

Month Ending	No. of Days	MWh/hr CECo 2	MWhs CECo 2	Monthly Support Payment Price ($/MWh) CECo 2
04/30/04	30	20.0000	14,400.0000
05/31/04	31	20.0000	14,880.0000
06/30/04	30	20.0000	14,400.0000
07/31/04	31	20.0000	14,880.0000
08/31/04	31	20.0000	14,880.0000
09/30/04	30	20.0000	14,400.0000
10/31/04	31	20.0000	14,880.0000
11/30/04	30	20.0000	14,400.0000
12/31/04	31	20.0000	14,880.0000
01/31/05	31	20.0000	14,880.0000
02/28/05	28	20.0000	13,440.0000
03/31/05	31	20.0000	14,880.0000
04/30/05	30	20.0000	14,400.0000
05/31/05	31	20.0000	14,880.0000
06/30/05	30	20.0000	14,400.0000
07/31/05	31	20.0000	14,880.0000
08/31/05	31	20.0000	14,880.0000
09/30/05	30	20.0000	14,400.0000
10/31/05	31	20.0000	14,880.0000
11/30/05	30	20.0000	14,400.0000
12/31/05	31	20.0000	14,880.0000
01/31/06	31	20.0000	14,880.0000
02/28/06	28	20.0000	13,440.0000
03/31/06	31	20.0000	14,880.0000
04/30/06	30	20.0000	14,400.0000
05/31/06	31	20.0000	14,880.0000
06/30/06	30	20.0000	14,400.0000
07/31/06	31	20.0000	14,880.0000
08/31/08	31	20.0000	14,880.0000
09/30/06	30	20.0000	14,400.0000
10/31/06	31	20.0000	14,880.0000
11/30/06	30	20.0000	14,400.0000
12/31/06	31	20.0000	14,880.0000
01/31/07	31	20.0000	14,880.0000
02/28/07	28	20.0000	13,440.0000
03/31/07	31	20.0000	14,880.0000
04/30/07	30	20.0000	14,400.0000
05/31/07	31	20.0000	14,880.0000
06/30/07	30	20.0000	14,400.0000
07/31/07	31	20.0000	14,880.0000
08/31/07	31	20.0000	14,880.0000
09/30/07	30	20.0000	14,400.0000
10/31/07	31	20.0000	14,880.0000
11/30/07	30	20.0000	14,400.0000
12/31/07	31	20.0000	14,880.0000
01/31/08	31	20.0000	14,880.0000
02/29/08	29	20.0000	13,920.0000
03/31/08	31	20.0000	14,880.0000
04/30/08	30	20.0000	14,400.0000
05/31/08	31	20.0000	14,880.0000
06/30/08	30	20.0000	14,400.0000

- 33 -

Month Ending	No. of Days	MWh/hr CECo 2	MWhs CECo 2	Monthly Support Payment Price ($/MWh) CECo 2
07/31/08	31	20.0000	14,880.0000
08/31/08	31	20.0000	14,880.0000
09/30/08	30	20.0000	14,400.0000
10/31/08	31	20.0000	14,880.0000
11/30/08	30	20.0000	14,400.0000
12/31/08	31	20.0000	14,880.0000
01/31/09	31	20.0000	14,880.0000
02/28/09	28	20.0000	13,440.0000
03/31/09	31	20.0000	14,880.0000
04/30/09	30	20.0000	14,400.0000
05/31/09	31	20.0000	14,880.0000
06/30/09	30	20.0000	14,400.0000
07/31/09	31	20.0000	14,880.0000
08/31/09	31	20.0000	14,880.0000
09/30/09	30	20.0000	14,400.0000
10/31/09	31	20.0000	14,880.0000
11/30/09	30	20.0000	14,400.0000
12/31/09	31	20.0000	14,880.0000
01/31/10	31	20.0000	14,880.0000
02/28/10	28	20.0000	13,440.0000
03/31/10	31	20.0000	14,880.0000
04/30/10	30	20.0000	14,400.0000
05/31/10	31	20.0000	14,880.0000
06/30/10	30	20.0000	14,400.0000
07/31/10	31	20.0000	14,880.0000
08/31/10	31	20.0000	14,880.0000
09/30/10	30	20.0000	14,400.0000
10/31/10	31	20.0000	14,880.0000
11/30/10	30	20.0000	14,400.0000
12/31/10	31	20.0000	14,880.0000
01/31/11	31	20.0000	14,880.0000
02/28/11	28	20.0000	13,440.0000
03/31/11	31	20.0000	14,880.0000
04/30/11	30	20.0000	14,400.0000
05/31/11	31	20.0000	14,880.0000
06/30/11	30	20.0000	14,400.0000
07/31/11	31	20.0000	14,880.0000
08/31/11	31	20.0000	14,880.0000
09/30/11	30	20.0000	14,400.0000
10/31/11	31	20.0000	14,880.0000
11/30/11	30	20.0000	14,400.0000
12/31/11	31	20.0000	14,880.0000
01/31/12	31	20.0000	14,880.0000
02/29/12	29	20.0000	13,920.0000
03/31/12	31	20.0000	14,880.0000
04/30/12	30	20.0000	14,400.0000
05/31/12	31	20.0000	14,880.0000
06/30/12	30	20.0000	14,400.0000
07/31/12	31	20.0000	14,880.0000
08/31/12	31	20.0000	14,880.0000
09/30/12	30	20.0000	14,400.0000

- 34 -

Month Ending	No. of Days	MWh/hr CECo 2	MWhs CECo 2	Monthly Support Payment Price ($/MWh) CECo 2
10/31/12	31	20.0000	14,880.0000
11/30/12	30	20.0000	14,400.0000
12/31/12	31	20.0000	14,880.0000
01/31/13	31	20.0000	14,880.0000
02/28/13	28	20.0000	13,440.0000
03/31/13	31	20.0000	14,880.0000
04/30/13	30	20.0000	14,400.0000
05/31/13	31	20.0000	14,880.0000
06/30/13	30	20.0000	14,400.0000
07/31/13	31	20.0000	14,880.0000
08/31/13	31	20.0000	14,880.0000
09/30/13	30	20.0000	14,400.0000
10/31/13	31	20.0000	14,880.0000
11/30/13	30	20.0000	14,400.0000
12/31/13	31	20.0000	14,880.0000
01/31/14	31	20.0000	14,880.0000
02/28/14	28	20.0000	13,440.0000
03/31/14	31	20.0000	14,880.0000
04/30/14	30	20.0000	14,400.0000
05/31/14	31	20.0000	14,880.0000
06/30/14	30	20.0000	14,400.0000
07/31/14	31	20.0000	14,880.0000
08/31/14	31	20.0000	14,880.0000
09/30/14	30	20.0000	14,400.0000
10/31/14	31	20.0000	14,880.0000
11/30/14	30	20.0000	14,400.0000
12/31/14	31	20.0000	14,880.0000
01/31/15	31	20.0000	14,880.0000
02/28/15	28	20.0000	13,440.0000
03/31/15	31	20.0000	14,880.0000
04/30/15	30	20.0000	14,400.0000
05/31/15	31	20.0000	14,880.0000
06/30/15	30	20.0000	14,400.0000
07/31/15	31	20.0000	14,880.0000
08/31/15	31	20.0000	14,880.0000
09/30/15	30	20.0000	14,400.0000
10/31/15	31	20.0000	14,880.0000
11/30/15	30	20.0000	14,400.0000
12/31/15	31	20.0000	14,880.0000
01/31/16	31	20.0000	14,880.0000
02/29/16	29	20.0000	13,920.0000
03/31/16	31	20.0000	14,880.0000
04/30/16	30	20.0000	14,400.0000
05/31/16	31	20.0000	14,880.0000
06/30/16	30	20.0000	14,400.0000
07/31/16	31	20.0000	14,880.0000
08/31/16	31	20.0000	14,880.0000
09/30/16	15	20.0000	7,200.0000

- 35 -

SCHEDULE 4.1(c)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

LIST OF APPROVED CAPACITY BUYERS

Constellation Power Source, Inc.

J Aron & Company

Morgan Stanley Group Capital

PP&L Energy Plus, LLC

PSE&G Energy Resources & Trading, LLC

Select Energy, Inc.

Sempra Energy Trading Corp.

TransCanada Power Marketing Ltd.

- 36 -

SCHEDULE 6.2(g)

to

AMENDED AND RESTATED

POWER PURCHASE AGREEMENT

MONTAUP PPA AMENDMENTS OR MODIFICATIONS

First Amendment dated as of June 28, 1989

Agreement dated May 11, 1992

Agreement dated December 18, 2001

Agreement dated March 31, 2003

- 37 -

EX-10.22

EXHIBIT 10.22

BELLINGHAM EXECUTION AGREEMENT

THIS BELLINGHAM EXECUTION AGREEMENT (the “Agreement”) is entered into as of August 19, 2004 (the “Contract Date”), between Boston Edison Company (“BECo”) and Commonwealth Electric Company (“CECo”) (BECo and CECo each, a “Utility”, jointly, the “Utilities”) and Northeast Energy Associates, A Limited Partnership, a Massachusetts limited partnership (“NEA”). The Utilities and NEA are sometimes referred to individually in this Agreement as a “Party” and collectively as the “Parties.”

RECITALS

A. The Utilities and NEA are parties to certain Power Purchase Agreements, as amended, and as set forth in Schedule A hereof (individually, BECo A, BECo B, CECo 1, CECo 2, collectively, the “Power Purchase Agreements”) pursuant to which the Utilities purchase from NEA contract capacity and the associated energy generated by NEA’s Bellingham power generation facility (the “Facility”). On October 17, 2003, Utilities requested the submission of proposals regarding the transfer of entitlements to certain power purchase agreements. In response, on December 3, 2003, NEA proposed the restructuring of the Power Purchase Agreements. The implementation of the agreement of the Parties with respect to the Utilities’ request for proposals and NEA’s proposal for the restructuring of the Power Purchase Agreements is effectuated by the provisions of this Agreement, including the Interim Amount Adjustments (as hereinafter defined), and the Amended and Restated Power Purchase Agreements (as hereinafter defined).

B. In connection with a financing relating to the Facility and a nominal 300 MW natural gas-fired electrical and steam generating plant owned by North Jersey Energy Associates, A Limited Partnership (“NJEA”) in the town of Sayreville, New Jersey (the “Sayreville Facility”), ESI Tractebel Funding Corp., a Delaware corporation (formerly IEC Funding Corporation) (“ESI Funding”) issued its senior secured securities (the “Senior Secured Notes”) pursuant to that certain Trust Indenture, dated as of November 15, 1994, among ESI Funding, NEA, NJEA and State Street Bank and Trust Company, as trustee (the “Senior Trustee”), as supplemented by that certain First Supplemental Indenture dated as of November 15, 1994, and that certain Second Supplemental Trust Indenture dated as of January 14, 1998, (collectively, the “Senior Indenture”). As part of the security for the Senior Secured Notes, NEA collaterally assigned its right, title and interest in and to the Power Purchase Agreements to the Senior Trustee on behalf of the holders of the Senior Secured Notes (the “Senior Note Holders”), and pledged all of the revenues received under, and granted a priority perfected security interest in, the Power Purchase Agreements to the Senior Trustee on behalf of the holders of the Senior Note Holders pursuant to the Senior Indenture and related security documents. The Senior Secured Notes are also secured by NEA’s interests in the Facility and its related revenue-generating agreements.

C. In connection with an additional financing to, among other purposes, acquire and provide additional capital for the Facility and the Sayreville Facility, ESI Tractebel Acquisition Corp., a Delaware corporation (“ESI Acquisition,” and together with ESI Funding, the “Issuers”) issued its secured securities (the “Junior Secured Notes”) pursuant to that certain Indenture, dated as of February 19, 1998, among ESI Acquisition, Northeast Energy, LP, a Delaware limited partnership (“NELP”) and Northeast Energy, LLC, a Delaware limited liability company (“NELLC”) directly and wholly owned by NELP, and State Street

Bank and Trust Company, as trustee (the “Junior Trustee”), as supplemented by that certain First Supplemental Indenture dated as of February 19, 1998, (collectively, the “Junior Indenture”). The Junior Secured Notes are payable by NELP from distributions to it by NEA and NJEA.

D. Simultaneously with the execution of this Agreement, the Utilities and NEA have executed and delivered amended and restated power purchase agreements (attached hereto as Schedule D and, as amended by the New PPA Amendments (as hereinafter defined), if any, collectively, the “Amended and Restated Power Purchase Agreements”) to provide, among other things, that NEA will sell and deliver and the Utilities will purchase and receive certain energy and a stated amount of capacity from the Facility and/or from sources other than the Facility. The Amended and Restated Power Purchase Agreements, the agreements and documents described in Section 2.2 hereof to which either or both of the Utilities is a party and the other certificates, instruments and documents to be delivered by the Utilities to consummate the Transactions (as hereinafter defined) and perform its obligations as contemplated hereby and thereby are collectively referred to as the “NSTAR Documents ”.

E. NEA will collaterally assign all of its rights under the Amended and Restated Power Purchase Agreements to the Senior Trustee on behalf of the Senior Note Holders as collateral security for the Senior Secured Notes pursuant to the “Assignment Agreement”.

F. On the Closing Date (as hereinafter defined): (1) the Amended and Restated Power Purchase Agreements will become effective in accordance with their terms, superceding the Power Purchase Agreements and (2) the collateral assignment contemplated by the Assignment Agreement will occur. The foregoing (and any necessary transactions between NEA and the Utilities incident to any of them) shall collectively be referred to herein as the “Transactions”.

G. The Closing Date will not occur until the Massachusetts Department of Telecommunications and Energy (the “MDTE”) has approved this Agreement, the Amended and Restated Power Purchase Agreements, and the Transactions, in each case, by a written decision (herein, the “MDTE Order”) that: (1) is reasonably acceptable in form and substance to the Utilities and NEA; (2) is final and non-appealable, unless such condition is waived in writing by the Parties (the “Final Decision”): and (3) includes the findings set forth in Schedule G hereof (the “Required Findings”). The date on which the MDTE Order containing the Required Findings becomes the Final Decision is referred to herein as the “Final Order Date.” The date on which the Utilities shall cause the Petition (as hereinafter defined) to be filed with the MDTE is referred to herein as the “Filing Date”.

H. The Parties believe that the consummation of the Transactions on the terms set forth herein and in the Execution Documents (as hereinafter defined) is in their respective best interests.

NOW, THEREFORE, in consideration of the foregoing and of the agreements contained herein, the Parties agree as follows:

ARTICLE 1

DEFINITIONS

In addition to terms defined in the introductory paragraph to this Agreement, the following terms shall have the meanings set forth below:

- 2 -

“Adjusted Bid Price Amount” shall mean the Initial NEA Bid Price Amount plus the Bid Date On-Peak Energy Cost, minus the Calculation Date On-Peak Energy Cost. The Adjusted Bid Price Amount will be calculated and agreed to by the Parties on the Calculation Date.

(i) Schedule 1 to this Agreement sets forth specific numerical values used to calculate various components of the Bid Date On-Peak Energy Cost and the Calculation Date On-Peak Energy Cost as well as sample numerical values used to calculate a sample Bid Date On-Peak Energy Cost and a sample Calculation Date On-Peak Energy Cost, which sample values shall be replaced with actual values for the Bid Date On-Peak Energy Cost and the Calculation Date On-Peak Energy Cost as of the Calculation Date in order to calculate the actual Adjusted Bid Price Amount, which shall be calculated and set forth on Schedule 1.5. The Parties acknowledge and agree that the mathematical operations (addition, subtraction, multiplication and division) performed on the numerical values contained or to be contained in Schedules 1 and 1.5 in order to calculate the Adjusted Bid Price Amount are embedded as functions in a Microsoft Excel spreadsheet, a copy of which has been provided to each Party.

(ii) It is the intent of the Parties that the provisions of this Agreement shall be construed consistently with Schedules 1 and 1.5 and the sample calculations contained therein, and that together such provisions and schedules shall embody the agreement of the Parties with respect to the calculation of the Adjusted Bid Price Amount.

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries’ controls, is controlled by, or is under common control with, such first Person. As used in this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“Amended and Restated Power Purchase Agreements” shall have the meaning set forth in the Recitals.

“Assignment Agreement” shall have the meaning set forth in the Recitals.

“Audit” shall have the meaning set forth in Section 5.2(c).

“BECo A” shall have the meaning set forth in Schedule A.

“BECo B” shall have the meaning set forth in Schedule A.

“Bid Date Gas Price” shall mean, for any month during the Term, the price of natural gas for such months as set forth in Schedule 1.

“Bid Date On-Peak Energy Cost” shall mean the present value of the monthly Bid Date On-Peak Energy Cost for each month in the Term, which shall be calculated on the Calculation Date, pursuant to which (a) for each month during the Term, the monthly Bid Date On-Peak Energy Cost, expressed in

- 3 -

dollars, will equal the product of (i) the applicable monthly Bid Date Gas Price, expressed in $/MMBtu, (ii) 8.6 MMBtu/MWh, and (iii) the applicable aggregate monthly volume of On-Peak MWh as set forth in Schedule 1 and (b) the present value of the monthly Bid Date On-Peak Energy Cost will be discounted to April 1, 2004, at an annual discount factor of 8.1%.

“Business Day” shall mean any day that is not a Saturday, Sunday, or NERC Holiday.

“Calculation Date” shall mean the Business Day immediately prior to the Closing Date.

“Calculation Date On-Peak Energy Cost” shall mean the present value of the monthly Calculation Date On-Peak Energy Cost for each month in the Term, which shall be calculated on the Calculation Date, pursuant to which (a) for each month during the Term, the monthly Calculation Date On-Peak Energy Cost, expressed in dollars, will equal the product of (i) the applicable monthly Forward NYMEX Gas Price, expressed in $/MMBtu, (ii) 8.6 MMBtu/MWh, and (iii) the applicable aggregate monthly volume of On-Peak MWh as set forth in Schedule 1 and (b) the present value of the monthly Calculation Date On-Peak Energy Cost will be discounted to April 1, 2004, at an annual discount factor of 8.1%.

“CECo 1” shall have the meaning set forth in Schedule A.

“CECo 2” shall have the meaning set forth in Schedule A.

“Closing Date” shall have the meaning set forth in Section 2.2.

“Closing Date Amount” shall mean the sum of (a) through (g) below. The amounts in (b) through (g) result from the calculations described therein and performed on the Calculation Date for each calendar month (or portion of a calendar month) during the Interim Period:

(a) $27,747,383.90, plus

(b) the product of (i) the Net Delivered MWhs delivered from the Facility in that month plus any Interim Period Make Up Delivery, but in no event an energy quantity greater than the aggregate of the Interim Period On-Peak Delivery Quantities and Interim Period Off-Peak Delivery Quantities and (ii) the Interim Period Support Payment Rate, plus

(c) the product of (i) the Net Delivered MWhs delivered from the Facility during On-Peak Hours at the applicable Interim Period Delivery Points up to the Interim Period On-Peak Delivery Quantities, and (ii) the Interim Period On-Peak Energy Price at the applicable Interim Period Delivery Point, expressed as a $/MWh, plus

(d) the product of (i) the Net Delivered MWhs delivered from the Facility during On-Peak Hours at the applicable Interim Period Delivery Points in excess of the Interim Period On-Peak Delivery Quantities and (ii) the applicable hourly DAM LMP Prices at the applicable Interim Period Delivery Points, expressed as a $/MWh, plus

(e) the product of (i) the Net Delivered MWhs delivered from the Facility during Off-Peak Hours at the applicable Interim Period Delivery Points and (ii) the applicable hourly DAM LMP Prices at the applicable Interim Period Delivery Points, plus

- 4 -

(f) the product of (i) a price, expressed in dollars per MW-month and determined in accordance with the procedure set forth in Section 4.1(b) of the Amended and Restated Power Purchase Agreements and (ii) the quantity of capacity, expressed in units of MW, delivered under the Power Purchase Agreements during such month, minus

(g) any amounts actually paid by the Utilities to NEA under the Power Purchase Agreements during such month;

provided, that where applicable, a good faith estimate will be made of the amounts under clauses (a) through (g), above, which amounts will be adjusted in the next billing cycle to reflect actual calculations performed promptly after the Contract Date in the case of (a) above or after the Closing Date in the case of (b) through (g) above. Prior to the Closing Date, the Utilities and NEA shall, at the request of either Party, exchange sample calculations of the Closing Date Amount.

“Closing Payment” shall have the meaning set forth in Section 5.5.

“Consent to Collateral Assignment” shall have the meaning set forth in Section 2.2(b)(iii).

“Contract Date” shall have the meaning set forth in the Preamble.

“DAM LMP Prices” in any hour for any node in NEPOOL shall mean the LMP prices resulting from the Day-Ahead Energy Market.

“Day-Ahead Energy Market” or “DAM” shall have the meaning as set forth in that certain Manual for Definitions and Abbreviations prepared by ISO, as may be amended from time to time.

“Data” shall have the meaning set forth in Section 5.4(b).

“Deadline” shall mean March 31, 2005.

“Effective Time” shall mean 11:59 PM EPT on the Closing Date.

“EPT” shall mean either Eastern Standard Time or Eastern Daylight Savings Time, as in effect from time to time.

“ESI Acquisition” shall have the meaning set forth in the Recitals.

“ESI Funding” shall have the meaning set forth in the Recitals.

“Execution Documents” shall mean, collectively, this Agreement, together with the Schedules hereto, the Amended and Restated Power Purchase Agreements, that certain Stipulation of Agreement of Non-Disclosure of Confidential or Protected Information entered into between the Parties, and any amendments to any of these documents made after the Contract Date.

“Existing Prices” shall mean the prices for energy and capacity set forth in the Power Purchase Agreements, as applicable.

- 5 -

“Facility” shall have the meaning set forth in the Recitals.

“FERC” shall mean the United States Federal Energy Regulatory Commission and shall include its successors.

“Filing Date” shall have the meaning set forth in the Recitals.

“Final Decision” shall have the meaning set forth in the Recitals.

“Final Order Date” shall have the meaning set forth in the Recitals.

“Forward NYMEX Gas Price” shall mean, for any month during the Term, the forward price for natural gas delivered to the Henry Hub for such month as posted by NYMEX as of the close of trading on the trading day immediately preceding the Calculation Date. With respect to any calendar month during the Term for which no such price is posted by NYMEX, the Forward NYMEX Gas Price will be such price posted by NYMEX for the same calendar month of the latest year for which such a forward price is posted by NYMEX.

“Gas Transactions” shall mean natural gas wholesale transactions.

“Initial NEA Bid Price Amount” shall mean negative $12,566,453.

“Interim Amount Adjustments” shall mean the Closing Date Amount paid pursuant to Section 5.4.

“Interim Period” shall mean the period commencing with the hour ending 0100 EPT on the day immediately following the Contract Date and ending on, and including, the earlier of (a) the Closing Date and (b) the Deadline.

“Interim Period Delivery Points” shall mean the delivery points for the delivery of energy by NEA to the Utilities during the Interim Period, which shall be the same delivery points as the delivery points under the applicable Power Purchase Agreement, as shown on attached Schedule 5.3 hereto.

“Interim Period Delivery Rate” shall mean the hourly rates during each month of the Interim Period at which NEA is projected to deliver energy to the Utilities at each of the Interim Period Delivery Points, expressed in MW and as set forth on Schedule 5.3.

“Interim Period Make Up Delivery” shall have the meaning set forth in Section 5.4(a).

“Interim Period Off-Peak Delivery Quantities” shall mean the monthly aggregate quantities of Off-Peak Hours energy that NEA is projected to deliver to the Utilities at each of the Interim Period Delivery Points during the Interim Period, expressed in MWh and as set forth on Schedule 5.3.

“Interim Period On-Peak Delivery Quantities” shall mean the monthly aggregate quantities of On-Peak Hours energy that NEA is projected to deliver to the Utilities at each of the Interim Period Delivery Points during the Interim Period, expressed in MWh and as set forth on Schedule 5.3.

- 6 -

“Interim Period On-Peak Energy Price” shall mean, during the Interim Period, a monthly scheduled price the Utilities will pay NEA for energy delivered from the Facility during On-Peak Hours at each of the Interim Period Delivery Points, expressed in $/MWh and as set forth on Schedule 5.3.

“Interim Period Support Payment Rate” shall mean, during the Interim Period, a scheduled dollar amount the Utilities will pay NEA for delivered energy in each month at each of the Interim Delivery Points, expressed in $/MWh and as set forth on Schedule 5.3.

“ISO” shall mean ISO New England, Inc., or its successors.

“Issuers” shall have the meaning set forth in the Recitals.

“Junior Indenture” shall have the meaning set forth in the Recitals.

“Junior Secured Notes” shall have the meaning set forth in the Recitals.

“Junior Trustee” shall have the meaning set forth in the Recitals.

“LMP” shall mean, for any ISO nodal point for any hour on any day, the “Day Ahead LMP” or “Real Time LMP” ($/MWh) at such ISO nodal point calculated in accordance with Section 2 of Market Rule 1, as reported on the ISO website at www.iso-ne.com on the “Data & Reports” page, “Hourly Markets Data” subpage and “Selectable Hourly LMP Data” category, for such nodal point on such date and time. If such price should ever cease to be published, then the LMP shall be a regularly published comparable substitute price, as agreed to by the Parties in writing.

“Material Adverse Change” shall mean an event, matter or circumstance (including any omission to act) arising after the Contract Date (but not an event, matter or circumstance which is reasonably likely to arise as of the date hereof) that has a detrimental economic impact of $10,000,000 or more to the party claiming such event, including, without limitation, a change in applicable law or in the interpretation of any applicable law by any court of competent jurisdiction or any other governmental entity, including, without limitation, a change in tax law or a change to the Public Utility Regulatory Policies Act of 1978, as amended, or a change in applicable accounting standards. A Materiel Adverse Change shall not include: (a) any act or omission expressly contemplated by this Agreement, (b) the execution or announcement of this Agreement or compliance with the terms hereof, or (c) any payment of the Interim Amount Adjustments or the Adjusted Bid Price Amount.

“MDTE” shall have the meaning set forth in the Recitals.

“MDTE Order” shall have the meaning set forth in the Recitals.

“Mutual Release” shall have the meaning set forth in Section 2.2(b)(iv).

“NEA Documents” shall mean, collectively, the agreements and documents described in Section 2.2 hereof to which NEA is a party (including, without limitation, the Amended and Restated Power Purchase Agreements) and the other certificates, instruments and documents to be delivered by NEA to consummate the Transactions and perform its obligations as contemplated hereby and thereby.

“NELP” shall have the meaning set forth in the Recitals.

- 7 -

“NELLC” shall have the meaning set forth in the Recitals.

“Net Delivered MWhs” shall mean, in any hour at any Interim Period Delivery Point during the Interim Period, the applicable net generation from the Facility allocated to the Power Purchase Agreements as follows: the gross generation from the Facility as reported by the Utilities to the ISO (and to NEA as Data pursuant to Section 5.4) shall be allocated to the Power Purchase Agreements according to the following percentages: BECO A - 46.5517%. BECO B - 28.9655%, CECo 1 - 8.6207% and CECo 2 - 7.2414%, with each such allocated amount then multiplied by the following applicable percentage: BECO A - 99.9711%, BECO B - 100%, CECo 1 - 99% and CECo 2 - 99%.

“NEPOOL” shall mean the New England Power Pool, or its successor.

“NERC” shall mean the North American Electric Reliability Council, or its successor.

“NERC Holiday” shall mean New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day, and any other day declared a holiday by NERC.

“New PPA Amendments” shall mean any amendments to the Amended and Restated Power Purchase Agreements which are entered into after the Contract Date and before the Closing Date, which such amendments shall not impair the validity or effectiveness of the Final Decision.

“NJEA” shall have the meaning set forth in the Recitals.

“NSTAR” shall mean NSTAR Electric & Gas Corporation.

“NSTAR Documents” shall have the meaning set forth in the Recitals.

“NYMEX” shall mean the New York Mercantile Exchange.

“Off-Peak Hours” shall mean all hours that are not On-Peak Hours.

“On-Peak Hours” shall mean, on any Business Day, the sixteen (16)-hour period beginning at the hour ending 0800 EPT and ending with the end of the hour ending 2300 EPT.

“Petition” shall have the meaning set forth in section 5.2(a).

“Power Purchase Agreements” shall have the meaning set forth in the Recitals.

“Real-Time Energy Market” or “RTM” shall have the meaning as set forth in that certain Manual for Definitions and Abbreviations prepared by ISO, as may be amended from time to time.

“RTM LMP Prices” in any hour for any node in NEPOOL shall mean the LMP prices resulting from the Real-Time Energy Market.

“Required Finding” shall have the meaning set forth in the Recitals.

“Sayreville Facility” shall have the meaning set forth in the Recitals.

- 8 -

“Senior Indenture” shall have the meaning set forth in the Recitals.

“Senior Note Holders” shall have the meaning set forth in the Recitals.

“Senior Secured Notes” shall have the meaning set forth in the Recitals.

“Senior Trustee” shall have the meaning set forth in the Recitals.

“Term” shall mean the period from and including the first day of the month immediately following the month in which the Closing Date occurs through and including September 30, 2016.

“Transactions” shall have the meaning set forth in the Recitals.

ARTICLE 2

TRANSACTION DELIVERABLES

2.1. Amended and Restated Power Purchase Agreements.

(a) On the Closing Date each Party shall deliver a certificate stating that all of the applicable conditions precedent set forth herein and in the Amended and Restated Power Purchase Agreements have been satisfied or waived by the Party entitled to the benefit thereof and that the “Effective Date” under the Amended and Restated Power Purchase Agreements and the New PPA Amendments has occurred. The Amended and Restated Power Purchase Agreements shall, among other things, provide: (i) that NEA will sell and deliver, and the Utilities will purchase and receive, certain energy and capacity from the Facility and/or from sources other than the Facility and (ii) that the Utilities shall purchase and receive such energy and capacity for the “Energy Payment” and at the “Capacity Price” specified therein.

(b) Subject to the terms and conditions set forth herein (including, without limitation, the satisfaction or waiver of the applicable conditions precedent set forth in Article 6 hereof), on the Closing Date, the Utilities and NEA agree to commence performance under the Amended and Restated Power Purchase Agreements and any New PPA Amendments in accordance with their terms and cause to be executed and delivered such other instruments and documents as are contemplated hereby and thereby.

2.2 Closing.

(a) Closing Date and Effective Time. Unless this Agreement is earlier terminated pursuant to the terms hereof, the Transactions shall be consummated at a closing to be held at approximately 10:00 a.m. EPT, at a location to be agreed upon by the Parties, on or as soon as reasonably practicable after the date that the conditions described in Article 6 hereof have been satisfied or waived by the Party entitled to the benefit thereof (the “Closing Date”), provided that the Closing Date shall not be earlier than January 2, 2005.

(b) Deliverables by the Utilities. On the Closing Date and subject to the terms and conditions set forth herein, the Utilities (as appropriate) shall deliver, or cause to be delivered, to NEA or its designee:

(i) the closing certificate described in the first sentence of Section 2.1(a) hereof;

- 9 -

(ii) any New PPA Amendments duly executed by the appropriate Utility;

(iii) the Affirmation of Consent to Collateral Assignment (“Consent to Collateral Assignment”) between the appropriate Utility and the Senior Trustee (on behalf of the Senior Note Holders), in form and substance reasonably acceptable to the Utility, NEA and the Senior Trustee, the form of which is attached hereto as Schedule 2.2(b)(iii), duly executed by the Utility, in which the Utility consents to the collateral assignment by NEA of the Amended and Restated Power Purchase Agreements to the Senior Trustee (on behalf of the Senior Note Holders) contemplated by the Assignment Agreement and provides certain rights and benefits to the Senior Trustee on behalf of the Senior Note Holders with respect to the Amended and Restated Power Purchase Agreements;

(iv) the Mutual Release between the appropriate Utility and NEA duly executed by the Utility which provides for a mutual release between the Utility and NEA of all of their respective obligations and liabilities under the Power Purchase Agreement arising prior to the Effective Time (the “Mutual Release”) the form of which is attached as Schedule 2.2(b)(iv);

(v) a certificate, executed by a duly authorized representative of the Utility (as appropriate), stating that the representations and warranties of the Utilities set forth in this Agreement and the Amended and Restated Power Purchase Agreements are true and correct as of the Closing Date; and

(vi) such other instruments and documents executed or provided by the appropriate Utility as may reasonably be required by NEA, the Senior Trustee or their respective legal counsel to evidence the consummation of the Transactions, including, without limitation, those items to be delivered by the Utilities pursuant to Article 6 hereof.

(c) Deliverables by NEA. On the Closing Date and subject to the terms and conditions set forth herein, NEA shall deliver, or cause to be delivered, to the Utilities or their designee:

(i) the closing certificate described in the first sentence of Section 2.1(a) hereof;

(ii) any New PPA Amendments duly executed by NEA;

(iii) the Mutual Release between the appropriate Utility and NEA duly executed by NEA;

(iv) a certificate, executed by a duly authorized representative of NEA, stating that the representations and warranties of NEA set forth in this Agreement and the Amended and Restated Power Purchase Agreements are true and correct as of the Closing Date; and

- 10 -

(v) such other instruments and documents executed or provided by NEA as may reasonably be required by the Utilities to evidence the consummation of the Transactions, including, without limitation, those items to be delivered by NEA pursuant to Article 6 hereof.

ARTICLE 3

REPRESENTATIONS AND WARRANTIES OF THE UTILITIES

Each Utility represents and warrants to NEA as of the Contract Date and as of the Closing Date (except in the event such representation or warranty by its terms is made only as of a certain date) as follows:

3.1. Authority.

The Utility is a corporation duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has all requisite corporate power and authority to enter into and be bound by the terms of this Agreement and, subject to the satisfaction or waiver by the Utility of the conditions set forth in Section 6.1 hereof, the NSTAR Documents. The execution and delivery of, and the performance by the Utility of its obligations under, this Agreement have been duly and validly authorized by all necessary corporate action of the Utility. This Agreement has been duly and validly executed and delivered by the Utility and constitutes a valid and binding obligation of the Utility, enforceable against the Utility in accordance with its terms, except as such enforceability may be limited by law or principles of equity. On the Closing Date and subject to the satisfaction or waiver by the Utility of the conditions set forth in Section 6.1 hereof, the NSTAR Documents, when executed and delivered by the Utility in accordance with this Agreement, shall constitute the valid and binding obligations of the Utility enforceable against the Utility in accordance with their respective terms, except as such enforceability may be limited by law or principles of equity.

3.2 No Conflicts.

Subject to the satisfaction or waiver by the Utility of the conditions set forth in Section 6.1 hereof, neither the execution and delivery of this Agreement and the NSTAR Documents by the Utility, nor the consummation or performance of the Transactions by the Utility, will (a) violate or conflict with any provisions of the Utility’s articles of organization or bylaws, (b) violate, conflict with or result in the breach or termination of any material agreement or instrument to which the Utility is a party or (c) violate or conflict with (or require any filing, consent, or similar action under) any law, rule, regulation, judgment, order, injunction, decree or award that applies to or binds the Utility or its property.

3.3 Litigation.

There is no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal, regulatory or otherwise, in law or in equity, pending or, to the knowledge of the Utility, threatened against or relating to the Utility or the Transactions which could reasonably be expected to (a) have a material adverse effect on the Transactions or (b) prevent the performance by the Utility of its obligations under the NSTAR Documents.

- 11 -

3.4 No Additional Conditions.

Except for the satisfaction of the conditions specifically identified in this Agreement (which may be waived by the applicable Utility), there are no other conditions precedent to (a) the Utility’s execution, delivery or performance of this Agreement and the NSTAR Documents or (b) the Utility’s implementation of the Transactions.

3.5 No Brokers.

Except as set forth on Schedule 3.5 hereto, no finder, broker or agent has been employed, appointed or authorized to act on behalf of the Utility in connection with the Transactions.

3.6 No Assignment; Amendment.

BECo and CECo are the sole owners of all right, title and interest of the power purchaser in, to and under the Power Purchase Agreements and have not assigned or otherwise transferred their rights or obligations under the Power Purchase Agreements to any third party. As of the Closing Date no amendment or modification of the Power Purchase Agreements is effective, except as identified in Schedule A hereof. As of the Closing Date no further amendment or modification of the Power Purchase Agreements will be effective or pending nor shall the Utility have assigned or otherwise transferred its rights or obligations under the Power Purchase Agreements, except pursuant to the Amended and Restated Power Purchase Agreements and the New PPA Amendments, if any.

ARTICLE 4

REPRESENTATIONS AND WARRANTIES OF NEA

NEA represents and warrants to the Utilities as of the Contract Date and as of the Closing Date (except in the event such representation or warranty by its terms is made only as of a certain date) as follows:

4.1 Authority.

NEA is a limited partnership validly formed and validly existing under the laws of the Commonwealth of Massachusetts and has all requisite partnership power and authority to be bound by the terms of this Agreement and, subject to the satisfaction or waiver by NEA of the conditions set forth in Section 6.2 hereof, the NEA Documents. The execution and delivery of, and the performance by NEA of its obligations under, this Agreement have been duly and validly authorized by all necessary partnership action of NEA. This Agreement has been duly and validly executed and delivered by NEA and constitutes a valid and binding obligation of NEA, enforceable against NEA in accordance with its terms, except as such enforceability may be limited by law or principles of equity. On the Closing Date and subject to the satisfaction or waiver by NEA of the conditions set forth in Section 6.2 hereof, the NEA Documents, when executed and delivered by NEA in accordance with this Agreement, shall constitute the valid and binding obligations of NEA enforceable against it in accordance with their respective terms, except as such enforceability may be limited by law or principles of equity.

- 12 -

4.2 No Conflicts.

Subject to the satisfaction or waiver by NEA of the conditions set forth in Section 6.2 hereof, neither the execution and delivery of this Agreement and the NEA Documents by NEA, nor the consummation or performance of the Transactions by NEA, will (a) violate or conflict with any provisions of NEA’s formation or governance documents, (b) violate, conflict with or result in the breach or termination of any material agreement or instrument to which NEA is a party or (c) violate or conflict with (or require any filing, consent, or similar action under) any law, rule, regulation, judgment, order, injunction, decree or award that applies to or binds NEA or its property.

4.3 Litigation.

There is no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal, regulatory or otherwise, in law or in equity, pending or, to the knowledge of NEA, threatened against or relating to NEA or the Transactions which could reasonably be expected to (a) have a material adverse effect on the Transactions or (b) prevent the performance by NEA of its obligations under the NEA Documents.

4.4 No Additional Conditions.

Except for the satisfaction of the conditions specifically identified in this Agreement (which may be waived by NEA), there are no other conditions precedent to (a) NEA’s execution, delivery or performance of this Agreement and the NEA Documents or (b) NEA’s implementation of the Transactions.

4.5 No Brokers.

Except as set forth in Schedule 4.5, no finder, broker or agent has been employed, appointed or authorized to act on behalf of NEA in connection with the Transactions.

ARTICLE 5

COVENANTS

5.1 Satisfaction of Conditions.

The Parties agree to cooperate in good faith and to take all commercially reasonable actions and devote resources reasonably necessary to comply with their obligations under this Article 5 and to obtain satisfaction of the conditions set forth in Article 6 hereof as soon as reasonably practicable, including using diligent efforts to secure the execution and delivery of the agreements and other instruments to be executed and delivered pursuant to Article 2 and Article 6 hereof. Each Party entitled to the benefit of conditions set forth in Article 6 hereof shall have the right to waive such conditions.

- 13 -

5.2 MDTE Approval.

(a) At any time after the Contract Date and no later than forty-five (45) days after NEA provides the Utilities with notice of waiver or satisfaction of the condition set forth in Section 6.2(k) hereof, the Utilities shall file, or cause to be filed, an initial petition (a “Petition”) with the MDTE requesting that the MDTE cause the Final Order Date to occur as soon as reasonably practicable, but in no event later than January 1, 2005. As and to the extent permitted by applicable law, the applicable Utility and NEA intend that certain provisions of this Agreement and related documents shall be “Confidential Information” and the applicable Utility and NEA shall seek confidential treatment by the MDTE of all confidential materials included in such Petition, or otherwise provided to the MDTE in support of the Petition. Prior to the Filing Date, the applicable Utility and NEA will reasonably cooperate with respect to identifying their respective confidential material in such agreements and related documents for which the Utility shall seek confidential treatment and any other materials to be submitted to the MDTE in support of the Petition. Upon filing of the Petition with the MDTE, the Parties will support the Petition and the data contained therein and shall use commercially reasonable efforts to obtain the Final Decision; provided that if the Final Order Date has not occurred by January 1, 2005, the Parties shall continue to use diligent efforts to secure the Final Decision, subject to their respective rights of termination under Section 7.1 hereof.

(b) Each party shall promptly provide to the other (whether in writing or orally) any information relating to any material event or development relating to the MDTE review and approval process referenced in Section 5.2(a) above. In addition, each Party shall respond promptly and fully to any reasonable inquiries that a requesting Party may make at any other time relating to such process.

(c) From the Contract Date through the Closing Date, neither Party shall enter into Gas Transactions outside of its ordinary course of business where such transactions are designed to manipulate the Adjusted Bid Price Amount. If a Party has cause to believe that such Gas Transactions have been executed by the other Party, the first Party may request an audit of the other Party’s records (an “Audit”). The Audit shall be conducted by a nationally recognized accounting firm reasonably acceptable to the audited Party and shall be confined to relevant Gas Transactions executed thirty (30) days prior to the Calculation Date. The Party requesting the Audit shall bear all costs of the Audit; provided, however, if the Audit reveals that there is a reasonable basis to conclude that the audited Party, acting outside of its ordinary course of business, has manipulated the Adjusted Bid Price Amount, then the auditor shall recalculate the Adjusted Bid Price Amount and the audited Party will pay the difference between the Adjusted Bid Price Amount originally paid and the corrected amount, plus the cost of the Audit. To the extent the audited Party disputes the Audit’s findings, the audited Party may submit the dispute to the dispute resolution process set forth at Article 10 of the Amended and Restated Power Purchase Agreements.

5.3 Status Pending Closing.

(a) Continued Effectiveness. The Power Purchase Agreements will remain in force and effect during the Interim Period and nothing herein shall constitute or be considered as an amendment or modification to the Power Purchase Agreements.

(b) Facility Scheduling. NEA shall continue to use the Facility to satisfy all capacity and energy obligations under the Power Purchase Agreements during the Interim Period. The Utilities will schedule NEA’s energy deliveries on a day-ahead basis at the Interim Period Delivery Points according to

- 14 -

the market rules, manuals and procedures adopted by ISO and/or the members of NEPOOL. In addition, the bidding, scheduling and operation of the Facility during the Interim Period shall be conducted in the same manner and on the same basis as was conducted during the period preceding the Contract Date, and shall be based on information customarily and routinely provided by NEA to the Utilities.

(c) Energy and Capacity Pricing. During the Interim Period, NEA will deliver energy and capacity from the Facility and the Utilities will purchase and receive such energy and capacity from the Facility. Energy generated by the Facility, and capacity attributable to the Facility, will be delivered by NEA to the Utilities at the Interim Period Delivery Points and will be purchased by the Utilities at the Existing Prices and paid for by the Utilities in accordance with the terms of the Power Purchase Agreements.

(d) Termination of Interim Period. Upon the earlier to occur of (i) the Closing Date or (ii) the Deadline, the Interim Period shall terminate and the provisions set forth in Sections 5.3 and 5.4 shall have no effect and will become void. If the Closing Date occurs prior to the Deadline, then from and after the termination of the Interim Period the Amended and Restated Power Purchase Agreements will govern the relationship between the Parties. If the Deadline occurs prior to the Closing Date, then from and after the termination of the Interim Period the terms and conditions of the Power Purchase Agreements will continue to govern the relationship between the Parties.

5.4 Deliveries of Energy Outside of the Power Purchase Agreements During the Interim Period.

(a) Interim Period Make Up Delivery. For any hour that the Facility is not capable of generating energy in a quantity sufficient for NEA to deliver energy at the Interim Period On-Peak Delivery Quantities and Interim Period Off-Peak Delivery Quantities, NEA, or a third party acting on behalf of NEA, shall deliver at the Interim Period Delivery Points, electric energy in a quantity equal to the difference between the Net Delivered MWhs delivered from the Facility and the sum of the Interim Period On-Peak Delivery Quantities and Interim Period Off-Peak Delivery Quantities (“Interim Period Make Up Delivery”). An Interim Period Make Up Delivery will not be subject to a loss adjustment factor.

(b) Interim Period Facility Meter Data. During the Interim Period, the Utilities will use commercially reasonable efforts to provide NEA with the prior day’s hourly net generator values in ISO upload format applicable to the Facility (“Data”) by no later than 1:00 PM EPT on the next NSTAR regular working day. NEA will schedule an Interim Period Make Up Delivery pursuant to Manual 28, Section 9.1.1 in the RTM upon receipt of such Data. Any errors will be corrected in the RTM pursuant to Manual 28, Section 9.1.1. In the event that a Utility fails to confirm a scheduled Interim Period Make Up Delivery in accordance with NEPOOL scheduling procedures for the RTM, then the Interim Period Make Up Delivery scheduled by NEA (whether or not confirmed by the Utility) plus the Net Delivered MWhs delivered by the Facility during the relevant period will be deemed to be the relevant Interim Period On-Peak Delivery Quantities and Interim Period Off-Peak Delivery Quantities.

(c) Interim Period Pricing. Energy delivered by or on behalf of NEA and received by the Utilities pursuant to an Interim Period Make Up Delivery will be purchased and sold at the RTM LMP Prices at the applicable Interim Period Delivery Points. Interim Period Make Up energy will be paid for by the Utilities directly to NEA or directly to the party providing energy on behalf of NEA within twenty (20) days of the receipt by the applicable Utility of an invoice for such energy.

- 15 -

5.5 Closing Payment.

(a) Payment Amount. The Closing Payment (equal to the sum of the Closing Date Amount and the revised Adjusted Bid Price Amount, as calculated pursuant to Section 5.5(b)), shall be paid on the Closing Date. If the Closing Payment is a positive amount, the Utilities shall cause NSTAR to make payment to NEA of such amount. If the Closing Payment is a negative amount, NEA shall pay NSTAR, on behalf of the Utilities, the absolute value of such amount.

(b) Revised Adjusted Bid Price Amount. For purposes of calculating the Closing Payment components, the revised Adjusted Bid Price Amount shall be determined as provided below:

(i) If, on the Calculation Date, the Adjusted Bid Price Amount is less than negative then (A) NEA may elect to have the revised Adjusted Bid Price Amount be the calculated Adjusted Bid Price Amount, in which event the Closing Date will occur as scheduled or (B) the Utilities may elect to have the revised Adjusted Bid Price Amount be negative in which event the Closing Date will occur as scheduled.

(ii) If, On the Calculation Date, the Adjusted Bid Price Amount is greater than negative and less than positive the revised Adjusted Bid Price Amount will be the Adjusted Bid Price Amount.

(iii) If, on the Calculation Date, the Adjusted Bid Price Amount is greater than positive then (A) the Utilities may elect to have the revised Adjusted Bid Price Amount be the calculated Adjusted Bid Price Amount, in which event the Closing Date will occur as scheduled or (B) NEA may elect to have the revised Adjusted Bid Price Amount equal in which event the Closing Date will occur as scheduled.

(iv) For the avoidance of doubt, if on the Calculation Date, the Adjusted Bid Price Amount equals zero, the revised Adjusted Bid Price Amount will be zero.

(v) If neither election as set forth in Section 5.5(b)(i) above is made, then the Closing Date may be postponed as provided in this Section 5.5(b)(v) and on each successive Business Day the Parties will recalculate the Adjusted Bid Price Amount until the earlier of: (A) the Business Day preceding the Deadline or (B) the first date on which the Adjusted Bid Price Amount is greater than or equal to an amount between negative and positive. None of the Parties shall have the obligation to extend or permit extension of the Closing Date beyond the Deadline. It is agreed that if the calculation described in clause (B) does not occur on or before the Business Day preceding the Deadline, then this Agreement will terminate on the Deadline. It is further agreed that if such calculation does occur on or before the Business Day preceding the Deadline, then the Closing Date will occur on the Business Day immediately following the date of such calculation, and the revised Adjusted Bid Price Amount will be determined in accordance with Section 5.5(b)(ii).

- 16 -

(vi) If neither election as set forth in Section 5.5(b)(iii) above is made, then the Closing Date may be postponed as provided in this Section 5.5(b)(vi) and on each successive Business Day the Parties will recalculate the Adjusted Bid Price Amount until the earlier of: (A the Business Day preceding the Deadline or (B) the first date on which the Adjusted Bid Price Amount is less than or equal to positive (and not less than negative). None of the Parties shall have the obligation to extend or permit extension of the Closing Date beyond the Deadline. It is agreed that if the calculation described in clause (B) does not occur on or before the Business Day preceding the Deadline, then this Agreement will terminate on the Deadline. It is further agreed that if such calculation does occur on or before the Business Day preceding the Deadline, then the Closing Date will occur on the Business Day immediately following the date of such calculation, and the revised Adjusted Bid Price Amount will be determined in accordance with Section 5.5(b)(ii).

ARTICLE 6

CONDITIONS

6.1 Conditions to the Obligations of the Utilities.

The Utility’s obligation to effect the Transactions is subject to the satisfaction at or before the Closing Date of the following conditions (any of which the applicable Utility may waive):

(a) Representations and Warranties. All of the representations and warranties of NEA herein shall be true and correct in all respects as though made on and as of the Closing Date (unless the incorrectness of such representations and warranties does not have a material adverse effect on the Utility’s rights herein), and NEA shall have delivered the certificate referred to in Section 2.2(c)(iv). NEA shall have performed, or caused to be performed, all of the agreements and covenants to be performed by NEA under this Agreement as of the Closing Date, unless the non-performance of such agreements and covenants does not have a Material Adverse Change on the Utility’s rights herein.

(b) No Legal Restraint. The applicable Utility shall not be subject to any order, decree, injunction, or other legal restraint or prohibition of a court or agency of competent jurisdiction that would enjoin, prohibit or interfere with the consummation of the Transactions.

(c) Documents. NEA shall have executed and delivered the Amended and Restated Power Purchase Agreements and any New PPA Amendments and the other NEA Documents, and all other documents required to be executed and delivered by it pursuant to this Agreement.

(d) MDTE Final Decision. The MDTE Order containing the Required Findings shall have become a Final Decision.

(e) Litigation. There shall be no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal or regulatory, in law or in equity, by or before any governmental authority with valid jurisdiction pending, or to the knowledge of the Utility, threatened in writing against the Utility or against or related to the Transactions which could reasonably be expected to have a Material Adverse Change on the consummation of the Transactions.

- 17 -

(f) NEPOOL/ISO. As related to the Amended and Restated Power Purchase Agreements, any and all necessary filings or notices shall have been given or made with NEPOOL and/or ISO and any and all approvals or authorizations concerning the Amended and Restated Power Purchase Agreements shall have been received in a form reasonably acceptable to the Utilities.

(g) Accounting and Tax Treatment. Each Utility and each of their Affiliates shall be entitled to accounting treatment and tax treatment reasonably satisfactory to each of them relating to the Transactions.

6.2 Conditions to the Obligations of NEA.

NEA’s obligation to effect the Transactions is subject to the satisfaction at or before the Closing Date of the following conditions (any of which NEA may waive):

(a) Representations and Warranties. All of the representations and warranties of the Utilities herein shall be true and correct in all respects as though made on and as of the Closing Date (unless the incorrectness of such representations and warranties does not have a material adverse effect on NEA’s rights herein), and each Utility shall have delivered the certificate referred to in Section 2.2(b)(v). Each Utility shall have performed, or caused to be performed, all of the agreements and covenants to be performed by the Utilities under this Agreement as of the Closing Date, unless the non-performance of such agreements and covenants does not cause a Material Adverse Change on NEA’s rights herein.

(b) No Legal Restraint. NEA shall not be subject to any order, decree, injunction, or other legal restraint or prohibition of a court or agency of competent jurisdiction that would enjoin, prohibit or interfere with the consummation of the Transactions.

(c) Documents. Each Utility shall have executed and delivered any New PPA Amendments and the other NSTAR Documents, and all other documents required to be executed and delivered by it pursuant to this Agreement.

(d) MDTE Final Decision. The MDTE Order containing the Required Findings shall have become a Final Decision.

(e) Litigation. There shall be no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal or regulatory, in law or in equity, by or before any governmental authority with valid jurisdiction pending, or to the knowledge of NEA, threatened in writing against NEA or against or related to the Transactions which could reasonably be expected to have a Material Adverse Change on the consummation of the Transactions.

(g) Lender Approvals. NEA shall have obtained approvals, certifications, rating confirmations and other arrangements acceptable to NEA in its sole discretion (not to be arbitrarily exercised) that will permit the amendment of the Power Purchase Agreements, the execution of the Amended and Restated Power Purchase Agreements and the consummation by NEA of its obligations under the NEA Documents in order to consummate the Transactions, in each case, in accordance with the

- 18 -

requirements of the Senior Indenture and the Junior Indenture. NEA shall have satisfied all conditions or requirements necessary for the approvals, certifications, rating confirmations and other arrangement described in the preceding sentence to be effective.

(h) Governmental Approvals. All necessary government approvals and authorizations required for the effectiveness of this Agreement and for the performance by NEA of its obligations under this Agreement, specifically including final approvals of FERC pursuant to Section 205 of the Federal Power Act and authorization by FERC of “exempt wholesale generator” status, shall have been received in a form reasonably acceptable to NEA, and such approvals and authorizations shall no longer subject to reconsideration or appeal.

(i) NEPOOL/ ISO. Any and all necessary filings or notices shall have been given or made with NEPOOL and/or ISO and any and all approvals or authorizations concerning this Agreement and the Amended and Restated Power Purchase Agreements shall have been received in a form reasonably acceptable to NEA.

(j) Accounting and Tax Treatment. NEA, its respective partners and members and each of their Affiliates shall be entitled to accounting treatment and tax treatment reasonably satisfactory to each of them relating to the Transactions.

(k) Approvals. NEA shall have obtained all necessary partnership approvals (including, without limitation, the approval of the restructuring transactions by Suez-Tractebel S.A., the indirect owner of a general partnership interest in NELP) for the restructuring activities as described in the Recitals, including, without limitation, the execution of all the Execution Documents.

ARTICLE 7

MISCELLANEOUS

7.1 Termination.

(a) This Agreement will terminate automatically, without liability to either Party, if the Closing Date does not occur by the Deadline.

(b) In addition to the right of termination under Sections 5.2(a), 5.4(b) and 7.1(a) hereof, this Agreement and the Transactions may only be terminated prior to the Closing Date as follows:

(i) By both Utilities if a representation or warranty herein of NEA is or becomes false or inaccurate in any material respect or if NEA fails to comply in any material respect with one or more of its covenants herein in a timely manner and, in either event, such falsity, inaccuracy, or failure is not cured within thirty (30) days of notice thereof and such failure to cure causes a Material Adverse Change on a Utility’s rights herein;

(ii) By NEA if a representation or warranty herein of a Utility is or becomes false or inaccurate in any material respect, or if a Utility fails to comply in any material respect with one or more of its covenants herein in a timely

- 19 -

manner and, in either event, such falsity, inaccuracy, or failure is not cured within thirty (30) days of notice thereof and such failure to cure causes a Material Adverse Change on NEA’s rights herein;

(iii) By NEA or both Utilities if consummation of the Transactions shall violate any final order, decree, or judgment of any court or governmental body having competent jurisdiction applicable to NEA on the one hand or a Utility on the other hand;

(iv) By NEA or both Utilities if the MDTE Order containing the Required Findings has not become a Final Decision in form and substance acceptable to each Party in its reasonable discretion by January 1, 2005;

(v) By a Party if at any time prior to the Closing Date such Party is affected by a Material Adverse Change, the effect of which will or is likely to continue after the Closing Date, has occurred and is not cured at least five (5) days prior to the Closing Date; or

(vi) By the Utilities if Suez-Tractebel S.A. does not give the approvals referred to in Section 6.2(k) by August 31, 2004.

(c) Upon termination of this Agreement pursuant to Sections 7.1(a) or 7.1(b) hereof, all rights and obligations of the Parties under this Agreement (other than any rights and obligations arising from the breach of this Agreement before termination) shall terminate. Any right of termination under Sections 7.1(b)(i) through (vi) shall be exercised by delivery of a written notice of termination to the other Party within ten (10) days after the right of termination arises, which with respect to the right of termination under Sections 7.1(b)(i) and (ii) hereof shall be the day following the cure periods referenced therein, and with respect to Section 7.1(b)(iii) hereof shall be within five (5) days of the date of discovery of the violation referenced therein. If not so timely exercised, such right of termination shall be deemed waived by the Party entitled thereto. Upon any termination of this Agreement (other than the expiration hereof upon the closing in accordance with Section 2.2 hereof), the Amended and Restated Power Purchase Agreements shall automatically terminate and be of no further force and effect, and none of the parties thereunder shall have any liability to each other in respect of such termination or otherwise in connection with any Execution Documents. Notwithstanding the foregoing, such a termination shall not cause the Utilities, NEA or the Facility to be in default under the Power Purchase Agreements.

7.2 Amendment and Waiver.

This Agreement may be amended, or its provisions and the effects thereof waived only by a writing executed by both Parties, and no subsequent conduct of any Party or course of dealings between the Parties shall effect or be deemed to effect any such amendment or waiver. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. Except for the failure to timely provide a notice of termination under Section 7.1 hereof, the failure of either Party to enforce any provision of this Agreement shall not be construed as a waiver of or an acquiescence to such provision.

- 20 -

7.3 Assignment.

(a) This Agreement shall be binding upon and inure to the benefit of the respective administrators, representatives, successors and permitted assigns of the Parties.

(b) Neither Party may assign, sell, transfer or in any other way convey its rights, duties or obligations under this Agreement, either in whole or in part, without the prior written consent of the other Party (which consent shall not be unreasonably withheld or delayed), except that (i) NEA may assign its interests in this Agreement to the Senior Note Holders and the Senior Trustee as collateral security without the consent of the Utilities; provided, however, that in the case of any such assignment, NEA shall not be released from any obligations under this Agreement and (ii) any subsequent assignment of the rights and interests under this Agreement and the Amended and Restated Power Purchase Agreements by the holders of the Senior Secured Notes or the Senior Trustee in accordance with the documents referenced in Schedule 2.2(b)(iii); to any third party arising as a result of a default hereunder or under the Senior Secured Notes may be made without the Utilities’ consent provided, however, that in the case of any such subsequent assignment, NEA shall not be released from any obligations under this Agreement.

7.4 Notices.

Any notice or communication given pursuant hereto shall be in writing and (a) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (b) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); or (c) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designated by either Party to the other in writing:

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

with a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

- 21 -

If to the Utilities:

Boston Edison Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

and

Commonwealth Electric Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

with a copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

7.5 Entire Agreement.

Upon the Effective Time, the Execution Documents shall constitute the entire agreement between the Parties with respect to the subject matter hereof. Upon the Effective Time, all prior or contemporaneous agreements, proposals, understandings or communications between or involving the Parties, whether oral or written (other than that certain Stipulation of Agreement of Non-Disclosure of Confidential or Protected Information) pertaining to or made in connection with the Execution Documents are void, shall have no binding force or effect, and are replaced in their entirety by the Execution Documents. Except as otherwise specifically provided in the Execution Documents, the Parties thereto do not intend to create rights in, or grant remedies to, any third party as a beneficiary of the Execution Documents or of any duty, covenant, obligation or understanding established under this Agreement or the other Execution Documents.

7.6 Expenses.

Each Party shall pay for its own fees and expenses incurred by it in structuring, negotiating and consummating the Execution Documents and the Transactions.

- 22 -

7.7 Interpretation.

This Agreement shall be interpreted in accordance with the plain meaning of its terms and not strictly for or against either of the Parties. This Agreement shall be construed as if both Parties were its author and each Party adopts the language of this Agreement as if it were its own. Each term, clause and provision of this Agreement is separate and independent, and should any term, clause or provision of this Agreement be found to be invalid, the validity of the remaining terms, clauses and provisions shall, to the fullest extent feasible, not be affected thereby.

7.8 Counterparts. Headings.

This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. The headings contained in this Agreement are for reference purposes only and shall not affect the meaning or interpretation of this Agreement.

7.9 Governing Laws.

This Agreement shall be governed by, and construed and enforced in accordance with, the internal laws of the Commonwealth of Massachusetts. All disputes arising between the Parties concerning the construction or enforcement of this Agreement that the Parties are unable to settle between themselves shall be submitted to a trial by judge. The Parties hereby waive any rights to a trial by jury. All proceedings shall be held in Massachusetts.

7.10 Damage Limitation.

Notwithstanding anything in this Agreement to the contrary, in no event shall any party be liable to one another hereunder for any indirect, consequential, incidental, punitive or exemplary damages.

7.11 Further Assurances.

The Parties acknowledge and agree that the Transactions are complex and that it shall require the reasonable, good faith cooperation of the Parties to implement the terms of this Agreement. If either Party reasonably determines or is advised that any further instruments, agreements or other matters are necessary or desirable to carry out the terms of this Agreement or to consummate the Transactions, the other Party shall do all things reasonably necessary and appropriate to carry out the terms of this Agreement and to execute and deliver all such instruments, agreements and to otherwise address such matters, including, without limitation, adjustments to Schedule 4.1(a) of both of the Amended and Restated Power Purchase Agreements with BECo (the schedules in the two agreements, collectively, the “BECo Support Payment Schedules”) and/or Schedule 4.1(a) of both of the Amended and Restated Power Purchase Agreements with CECo (the schedules in the two agreements, collectively, the “CECo Support Payment Schedules”); provided no adjustments will be made to the BECo Support Payment Schedules or the CECo Support Payment Schedules without the written agreement of the Parties.

[SIGNATURES APPEAR ON FOLLOWING PAGE]

- 23 -

IN WITNESS WHEREOF, NEA and the Utilities have caused this Agreement to be executed by their duly authorized officers or representatives, as applicable, as of the date first above written.

BOSTON EDISION COMPANY
By:	/s/ Ellen K. Angley
Name:	Ellen K Angley
Title:	VP Energy Supply & Transmission
COMMONWEALTH ELECTRIC COMPANY
By:	/s/ Ellen K Angley
Name:	Ellen K Angley
Title:	VP Energy Supply & Transmission
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:	/s/ Nathan E. Hanson
	Nathan E. Hanson
	Authorized Representative

- 24 -

List of Schedules

Schedule A	Power Purchase Agreements (including all amendments)
Schedule D	Executed Amended and Restated Power Purchase Agreements
Schedule G	Required Findings
Schedule 1	Adjusted Bid Price Amount: Sample Calculations
Schedule 1.5	Calculation Date Adjusted Bid Price Amount
Schedule 2.2(b)(iii)	Form of Collateral Assignment
Schedule 2.2(b)(iv)	Form of Mutual Release
Schedule 3.5	Utility Broker/Agent
Schedule 4.5	NEA Broker/Agent
Schedule 5.3	Interim Period Deliveries
	•      Interim Period Delivery Points •      Interim Period On-Peak Energy Price •      Interim Period On-Peak Delivery Quantities •      Interim Period Off-Peak Delivery Quantities •      Interim Period Delivery Rate •      Interim Period Support Payment Rate

- 25 -

SCHEDULE A

POWER PURCHASE AGREEMENTS

BECo A

Power Purchase Agreement between NEA and BECo, dated April 1, 1986

First Amendment to Power Purchase Agreement, dated June 8, 1987

Second Amendment to Power Purchase Agreement, dated June 21, 1989

Third Amendment to Power Purchase Agreement, dated August 31, 1990

Letter from BECo to NEA, dated April 29, 1999

Protocol Agreement between NEA and BECo, dated February 28, 2003

BECo B

Power Purchase Agreement between NEA and BECo, dated January 28, 1988

First Amendment to Power Purchase Agreement, dated June 21, 1989

Letter from BECo to NEA, dated April 29, 1999

Protocol Agreement between NEA and BECo, dated February 28, 2003

CECo 1

Power Sale Agreement between CECo and NEA, dated November 26, 1986

First Amendment to Power Sale Agreement, dated August 15, 1988

Second Amendment to Power Sale Agreement, dated January 1, 1989

Letter from CECo to NEA, dated July 9, 1993

Protocol Agreement between NEA and CECo, dated February 28, 2003

CECo 2

Power Sale Agreement between CECo and NEA, dated August 15, 1988

Amendment to Power Sale Agreement, dated January 1, 1989

Letter from CECo to NEA, dated July 9, 1993

Protocol Agreement between NEA and CECo, dated February 28, 2003

SCHEDULE D

EXECUTED AMENDED AND RESTATED POWER PURCHASE AGREEMENTS

BECo A

Amended and Restated Power Purchase Agreement between BECO and NEA, dated as of August 19, 2004 (attached hereto).

BECo B

Amended and Restated Power Purchase Agreement between BECO and NEA, dated as of August 19, 2004 (attached hereto).

CECo 1

Amended and Restated Power Purchase Agreement between CECo and NEA, dated as of August 19, 2004 (attached hereto).

CECo 2

Amended and Restated Power Purchase Agreement between CECo and NEA, dated as of August 19, 2004 (attached hereto).

SCHEDULE G

REQUIRED FINDINGS

(1) The MDTE shall find that the Utilities’ auction from which the Agreement was negotiated was consistent with BECo’s Restructuring Settlement Agreement approved by the MDTE in D.P.U./D.T.E. 96-23 (the “Settlement Agreement”) and CECo’s Restructuring Plan approved by the MDTE in D.P.U./D.T.E. 97-111 (the “Restructuring Plan”) in that the auction was equitable and maximized the value of the assets that were subject to the auction

(2) The MDTE shall find the renegotiating the Power Purchase Agreements is consistent with the Massachusetts Electric Restructuring Act of 1997 (“Restructuring Act”) and maximizes the mitigation of the Utilities’ respective transition costs.

(3) The MDTE shall find that the Bellingham Execution Agreement and the Amended and Restated Power Purchase Agreements are reasonable, are in the public interest and are consistent with the requirements of G.L. c. 164.

(4) The MDTE shall find that the Utilities’ proposed ratemaking treatment for the above-market portion of the Amended and Restated Purchase Power Agreements are consistent with the Settlement Agreement, the Restructuring Plan, the Restructuring Act and G.L. c. 164.

SCHEDULE 1

ADJUSTED BID PRICE AMOUNT:

SAMPLE

CALCULATIONS

Peak MWh percentage of total MWh Peak Heat Rate (MMBtu/MWh) Discount Rate		46.5763	%
Closing Date*		01/01/05
Start of Adjuster Period*		02/01/05
Initial NEA Bid Price Amount	-$	12,568,453.00
Bid Date On Peak Energy Cost*	$	273,886,759.99
Calculation Date On-Peak Energy Cost*	$	293,296,029.90
Adjusted Bid Price Amount	-$	31,975,722.91

Month	Discount Rate	On-Peak MWhs BECo 1	BECo 2	CECo	Total	Bid Date Gas Price ($/MMBtu)	Bid Date On-Peak Energy Price ($/MWh)		Bid Date On-Peak Energy Cost* ($)	Forward NYMEX Gas Price* ($/MMBtu)	Calculation Date On-Peak Energy Price* ($/MWh)	Calculation Date On-Peak Energy Cost* ($)
						12/1/2003	12/1/2003		12/1/2003	Example	Example	Example
4/1/2004									273,886,759.9900			293,296,029.9000
4/30/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
5/31/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
6/30/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
7/31/04		0.0000	0.0000	0.0000	0 0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
8/31/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
9/30/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
10/31/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
11/30/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
12/31/04		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
1/31/05		0.0000	0.0000	0.0000	0.0000	0.000	$	0.0000	0.0000	0.000	0.0000	0.0000
2/28/05		46,300.7725	28,245.0787	15,615.0022	90,163.8534	5.125	$	44.0750	3,973,971.8386	7.065	80.7590	5,476,265.5687
3/31/05		50,186.2826	30,970.8616	16,928.6588	98,085.6010	4.980	$	42.8260	4,200,610.1196	6.900	59.3400	5,820,399.5633
4/30/05		47,049.4440	29,842.9036	15,870.5372	92,782.8848	4.605	$	39.6030	3,673,688.5267	6.126	52.7008	4,888,678.2393
5/31/05		33,795.2519	22,252.8709	11,399.6840	67,447.8068	4.533	$	36.9838	2,629,371.8107	5.943	51.1098	3,447,243.9160
6/30/05		41,733.3989	21,049.6621	14,077.3621	76,860.4231	4.550	$	39.1300	3,007,548.3559	5.943	51.1098	3,928,320.8526
7/31/05		45,954.4043	23,303.2777	15,501.2014	84,768.8834	4.567	$	39.2762	3,329,008.8562	5.973	51.3676	4,353,677.3707
8/31/05		45,597.7310	23,399.0905	15,380.8203	84,377.6418	4.589	$	38.4854	3,329,997.3847	5.978	51.4108	4,337,922.0671
9/30/05		43,080.5019	23,624.9558	15,951.6900	82,657.1477	4.577	$	30.3622	3,253,687.1792	5.948	51.1528	4,228,144.5449
10/31/05		46,304.2284	32,341.4956	15,755.9165	94,401.6405	4.602	$	39.5772	3,736,152.6064	5.961	51.2646	4,839,462.3396
11/30/05		37,869.7542	28,629.1520	14,302.2090	76,801.1152	4.772	$	41.0382	3,233,934.7269	6.128	52.6836	4,151,528.4328
12/31/05		47,527.4329	29,132.8489	16,031.7585	92,691.6403	4.952	$	42.6872	3,947,485.9412	6.291	54.1026	5,014,869.5590
1/31/06		51,990.4402	31,595.1950	17,537.2157	101,122.8509	5.053	$	43.4558	4,394,374.3841	6.406	55.0916	5,571,019.6526
2/28/06		46,300.7725	26,245.0787	16,618.0022	90,163.6534	5.018	$	43.1548	3,891,003.0607	6.361	54.7048	4,932,377.5347
3/31/06		50,186.2826	30,970.6616	16,928.6568	98,085.6010	4.873	$	41.8078	4,110,551.7496	6.171	53.0706	5,205,481.6964
4/30/06		47,049.4440	29,842.9038	15,870.5372	92,782.6848	4.673	$	39.3276	3,648,180.1808	5.511	47.3946	4,398,459.6188
5/31/06		33,795.2519	22,252.8709	11,399.6840	67.447.6068	4.613	$	38.6116	2,617,770.7880	5.346	45.9756	3,100,963.3863
6/30/06		41,733.3989	21,049.6621	14,077.3621	76,860.4231	4.513	$	38.6116	2,963,091.3693	5.351	46.0186	3,537,009.0686
7/31/06		45,954.4043	23,303.2777	15,501.2014	84,758.8834	4.528	$	38.9408	3,300,578.7267	5.371	46.1906	3,915,083.5796
8/31/06		45,597.7310	23,399.0905	15,380.8203	84,377.6418	4.544	$	39.0784	3,297,343.2373	5.389	46.8454	3,910,515.5603
9/30/06		43,080.5019	23,624.9558	15,951.6900	82.657.1477	4.544	$	38.0784	3,230,109.0607	5.359	46.0874	3,809,453.0289

* Asterik indicates an assumption that will be inserted at Calculation Date or a numeric value that will change as a result of that Calculation Date insertion

Month	Discount Rate	On-Peak MWhs BECo 1	BECo 2	CECo	Total	Bid Date Gas Price ($/MMBtu)	Bid Date On-Peak Energy Price ($/MWh)		Bid Date On-Peak Energy Cost* ($)	Forward NYMEX Gas Price * ($/MMBtu)	Calculation Date On-Peak Energy Price* ($/MWh)	Calculation Date On-Peak Energy Cost* ($)
						12/1/2003	12/1/2003		12/1/2003	Example	Example	Example
10/31/06		45,304.2284	32,341.4956	16,755.9165	94,401.6405	4.589	$	39.4654	3,725,596.5030	5.371	46.1908	4,360,468.4157
11/30/06		37,869.7542	26,829.1520	14,302.2090	78,601.1152	4.770	$	41.0220	3,232,579.3477	5.541	47.6526	3,755,078.0222
12/31/06		47,527.4329	29,132.6489	18,031.7585	92,891.8403	4.940	$	42.4840	3,937,920.1433	5.706	49.0718	4,548,538.9105
1/31/07		51,990.4402	31,595.1950	17,637.2157	101,122.8509	5.049	$	43.4214	4,390,895.7581	5.806	49.9316	5,049,225.7420
2/28/07		46,300.7725	28,245.0787	15,618.0022	90,163.8534	5.009	$	43.0774	3,684,024.3785	5.758	49.5018	4,463,256.0055
3/31/07		50,166.2626	30,970.6616	16,928.6568	98,085.8010	4.889	$	41.6734	4,107,177.8049	5.558	47.7816	4,686,688.9527
4/30/07		47,049.4440	29,642.9036	15,870.5372	92,762.8845	4.614	$	39.6804	3,680,868.3740	5.081	43.6968	4,053,422.6720
5/31/07		33,795.2519	22,252.8709	11,399.6840	67,447.8068	4.579	$	39.3794	2,656,054.1631	4.921	42.3206	2,854,431.6525
6/30/07		41,733.3989	21,049.5621	14,077.3621	78,860.4231	4.568	$	39.4568	3,032,686.3422	4.923	42.3376	3,254,101.2211
7/31/07		45,954.4043	23,303.2777	15,501.2014	84,758.8834	4.608	$	39.6288	3,358,892.8385	4.933	42.4238	3,595,793.9176
8/31/07		45,597.7310	23,399.0905	15,360.8203	94,377.6418	4.623	$	39.7578	3,354,668.4072	4.946	42.5356	3,589,053.8205
9/30/07		43,080.5019	23,624.9556	15,951.6900	82,657.1477	4.608	$	39.6288	3,275,603.5748	4.909	42.2174	3,489,569.6673
10/31/07		45,304.2264	32,341.4956	18,755.9165	94,401.6405	4.598	$	39.5426	3,732,905.1900	4 922	42.3292	3,995,945.9211
11/30/07		37,869.7542	26,629.1520	14,302.2090	78,801.1152	4.728	$	40.6608	3,204,118.3849	5.066	43.7396	3,446.729.2584
12/31/07		47,527.4329	29,132.6489	18,031.7585	92,691.8403	4.656	$	41.7788	3,872,553.8575	5.251	45.1586	4,185,833.7394
1/31/08		51,990.4402	31,595.1950	17,537.2157	101,122.8509	4.953	$	42.5958	4,307,408.7324	5.351	46.0186	4,653,532.0264
2/29/08		47,954.3715	29,253.8315	16,175.7680	93,383.9910	4.893	$	42.0798	3,929,579.6645	5.318	45.7178	4,269,291.9459
3/31/08		50,186.2626	30,970.6618	16,928.6568	98,085.6010	4.803	$	41.3058	4,051,504.2178	5.136	44.1696	4,332,401.7819
4/30/08		47,049.4440	29,842.9038	15,870.5372	92,762.8846	4.813	$	39.6718	3,680,070.8132	4.726	40.6436	3,770,217.5847
5/31/08		33,795.2519	22,252.8709	11,399.6840	67,447.8068	4.813	$	39.6718	2,675,775.9018	4.673	40.1878	2,710,578.9701
6/30/08		41,733.3989	21,049.6621	14,077.3621	76,880.4231	4.613	$	39.6718	3,049,191.3331	4.673	40.1878	3,088,851.3115
7/31/08		45,954.4043	23,303.2777	15,501.2014	84,758.8834	4.643	$	39.9295	3,384,405.2624	4.898	40.4026	3.424,496.2142
8/31/08		45,597.7310	23,399.0905	15,380.6203	84,377.6418	4.673	$	40.1875	3,390,951.7931	4.723	40.8178	3,427,234.1791
9/30/08		43,080.5019	23,624.9558	15,951.6900	82,657.1477	4.683	$	40.2736	3,328,917.4350	4.703	40.4458	3,343,134.4644
10/31/08		45,304.2284	32,341.4956	18,755.9165	94.401.6405	4.873	$	40.1878	3,793,794.2481	4.708	40.4888	3,822,209.1419
11/30/08		37,869.7542	26,629.1520	14,302.2090	78,801.1152	4.773	$	41.0478	3,234,812.4185	4.653	41.7358	3,288,827.5838
12/31/08		47,527.4329	29,132.6489	18,031.7585	92,691.8403	4.873	$	41.9076	3,664,511.1049	5.006	43.0688	3,992,126.3315
1/31/09		51,990.4402	31,595.1950	17.537.2157	101,122.8509	4.943	$	42.5096	4,296,712.1672	5.113	43.9718	4,446,553.7752
2/28/09		46,300.7725	28,245.0787	15,818.0022	90,163.6534	4.693	$	42.0796	3,794,076.9163	5.073	43.6278	3,933,850.5634
3/31/09		50,186.2826	30,970.6618	16,928.6568	98,085.6010	4.833	$	41.5636	4,076,810.3028	4.923	42.3378	4,152,728.5580
4/30/09		47,049.4440	29,842.9038	15,870.5372	92,762.8848	4.678	$	40.2308	3,731,925.0655	4.583	39.4138	3,656,137.7889
5/31/09		33,795.2519	22,252.8709	11,389.6840	87,447.8068	4.676	$	40.2308	2,713,479.2258	4.538	39.0268	2,632,272.0664
6/30/09		41,733.3989	21,048.6621	14,077.3621	76,880.4231	4.678	$	40.2308	3,092,156.3097	4.548	39.1128	3,006,226 3566
7/31/09		45,954.4043	23,303.2777	15,601.2014	84,768.8834	4.678	$	40.2308	3,409,917.6863	4.558	39.1988	3,322,446.5186
8/31/09		45,597.7310	23,399.0906	16,380.8203	84,377.6416	4.583	$	40.2738	3,395,208.2703	4.568	39.2846	3,314,768.7826
9/30/09		43,080.5019	23,624.9558	15,951.8900	82,657.1477	4.583	$	40.2738	3,326,917.4350	4.568	39.2848	3,247,169.5160

Month	Discount Rate	On-Peak MWhs BECo 1	BECo 2	CECo	Total	Bid Date Gas Price ($/MMBtu)	Bid Date On-Peak Energy Price ($/MWh)		Bid Date On-Peak Energy Cost* ($)	Forward NYMEX Gas Price* ($/MMBtu)	Calculation Date On-Peak Energy Price* ($/MWh)	Calculation Date On-Peak Energy Cost* ($)
						12/1/2003	12/1/2003		12/1/2003	Example	Example	Example
10/31/09		45,304.2284	32,341.4958	18,755.9165	94,401.6405	4.883	$	40.2738	3,801,912.7862	4.578	39.3708	3,716,668.1078
11/30/09		37,869.7542	26,629.1520	14,302.2090	78,601.1152	4.758	$	40.9168	3,224,447.0726	4.688	40.3168	3,177,008.8013
12/31/09		47,527.4329	29,132.6489	18,031.7585	92,891.6403	4.893	$	42.0798	3,900,454.1015	4.808	41.3488	3,832,698.3662
1/31/10		51,990.4402	31,596.1950	17,537.2157	101,122.8509	4.043	$	42.5098	4,298,712.1672	4.903	42.1658	4,263,925.9085
2/28/10		46,300.7725	26,245.0767	15,618.0022	90,163.8534	4.883	$	42.0798	3,794,078.9183	4.863	41.6218	3,770,814.6441
3/31/10		50,186.2826	30,970.6616	18,928.6568	96,085.6010	4.833	$	41.5638	4,078,810.3028	4.783	41.1338	4,034,633.4944
4/30/10		47,049.4440	29,842.9038	15,870.5372	92,752.8846	4.678	$	40.2308	3,731,925.0658	4.433	38.1238	3,536,473.8675
5/31/10		33,795.2519	22,252.8709	11,399.6840	67,447.8068	4.678	$	40.2308	2,713,479.2258	4.393	37.7798	2,548,164.6513
6/30/10		41,733.3989	21,049.8821	14,077.3621	78,860.4231	4.678	$	40.2308	3,092,156.3097	4.393	37.7798	2,903,771.4126
7/31/10		45,954.4043	23,303.2777	15,501.2014	64,756.8834	4 676	$	40.2308	3,409,917.6863	4.558	39.1968	3,322,446.5168
6/31/10		45,597.7310	23,399.0905	16,360.8203	84,377.6418	4.683	$	40.2738	3,398,208.2703	4.568	39.2848	3,314,758.7626
9/30/10		43,080.5019	23,524.9558	15,951.6900	62,657.1477	4.663	$	40.2738	3,328,917.4350	4.568	39.2848	3,247,189.5160
10/31/10		45,304.2284	32,341.4956	18,755.9165	94,401.8405	4.683	$	40.2738	3,801.912.7892	4.578	39.3708	3,716,666.1078
11/30/10		37,869.7642	26,629.1520	14,302.2090	78,801.1152	4.758	$	40.9188	3,224,447.0726	4.688	40.3158	3,177,006.8013
12/31/10		47,527.4329	29,132.6489	16,031.7585	92,691.8403	4.893	$	42.0798	3,900,454.1015	4.806	41.3488	3,832,696.3662
1/31/11		51,990.4402	31,595.1950	17,537.2157	101.122.8509	4.943	$	42.5098	4,298.712.1672	4.903	42.1858	4,263,926.9065
2/28/11		46,300.7725	28,245.0787	15,618.0022	90,163.5534	4.693	$	42.0796	3,794.076.9183	4.863	41.5218	3,770,814.5441
3/31/11		50,186.2826	30,970.6618	18,928.6568	98,085.6010	4.833	$	41.5638	4,076,810.3028	4.783	41.1338	4,034,633.4944
4/30/11		47,049.4440	29,842.9038	15,870.5372	92,782.8848	4.878	$	40.2308	3,731,925.0658	4.433	38.1238	3,536,473.6676
5/31/11		33,795.2519	22,252.8709	11,399.6840	67,447.8068	4.678	$	40.2306	2,713,479.2256	4.393	37.7798	2,548,164.6513
6/30/11		41,733.3969	21,049.6621	14,077.3621	76,860.4231	4.678	$	40.2306	3,092,158.3097	4.393	37.7798	2,903,771.4128
7/31/11		45,954.4043	23,303.2777	15,501.2014	64,758.8834	4.678	$	40.2308	3,409.917.6863	4.558	39.1988	3,322,446.5186
8/31/11		45,597.7310	23,399.0905	15,380.6203	84,377.6418	4.683	$	40.2738	3,398,208.2703	4.568	39.2848	3,314,758.7826
9/30/11		43,080.5019	11,024.9771	15,951.6900	70,057.1690	4.683	$	402738	2,521,468.4129	4.568	39.2848	2,762,181.8727
10/31/11		45,304.2284	0.0000	16,755.9185	52,060.1449	4.683	$	40.2738	2,499,397.8637	4.578	39.3708	2,443,357.5628
11/30/11		37,869.7542	0.0000	14,302.2090	52,171.9832	4.758	$	40.9166	2,134,814.1276	4.686	40.3188	2,103,406.6059
12/31/11		47,527.4329	0.0000	16,031.7585	83,559.1914	4.893	$	42.0798	2,574,556.0623	4.808	41.3488	2,826,096.2934
1/31/12		51,990.4402	0.0000	17,537.2157	69,527.6559	4.943	$	42.5098	2,955,606.7488	4.903	42.1658	2,931,689.2331
2/29/12		47,954.3718	0.0000	16,175.7880	64,130.1595	4.893	$	42.0796	2,698,584.2857	4.863	41.8218	2,682,038.7048
3/31/12		50,186.2628	0.0000	18,928.6566	87,114.9394	4.633	$	41.5636	2,789,651.9152	4.783	41.1338	2,760,692.4943
4/30/12		47,049.4440	0.0000	15,670.5372	82,919.9812	4.678	$	40.2308	2,531,321.1797	4.433	38.1238	2,398,748.7793
5/31/12		33,795.2519	0.0000	11,399.6840	45,194.9359	4.678	$	40.2308	1,816,228.4272	4.393	37.7798	1,707,455.6393
6/30/12		41,733.3989	0.0000	14,077.3621	55,810.7810	4.678	$	40.2308	2,245,311.5636	4.393	37.7798	2,108,519.3884
7/31/12		45,954.4043	0.0000	15,501.2014	81,455.6057	4.678	$	40.2308	2,472,408.1818	4.558	39.1988	2,408,985.9967
8/31/12		45,597.7310	0.0000	15,380.8203	60,978.6513	4.683	$	40.2738	2,455,637.9793	4.568	39.2848	2,396,630.1921
9/30/12		43,080.5019	0.0000	15,951.8900	59,032.1919	4.683	$	40.2738	2,377,450.6901	4.568	39.2848	2,319,067.8524

Month	Discount Rate	On-Peak MWhs BECo 1	BECo 2	CECo	Total	Bld Date Gas Price ($/MMBtu)	Bid Date On-Peak Energy Price ($/MWh)		Bid Date On-Peak Energy Cost* ($)	Forward NYMEX Gas Price* ($/MMBtu)	Calculation Date On-Peak Energy Price* ($/MWh)	Calculation Date On-Peak Energy Cost* ($)
						12/1/2003	12/1/2003		12/1/2003	Example	Example	Example
10/31/12		45,304.2284	0.0000	16,755.9185	62,060.1449	4.685	$	40.2736	2,499,387.8837	4.578	39.3708	2,443,357.5528
11/30/12		37,869.7542	0.0000	14,302.2090	52,171.9632	4.758	$	40.9180	2,134,814.1278	4.688	40.3168	2,103,406.6059
12/31/12		47,527.4329	0.0000	16,031.7585	63,559.1914	4.893	$	42.0798	2,674,558.0823	4.808	41.3488	2,820,096.2934
1/31/13		51,990.4402	0.0000	17,537.2157	80,527.8559	4.943	$	42.5098	2,955,006.7488	4.903	42.1658	2,931,669.2331
2/28/13		46,300.7725	0.0000	15,618.0022	61,918.7747	4.893	$	42.0798	2,606,528.8658	4.863	41.8216	2,589,554.6117
3/31/13		50,186.2826	0.0000	18,928.8588	67,114.9394	4.833	$	41.5638	2,789,561.9182	4.783	41.1338	2,760,692.4943
4/30/13		47,049.4440	0.0000	15,870.5372	62,919.9812	4.678	$	40.2308	2,531,321.1797	4.433	38.1238	2,398,748.7793
5/31/13		33,795.2519	0.0000	11,399.6840	45,194.8359	4.678	$	40.2308	1,818,226.4272	4 393	37.7798	1,707,455.6393
6/30/13		41,733.3989	0.0000	14,077.3621	55,810.7610	4.678	$	40.2308	2,245,311.5636	4.393	37.7796	2,108,518.3884
7/31/13		45,964.4043	0.0000	15,501.2014	81,455.8057	4.678	$	40.2308	2,472,408.1818	4.558	39.1988	2,408,985.8867
8/31/13		45,597.7310	0.0000	15,380.8203	60,978.5513	4.883	$	40.2736	2,455,837.9793	4.568	39.2848	2,395,530.1921
9/30/13		43,060.5019	0.0000	15,951.6900	59,032.1919	4.683	$	40.2738	2,377,450.6901	4.588	38.2648	2,319,067.8524
10/31/13		45,304.2284	0.0000	16,755.9165	62,060.1449	4.883	$	40.2738	2,499,397.8637	4.578	39.3708	2,443,357.5528
11/30/13		37,869.7542	0.0000	14,302.2090	52,171.9832	4.758	$	40.9180	2,134,814.1278	4.688	40.3168	2,103,406.6059
12/31/13		47,527.4329	0.0000	16,031.7585	83,559.1914	4.893	$	42.0796	2,674,668.0823	4.808	41.3488	2,628,098.2934
1/31/14		51,990.4402	0.0000	17,537.2157	89,527.6559	4.943	$	42.5096	2,955,806.7488	4.903	42.1658	2,931,689.2331
2/28/14		46,300.7725	0.0000	15,818.0022	61,918.7747	4.893	$	42.0798	2,605,629.6556	4.863	41.8218	2,569,554.6117
3/31/14		50,186.2826	0.0000	16,928.6568	67,114.9394	4.833	$	41.5638	2,789,551.9182	4.783	41.1338	2,780,692.4943
4/30/14		47,049.4440	0.0000	15,870.5372	62,919.9812	4.678	$	40.2308	2,531,321.1797	4.433	38.1238	2,398,748.7793
5/31/14		33,795.2519	0.0000	11,399.6840	48,194.9359	4.678	$	40.2306	1,818,228.4272	4.393	37.7799	1,707,455.6393
6/30/14		41,733.3969	0.0000	14,077.3821	55,610.7610	4.678	$	40.2308	2,245.311.5836	4.393	37.7799	2,106,519.3884
7/31/14		45,954.4043	0.0000	15,501.2014	61,455.6057	4.678	$	40.2308	2,472,406.1816	4.558	39.1988	2,408,985.9967
8/31/14		45,597.7310	0.0000	15,380.6203	60,978.5613	4.683	$	40.2738	2,455,837.9793	4.568	39.2848	2,395,530.1921
9/30/14		43,060.5019	0.0000	15,951.6900	59,032.1919	4.683	$	40.2738	2,377,450.6901	4.568	39.2848	2,319,067.8524
10/31/14		45,304.2284	0.0000	16,755.9165	62,060.1449	4.683	$	40.2738	2,499,397.0637	4.578	39.3708	2,443,357.5528
11/30/14		37,869.7542	0.0000	14,302.2090	52,171.9532	4.758	$	40.9188	2,134.814.1278	4.688	40.3168	2,103,408.6058
12/31/14		47,527.4328	0.0000	16,031.7565	63,559.1914	4.893	$	42.0798	2,674,558.0623	4.808	41.3488	2,628,096.2834
1/31/15		51,990.4402	0.0000	17,537.2157	69,527.6559	4.943	$	42.5096	2,955,606.7468	4.003	42.1658	2,931,689.2331
2/28/15		46,300.7725	0.0000	15,618.0022	81,918.7747	4.893	$	42.0798	2,605,529.8556	4.853	41.8218	2,589,554.8117
3/31/15		50,186.2626	0.0000	16,928.6566	67,114.9394	4.833	$	41.5638	2,789,551.8182	4.783	41.1338	2,780,692.4943
4/30/15		47,049.4440	0.0000	15,870.5372	62,919.9612	4.678	$	40.2308	2,531,321.1797	4.433	38.1238	2,396,748.7733
5/31/15		33,795.2519	0.0000	11,399.6840	45,194.9359	4.678	$	40.2306	1,818,228.4272	4.393	37.7798	1,707,455.6393
6/30/15		41,733.3999	0.0000	14,077.3821	55,810.7610	4.678	$	40.2306	2,245,311.5638	4.393	37.7798	2,106,519.3884
7/31/15		45,954.4043	0.0000	15,501.2014	61,455.6057	4.678	$	40.2306	2,472,408.1818	4.558	39.1988	2,408,985.9967
8/31/15		45,597.7310	0.0000	15,380.8203	60,978.5513	4.693	$	40.2738	2,455,837.9793	4.568	39.2648	2,395,530.1921
9/30/15		43,080.5019	0.0000	15,951.6800	59,032.1919	4.683	$	40.2738	2,377,450.6901	4.568	39.2846	2,319,067.8524
10/31/15		45,304.2284	0.0000	16,755.9165	62,080.1448	4.883	$	40.2738	2,499,397.8637	4.578	39.3708	2,443,357.5528
11/30/15		37,869.7542	0.0000	14,302.2090	52,171.9632	4.758	$	40.9188	2,134,614.1278	4.688	40.3168	2,103,406.8058
12/31/15		47,527.4328	0.0000	16,031.7585	83,558.1914	4.893	$	42.0798	2,674,658.0623	4.808	41.3488	2,626,096.2934
1/31/16		51,990.4402	0.0000	17,537.2157	89,527.6559	4.943	$	42.5096	2,955,806.7456	4.903	42.1858	2,931,689.2331
2/29/16		47,864.3715	0.0000	16,175.7890	64,130.1595	4.893	$	42.0798	2,698,564.2657	4.883	41.8218	2,682,038.7046
3/31/16		50,186.2826	0.0000	16,928.6568	67,114.9394	4.833	$	41.5638	2,789,561.9182	4.783	41.1338	2,780,692.4943
4/30/16		47,049.4440	0.0000	15,870.5372	82,919.9612	4.670	$	40.2308	2,531,321.1797	4.433	38.1238	2,396,748.7793
5/31/16		33,795.2519	0.0000	11,399.6940	45,194.8359	4.678	$	40.2308	1,818.228.4272	4.393	37.7796	1,707,455.6393
6/30/16		41,733.3988	0.0000	14,077.3821	55,810.7810	4.678	$	40.2308	2,245,311.5836	4.393	37.7798	2,108,519.3884
7/31/16		45,954.4043	0.0000	15,501.2014	81,455.6057	4.578	$	40.2308	2,472,406.1818	4.558	39.1988	2,408,985.9967
8/31/16		45,597.7310	0.0000	15,360.8203	60,976.5513	4.683	$	40.2738	2,455,837.9793	4.568	39.2848	2,395,530.1921
9/30/16		21,011.8422	0.0000	8,507.5680	29,519.4102	4.683	$	40.2738	1,168,658.8225	4.568	39.2848	1,159,684.1258

SCHEDULE 1.5

CALCULATION DATE ADJUSTED BID PRICE AMOUNT

SCHEDULE 2.2(b)(iii)

FORM OF COLLATERAL ASSIGNMENT

AFFIRMATION OF CONSENT

TO

COLLATERAL ASSIGNMENT

Reference is made to (a) the Consent and Agreement dated as of June 28, 1989 (the “Consent”) between Boston Edison Company (“BECo”) and the Chase Manhattan Bank (National Association) as agent (the “Agent”), and accepted by Northeast Energy Associates, a Limited Partnership (“Northeast”), (b) the Accommodation Agreement dated as of June 28, 1989 (the “Accommodation Agreement”) among Northeast, the Agent, BECo and certain other parties, (c) the Confirmation Agreement dated September 16, 1994 (the “Confirmation Agreement”) between BECo, NEA and State Street Bank and Trust Company as collateral agent (the Collateral Agent”) and (d) the confirmation letter dated December 1, 1994 (the “Confirmation Letter”) between BECo and the Collateral Agent.

BECo hereby affirms and agrees as follows:

(a) The Consent, Accommodation Agreement, Confirmation Letter and Confirmation Agreement shall remain in full force and effect following the “Effective Date” of the Amended and Restated Power Purchase Agreement (as such term is defined in that agreement).

(b) Upon the Effective Date, all references in Paragraphs 3, 4(c), 4(d), 4(f), 4(j), 5, 6, 7, 8, 9, 10, 11 and 12 of the Consent to the “Power Purchase Agreement” shall mean the Amended and Restated Power Purchase Agreement and all references to the “Power Purchase Agreements” shall mean the Amended and Restated Power Purchase Agreements.

(c) Upon the Effective Date, all references in Articles 4 and 5 and Appendix A of the Accommodation Agreement to the “Power Sale Agreements,” “Commonwealth Agreements” and “Edison Agreements” shall mean the Amended and Restated Power Purchase Agreements.

The provisions hereof shall be governed by the laws of the Commonwealth of Massachusetts.

IN WITNESS WHEREOF, BECo has caused this agreement to be executed as of the date set forth below.

	BOSTON EDISON COMPANY
	By:
	Name:
	Title:
Dated:

AGREED:
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:
	Authorized Representative

SCHEDULE 2.2(b)(iv)

FORM OF MUTUAL RELEASE

Schedule 2.2(b)(iv) to Execution Agreement

MUTUAL RELEASE

THIS MUTUAL RELEASE (“Release”) is made as of                     , 2004, by and between Boston Edison Company, a Massachusetts corporation (the “Utility”), and Northeast Energy Associates, A Limited Partnership, a Massachusetts limited partnership (“NEA”). The Utility and NEA are individually referred to herein as a “Party” and are collectively referred to herein as the “Parties”).

Recitals

A. NEA owns a nominal 300 MW natural gas-fired electricity and steam generating plant located in Bellingham, Massachusetts (the “Facility”).

B. BECO and NEA are parties to (1) a certain Power Purchase Agreement dated April 1, 1986, as amended as of the Effective Time (as defined herein), pursuant to which BECO purchases from NEA a portion of the Facility’s capacity and associated energy, and (2) a certain Power Purchase Agreement dated January 28, 1988, as mended as of the Effective Time, pursuant to which BECO purchases from NEA a portion of the Facility’s capacity and associated energy (each of (1) and (2), singly, a “Power Purchase Agreement,” and collectively, the “Power Purchase Agreements”).

C. BECO and NEA desire to amend and restate each of the Power Purchase Agreements, and contemporaneously herewith, are entering into amended and restated power purchase agreements for each of the Power Purchase Agreements (collectively, the “Amended and Restated Power Purchase Agreements”).

D. In connection with entering into the Amended and Restated Power Purchase Agreements, BECO and NEA, pursuant to all terms, conditions and provisions of this Release, desire to release each other from obligations arising prior to the Effective Time under the Power Purchase Agreements.

Agreement

NOW, THEREFORE, in consideration of the premises, the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereto, intending to be legally bound hereby, agree as follows:

1. Effective Time of Release. This Release shall be effective as of the Effective Time (the “Effective Time”) as such term is defined in that certain Bellingham Execution Agreement dated as of                     , 2004 by and among the Utility, NEA, and Commonwealth Electric Company (the “Execution Agreement”).

2. Releases.

(a) Except as provided in Section 2(b) hereof, each Party (the “Releasing Party”), intending to be legally bound on behalf of themselves, their past, present and future parents, subsidiaries, Affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, employees (acting in their capacity as such), members, partners and representatives ABSOLUTELY, IRREVOCABLY AND

UNCONDITIONALLY, FULLY AND FOREVER ACQUIT, RELEASE AND DISCHARGE AND COVENANT NOT TO SUE the other Party (the “Released Party”) and any and all of its past, present and future parents, subsidiaries, Affiliates, successors, predecessors, assigns, directors, officers, agents, attorneys, employees (acting in their capacity as such), members, partners and representatives (i) from or with respect to any and all Claims (as hereinafter defined) that the Releasing Party ever had, now has or hereafter can, shall or may have arising out of or in connection with the execution, performance or nonperformance or assignment of the Power Purchase Agreements and the sale and purchase of electric energy and capacity from the Facility up to the Effective Time and (ii) from or with respect to any and all Claims whether in law or equity and whether arising in contract (including breach), tort or otherwise, and irrespective of fault, negligence or strict liability that the Releasing Party ever had, now has or hereafter can, shall or may have arising out of or in connection with any business or activities of the Released Party, including activities associated with the Facility or relating to the Power Purchase Agreements and the sale and purchase of electric energy and capacity from the Facility up to the Effective Time. For purposes of this Release, “Claims” shall mean all claims, causes of action, demands, obligations, charges, complaints, controversies, damages, liabilities, costs, expenses (including, without limitation, interest penalties and attorneys’ fees and disbursements), judgments, guarantees, agreements or defaults of every and any nature.

(b) The Releases set forth in this Section 2 will not apply with respect to any electric energy or capacity delivered by NEA to the Utility under the Power Purchase Agreements for which NEA has not been compensated by the Utility as of the Effective Time or as to which NEA owes refunds or credits to the Utility as of the Effective Time.

3. Representations and Warranties of the Utility. The Utility hereby represents and warrants as of the Effective Time that:

(a) Authority. The Utility is a corporation duly organized, validly existing and in good standing under the laws of the Commonwealth of Massachusetts and has all requisite corporate power and authority to enter into and be bound by the terms of this Release. The execution and delivery of, and the performance by the Utility of its obligations under, this Release have been duly and validly authorized by all necessary corporate action of the Utility. This Release has been duly and validly executed and delivered by the Utility and constitutes a valid and binding obligation of the Utility, enforceable against the Utility in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(b) No Conflicts. The execution and delivery of this Release will not (i) violate or conflict with any provisions of the Utility’s articles of organization or bylaws, (ii) violate, conflict with or result in the breach or termination of any material agreement or instrument to which the Utility is a party or (iii) violate or conflict with (or require any filing, consent, or similar action under) any law, rule, regulation, judgment, order, injunction, decree or award that applies to or binds the Utility or its property.

(c) Litigation. There is no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal, regulatory or otherwise, in law or in equity, pending or, to the knowledge of the Utility, threatened against or relating to this Release, which could reasonably be expected to (i) have a material adverse effect on this Release or (ii) prevent the performance by the Utility of its obligations under this Release.

(d) Consents and Approvals. The execution, delivery and performance by the Utility of its obligations under this Release does not and, under existing facts and law, will not, require any approval,

consent, permit, license or other authorization of, or filing or registration with, or any other action by, any person or entity which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(e) Assignments. The Utility has not assigned nor otherwise transferred its rights or obligations under either of the Power Purchase Agreements to any third party.

(f) No Default. Neither the Utility nor, to the best of the Utility’s knowledge, NEA is in default under either of the Power Purchase Agreements, and no condition exists that, with the passage of time, the giving of notice, or both, would constitute any such default.

(g) Negotiations. The terms and provisions of this Release are the result of arm’s length and good faith negotiations on the part of the Utility.

4. Representations and Warranties of NEA. NEA hereby represents and warrants as of the Effective Time that:

(a) Authority. NEA is a limited partnership validly formed and validly existing under the laws of the Commonwealth of Massachusetts and has all requisite partnership power and authority to be bound by the terms of this Release. The execution and delivery of, and the performance by NEA of its obligations under, this Release have been duly and validly authorized by all necessary partnership action of NEA. This Release has been duly and validly executed and delivered by the Utility and constitutes a valid and binding obligation of NEA, enforceable against NEA in accordance with its terms, except as such enforceability may be limited by law or principles of equity.

(b) No Conflicts. The execution and delivery of this Release will not (i) violate or conflict with any provisions of NEA’s formation or governance documents, (ii) violate, conflict with or result in the breach or termination of any material agreement or instrument to which NEA is a party or (iii) violate or conflict with (or require any filing, consent, or similar action under) any law, rule, regulation, judgment, order, injunction, decree or award that applies to or binds NEA or its property.

(c) Litigation. There is no action, claim, demand, suit, proceeding, arbitration, grievance, citation, summons, subpoena, inquiry or investigation of any nature, civil, criminal, regulatory or otherwise, in law or in equity, pending or, to the knowledge of NEA, threatened against or relating to this Release, which could reasonably be expected to (i) have a material adverse effect on this Release or (ii) prevent the performance by NEA of its obligations under this Release.

(d) Consents and Approvals. The execution, delivery and performance by NEA of its obligations under this Release does not and, under existing facts and law, will not, require any approval, consent, permit, license or other authorization of, or filing or registration with, or any other action by, any person or entity which has not been duly obtained, made or taken, and all such approvals, consents, permits, licenses, authorizations, filings, registrations and actions are in full force and effect, final and non-appealable.

(e) Assignments. Except for such assignments that have been made in connection with the financing of the Facility, NEA has not assigned nor otherwise transferred its rights or obligations under either of the Power Purchase Agreements to any third party.

(f) No Default. Neither NEA nor, to the best of NEA’s knowledge, the Utility is in default under either of the Power Purchase Agreements, and no condition exists that, with the passage of time, the giving of notice, or both, would constitute any such default.

(g) Negotiations. The terms and provisions of this Release are the result of arm’s length and good faith negotiations on the part of NEA.

5. Governing Law. This Release shall be governed by, and construed and enforced in accordance with, the internal laws of the Commonwealth of Massachusetts. All disputes arising between the Parties concerning the construction or enforcement of this Release that the Parties are unable to settle between themselves shall be submitted to a trial by judge. The Parties hereby waive any rights to a trial by jury. All proceedings shall be held in Massachusetts.

6. Assignment. This Release shall be binding upon and inure to the benefit of the respective administrators, representatives, successors and permitted assigns of the Parties.

7. Entire Agreement. As of the Effective Time, this Release, the Execution Agreement and the Amended and Restated Power Purchase Agreements between the Parties constitute the entire agreement between the Parties with respect to the release of each of the Parties’ Claims under the Power Purchase Agreements. All prior communications between or involving the Parties, whether oral or written, pertaining to or made in connection with this Release are void, shall have no binding force or effect and are replaced in their entirety by this Release.

8. Notices. Any notice or communication given pursuant hereto shall be in writing and (a) delivered personally (personally delivered notices shall be deemed given upon written acknowledgment of receipt after delivery to the address specified or upon refusal of receipt); (b) mailed by registered or certified mail, postage prepaid (mailed notices shall be deemed given on the actual date of delivery, as set forth in the return receipt, or upon refusal of receipt); (c) e-mailed (e-mailed notices shall be deemed given upon actual receipt) or (d) delivered in full by telecopy (telecopied notices shall be deemed given upon actual receipt), in either case addressed or telecopied as follows or to such other addresses or telecopy numbers as may hereafter be designated by either Party to the other in writing:

If to NEA:

Northeast Energy Associates, A Limited Partnership

c/o Northeast Energy LP

c/o ESI Northeast Energy GP, Inc.

Its Administrative General Partner

700 Universe Blvd.

P.O. Box 14000

Juno Beach, FL 33408

Attention: Business Manager

Facsimile: 561-304-5161

with a copy to:

Tractebel Power, Inc.

1990 Post Oak Blvd

Suite 1900

Houston, TX 77056

Attention: General Counsel

Facsimile: 713-636-1858

If to the Utility:

Boston Edison Company

One NSTAR Way, NE 220

Westwood, MA 02090-9230

Attention: Ellen K. Angley, Vice President, Energy Supply and Transmission

Facsimile: (781) 441-8078

with a copy to:

Legal Department

NSTAR Electric & Gas Corporation

800 Boylston Street

Boston, Ma 02109

Attention: T.N. Cronin, Assistant General Counsel

Facsimile: (617) 424-2733

9. Counterparts. This Release may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

[Reminder of this page intentionally left blank; next page is signatory page]

IN WITNESS WHEREOF, each Party has caused this Release to be executed by its duly authorized officer or representative, as applicable, as of the date first above written.

Boston Edison Company
By:
Name:
Title:
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
By Northeast Energy LP Its General Partner
By ESI Northeast Energy GP Inc. Its Administrative General Partner
By:
	Authorized Representative

SCHEDULE 3.5

UTILITY BROKER/AGENT

Concentric Energy Advisors, Inc.

SCHEDULE 4.5

NEA BROKER/AGENT

None.

SCHEDULE 5.3

INTERIM PERIOD DELIVERIES

Interim Period Delivery Points

Interim Period Delivery Point Power Purchase Agreement	Medway115 BECo A	Bellingharn Bus132 BECo B	Sandwich 115 CECo 1	Sandwich 115 CECo 2
Interim Period On-Peak Energy Price ($/MWh)
Month	Medway 115	Bellingham Bus 132	Sandwich 115
April-04	45.1846	43.9375	43.7705
May-04	48.8668	47.5389	47.3583
June-04	50.8410	49.4597	49.2718
July-04	58.7387	57.1427	56.9256
August-04	58.7387	57.1427	56.9256
September-04	48.8668	47.5389	47.3583
October-04	47.8794	46.5785	46.4016
November-04	47.8794	46.5785	46.4016
December-04	49.8538	48.4993	48.3150
January-05	57.4232	55.8630	55.6508
February-05	55.5739	54.0639	53.8585
March-05	48.4982	47.1805	47.0012
Interim Period On-Peak Delivery Quantities (MWh)
Interim Period On-Peak Delivery Quantities (MWh)
Month	BECo A	BECo B	CECo 1	CECo 2	Total
April-04	50,896.2705	31,677.9430	9,333.6964	7,840.3180	99,746.2279
May-04	13,650.7412	8,496.2493	2,503.3637	2,102.8289	26,753.1831
June-04	46,327.9168	23,363.4368	8,493.0208	7,134.1248	85,318.4992
July-04	43,115.7552	22,301.4624	7,904.1648	6,639.4944	79,960.6768
August-04	45,486.1792	23,363.4368	8,338.7040	7,004.5184	84,192.8384
September-04	40,388.3088	22,301.4624	8,176.6944	6,868.4112	77,734.8768
October-04	38,288.8128	27,726.0816	7,794.8640	6,547.6992	80,357.4576
November-04	43,433.1744	30,172.5984	8,793.1536	7,386.2208	89,785.1472
December-04	53,802.4832	33,046.1792	9,863.2832	8,285.1520	104,997.0976
January-05	50,412.0288	30,635.9760	9,241.7472	7,763.0448	98,052.7968
February-05	47,338.3680	28,878.0480	8,678.2720	7,289.7280	92,184.4160
March-05	53,297.1824	32,890.4416	9,770.6576	8,207.3568	104,165.6384
Interim Period Off-Peak Delivery Quantities (MWh)
Interim Period Off-Peak Delivery Quantities (MWh)
Month	BECo A	BECo B	CECo 1	CECo 2	Total
Aprtl-04	53,209.7373	33,117.8495	9,757.9553	8,196.6960	104,282.2381
May-04	18,087.2321	11,257.5303	3,316.9568	2,786.2484	35,447.9676
June-04	48,433.7312	24,425.4112	8,879.0672	7,458.4032	89,196.6128
July-04	52,354.8458	27,060.3472	9,597.9144	8,062.2432	97,095.3504
August-04	50,655.0632	26,018.3728	9,286.2840	7,800.4864	93,760.2064
September-04	46,158.0672	25,487.3856	9,344.7936	7,849.6128	88,639.8592
October-04	46,493.5584	33,667.3848	9,465.1920	7,950.7776	97,576.9128
November-04	49,637.9136	34,482.9696	10,049.3164	8,441.3952	102,611.5968
December-04	54,972.1024	33,764.5744	10,077.7024	8,465.2640	107,279.6432
January-05	61,214.6064	37,200.8280	11,222.1216	9,426.5544	119,064.1104
February-05	52,072.2048	31,765.8528	9,546.0992	8,018.7008	101,402.8576
March-05	54,455.8168	33,605.4512	9,983.0632	8,385.7776	106,430.1088

Schedule 5.3 continued

Interim Period Delivery Rate (MWh/h)

Interim Period Delivery Schedule MWh/h
Month	BECo A	BECo B	CECo 1	CECo 2	Total
April-04	144.5917	89.9942	26.5162	22.2736	283.3757
May-04	42.8586	26.5508	7.8230	6.5713	83.6037
June-04	131.6134	66.3734	24.1279	20.2874	242.3821
July-04	128.3207	66.3734	23.5243	19.7604	237.9788
August-04	129.2221	68.3734	23.6895	19.8992	239.1842
September-04	120.2033	66.3734	24.3354	20.4417	231.3538
October-04	113.9548	82.5161	23.1990	19.4872	239.1591
November-04	129.2654	89.7994	26.1701	21.9828	267.2177
December-04	146.2024	89.7994	26.8024	22.5140	285.3182
January-05	150.0358	91.1785	27.5052	23.1043	291.8238
February-05	147.9324	90.2439	27.1196	22.7804	266.0763
March-05	144.8293	89.3762	28.5507	22.3026	283.0588
Interim Period Support Payment Rate ($/MWh)
Interim Period Support Payment Rate ($/MWh)
Month	BECo A	BECo B	CECo 1	CECo 2
April-04	28.5286	87.9687	53.9503	77.3211
May-04	93.5786	288.5524	178.9662	253.8266
June-04	31.3416	119.2747	59.2905	84.9750
July-04	31.1091	115.4271	58.8502	84.3438
August-04	30.8920	115.4271	58.4398	83.7555
September-04	34.3169	119.2747	58.7860	84.2504
October-04	35.0309	92.8438	59.6754	85.5282
November-04	31.9111	88.1595	54.6637	78.3441
December-04	27.3042	85.3156	51.6524	74.0280
January-05	19.2606	70.4632	31.7633	59.9200
February-05	21.8275	78.8208	35.6665	67.2832
March-05	19.9530	71.8841	32.9052	62.0739

EX-10.23

EXHIBIT 10.23

PURCHASE AND SALE AGREEMENT

Between

BOSTON EDISON COMPANY

and

TRANSCANADA ENERGY LTD.

June 23, 2004

Table of Contents

ARTICLE 1 - DEFINITIONS		1
ARTICLE 2 - PURCHASE AND SALE		3
2.1	The Sale	3
ARTICLE 3 - PURCHASE PRICE AND CLOSING		3
3.1	Purchase Price	3
3.2	Closing	3
3.3	Deliveries by the Seller	3
3.4	Deliveries by the Buyer	3
ARTICLE 4 - CONDITIONS TO SALE		4
4.1	Conditions to Obligations of both Parties	4
4.2	Conditions to Obligation of the Seller	4
4.3	Conditions to Obligation of Buyer	5
4.4	Obligation with Respect To Conditions	5
ARTICLE 5 - REPRESENTATIONS AND WARRANTIES		6
5.1	Representations and Warranties of Both Parties	6
5.2	Additional Representations and Warranties of Buyer	6
5.3	Additional Representations and Warranties of Seller	7
5.4	Survival of Representations and Warranties	7
ARTICLE 6 - COVENANTS		8
6.1	Seller’s Covenants with Respect to the OSP Contracts	8
6.2	Buyer’s Covenants.	8
6.3	Consents and Approvals	9
6.4	Taxes	9
ARTICLE 7 - INDEMNIFICATION		9
7.1	Indemnification by Buyer	9
7.2	Indemnification by the Seller	9
7.3	Indemnification Procedures	10
ARTICLE 8 - TERMINATION		10
8.1	Grounds for Termination Prior to Closing	10
8.2	Effect of Termination.	11
ARTICLE 9 - GENERAL PROVISIONS		11
9.1	Expenses	11
9.2	Further Assurances	11
9.3	Entire Agreement	11
9.4	Notices	11
9.5	Announcements	12
9.6	Benefit of the Agreement	12
9.7	Time	12
9.8	Assignment	12
9.9	Counterparts	12
9.10	Severability	13
9.11	Amendments and Waivers	13
9.12	Headings	13
9.13	Interpretation	13
9.14	Statutory References	13
9.15	Funds	13
9.16	Exhibits	14
9.17	No Drifting Presumption	14
9.18	Governing Law	14

EXHIBIT A	OSP CONTRACTS
EXHIBIT B	ASSIGNMENT AND ASSUMPTION AGREEMENT
EXHIBIT C	ENTITLEMENT PAYMENT AGREEMENT
EXHIBIT D	INTERIM PERIOD
EXHIBIT E	CONSENT AND RELEASE FROM OSP
EXHIBIT F	CONSENT AND RELEASE FROM OSP II

PURCHASE AND SALE AGREEMENT

Purchase and Sale Agreement made on this 23rd day of June, 2004 by and between TransCanada Energy Ltd., a Canadian corporation (the “Buyer”) and Boston Edison Company, a Massachusetts corporation (the “Seller”), each individually a “Party” and collectively the “Parties”.

WITNESSETH:

WHEREAS, the Seller is party to certain power contracts described in Exhibit A to this Agreement (the “OSP Contracts”); and

WHEREAS, pursuant to a solicitation process commenced in October, 2003, the Seller solicited competitive bids for certain power supply contracts; and

WHEREAS, the Seller and the Buyer desire to enter into this Agreement (to establish the terms of the purchase and sale of the OSP Contracts;

NOW, THEREFORE, in consideration of these premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Seller and the Buyer agree as follows:

ARTICLE 1 - DEFINITIONS

1.1 Definitions

In this Agreement, unless something in the subject matter or context is inconsistent therewith, all capitalized terms shall have the meanings ascribed thereto as follows:

(a) “Affiliate” has the meaning ascribed to that term by the Securities Exchange Act of 1934;

(b) “Agreement” means this agreement and all amendments made hereto in accordance with the provisions hereof;

(c) “Assignment and Assumption Agreement” means the Assignment and Assumption Agreement attached as Exhibit B between the Buyer and the Seller;

(d) “Business Day” means any day other than a Saturday, Sunday or holiday which is recognized in The Commonwealth of Massachusetts;

(e) “Claims” shall mean any and all losses, damages, costs, expenses, injuries of any kind or character, claims, actions, causes of action, demands, fees (including, without limitation, all legal and other professional fees and disbursements, court costs and experts’ fees), levies, taxes, judgments, fines, charges, deficiencies, interest, penalties and amounts paid in settlement, whether arising in equity, at common law, by statute, or under the law of contract, tort (including, without limitation, negligence and strict liability without regard to fault) or property law, of every kind or character;

Page 1

(f) “Closing” has the meaning ascribed to that term in Section 3.2;

(g) “Closing Conditions” has the meaning ascribed to that term in Section 3.2;

(h) “Closing Date” has the meaning ascribed to that term in Section 3.2;

(i) “Consent and Release Agreements” means the Consent and Release Agreements attached as Exhibits E and F;

(j) “Encumbrances” means any mortgages, pledges, liens, security interests, assessments, encumbrances and charges of any kind;

(k) “Entitlement Payment Agreement” means the Entitlement Payment Agreement between Buyer and Seller attached as Exhibit C;

(1) “FERC” means the Federal Energy Regulatory Commission;

(m) “Form W-8BEN” means Form W-8BEN attached as Exhibit G or any successor form thereto;

(n) “Interim Period” has the meaning ascribed to that term in Exhibit D;

(o) “Interim Period Refund” has the meaning ascribed to that term in Exhibit D;

(p) “MDTE” means the Massachusetts Department of Telecommunications and Energy;

(q) “OSP” means Ocean State Power, a Rhode Island partnership and party to one of the OSP Contracts;

(r) “OSP II” means Ocean State Power II, a Rhode Island partnership and party to one of the OSP Contracts;

(s) “OSP Contracts” has the meaning ascribed to that term in the Recital;

(t) “Purchased Assets” means all right, title and interests of the Seller in and to and all liabilities and obligations of the Seller under the OSP Contracts;

(u) “Purchase Price” has the meaning ascribed to that term in Section 3.1;

(v) “Taxes” means all taxes, charges, fees, levies, penalties or other assessments imposed by any United States federal, state or local or foreign taxing authority, including, but not limited to, income, excise, property, sales, transfer, franchise, payroll, withholding, social security or other taxes, including any interest, penalties, or additions attributable thereto.

Page 2

ARTICLE 2 - PURCHASE AND SALE

2.1 The Sale

Upon the terms and subject to the satisfaction of the conditions set forth herein and effective as of the Closing Date, the Seller will permanently assign, convey, transfer and deliver to the Buyer and the Buyer will purchase and acquire from the Seller, free and clear of all Encumbrances, all of the Seller’s right, title and interest in the Purchased Assets. Subject to the provisions of Section 7.2, the Parties acknowledge and agree that, from and after the Closing Date, the Seller shall have no further obligations or liabilities under the OSP Contracts except for such obligations and liabilities arising prior to the Closing Date.

ARTICLE 3 - PURCHASE PRICE AND CLOSING

3.1 Purchase Price

The purchase price to be paid for the Purchased Assets shall be one dollar (the “Purchase Price”), the receipt of which is hereby acknowledged.

3.2 Closing

Upon the terms and subject to the satisfaction of the conditions contained in Article 4 (the “Closing Conditions”), the closing of the sale of the Purchased Assets contemplated by this Agreement (the “Closing”) will take place at Seller’s offices in Boston, Massachusetts at 10:00 a.m. (local time) on such date as the Parties may agree, which date is as soon as practicable but no later than fifteen (15) Business Days following the date on which all of the Closing Conditions have been satisfied or waived; or at such other place or time as the Parties may agree. The date and time at which the Closing actually occurs is herein after referred to as the “Closing Date”.

3.3 Deliveries by the Seller

At the Closing, the Seller shall deliver or cause to be delivered to the Buyer the following:

(a) the Assignment and Assumption Agreement, duly executed by the Seller;

(b) the Entitlement Payment Agreement, duly executed by the Seller;

(c) the Officer’s certificate referred to in Section 4.3(a); and

(d) the Consent and Release Agreements, duly executed by Seller and OSP or OSP II, as the case may be.

3.4 Deliveries by the Buyer

At the Closing, the Buyer shall deliver or cause to be delivered to the Seller the following:

(a) the Assignment and Assumption Agreement, duly executed by the Buyer;

(b) the Entitlement Payment Agreement, duly executed by the Buyer;

(c) the Officer’s certificate referred to in Section 4.2(a); and

(d) a completed Form W-8BEN.

Page 3

ARTICLE 4 - CONDITIONS TO SALE

4.1 Conditions to Obligations of both Parties

The obligations of the Buyer and the Seller under this Agreement are subject to the fulfillment and satisfaction, on or prior to the Closing Date, of each of the following obligations, any one or more of which may be waived, in whole or in part, only in writing by both the Buyer and the Seller:

(a) No Restraining Proceedings. No preliminary or permanent injunction or other order or decree by any court of competent jurisdiction or any governmental entity which prevents the consummation of the sale of the Purchased Assets contemplated hereby shall have been issued and remain in effect (each Party agreeing to use its reasonable best efforts to have any such injunction, order or decree lifted) and no statutes, rule or regulation shall be enacted by any state or federal government or governmental agency in the United States which prohibits the consummation of the sale of the Purchased Assets.

(b) Governmental Approvals. All the approvals and authorizations required for the effectiveness of this Agreement and for the performance by the Seller and the Buyer of their respective obligations under this Agreement, shall have been received in a form reasonably acceptable to the Buyer and the Seller, specifically including final approvals of the MDTE and the FERC, and are no longer subject to reconsideration or appeal.

(c) NEPOOL/ ISO. Any and all necessary filings or notices shall have been given or made with the New England Power Pool and/or the New England Independent System Operator and any and all approvals or authorizations concerning the transaction contemplated by this Agreement shall have been received in a form reasonably acceptable to each Party.

4.2 Conditions to Obligation of the Seller

The obligations of the Seller under this Agreement are subject to the fulfillment and satisfaction, on or prior to the Closing Date, of each of the following conditions, any one or more of which may be waived, in whole or in part, only in writing by the Seller:

(a) Representations, Warranties and Covenants True at the Closing Date. (i) All representations and warranties of Buyer contained in Sections 5.1 and 5.2 of this Agreement shall be true and correct in all material respects as of the date when made and at and as of the Closing Date as though such representations and warranties had been made or given on such date (except to the extent such representations and warranties specifically pertain to an earlier date), except (x) for changes contemplated by this Agreement and (y) where the failure to be true and correct will not have a material adverse effect on the business, property, financial condition, results of operations or prospects of Seller, or on the Seller’s rights under this Agreement; (ii) Buyer shall have performed and complied with, in all material respects, its

Page 4

obligations that are to be performed by or complied with prior to or on the Closing Date; and (iii) Buyer shall have delivered a certificate signed by one of its duly authorized officers certifying as to the fulfillment of the conditions set forth in the foregoing clauses (i) and (ii).

(b) Consents/ Releases. All consents, approvals and releases for the transactions contemplated hereby under the terms of the OSP Contracts or any other related agreement have been obtained in a form satisfactory to the Seller, including without limitation the Consent and Release documents executed by OSP and OSP II which are attached as Exhibits E and F.

4.3 Conditions to Obligation of Buyer

The obligations of Buyer under this Agreement are subject to the fulfillment and satisfaction, on or prior to the Closing Date, of each of the following conditions, any one or more of which may only be waived in writing, in whole or in part, by Buyer:

(a) Representations, Warranties and Covenants True at the Closing Date. (i) All representations and warranties of the Seller contained in Sections 5.3 (a), (c) and (e) of this Agreement shall be true and correct in all respects and all other representations of the Seller contained in Sections 5.1 and Section 5.3 (b) and (d) of this Agreement shall be true and correct in all material respects, when made and at and as of the Closing Date as though such representations and warranties had been made or given on such date (except to the extent such representations and warranties specifically pertain to an earlier date), except (x) for changes contemplated by this Agreement and (y) where the failure to be true and correct will not have a material adverse effect on the OSP Contracts or the Buyer’s rights under this Agreement; (ii) the Seller shall have performed and complied with, in all material respects, its obligations that are to be performed or complied with by it prior to or on the Closing Date; and (iii) the Seller shall deliver a certificate signed by one of its duly authorized officers certifying as to the fulfillment of the conditions set forth in the foregoing clauses (i) and (ii).

(b) Encumbrances. There shall be no Encumbrances on the Purchased Assets.

4.4 Obligation with Respect To Conditions

The Seller and the Buyer shall each use reasonable efforts to obtain all of the foregoing approvals and authorizations and to otherwise satisfy the foregoing conditions. Each Party agrees to promptly advise the other of the fulfillment or waiver of any condition and any material events associated with such conditions, and further each Party agrees to promptly notify the other in the event that such Party determines that any required consent or government approval or authorization is not acceptable to such Party.

Page 5

ARTICLE 5 - REPRESENTATIONS AND WARRANTIES

5.1 Representations and Warranties of Both Parties

Each Party hereby represents and warrants to the other that:

(a) It is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization and is duly qualified to do business in all jurisdictions where such qualification is required.

(b) It has full power and authority to enter this Agreement and perform its obligations hereunder. The execution, delivery and performance of this Agreement have been duly authorized by all necessary corporate action and do not and will not contravene its organizational documents or conflict with, result in a breach of, or entitle any party (with due notice or lapse of time or both) to terminate, accelerate or declare a default under, any agreement or instrument to which it is a party or by which it is bound. The execution, delivery and performance by it of this Agreement will not result in any violation by it of any law, rule or regulation applicable to it. It is not a party to, nor subject to or bound by, any judgment, injunction or decree of any court or other governmental entity, which may restrict or interfere with the performance of this Agreement by it. This Agreement has been duly and validly executed and delivered on its behalf and is its valid and binding obligation and is enforceable against it in accordance with its terms, except that such enforceability may be limited by applicable bankruptcy, insolvency, moratorium, reorganization or other similar laws affecting or relating to the enforcement of creditor’s rights generally or general principles of equity.

(c) Except for the approvals of the FERC and MDTE, no consent, waiver, order, approval, authorization or order of, or registration, qualification or filing with, any court or other governmental agency or authority is required for the execution, delivery and performance by such Party of this Agreement and the consummation by such Party of the transactions contemplated hereby. No agreement, consent or waiver of any party to any contract to which such Party is a party or by which it is bound is required for the execution, delivery and performance by such Party of this Agreement which has not been duly obtained.

(d) Except for any fees payable by the Seller to Concentric Energy Advisors, Inc., no broker, finder or other person is entitled to any fees or commissions in connection with this Agreement or the transaction contemplated herein.

5.2 Additional Representations and Warranties of Buyer

The Buyer hereby represents and warrants with the Seller that the Buyer has (i) been represented by counsel, (ii) had the opportunity to make a complete and thorough review of the OSP Contracts and all related documents, sufficient for it to understand the benefits and risks of the transactions contemplated by this Agreement, and (iii) that the Buyer is not relying on any representations or warranties by the Seller or any person actually or purportedly acting on the Seller’s behalf with respect to any matter affecting or arising out of or in connection with the OSP Contracts, except as otherwise expressly set forth in this Agreement.

Page 6

5.3 Additional Representations and Warranties of Seller

Seller hereby represents and warrants with the Buyer that:

(a) The Seller has good and valid title to the Purchased Assets, free and clear of all Encumbrances.

(b) The OSP Contracts (i) constitute valid and binding obligations of the Seller and to the best knowledge of the Seller constitute valid and binding obligations of OSP and OSP II, (ii) are in full force and effect, and (iii) upon receipt of the Consent and Release Agreements, do not prohibit the transfer of the OSP Contracts hereunder and will continue in full force and effect thereafter, in each case without breaching the terms thereof or resulting in the forfeiture or impairment of any rights thereunder.

(c) There is not, under the OSP Contracts, any default or event which, with notice or lapse of time or both, would constitute a default on the part of Seller or, to the knowledge of Seller, OSP or OSP II.

(d) There are no actions or proceedings pending or to the knowledge of the Seller, threatened, against the Seller or its Affiliates relating to the Purchased Assets or any such actions or proceedings, the subject matter of which is the Purchased Assets, except to the extent that such actions or proceedings would be subject to an indemnity obligation of the Seller pursuant to Section 7.2.

(e) No person has any agreement, option, understanding or commitment, or any right or privilege (whether by law, pre-emptive or contractual) capable of becoming an agreement, option or commitment, including convertible securities, warrants or convertible obligations of any nature, for the purchase from the Seller of any interest in the Purchased Assets.

5.4 Survival of Representations and Warranties

(a) The representations and warranties made by the Seller herein or contained in any schedule or exhibit attached hereto or other document or certificate given in order to carry out the transaction contemplated herein shall survive the Closing and, notwithstanding such Closing or any investigation made by or on behalf of the Buyer or any other person or any knowledge of the Buyer or any other person, shall continue in full force and effect for the benefit of the Buyer.

(b) The representations and warranties made by the Buyer herein or contained in any schedule or exhibit attached hereto or other document of certificate given in order to carry out the transaction contemplated herein shall survive the Closing and, notwithstanding such Closing or any investigation made by or on behalf of the Seller or any other person or any knowledge of the Seller or any other person, shall continue in full force and effect for the benefit of the Seller.

Page 7

ARTICLE 6 - COVENANTS

6.1 Seller’s Covenants with Respect to the OSP Contracts

(a) During the period from the date of this Agreement to the Closing Date and subject to the activities contemplated in Exhibit D hereto, the Seller will conduct its business with respect to the Purchased Assets according to its ordinary and usual course of business consistent with past practice and will not amend (or waive any rights under) the OSP Contracts without the Buyer’s prior written consent or take any action or fail to take any action that would result in a material breach of the Seller’s obligations under the OSP Contracts.

(b) The Seller shall use reasonable efforts to promptly provide the Buyer with documents and information regarding operation, dispatch, scheduling and other matters relevant to the OSP Contracts prior to the Closing Date and which are available to the Seller. To the extent that the Seller receives any notices issued prior to the Closing Date pursuant to the terms of the OSP Contracts, the Seller agrees promptly to forward such notices to the Buyer within five (5) Business Days from the Seller’s receipt thereof.

(c) The Seller shall make timely payments of all amounts due for periods prior to the Closing Date under the OSP Contracts.

(d) The Seller shall keep the OSP Contracts in good standing and shall not take any action or fail to take any action that would result in a breach of the Seller’s obligations under the OSP Contracts. In the case of a breach by OSP or OSP II under the OSP Contracts prior to the Closing Date, the Seller shall cooperate with the Buyer to enforce the provisions of the OSP Contracts.

(e) The Seller shall keep the Purchased Assets free and clear of any and all Encumbrances except such Encumbrances imposed on account of Buyer or Buyer’s affiliates.

(f) During the Interim Period, the Seller shall perform its obligations set out in Exhibit D.

(g) From and after the Closing Date, the Seller shall pay to the Buyer the amounts due pursuant to and in accordance with the Entitlement Payment Agreement.

6.2 Buyer’s Covenants

(a) The Buyer hereby assumes and agrees to pay, perform or discharge in accordance with their terms, from and after the Closing Date, to the extent not heretofore paid, performed or discharged, all liabilities and obligations of the Seller under the OSP Contracts, except for any obligations or liabilities arising prior to the Closing Date.

Page 8

(b) During the Interim Period, the Buyer shall perform all obligations assumed by it pursuant to the temporary entitlement transfer referred to in Exhibit D.

(c) The Buyer shall use reasonable efforts to promptly provide the Seller with documents and information regarding operation, dispatch, scheduling and other matters relevant to the OSP Contracts prior to the Closing Date and which are available to the Buyer.

6.3 Consents and Approvals

The Seller and the Buyer shall cooperate with each other and (i) promptly prepare and file all necessary documentation, (ii) effect all necessary applications, notices, petitions and filings and execute all agreements and documents, (iii) use all commercially reasonably efforts to obtain all necessary consents, approvals and authorization of all other parties, necessary or advisable to consummate the transaction contemplated by this Agreement

6.4 Taxes

All payments made under this Agreement shall be made without withholding or deduction for Taxes, provided that the Buyer has provided to the Seller at Closing and thereafter as reasonably requested by the Seller a Form W-8BEN.

ARTICLE 7 - INDEMNIFICATION

7.1 Indemnification by Buyer

The Buyer shall indemnify, defend and hold harmless the Seller and the Seller’s officers, directors, agents, employees and Affiliates from and against any and all Claims relating to or arising out of:

(a) Any material failure of the Buyer to observe or perform any term or provision of this Agreement or the Entitlement Payment Agreement which is the Buyer’s obligation to observe or perform;

(b) All liabilities and obligations arising under or relating to the OSP Contracts from and after the Closing Date; or

(c) Any failure of any representation or warranty made by the Buyer herein to be true in any material respect.

7.2 Indemnification by the Seller

The Seller shall indemnify, defend and hold harmless the Buyer, its officers, directors, agents, employees and Affiliates from and against any and all Claims relating to or arising; out of:

(a) Any material failure of the Seller to observe or perform any term or provision of this Agreement, the Entitlement Payment Agreement or the OSP Contracts which is the Seller’s obligation to observe or perform;

Page 9

(b) All liabilities and obligations arising under or relating to the OSP Contracts, prior to the Closing Date;

(c) Any failure of any representation or warranty made by the Seller in Sections 5.1, 5.3 (b) and 5.3 (d) to be true in any material respect; or

(d) Any failure of any representation or warranty made by the Seller in Sections 5.3 (a), (c) and (e) to be true in any respect.

7.3 Indemnification Procedures

If any Party intends to seek indemnification under this Article 7 from the other Party with respect to any Claim, the Party seeking indemnification shall give the other Party notice of such Claim within fifteen (15) days of the commencement of, or actual knowledge of, such Claim. The omission of any Party seeking indemnification under this Article 7 to so notify the other Party of any such Claim within the time period set forth above shall not relieve such other Party from any liability which they may have to the Party seeking indemnification under this Article 7 unless, and only to the extent that, such omission results in the forfeiture of substantive rights or defenses of such other Party. With respect to any third party claim, the Party indemnification shall have the right, at its sole cost and expense, to participate in the defense of any such Claim. The Party providing indemnification shall not compromise or settle any such Claim unless such settlement or compromise includes an unconditional release of the Party seeking indemnification from all liability arising or that may arise from such Claim and imposes no material obligations upon the Party seeking indemnification. Each Party agrees that it will not, without the prior consent of the other Party, settle, compromise or consent to the entry of any judgment in any pending or threatened Claim, which consent shall not be unreasonably withheld.

ARTICLE 8 - TERMINATION

8.1 Grounds for Termination Prior to Closing

This Agreement may be terminated at any time prior to Closing;

(a) by the mutual written agreement of the Parties;

(b) by the Seller or the Buyer if Closing shall not have been completed on or before December 31, 2004, or such other date, if any, as the Buyer and the Seller shall have agreed to in writing; or

(c) by one Party if the other Party has materially breached its obligations hereunder and such breach has not been cured within thirty (30) days of written notification thereof.

Page 10

8.2 Effect of Termination.

If this Agreement is terminated by the Buyer or the Seller as permitted under Section 8.1(a) or (b):

(a) the Buyer shall pay to the Seller the Interim Period Refund in accordance with Exhibit D.

(b) except as provided for in Section 8.2 (a), and with respect to any Party then in breach, such termination shall be without liability of either Party to the other Party, or to any of its or their shareholders, directors, officers, employees, agents, consultants or representatives.

ARTICLE 9 - GENERAL PROVISIONS

9.1 Expenses

Subject to the provisions of Section 8.2(b), each Party is responsible for its own legal fees and other charges incurred in connection with the preparation of this Agreement, all negotiations between the Parties, and the consummation of the transactions contemplated hereby.

9.2 Further Assurances

Each of the Parties hereto shall from time to time execute and deliver all such further documents and instruments and do all acts and things as any other party may reasonably require to effectively carry out or better evidence or perfect the full intent and meaning of this Agreement.

9.3 Entire Agreement

Except as specifically provided in this Agreement, this Agreement constitutes the entire agreement between the Parties in respect of the subject matter hereof and cancel and supersede any prior agreements, undertakings, declarations, commitments, representations, written or oral, in respect thereof.

9.4 Notices

Any demand, notice or communication to be made or given hereunder shall be in writing and may be made or given by personal delivery or by transmittal by telecopy or other electronic means of communication addressed to the respective Party as follows:

To the Seller: One NSTAR Way Westwood, MA 02090
Attention:	Ellen K. Angley, Vice President, Energy Supply and Transmission
Fax No.:	(781) 441-8078

Page 11

To the Buyer:
450 – 1st Street SW
Calgary, Alberta
T2P 5H1
Attention:	Director, Business Development
Fax No.:	(403) 920-2421

or to such other address or telecopy number as any Party may from time to time notify the other in accordance with this Section 9.4. Any demand, notice or communication made or given by personal delivery shall be conclusively deemed to have been given on the day of actual delivery thereof, or, if made or given by electronic means of communication, on the first Business Day following the transmittal thereof.

9.5 Announcements

No announcement with respect to this Agreement or the transaction contemplated herein shall be made by either Party without the prior written approval of the other Party. The foregoing shall not apply to any announcement by a Party required in order to comply with laws or stock exchange regulations pertaining to timely disclosure, provided that such Party consults with the other Party before making any such announcement.

9.6 Benefit of the Agreement

This Agreement shall enure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.

9.7 Time

Time shall be of the essence. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day) then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

9.8 Assignment

Neither of the Parties hereto shall assign its rights or obligations hereunder without the prior written consent of the other Party.

9.9 Counterparts

This Agreement may be executed in any number of counterparts each of which shall be deemed to be an original and all of which taken together shall be deemed to constitute one and the same instrument, and it shall not be necessary in making proof of this Agreement to produce or account for more than one such executed counterpart.

Page 12

9.10 Severability

Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall not invalidate the remaining provisions hereof and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. In respect of any provision so determined to be unenforceable or invalid, the Parties agree to negotiate in good faith in order to replace the unenforceable or invalid provision with a new provision that is enforceable and valid in order to give effect to the business intent of the original provision to the extent permitted by law and in accordance with the intent of this Agreement.

9.11 Amendments and Waivers

No modification of or amendment to this Agreement shall be valid or binding unless set forth in writing and duly executed by each of the Parties hereto and no waiver of any breach of any term or provision of this Agreement shall be effective or binding unless made in writing and signed by the Party purporting to give the same and, unless otherwise provided, shall be limited to the specific breach waived.

9.12 Headings

The division of this Agreement into Articles and Sections and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation of this Agreement. The terms “hereof”, “hereunder” and similar expressions refer to this Agreement and not to any particular Article, Section or other portion hereof and include any agreement supplemental hereto. Unless something in the subject matter or context is inconsistent therewith, references herein to Exhibits, Articles and Sections shall refer to Exhibits, Articles and Sections of this Agreement.

9.13 Interpretation

In this Agreement words importing the singular number only shall include the plural and vice versa, and words importing gender shall include all genders and words importing persons shall include individuals, sole proprietorships, partnerships, associations, trusts, joint ventures, unincorporated organizations and corporations and natural persons in their capacities as trustees, executors, administrators or other legal representatives.

9.14 Statutory References

Any reference to a statute shall include and shall be deemed to be, a reference to such statute and to the regulations made pursuant thereto, and all amendments made thereto and enforced from time to time, and to any statute or regulation that may be passed that has the effect of supplementing or replacing the statute so referred to or the regulations made pursuant thereto, and any reference to an order, ruling or decision shall be deemed to be a reference to such order, ruling or decision as the same may be varied, amended, modified, supplemented or replaced from time to time.

9.15 Funds

All dollar amounts referred to in this Agreement are in US dollars.

Page 13

9.16 Exhibits

The following are the Exhibits annexed hereto and incorporated by reference and deemed to be part hereof:

Exhibit A	-	OSP Contracts
Exhibit B	-	Assignment and Assumption Agreement
Exhibit C	-	Entitlement Payment Agreement
Exhibit D	-	Interim Period
Exhibit E	-	Consent and Release from OSP
Exhibit F	-	Consent and Release from OSP II

9.17 No Drafting Presumption

The Parties acknowledge that their respective legal counsel have reviewed and participated in settling the terms of this Agreement and the Parties hereby agree that any rule of construction to the effect that any ambiguity is to be resolved against the drafting party shall not be applicable in the interpretation of this Agreement.

9.18 Governing Law

This Agreement shall be construed and enforced in accordance with the laws of The Commonwealth of Massachusetts without regard to the conflicts of laws provisions in effect therein.

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the duly authorized officers of the Parties as of the date first above written.

TRANSCANADA ENERGY LTD.		BOSTON EDISON COMPANY
By:	/s/ Sean D. McMaster	By:	/s/ Ellen K. Angley
Name:	Sean D. McMaster	Name:	Ellen K. Angley
Title:	Vice President	Title:	Vice President Energy Supply & Transmission
By:	/s/ Kristine L. Delkns
Name:	Kristine L. Delkns
Title:	Vice-President, Law

LEGAL	/s/ [ILLEGIBLE]
CONTENT

Page 14

EXHIBIT A

OSP CONTRACTS

I. Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power to Boston Edison Company dated December 31,1985, as amended.

II. Unit Power Agreement for the Sale of Unit 2 Capacity and Energy from Ocean State Power II to Boston Edison Company dated July 1, 1988, as amended.

EXHIBIT B

TO PURCHASE AND SALE AGREEMENT

ASSIGNMENT AND ASSUMPTION AGREEMENT

Assignment and Assumption Agreement (this “Agreement”) made, executed and delivered on this      day of             , 2004, by and between TRANSCANADA ENERGY LTD., a Canadian corporation (the “Buyer”), and BOSTON EDISON COMPANY, a Massachusetts corporation (the “Seller”).

WITNESSETH:

WHEREAS, pursuant to that certain Purchase and Sale Agreement, dated as of June 23, 2004 (as amended, supplemented or otherwise modified from time to time, the “Purchase Agreement”), by and between the Seller and the Buyer, the Seller agreed to sell and the Buyer agreed to buy the Purchased Assets (as defined in the Purchase Agreement); and

WHEREAS, the Purchase Agreement requires that the Seller assign all of its right, title and interest in, and that the Buyer assume all liabilities and obligations of the Seller under, the OSP Contracts (as defined in the Purchase Agreement);

NOW THEREFORE, in good consideration of these premises and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Seller and the Buyer agree as follows:

1. Capitalized terms which are used in this Agreement but are not defined in this Agreement shall have the meaning ascribed to such terms in the Purchase Agreement.

2. As of the Closing Date, the Seller hereby assigns, transfers and sets over to the Buyer all of the Seller’s rights, title and interest in and to the OSP Contracts, free and clear of all Encumbrances.

3. As of the Closing Date, the Buyer hereby assumes and agrees to pay, perform or discharge in accordance with their terms, to the extent not heretofore paid, performed or discharged, all liabilities and obligations of the Seller under the OSP Contracts except for such liabilities and obligations arising prior to the Closing Date.

4. It is understood and agreed that nothing in this Agreement Shall constitute a waiver or release of any claims arising out the contractual relationships between the Seller and the Buyer.

5. This Agreement shall inure to the benefit and be enforceable against the respective successors and assigns of the Seller and the Buyer.

6. This Agreement shall be governed by and construed in accordance with the laws of The Commonwealth of Massachusetts (regardless of the laws that might otherwise govern under applicable Massachusetts principles of conflicts of laws).

7. This Agreement is delivered pursuant to and is subject to the Purchase Agreement. In the event of any conflict between the terms of the Purchase Agreement and the terms of this Agreement, the terms of the Purchase Agreement shall prevail.

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the respective duly authorized officers of the Seller and the Buyer as of the date first above written.

TRANSCANADA ENERGY LTD.

By:

Name:

Title:

By:

Name:

Title:

BOSTON EDISON COMPANY

By:

Name:

Title:

EXHIBIT C

ENTITLEMENT PAYMENT AGREEMENT

ENTITLEMENT PAYMENT AGREEMENT

Between

BOSTON EDISON COMPANY

and

TRANSCANADA ENERGY LTD.

December 21, 2004

Table of Contents

ARTICLE 1 - DEFINITIONS		1
1.1	Definitions	1
ARTICLE 2 - ENTITLEMENT PAYMENT		2
2.1	Entitlement Payment	2
2.2	True-Up Amounts	3
2.3	Payment	3
2.4	Financial Assurances	3
2.5	Taxes	4
ARTICLE 3 - TERM		4
3.1	Term	4
ARTICLE 4 - DEFAULTS		4
4.1	Boston Edison Defaults	4
4.2	TCE Defaults	4
ARTICLE 5 - GENERAL PROVISIONS		5
5.1	Expenses	5
5.2	Further Assurances	5
5.3	Entire Agreement	5
5.4	Notices	5
5.5	Benefit of the Agreement	6
5.6	Time	6
5.7	Assignment	6
5.8	Counterparts	6
5.9	Severability	6
5.10	Amendments and Waivers	6
5.11	Headings	7
5.12	Interpretation	7
5.13	Funds	7
5.14	Exhibits	7
5.15	No Drafting Presumption	7
5.16	Governing Law	7
EXHIBIT A OSP CONTRACTS
EXHIBIT B TRUE-UP PERIOD
EXHIBIT C FORM W-8BEN

ENTITLEMENT PAYMENT AGREEMENT

Entitlement Payment Agreement made on this 21^st day of December, 2004 by and between TransCanada Energy Ltd., a Canadian corporation (“TCE”) and Boston Edison Company, a Massachusetts corporation (“Boston Edison”), each individually a “Party” and collectively the ‘Parties”

WHEREAS, pursuant to that certain Purchase and Sale Agreement dated as of June 23, 2004 and the exhibits thereto (as amended, supplemented or otherwise modified from time to time, the “Purchase Agreement”) by and between TCE and Boston Edison, Boston Edison agreed to sell and assign and TCE agreed to buy and assume the OSP Contracts; and

WHEREAS, the Purchase Agreement requires that Boston Edison make certain payments to TCE and, for that purpose, Boston Edison and TCE have agreed to execute and deliver this Entitlement Payment Agreement;

NOW THEREFORE, in good consideration of the execution of the Purchase Agreement, these premises and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, Boston Edison and TransCanada agree as follows:

ARTICLE 1 - DEFINITIONS

1.1 Definitions

In this Agreement, unless something in the subject matter or context is inconsistent therewith, all capitalized terms shall have the meanings ascribed thereto as follows:

(a) “Agreement” means this agreement and all amendments made hereto in accordance with the provisions hereof;

(b) “Business Day” means any day other than a Saturday, Sunday or holiday which is recognized in The Commonwealth of Massachusetts;

(c) “Closing Date” means the date of this Agreement set out above;

(d) “Form W-8BEN” means Form W-8BEN attached as Exhibit C or any successor form thereto;

(e) “Insolvency Event” means with respect to Boston Edison the occurrence of one or more of the following:

(i) a custodian, receiver, liquidator or trustee of it or of any of its property is appointed or takes possession and such appointment or possession remains uncontested or in effect for more than 30 days;

(ii) it makes an assignment for the benefit of its creditors or admits in writing its inability to pay its debts as they mature;

(iii) it is adjudicated bankrupt or insolvent; or an order for relief is entered under the United States Bankruptcy Code against it;

Page 1

(iv) a petition is filed against it under any bankruptcy, reorganization, arrangement, insolvency, readjustment of debt, dissolution or liquidation law of any jurisdiction, whether now or subsequently in effect, and is not stayed or dismissed within 30 days after filing;

(v) it files a petition in voluntary bankruptcy or seeking relief under any provision of any bankruptcy, reorganization, arrangement, insolvency, readjustment of debt, dissolution or liquidation law of any jurisdiction, whether now or subsequently in effect; or consents to the filing of any petition against it under any such law; or consents to the appointment of or taking possession by a custodian, receiver, trustee or liquidation of it or any of its property;

(f) “Moody’s” means Moody’s Investors Service, Inc. and its successors;

(g) “OSP” means Ocean State Power, a Rhode Island partnership and party to one of the OSP Contacts;

(h) “OSP II” means Ocean State Power II, a Rhode Island partnership and party to one of the OSP Contracts;

(i) “OSP Contracts” means those contracts listed in Exhibit A;

(j) “Prime Rate” means the prime rate published in the “Money Rates” section of the Wall Street Journal;

(k) “S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc. and its successors;

(l) “Taxes” means all taxes, charges, fees, levies, penalties or other assessments imposed by any United States federal, state or local or foreign taxing authority, including, but not limited to, income, excise, property, sales, transfer, franchise, payroll, withholding, social security or other taxes, including any interest, penalties, or additions attributable thereto;

(m) “United States Bankruptcy Code” means the Federal Bankruptcy Reform Act of 1978 C11 U.S.C § 101, et seq., as amended and in effect from time to time and the regulations issued from time to time thereunder.

ARTICLE 2 - ENTITLEMENT PAYMENT

2.1 Entitlement Payment

Boston Edison agrees to pay to TCE monthly, on the first Business Day of each month following the Closing Date and otherwise in accordance with Section 2.2 and Exhibit B, the amounts set forth below:

2004: $                     per month for the months of April through December

Page 2

2005: $                  per month

2006: $                  per month

2007: $                  per month

2008: $                  per month

2009: $                  per month

2010: $                  per month

2011: $                  per month for the months of January through September

If the Closing Date occurs other than on the first day of a month, the amount payable by Boston Edison for such month shall be pro rated based on the number of days in such month following and including the Closing Date and shall be payable on the Closing Date.

2.2 True-Up Amounts

The responsible Party shall pay any amounts owing to the other pursuant to Exhibit B. Such payment shall be made to the Party to receive such payment in accordance with the provisions set forth in Exhibit B.

2.3 Payment

All payments required under this Agreement shall be paid by wire transfer of immediately available funds to an account designated by the Party to receive such payment. If all or any part of any amount due and payable hereunder shall not be paid by the owing Party on the date specified herein, interest on the unpaid amount shall accrue from the due date of such payment until the date that payment is received and shall be paid to the other Party at the rate per annum of 2% above the Prime Rate in effect on such due date.

2.4 Financial Assurances

If at any time throughout the term of this Agreement,

(i) the debt rating on Boston Edison’s long term senior unsecured debt (or, if unavailable, its corporate credit rating) falls below BBB by S&P or Baa2 by Moody’s; or

(ii) the debt rating on the long term senior unsecured debt (or, if unavailable, its corporate credit rating) of any provider of any Performance Assurance falls below BBB by S&P or Baa2 by Moody’s,

then TCE shall be entitled to request that Boston Edison provide TCE with Performance Assurance, or replacement Performance Assurance in the case of Section 2.4 (ii), and Boston Edison shall have seven (7) Business Days from the date of such request to provide TCE with the requested Performance Assurance “Performance Assurance” means sufficient security in the form and for the term reasonably satisfactory to TCE, including, but not limited to, one of the following: a standby irrevocable letter of credit from a financial institution reasonably acceptable to TCE, or a guarantee by an entity deemed to be creditworthy by TCE in its sole discretion. Such Performance Assurance shall be required to be maintained for only that period of time during which the debt ratings specified in this Section 2.4 are not satisfied.

Page 3

2.5 Taxes

All payments made under this Agreement shall be made without withholding or deduction for Taxes, provided that the Buyer has provided to the Seller at Closing and thereafter as reasonably requested by the Seller a Form W-8BEN.

ARTICLE 3 - TERM

3.1 Term

The term of this Agreement shall commence on the Closing Date and shall remain in effect until Boston Edison has, after giving effect to the obligations set forth in Section 2.2, fully paid to TCE the amounts set out in Section 2.1.

ARTICLE 4 - DEFAULTS

4.1 Boston Edison Defaults

In the event that:

(a) Boston Edison defaults in the performance of any of its obligations hereunder, including without limitation its obligations under Article 2 above, and fails to remedy such default within five (5) Business Days of notice thereof from TCE, or

(b) an Insolvency Event occurs or exists in respect of Boston Edison,

then Boston Edison shall be considered in default hereof and TCE shall be entitled to pursue all legal remedies available to it.

4.2 TCE Defaults

In the event that:

(a) TCE defaults in the performance of any of its obligations hereunder, including without limitation its obligations under Section 2.2 above, or

(b) TCE defaults under the Assignment and Assumption Agreement and as a result thereof Boston Edison assumes any obligations or liabilities under the OSP Contracts,

and fails to remedy such default within five (5) Business Days of notice thereof from Boston Edison, then TCE shall be considered in default hereof and Boston Edison shall be entitled to pursue all legal remedies available to it.

Page 4

ARTICLE 5 - GENERAL PROVISIONS

5.1 Expenses

Each Party is responsible for its own legal fees and other charges incurred in connection with the preparation of this Agreement, all negotiations between the Parties, and the consummation of the transactions contemplated hereby.

5.2 Further Assurances

Each of the Parties hereto shall from time to time execute and deliver all such further documents and instruments and do all acts and things as any other party may reasonably require to effectively carry out or better evidence or perfect the full intent and meaning of this Agreement.

5.3 Entire Agreement

Except, as specifically provided in this Agreement, this Agreement and the Purchase Agreement constitute the entire agreement between the Parties in respect of the subject matter hereof and cancel and supersede any prior agreements, undertakings, declarations, commitments, representations, written or oral, in respect thereof.

5.4 Notices

Any demand, notice or communication to be made or given hereunder shall be in writing and may be made or given by personal delivery or by transmittal by telecopy or other electronic means of communication addressed to the respective Party as follows:

To Boston Edison:

One NSTAR Way

Westwood, MA 02090

Attention:     Ellen K. Angley, Vice President, Energy Supply and Transmission

Fax No:         (781) 441-8078

To TCE:

55 Yonge Street, 8^th Floor

Toronto, Ontario

M5E IJ4

Attention:     Manager, Eastern Commercial Operation

Fax No:         (416) 869-2056

or to such other address or telecopy number as any Party may from time to time notify the other Party in accordance with this Section 5.4. Any demand, notice or communication made or given by personal delivery shall be conclusively deemed to have been given on the day of actual delivery thereof, or, if made or given by electronic means of communication, on the first Business Day following the transmittal thereof.

Page 5

5.5 Benefit of the Agreement

This Agreement shall enure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.

5.6 Time

Time shall be of the essence. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day) then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

5.7 Assignment

Boston Edison shall not assign its rights or obligations hereunder without the prior written consent of TCE, such consent not to be unreasonably withheld. TCE may assign its rights and obligations hereunder at any time, provided that any purported assignee shall provide written confirmation to Seller of such party’s acknowledgement and agreement that such assignment is subject to the terms and conditions of this Agreement and Seller’s rights and defenses hereunder.

5.8 Counterparts

This Agreement may be executed in any number of counterparts each of which shall be deemed to be an original and all of which taken together shall be deemed to constitute one and the same instrument, and it shall not be necessary in making proof of this Agreement to produce or account for more than one such executed counterpart.

5.9 Severability

Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall not invalidate the remaining provisions hereof and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. In respect of any provision so determined to be unenforceable or invalid, the Parties agree to negotiate in good faith in order to replace the unenforceable or invalid provision with a new provision that is enforceable and valid in order to give effect to the business intent of the original provision to the extent permitted by law and in accordance with the intent of this Agreement.

5.10 Amendments and Waivers

No modification of or amendment to this Agreement shall be valid or binding unless set forth in writing and duly executed by each of the Parties hereto and no waiver of any breach of any term or provision of this Agreement shall be effective or binding unless made in writing and signed by the Party purporting to give the same and, unless otherwise provided, shall be limited to the specific breach waived.

Page 6

5.11 Headings

The division of this Agreement into Articles and Sections and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation of this Agreement. The terms “hereof”, “hereunder” and similar expressions refer to this Agreement and not to any particular Article, Section or other portion hereof and include any agreement supplemental hereto. Unless something in the subject matter or context is inconsistent therewith, references herein to Exhibits, Articles and Sections shall refer to Exhibits, Articles and Sections of this Agreement.

5.12 Interpretation

In this Agreement words importing the singular number only shall include the plural and vice versa, and words importing gender shall include all genders and words importing persons shall include individuals, sole proprietorships, partnerships, associations, trusts, joint ventures, unincorporated organizations and corporations and natural persons in their capacities as trustees, executors, administrators or other legal representatives.

5.13 Funds

All dollar amounts referred to in this Agreement are in US Dollars.

5.14 Exhibits

The following are the Exhibits annexed hereto and incorporated by reference and deemed to be part hereof:

Exhibit A	-	OSP Contracts
Exhibit B	-	True-Up Amounts
Exhibit C	-	Form W-8BEN

5.15 No Drafting Presumption

The Parties acknowledge that their respective legal counsel have reviewed and participated in settling the terms of this Agreement and the Parties hereby agree that any rule of construction to the effect that any ambiguity is to be resolved against the drafting party shall not be applicable in the interpretation of this Agreement.

5.16 Governing Law

This Agreement shall be construed and enforced in accordance with the laws of the Commonwealth of Massachusetts without regard to the conflicts of laws provisions in effect therein.

Page 7

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the duly authorized officers of the Parties as of the date first above written.

TRANSCANADA ENERGY LTD.		BOSTON EDISON COMPANY
By:	/s/ Sean D. McMaster	By:	/s/ Ellen K. Angley
Name:	Sean D. McMaster	Name:	Ellen K. Angley
Title:	Vice President	Title:	Vice President Energy Supply & Transmission

By:	/s/ Karl Johannson
Name:	Karl Johannson
Title:	Vice President Western Power

LEGAL	/s/ Illegible
CONTENT	/s/ Illegible

Page 8

EX-10.24

EXHIBIT 10.24

Execution Copy

TERMINATION AGREEMENT

This TERMINATION AGREEMENT (this “Agreement”) is entered into on the 2nd day of June, 2004, by and between CAMBRIDGE ELECTRIC LIGHT COMPANY, a Massachusetts corporation having its principal place of business at 800 Boylston Street, Boston, Massachusetts 02199 (“Cambridge”), and PITTSFIELD GENERATING COMPANY, L.P. (f/k/a Altresco Pittsfield, L.P.), a Delaware limited partnership with a principal place of business at 235 Merrill Road, Pittsfield, Massachusetts (“Pittsfield”).

W I T N E S S E T H:

WHEREAS, Cambridge and Pittsfield are parties to that certain Power Sale Agreement, dated February 20, 1992, as amended by an Amendment to Power Sale Agreement dated as of November 7, 1994 and a Second Amendment to Power Purchase Agreement dated as of November 21, 1996 (as so amended, the “Power Purchase Agreement”), pursuant to which Pittsfield sells to Cambridge, and Cambridge purchases from Pittsfield, a seventeen and two-tenths per cent (17.2%) entitlement to the capacity and associated electric energy produced by Pittsfield’s facility situated in Pittsfield, Massachusetts (the “Facility”); and

WHEREAS, Pittsfield and Cambridge desire to terminate the Power Purchase Agreement pursuant to, and in accordance with, the terms and provisions contained herein.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto hereby agree as follows:

1. Definitions. Capitalized terms used herein without definition shall have the respective meanings given to such terms in the Power Purchase Agreement. In addition, the term “Business Day” shall mean a day other than a Saturday, Sunday or any other day which is a legal holiday or a day on which banking institutions are authorized or required by law to close or be closed in Massachusetts.

2. Effectiveness.

2.1. The “Effective Date” shall be the third Business Day after the first date on which all of the following conditions have been satisfied: (i) approval by the Massachusetts Department of Telecommunications and Energy (“DTE”), in form and substance reasonably satisfactory to the parties, of (A) this Agreement, including but not limited to the termination of the Power Purchase Agreement pursuant to the terms hereof, and (B) the full recovery of the Termination Payments through Cambridge’s Transition Charge (as defined under G.L. c. 164, Section 1G), and either (x) the expiration of any appeal periods applicable to such DTE approval, or (y) if an appeal of such approval is filed within any such applicable appeal period, the issuance of a final ruling denying such appeal or resolving such appeal on terms acceptable to both parties (collectively, the “Cambridge Approvals”); (ii) notice of termination (the “FERC Notice”) of the Power

1

Execution Copy

Purchase Agreement is provided by Pittsfield to the Federal Energy Regulatory Commission (“FERC”) consistent with FERC’s requirements therefore and such FERC Notice becomes effective; (iii) Cambridge and Pittsfield shall have given (or been deemed to have given) notice that the Cambridge Approvals are acceptable pursuant to Section 2.2; and (iv) Cambridge and Pittsfield shall have given (or been deemed to have given) notice that the final order or other determination approving, disapproving or ruling in any way on the FERC Notice is acceptable pursuant to Section 2.3; provided, however, that notwithstanding satisfaction of the foregoing conditions, the Effective Date shall be no earlier than October 1, 2004. Notwithstanding the foregoing, this Agreement shall terminate and be of no further force or effect whatsoever (including, without limitation, the provisions of Sections 3, 4, and 5 hereof) as provided in Section 7.

2.2. No later than five (5) Business Days after the issuance by DTE or any appellate court or other judicial body with jurisdiction over the DTE, of any order or other determination approving, disapproving or ruling in any way on this Agreement, Cambridge shall provide Pittsfield with: (i) written notice of such order or determination including a copy thereof; and (ii) certification of an authorized officer of Cambridge as to whether such order or determination is reasonably acceptable to Cambridge. No later than five (5) Business Days after receipt of such notice and documentation, Pittsfield shall provide Cambridge with a certification of an authorized officer of Pittsfield as to whether such order or determination is reasonably acceptable to Pittsfield. Failure by either party to provide such written certification within five (5) Business Days of a written request by the other party shall constitute certification that such order or determination is reasonably acceptable to such party.

2.3 No later than five (5) Business Days after the issuance by FERC or any appellate court or other judicial body with jurisdiction over the FERC, of any order or other determination approving, disapproving or ruling in any way on the termination of the Power Purchase Agreement, Pittsfield shall provide Cambridge with: (i) written notice of such order or determination including a copy thereof any; and (ii) certification of an authorized officer of Pittsfield as to whether such order or determination is reasonably acceptable to Pittsfield. No later than five (5) Business Days after receipt of such notice and documentation, Cambridge shall provide Pittsfield with a certification of an authorized officer of Cambridge as to whether such order or determination is reasonably acceptable to Cambridge. Failure by either party to provide such written certification within five (5) Business Days of a written request by the other party shall constitute certification that such order or determination is reasonably acceptable to such party.

2

Execution Copy

3. Termination of Agreements.

3.1. Agreement to Terminate. Pittsfield and Cambridge hereby agree that, effective as of 12:00:01 am eastern time on the Effective Date, the Power Purchase Agreement shall be deemed terminated without any further action being required on the part of either Cambridge or Pittsfield, provided that Pittsfield has received confirmation of the transfer of the initial Termination Payment to be made pursuant to Section 4 of this Agreement. Upon such termination: (i) Cambridge shall have no obligation whatsoever under the Power Purchase Agreement, including, without limitation, any obligation to purchase or accept electric energy or capacity produced by the Facility, and (ii) Pittsfield shall have no obligation whatsoever under the Power Purchase Agreement, including, without limitation, any obligation to sell to Cambridge any electric energy or capacity produced by the Facility. Notwithstanding the preceding sentence and said termination of the Power Purchase Agreement: (a) Cambridge shall remain obligated to make payments to Pittsfield pursuant to the terms of the Power Purchase Agreement on account of any electric energy and capacity produced by the Facility and supplied to Cambridge at any time up to the Effective Date (“PPA Payments”), to the extent that any such amounts remain unpaid on the Effective Date; and (b) Pittsfield shall remain obligated to make any PPA Refunds. “PPA Refunds” shall be any amounts owed by Pittsfield to Cambridge pursuant to the terms of the Power Purchase Agreement on account of adjustments or reconciliations resulting from errors in measuring, or calculating charges for, energy or capacity delivered by Pittsfield to Cambridge at any time up to the Effective Date that Cambridge provides notice of no later than ninety (90) days after the Effective Date. Any disputes regarding PPA Payments and/or PPA Refunds shall be resolved pursuant to the terms of the Power Purchase Agreement. The parties agree to cooperate with each other in taking any and all actions that may be reasonably requested by the other in order to facilitate the approval of this Agreement by the DTE and, if this Agreement is approved by the DTE in for and substance acceptable to the parties, the termination of the Power Purchase Agreement.

3.2. Release of Liens. On the Effective Date, Cambridge shall release and discharge any and all mortgages, security interests, letters of credit and/or other liens (collectively, “Liens”) that it may have on or with respect to the Facility or Pittsfield, including without limitation: (a) the Agreement in Lieu of Second Mortgage dated as of March 20, 1992 among Cambridge, Pittsfield and certain other parties; (b) the Declaration of Easements, Covenants and Restrictions made by Pittsfield and the owner participant under Pittsfield’s lease financing dated March 20, 1992; and (c) the Accommodation Agreement dated as of March 20, 1992 among Pittsfield, Cambridge and certain other parties. Cambridge shall execute and deliver any and all documents and take any further actions that Pittsfield may reasonably request in order to effectively release and discharge all of such Liens.

3

Execution Copy

4. Payments by Cambridge.

4.1 Termination Payments. For and in consideration of Pittsfield’s agreement to terminate the Power Purchase Agreement, Cambridge shall pay, and hereby promises to pay, to the order of Pittsfield the following monthly payment amounts (collectively, the “Termination Payments”, and individually, each monthly payment a “Termination Payment”); provided that the first Termination Payment shall be due on the Effective Date and shall be equal to (x) the monthly payment amount owed for the month in which the Effective Date occurs multiplied by (y) a fraction, the numerator of which is the number of days remaining in such month (including the Effective Date) and the denominator of which is the number of days in such month.

Calendar Year During Which Termination Payment is Owed	Termination Payment Amount
2004
2005
2006
2007
2008

After the Effective Date, Cambridge shall make Termination Payments on the first Business Day of each calendar month beginning with the month following the month in which the Effective Date occurs and continuing through and including December 1, 2008. Each Termination Payment shall be made by wire transfer to an account designated in writing from time to time by Pittsfield.

4.2 Unconditional Obligation. Cambridge’s obligations to make each Termination Payment when due under this Agreement are subject to the terms and conditions set forth in this Agreement and are otherwise absolute, unconditional and irrevocable and are not subject to cancellation, termination, modification, repudiation, excuse or substitution by Cambridge. Cambridge is not entitled to any abatement, reduction, offset, defense or counterclaim with respect to the obligations to make each Termination Payment when due under this Agreement for any reason whatsoever.

4.3 PPA Payments. Cambridge shall pay Pittsfield for: (a) all energy delivered up to the Effective Date; and (b) any other charges owed by Cambridge pursuant to the Power Purchase Agreement with respect to the month in which the Effective Date occurs, which charges shall be prorated based on the number of days in such month during which the Purchase Power Agreement was in effect.

5. Releases.

5.1. Releases by Cambridge. Effective as of midnight on the Effective Date, Cambridge, for itself, its successors and assigns, hereby releases and forever discharges Pittsfield, the general and limited partners of Pittsfield, all of the officers, directors, employees and agents of Pittsfield and all of the partners, officers, directors, employees

4

Execution Copy

and agents of the general or limited partners of Pittsfield (collectively, for purposes of this Section 5.1, the “Pittsfield Released Parties”) from any and all claims, demands, actions, causes of action, accounts, covenants, contracts, torts, agreements, obligations, debts, suits, judgments, executions, sums, damages, or liabilities whatsoever in law or equity, whether known or unknown to Cambridge, which Cambridge, its successors and assigns ever had, now have or may ever have for, upon or by reason of any matter, cause, circumstance or fact whatsoever existing at any time from the beginning of the world to and including the Effective Date, against any and all of the Pittsfield Released Parties related to or arising under the Power Purchase Agreement; provided, however, that Cambridge does not hereby release Pittsfield from: (i) any of Pittsfield’s obligations under this Agreement; or (ii) any of Pittsfield’s obligations to pay PPA Refunds.

5.2. Release by Pittsfield. Effective as of midnight on the Effective Date, Pittsfield, for itself, its successors and assigns, hereby releases and forever discharges Cambridge and its officers, directors, employees and agents (collectively, for purposes of this Section 5.2, the “Cambridge Released Parties”) from any and all claims; demands, actions, causes of action, accounts, covenants, contracts, torts, agreements, obligations, debts, suits, judgments, executions, sums, damages, or liabilities whatsoever in law or equity, whether known or unknown to Pittsfield, which Pittsfield, its successors and assigns ever had, now have or may ever have for, upon or by reason of any matter, cause, circumstance or fact whatsoever existing at any time from the beginning of the world to and including the Effective Date, against any and all of the Cambridge Released Parties related to or arising under the Power Purchase Agreement; provided, however, that Pittsfield does not hereby release Cambridge from: (i) any of Cambridge’s obligations under this Agreement; or (ii) any of Cambridge’s obligations to pay PPA Payments.

6. Consent of Regulatory Bodies.

6.1 Consent of the DTE. Cambridge shall: (i) within thirty (30) days of the date of this Agreement file a copy of this Agreement with the DTE together with a request for approval of the same; (ii) exercise all commercially reasonable efforts to obtain an expedited review by the DTE of this Agreement and the termination of the Power Purchase Agreement pursuant hereto; and (iii) exercise all commercially reasonable efforts to secure the DTE’s approval of this Agreement, the termination of the Power Purchase Agreement, and the full recovery of the Termination Payments through Cambridge’s Transition Charge. Cambridge agrees to provide Pittsfield with a draft of the proposed request for approval of this Agreement to be filed with the DTE at least five (5) days prior to its submission to the DTE, to consider modifications to such request that are suggested by Pittsfield, and to generally consult with Pittsfield prior to filing such request; provided that the draft provided Cambridge may exclude: (a) competitive, proprietary or confidential information relating to other power purchase agreements; and (b) information relating to the Power Purchase Agreement which is being submitted to the DTE on a confidential basis. Pittsfield hereby agrees to diligently cooperate with, to not oppose or protest, and to use all commercially reasonable efforts to assist Cambridge with respect to the Cambridge Approvals, said cooperation and commercially reasonable efforts to include, without limitation: (i) providing any information or supporting

5

Execution Copy

documentation as may be reasonably required to establish to the satisfaction of the DTE that the payment to be made hereunder is reasonable and prudent; and (ii) making its employees or agents reasonably available for any appearance before the DTE that may be required by the DTE.

6.2 Notice to FERC. Pittsfield shall: (i) within thirty (30) days of the date of this Agreement, file the FERC Notice in accordance with FERC regulations and procedures; and (ii) exercise all commercially reasonable efforts to secure that FERC deems such notice effective as of the earliest date feasible. Pittsfield agrees to provide Cambridge with a draft of the proposed FERC Notice at least five (5) days prior to its submission to the FERC, to consider modifications to such FERC Notice that are suggested by Cambridge, and to generally consult with Cambridge prior to filing such notice. Cambridge hereby agrees to diligently cooperate with, to not oppose or protest, and to use all commercially reasonable efforts to assist Pittsfield with respect to the FERC Notice, said cooperation and commercially reasonable efforts to include, without limitation, providing any information or supporting documentation as may be reasonably required by Pittsfield.

7. Termination; Remedies.

7.1 Pittsfield may terminate this Agreement on written notice to Cambridge if the Effective Date has not occurred by January 3, 2005.

7.2 Cambridge may terminate this Agreement on written notice to Pittsfield if, despite Cambridge’s compliance with Section 6, the Effective Date has not occurred by January 3, 2005.

7.3 Upon any termination under Section 7.1 or 7.2: (i) this Agreement shall terminate and be of no further force or effect whatsoever (including, without limitation, the provisions of Sections 3, 4, and 5 hereof); and (ii) each of the Power Purchase Agreement, and the Liens shall continue in full force and effect and shall remain the valid and binding obligation of each party thereto enforceable against each such party in accordance with their terms.

7.4 Without limiting other remedies available to Pittsfield or Cambridge, if Cambridge fails to make any Termination Payment or other payments required pursuant to this Agreement, as and when such payments are due in accordance with the terms hereof interest shall accrue on any such unpaid amounts at an annual rate of interest equal to the prime rate of interest on commercial loans then in effect at Bank of America plus six hundred (600) basis points, compounded daily. In addition, to the extent any such amounts remain unpaid for a period of ten (10) Business Days following notice of such failure by Pittsfield, Cambridge shall be obligated to post security in the form of a segregated cash collateral account or a letter of credit in form and substance and held by an agent or issued by an issuer, as applicable, reasonably acceptable to Pittsfield, in an amount equal to two (2) Termination Payments (            ). Such security shall be available for drawing by Pittsfield in an amount or amounts equal to overdue sums

6

Execution Copy

(including interest thereon) owed by Cambridge; provided that in the event Pittsfield makes a drawing of any such security as permitted hereunder, Cambridge shall replenish the amount of such security to the value specified above. In addition, if Pittsfield incurs any costs (including but not limited to internal costs and attorneys’ fees) in order to collect overdue amounts owed hereunder (other than PPA Payments) or to enforce its right to obtain security as provided herein, Cambridge shall reimburse Pittsfield for any reasonable costs incurred in connection with such collection efforts no later than ten (10) days after submission by Pittsfield of any invoice accompanied by reasonable supporting documentation.

8. Facility Status. After the Effective Date, Pittsfield, at its sole discretion, may sell, modify, close, or utilize the Facility for sales to others.

9. Stay. As of the date of this Agreement, any and all notices of any breaches, events of default or disputes under the Power Purchase Agreement shall be stayed, without prejudice. The parties agree further not to submit any such notices unless and until this Agreement is terminated. Nothing contained herein shall prejudice either party’s right to pursue any claim(s) arising after the date of this Agreement for PPA Payments or PPA Refunds, or any claim so stayed to the extent this Agreement is terminated.

10. Representations and Warranties.

10.1 Cambridge’s Representations and Warranties. Cambridge represents and warrants to Pittsfield that:

(A) It has all requisite power and authority (including full corporate power and legal authority) to execute and deliver this Agreement, and subject to receipt of the Cambridge Approvals, to perform its obligations hereunder;

(B) All necessary action has been taken to authorize the execution, delivery and performance by Cambridge of this Agreement and this Agreement constitutes the valid, legal, and binding commitment of Cambridge and is fully enforceable against Cambridge in accordance with the terms hereof;

(C) Cambridge’s execution, delivery, and performance of this Agreement have been duly authorized by or are in accordance with its corporate charter, bylaws, and other organizational documents and constitutes Cambridge’s legal, valid, and binding 5 obligation;

(D) The person executing this Agreement is duly authorized to do so by Cambridge’s governing body;

7

Execution Copy

(E) There is no action, suit or proceeding, at law or in equity, nor is there any official investigation pending or, to the best of Cambridge’s knowledge, threatened against Cambridge wherein an unfavorable decision, ruling or finding would adversely affect the performance by Cambridge of its obligations hereunder or which, in any way, calls into question or may adversely and materially affect the validity or enforceability of this Agreement;

(F) Subject to Cambridge’s obtaining the Cambridge Approvals and Pittsfield’s proper filing of the FERC Notice, neither the execution or delivery of this Agreement nor performance by Cambridge of the transactions contemplated hereby will: (1) conflict with or violate any provision of Cambridge’s corporate charter or bylaws; or (2) conflict with, violate or result in a breach of any duty under any applicable constitution, law, judgment, regulation, or order of any governmental authority;

(G) Except for the Cambridge Approvals and FERC Notice, no approval, authorization, order or consent of, or declaration, registration or filing with any governmental authority is required for the valid execution, delivery and performance of this Agreement by Cambridge; and

(H) Cambridge’s execution, delivery and performance of this Agreement will not result in a breach or violation of, or constitute a default under, any agreement, lease, or instrument to which it is a party or by which it is bound as of the date hereof.

10.2 Pittsfield’s Representations and Warranties. Pittsfield represents and warrants to Cambridge that:

(A) It has all requisite power and authority (including full corporate power and legal authority) to execute and deliver this Agreement, and, subject to the effectiveness of the FERC Notice, to perform its obligations hereunder;

(B) All necessary action has been taken to authorize the execution, delivery and performance by Pittsfield of this Agreement and this Agreement constitutes the valid, legal, and binding commitment of Pittsfield and is fully enforceable against Pittsfield in accordance with the terms hereof;

(C) Pittsfield’s execution, delivery, and performance of this Agreement have been duly authorized by or are in accordance with its corporate charter, bylaws, and other organizational documents and constitutes Pittsfield’s legal, valid, and binding obligation;

8

Execution Copy

(D) The person executing this Agreement is duly authorized to do so by Pittsfield’s governing body;

(E) There is no action, suit or proceeding, at law or in equity, nor is there any official investigation pending or, to the best of Pittsfield’s knowledge, threatened against Pittsfield wherein an unfavorable decision, ruling or finding would adversely affect the performance by Pittsfield of its obligations hereunder or which, in any way, calls into question or may adversely and materially affect the validity or enforceability of this Agreement;

(F) Neither the execution or delivery of this Agreement nor performance by Pittsfield of the transactions contemplated hereby will: (1) conflict with or violate any provision of Pittsfield’s corporate charter or bylaws; or (2) conflict with, violate or result in a breach of any duty under any applicable constitution, law, judgment, regulation, or order of any governmental authority;

(G) No approval, authorization, order or consent of, or declaration, registration or filing with any governmental authority is required for the valid execution, delivery and performance of this Agreement by Pittsfield, except for the filing of the FERC Notice; and

(H) Pittsfield’s execution, delivery and performance of this Agreement will not result in a breach or violation of, or constitute a default under, any agreement, lease, or instrument to which it is a party or by which it is bound as of the date hereof.

11. Miscellaneous.

11.1. No Waiver. No failure on the part of any party to exercise, and no delay in exercising, any right, remedy or power hereunder shall operate as a waiver thereof, nor shall any single or partial exercise by any party of any right, remedy or power hereunder preclude any other or future exercise of any other right, remedy or power.

11.2. Severability. In the event any provision of this Agreement that is not material shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not effect any other term or provision hereof.

11.3. Entire Agreement; Amendment. This Agreement contains the entire understanding of the parties, supersedes all prior agreements and understandings relating to the subject matter hereof, and shall not be amended, modified or terminated except by a written instrument hereafter signed by all of the parties hereto.

9

Execution Copy

11.4. Sections and Section Headings. The headings of any of the sections and subsections are for reference only and shall not limit or control the meaning thereof.

11.5. Governing Law. The validity and construction of this Agreement shall be governed by the internal laws (and not the choice-of-law rules) of the Commonwealth of Massachusetts.

11.6 Binding Effect; Assignment. All terms of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the respective successors and assigns of the parties hereto. Neither party shall have the right to assign this Agreement or any right, obligation or privilege hereunder without first obtaining the consent of the other party hereto; provided that: (i) Pittsfield shall have the right to assign its right to receive the Termination Payments, provided that any such assignee shall confirm in writing that it is taking such assignment subject to the terms of this Agreement; (ii) Pittsfield shall have the right to assign this Agreement at any time after the deadline for Cambridge to claim any PPA Refunds shall have expired and either: (a) Cambridge shall not have claimed any PPA Refunds, (b) Pittsfield shall have paid all PPA Refunds claimed by Cambridge or determined to be owed to Cambridge; or (c) Pittsfield shall have posted an irrevocable letter of credit in favor of Cambridge, and in form and substance reasonably acceptable to Cambridge, in the amount of any PPA Refunds claimed by Cambridge; and (iii) Cambridge shall have the right to assign this Agreement to a wholly-owned subsidiary of NSTAR that is a regulated utility with a credit rating on its senior unsecured non-credit enhanced long-term debt of “A” or better as determined by Standard & Poor’s.

11.7. Notices. All notices, demands and other communications hereunder shall be in writing and shall be delivered personally, mailed by certified mail, return receipt requested, postage prepaid, or sent by certified overnight courier (e.g., Federal Express) to the following addresses or to such other addresses as any party may specify by notice to the other party given pursuant hereto:

If to Pittsfield, to:

Pittsfield Generating Company, L.P.

c/o PE-Pittsfield, L.L.C.

1732 West Genesee Street

Syracuse, NY 13204

Attention: Donald W. Scholl

If to Cambridge, to:

Cambridge Electric Light Company

One NSTAR Way

Westwood, MA 02090

Attention: Ellen Angley, Vice President Energy Supply and Transmission

10

Execution Copy

Any notice hereunder shall be deemed given when received by the intended recipient.

11.8. Counterparts. This Agreement and any amendment hereof may be executed in several counterparts and by each party on a separate counterpart, each of which when so executed and delivered shall be an original, but all of which together shall constitute one instrument. In proving this Agreement it shall not be necessary to produce or account for more than one such counterpart signed by the party against whom enforcement is sought.

IN WITNESS WHEREOF, and intending to be legally bound hereby, the parties hereto have caused this Agreement to be duly executed as an instrument under seal by their respective duly authorized officers as of the date and year first above written.

PITTSFIELD GENERATING COMPANY, L.P.
By:	PE-Pittsfield, LLC, its General Partner
	/s/ Jack E. Wolf
	Jack E. Wolf Vice-President
CAMBRIDGE ELECTRIC LIGHT COMPANY
By
	Ellen K. Angley
	Vice President Energy Supply and Transmission

11

EX-10.25

EXHIBIT 10.25

Execution Copy

TERMINATION AGREEMENT

This TERMINATION AGREEMENT (this “Agreement”) is entered into on the 2nd day of June, 2004, by and between COMMONWEALTH ELECTRIC COMPANY, a Massachusetts corporation having its principal place of business at 800 Boylston Street, Boston, Massachusetts 02199 (“Commonwealth”), and PITTSFIELD GENERATING COMPANY, L.P. (f/k/a Altresco Pittsfield, L.P.), a Delaware limited partnership with a principal place of business at 235 Merrill Road, Pittsfield, Massachusetts (“Pittsfield”).

W I T N E S S E T H:

WHEREAS, Commonwealth and Pittsfield are parties to that certain Power Sale Agreement, dated February 20, 1992, as amended by an Amendment to Power Sale Agreement dated as of November 7, 1994 and a Second Amendment to Power Purchase Agreement dated as of November 21, 1996 (as so amended, the “Power Purchase Agreement”), pursuant to which Pittsfield sells to Commonwealth, and Commonwealth purchases from Pittsfield, a seventeen and two-tenths per cent (17.2%) entitlement to the capacity and associated electric energy produced by Pittsfield’s facility situated in Pittsfield, Massachusetts (the “Facility”); and

WHEREAS, Pittsfield and Commonwealth desire to terminate the Power Purchase Agreement pursuant to, and in accordance with, the terms and provisions contained herein.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto hereby agree as follows:

1. Definitions. Capitalized terms used herein without definition shall have the respective meanings given to such terms in the Power Purchase Agreement. In addition, the term “Business Day” shall mean a day other than a Saturday, Sunday or any other day which is a legal holiday or a day on which banking institutions are authorized or required by law to close or be closed in Massachusetts.

2. Effectiveness.

2.1. The “Effective Date” shall be the third Business Day after the first date on which all of the following conditions have been satisfied: (i) approval by the Massachusetts Department of Telecommunications and Energy (“DTE”), in form and substance reasonably satisfactory to the parties, of (A) this Agreement, including but not limited to the termination of the Power Purchase Agreement pursuant to the terms hereof, and (B) the full recovery of the Termination Payments through Commonwealth’s Transition Charge (as defined under G.L. c. 164, Section 1G), and either (x) the expiration of any appeal periods applicable to such DTE approval, or (y) if an appeal of such approval is filed within any such applicable appeal period, the issuance of a final ruling denying such appeal or resolving such appeal on terms acceptable to both parties (collectively, the “Commonwealth Approvals”): (ii) notice of termination (the “FERC

1

Execution Copy

Notice”) of the Power Purchase Agreement is provided by Pittsfield to the Federal Energy Regulatory Commission (“FERC”) consistent with FERC’s requirements therefore and such FERC Notice becomes effective; (iii) Commonwealth and Pittsfield shall have given (or been deemed to have given) notice that the Commonwealth Approvals are acceptable pursuant to Section 2.2; and (iv) Commonwealth and Pittsfield shall have given (or been deemed to have given) notice that the final order or other determination approving, disapproving or ruling in any way on the FERC Notice is acceptable pursuant to Section 2.3; provided, however, that notwithstanding satisfaction of the foregoing conditions, the Effective Date shall be no earlier than October 1, 2004. Notwithstanding the foregoing, this Agreement shall terminate and be of no further force or effect whatsoever (including, without limitation, the provisions of Sections 3, 4, and 5 hereof) as provided in Section 7.

2.2. No later than five (5) Business Days after the issuance by DTE or any appellate court or other judicial body with jurisdiction over the DTE, of any order or other determination approving, disapproving or ruling in any way on this Agreement, Commonwealth shall provide Pittsfield with: (i) written notice of such order or determination including a copy thereof; and (ii) certification of an authorized officer of Commonwealth as to whether such order or determination is reasonably acceptable to Commonwealth. No later than five (5) Business Days after receipt of such notice and documentation, Pittsfield shall provide Commonwealth with a certification of an authorized officer of Pittsfield as to whether such order or determination is reasonably acceptable to Pittsfield. Failure by either party to provide such written certification within five (5) Business Days of a written request by the other party shall constitute certification that such order or determination is reasonably acceptable to such party.

2.3 No later than five (5) Business Days after the issuance by FERC or any appellate court or other judicial body with jurisdiction over the FERC, of any order or other determination approving, disapproving or ruling in any way on the termination of the Power Purchase Agreement, Pittsfield shall provide Commonwealth with: (i) written notice of such order or determination including a copy thereof any; and (ii) certification of an authorized officer of Pittsfield as to whether such order or determination is reasonably acceptable to Pittsfield. No later than five (5) Business Days after receipt of such notice and documentation, Commonwealth shall provide Pittsfield with a certification of an authorized officer of Commonwealth as to whether such order or determination is reasonably acceptable to Commonwealth. Failure by either party to provide such written certification within five (5) Business Days of a written request by the other party shall constitute certification that such order or determination is reasonably acceptable to such party.

2

Execution Copy

3. Termination of Agreements.

3.1. Agreement to Terminate. Pittsfield and Commonwealth hereby agree that, effective as of 12:00:01 am eastern time on the Effective Date, the Power Purchase Agreement shall be deemed terminated without any further action being required on the part of either Commonwealth or Pittsfield, provided that Pittsfield has received confirmation of the transfer of the initial Termination Payment to be made pursuant to Section 4 of this Agreement. Upon such termination: (i) Commonwealth shall have no obligation whatsoever under the Power Purchase Agreement, including, without limitation, any obligation to purchase or accept electric energy or capacity produced by the Facility, and (ii) Pittsfield shall have no obligation whatsoever under the Power Purchase Agreement, including, without limitation, any obligation to sell to Commonwealth any electric energy or capacity produced by the Facility. Notwithstanding the preceding sentence and said termination of the Power Purchase Agreement: (a) Commonwealth shall remain obligated to make payments to Pittsfield pursuant to the terms of the Power Purchase Agreement on account of any electric energy and capacity produced by the Facility and supplied to Commonwealth at any time up to the Effective Date (“PPA Payments”), to the extent that any such amounts remain unpaid on the Effective Date; and (b) Pittsfield shall remain obligated to make any PPA Refunds. “PPA Refunds” shall be any amounts owed by Pittsfield to Commonwealth pursuant to the terms of the Power Purchase Agreement on account of adjustments or reconciliations resulting from errors in measuring, or calculating charges for, energy or capacity delivered by Pittsfield to Commonwealth at any time up to the Effective Date that Commonwealth provides notice of no later than ninety (90) days after the Effective Date. Any disputes regarding PPA Payments and/or PPA Refunds shall be resolved pursuant to the terms of the Power Purchase Agreement. The parties agree to cooperate with each other in taking any and all actions that may be reasonably requested by the other in order to facilitate the approval of this Agreement by the DTE and, if this Agreement is approved by the DTE in for and substance acceptable to the parties, the termination of the Power Purchase Agreement.

3.2. Release of Liens. On the Effective Date, Commonwealth shall release and discharge any and all mortgages, security interests, letters of credit and/or other liens (collectively, “Liens”) that it may have on or with respect to the Facility or Pittsfield, including without limitation: (a) the Agreement in Lieu of Second Mortgage dated as of March 20, 1992 among Commonwealth, Pittsfield and certain other parties; (b) the Declaration of Easements, Covenants and Restrictions made by Pittsfield and the owner participant under Pittsfield’s lease financing dated March 20, 1992; and (c) the Accommodation Agreement dated as of March 20, 1992 among Pittsfield, Commonwealth and certain other parties. Commonwealth shall execute and deliver any and all documents and take any further actions that Pittsfield may reasonably request in order to effectively release and discharge all of such Liens.

3

Execution Copy

4. Payments by Commonwealth.

4.1 Termination Payments. For and in consideration of Pittsfield’s agreement to terminate the Power Purchase Agreement, Commonwealth shall pay, and hereby promises to pay, to the order of Pittsfield the following monthly payment amounts (collectively, the “Termination Payments”, and individually, each monthly payment a “Termination Payment”); provided that the first Termination Payment shall be due on the Effective Date and shall be equal to (x) the monthly payment amount owed for the month in which the Effective Date occurs multiplied by (y) a fraction, the numerator of which is the number of days remaining in such month (including the Effective Date) and the denominator of which is the number of days in such month.

Calendar Year During Which Termination Payment is Owed	Termination Payment Amount
2004
2005
2006
2007
2008

After the Effective Date, Commonwealth shall make Termination Payments on the first Business Day of each calendar month beginning with the month following the month in which the Effective Date occurs and continuing through and including December 1, 2008. Each Termination Payment shall be made by wire transfer to an account designated in writing from time to time by Pittsfield.

4.2 Unconditional Obligation. Commonwealth’s obligations to make each Termination Payment when due under this Agreement are subject to the terms and conditions set forth in this Agreement and are otherwise absolute, unconditional and irrevocable and are not subject to cancellation, termination, modification, repudiation, excuse or substitution by Commonwealth. Commonwealth is not entitled to any abatement, reduction, offset, defense or counterclaim with respect to the obligations to make each Termination Payment when due under this Agreement for any reason whatsoever.

4.3 PPA Payments. Commonwealth shall pay Pittsfield for: (a) all energy delivered up to the Effective Date; and (b) any other charges owed by Commonwealth pursuant to the Power Purchase Agreement with respect to the month in which the Effective Date occurs, which charges shall be prorated based on the number of days in such month during which the Purchase Power Agreement was in effect.

5. Releases.

5.1. Releases by Commonwealth. Effective as of midnight on the Effective Date, Commonwealth, for itself, its successors and assigns, hereby releases and forever discharges Pittsfield, the general and limited partners of Pittsfield, all of the officers,

4

Execution Copy

directors, employees and agents of Pittsfield and all of the partners, officers, directors, employees and agents of the general or limited partners of Pittsfield (collectively, for purposes of this Section 5.1, the “Pittsfield Released Parties”) from any and all claims, demands, actions, causes of action, accounts, covenants, contracts, torts, agreements, obligations, debts, suits, judgments, executions, sums, damages, or liabilities whatsoever in law or equity, whether known or unknown to Commonwealth, which Commonwealth, its successors and assigns ever had, now have or may ever have for, upon or by reason of any matter, cause, circumstance or fact whatsoever existing at any time from the beginning of the world to and including the Effective Date, against any and all of the Pittsfield Released Parties related to or arising under the Power Purchase Agreement; provided, however, that Commonwealth does not hereby release Pittsfield from: (i) any of Pittsfield’s obligations under this Agreement; or (ii) any of Pittsfield’s obligations to pay PPA Refunds.

5.2. Release by Pittsfield. Effective as of midnight on the Effective Date, Pittsfield, for itself, its successors and assigns, hereby releases and forever discharges Commonwealth and its officers, directors, employees and agents (collectively, for purposes of this Section 5.2, the “Commonwealth Released Parties”) from any; and all claims; demands, actions, causes of action, accounts, covenants, contracts, torts, agreements, obligations, debts, suits, judgments, executions, sums, damages, or liabilities whatsoever in law or equity, whether known or unknown to Pittsfield, which Pittsfield, its successors and assigns ever had, now have or may ever have for, upon or by reason of any matter, cause, circumstance or fact whatsoever existing at any time from the beginning of the world to and including the Effective Date, against any and all of the Commonwealth Released Parties related to or arising under the Power Purchase Agreement; provided, however, that Pittsfield does not hereby release Commonwealth from: (i) any of Commonwealth’s obligations under this Agreement; or (ii) any of Commonwealth’s obligations to pay PPA Payments.

6. Consent of Regulatory Bodies.

6.1 Consent of the DTE. Commonwealth shall: (i) within thirty (30) days of the date of this Agreement file a copy of this Agreement with the DTE together with a request for approval of the same; (ii) exercise all commercially reasonable efforts to obtain an expedited review by the DTE of this Agreement and the termination of the Power Purchase Agreement pursuant hereto; and (iii) exercise all commercially reasonable efforts to secure the DTE’s approval of this Agreement, the termination of the Power Purchase Agreement, and the full recovery of the Termination Payments through Commonwealth’s Transition Charge. Commonwealth agrees to provide Pittsfield with a draft of the proposed request for approval of this Agreement to be filed with the DTE at least five (5) days prior to its submission to the DTE, to consider modifications to such request that are suggested by Pittsfield, and to generally consult with Pittsfield prior to filing such request; provided that the draft provided Commonwealth may exclude: (a) competitive, proprietary or confidential information relating to other power purchase agreements; and (b) information relating to the Power Purchase Agreement which is being submitted to the DTE on a confidential basis. Pittsfield hereby agrees to diligently

5

Execution Copy

cooperate with, to not oppose or protest, and to use all commercially reasonable efforts to assist Commonwealth with respect to the Commonwealth Approvals, said cooperation and commercially reasonable efforts to include, without limitation: (i) providing any information or supporting documentation as may be reasonably required to establish to the satisfaction of the DTE that the payment to be made hereunder is reasonable and prudent; and (ii) making its employees or agents reasonably available for any appearance before the DTE that may be required by the DTE.

6.2 Notice to FERC. Pittsfield shall: (i) within thirty (30) days of the date of this Agreement, file the FERC Notice in accordance with FERC regulations and procedures; and (ii) exercise all commercially reasonable efforts to secure that FERC deems such notice effective as of the earliest date feasible. Pittsfield agrees to provide Commonwealth with a draft of the proposed FERC Notice at least five (5) days prior to its submission to the FERC, to consider modifications to such FERC Notice that are suggested by Commonwealth, and to generally consult with Commonwealth prior to filing such notice. Commonwealth hereby agrees to diligently cooperate with, to not oppose or protest, and to use all commercially reasonable efforts to assist Pittsfield with respect to the FERC Notice, said cooperation and commercially reasonable efforts to include, without limitation, providing any information or supporting documentation as may be reasonably required by Pittsfield.

7. Termination; Remedies.

7.1 Pittsfield may terminate this Agreement on written notice to Commonwealth if the Effective Date has not occurred by January 3, 2005.

7.2 Commonwealth may terminate this Agreement on written notice to Pittsfield if, despite Commonwealth’s compliance with Section 6, the Effective Date has not occurred by January 3, 2005.

7.3 Upon any termination under Section 7.1 or 7.2: (i) this Agreement shall terminate and be of no further force or effect whatsoever (including, without limitation, the provisions of Sections 3, 4, and 5 hereof); and (ii) each of the Power Purchase Agreement, and the Liens shall continue in full force and effect and shall remain the valid and binding obligation of each party thereto enforceable against each such party in accordance with their terms.

7.4 Without limiting other remedies available to Pittsfield or Commonwealth, if Commonwealth fails to make any Termination Payment or other payments required pursuant to this Agreement, as and when such payments are due in accordance with the terms hereof interest shall accrue on any such unpaid amounts at an annual rate of interest equal to the prime rate of interest on commercial loans then in effect at Bank of America plus six hundred (600) basis points, compounded daily. In addition, to the extent any such amounts remain unpaid for a period of ten (10) Business Days following notice of such failure by Pittsfield, Commonwealth shall be obligated to post security in the form of a segregated cash collateral account or a letter of credit in form and substance and held

6

Execution Copy

by an agent or issued by an issuer, as applicable, reasonably acceptable to Pittsfield, in an amount equal to two (2) Termination Payments             . Such security shall be available for drawing by Pittsfield in an amount or amounts equal to overdue sums (including interest thereon) owed by Commonwealth; provided that in the event Pittsfield makes a drawing of any such security as permitted hereunder, Commonwealth shall replenish the amount of such security to the value specified above. In addition, if Pittsfield incurs any costs (including but not limited to internal costs and attorneys’ fees) in order to collect overdue amounts owed hereunder (other than PPA Payments) or to enforce its right to obtain security as provided herein, Commonwealth shall reimburse Pittsfield for any reasonable costs incurred in connection with such collection efforts no later than ten (10) days after submission by Pittsfield of any invoice accompanied by reasonable supporting documentation.

8. Facility Status. After the Effective Date, Pittsfield, at its sole discretion, may sell, modify, close, or utilize the Facility for sales to others.

9. Stay. As of the date of this Agreement, any and all notices of any breaches, events of default or disputes under the Power Purchase Agreement shall be stayed, without prejudice. The parties agree further not to submit any such notices unless and until this Agreement is terminated. Nothing contained herein shall prejudice either party’s right to pursue any claim(s) arising after the date of this Agreement for PPA Payments or PPA Refunds, or any claim so stayed to the extent this Agreement is terminated.

10. Representations and Warranties.

10.1 Commonwealth’s Representations and Warranties. Commonwealth represents and warrants to Pittsfield that:

(A) It has all requisite power and authority (including full corporate power and legal authority) to execute and deliver this Agreement, and subject to receipt of the Commonwealth Approvals, to perform its obligations hereunder;

(B) All necessary action has been taken to authorize the execution, delivery and performance by Commonwealth of this Agreement and this Agreement constitutes the valid, legal, and binding commitment of Commonwealth and is fully enforceable against Commonwealth in accordance with the terms hereof;

(C) Commonwealth’s execution, delivery, and performance of this Agreement have been duly authorized by or are in accordance with its corporate charter, bylaws, and other organizational documents and constitutes Commonwealth’s legal, valid, and binding obligation;

7

Execution Copy

(D) The person executing this Agreement is duly authorized to do so by Commonwealth’s governing body;

(E) There is no action, suit or proceeding, at law or in equity, nor is there any official investigation pending or, to the best of Commonwealth’s knowledge, threatened against Commonwealth wherein an unfavorable decision, ruling or finding would adversely affect the performance by Commonwealth of its obligations hereunder or which, in any way, calls into question or may adversely and materially affect the validity or enforceability of this Agreement;

(F) Subject to Commonwealth’s obtaining the Commonwealth Approvals and Pittsfield’s proper filing of the FERC Notice, neither the execution or delivery of this Agreement nor performance by Commonwealth of the transactions contemplated hereby will: (1) conflict with or violate any provision of Commonwealth’s corporate charter or bylaws; or (2) conflict with, violate or result in a breach of any duty under any applicable constitution, law, judgment, regulation, or order of any governmental authority;

(G) Except for the Commonwealth Approvals and FERC Notice, no approval, authorization, order or consent of, or declaration, registration or filing with any governmental authority is required for the valid execution, delivery and performance of this Agreement by Commonwealth; and

(H) Commonwealth’s execution, delivery and performance of this Agreement will not result in a breach or violation of, or constitute a default under, any agreement, lease, or instrument to which it is a party or by which it is bound as of the date hereof.

10.2 Pittsfield’s Representations and Warranties. Pittsfield represents and warrants to Commonwealth that:

(A) It has all requisite power and authority (including full corporate power and legal authority) to execute and deliver this Agreement, and, subject to the effectiveness of the FERC Notice, to perform its obligations hereunder;

(B) All necessary action has been taken to authorize the execution, delivery and performance by Pittsfield of this Agreement and this Agreement constitutes the valid, legal, and binding commitment of Pittsfield and is fully enforceable against Pittsfield in accordance with the terms hereof;

8

Execution Copy

(C) Pittsfield’s execution, delivery, and performance of this Agreement have been duly authorized by or are in accordance with its corporate charter, bylaws, and other organizational documents and constitutes Pittsfield’s legal, valid, and binding obligation;

(D) The person executing this Agreement is duly authorized to do so by Pittsfield’s governing body;

(E) There is no action, suit or proceeding, at law or in equity, nor is there any official investigation pending or, to the best of Pittsfield’s knowledge, threatened against Pittsfield wherein an unfavorable decision, ruling or finding would adversely affect the performance by Pittsfield of its obligations hereunder or which, in any way, calls into question or may adversely and materially affect the validity or enforceability of this Agreement;

(F) Neither the execution or delivery of this Agreement nor performance by Pittsfield of the transactions contemplated hereby will: (1) conflict with or violate any provision of Pittsfield’s corporate charter or bylaws; or (2) conflict with, violate or result in a breach of any duty under any applicable constitution, law, judgment, regulation, or order of any governmental authority;

(G) No approval, authorization, order or consent of, or declaration, registration or filing with any governmental authority is required for the valid execution, delivery and performance of this Agreement by Pittsfield, except for the filing of the FERC Notice; and

(H) Pittsfield’s execution, delivery and performance of this Agreement will not result in a breach or violation of, or constitute a default under, any agreement, lease, or instrument to which it is a party or by which it is bound as of the date hereof.

11. Miscellaneous.

11.1. No Waiver. No failure on the part of any party to exercise, and no delay in exercising, any right, remedy or power hereunder shall operate as a waiver thereof, nor shall any single or partial exercise by any party of any right, remedy or power hereunder preclude any other or future exercise of any other right, remedy or power.

11.2. Severability. In the event any provision of this Agreement that is not material shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not effect any other term or provision hereof.

9

Execution Copy

11.3. Entire Agreement; Amendment. This Agreement contains the entire understanding of the parties, supersedes all prior agreements and understandings relating to the subject matter hereof, and shall not be amended, modified or terminated except by a written instrument hereafter signed by all of the parties hereto.

11.4. Sections and Section Headings. The headings of any of the sections and subsections are for reference only and shall not limit or control the meaning thereof.

11.5. Governing Law. The validity and construction of this Agreement shall be governed by the internal laws (and not the choice-of-law rules) of the Commonwealth of Massachusetts.

11.6 Binding Effect; Assignment. All terms of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the respective successors and assigns of the parties hereto. Neither party shall have the right to assign this Agreement or any right, obligation or privilege hereunder without first obtaining the consent of the other party hereto; provided that: (i) Pittsfield shall have the right to assign its right to receive the Termination Payments, provided that any such assignee shall confirm in writing that it is taking such assignment subject to the terms of this Agreement; (ii) Pittsfield shall have the right to assign this Agreement at any time after the deadline for Commonwealth to claim any PPA Refunds shall have expired and either: (a) Commonwealth shall not have claimed any PPA Refunds, (b) Pittsfield shall have paid all PPA Refunds claimed by Commonwealth or determined to be owed to Commonwealth; or (c) Pittsfield shall have posted an irrevocable letter of credit in favor of Commonwealth, and in form and substance reasonably acceptable to Commonwealth, in the amount of any PPA Refunds claimed by Commonwealth; and (iii) Commonwealth shall have the right to assign this Agreement to a wholly-owned subsidiary of NSTAR that is a regulated utility with a credit rating on its senior unsecured non-credit enhanced long-term debt of “A” or better as determined by Standard & Poor’s.

11.7. Notices. All notices, demands and other communications hereunder shall be in writing and shall be delivered personally, mailed by certified mail, return receipt requested, postage prepaid, or sent by certified overnight courier (e.g., Federal Express) to the following addresses or to such other addresses as any party may specify by notice to the other party given pursuant hereto:

If to Pittsfield, to:

Pittsfield Generating Company, L.P.

c/o PE-Pittsfield, L.L.C.

1732 West Genesee Street

Syracuse, NY 13204

Attention: Donald W. Scholl

10

Execution Copy

If to Commonwealth, to:

Commonwealth Electric Company

One NSTAR Way

Westwood, MA 02090

Attention: Ellen Angley, Vice President Energy Supply and Transmission

Any notice hereunder shall be deemed given when received by the intended recipient.

11.8. Counterparts. This Agreement and any amendment hereof may be executed in several counterparts and by each party on a separate counterpart, each of which when so executed and delivered shall be an original, but all of which together shall constitute one instrument. In proving this Agreement it shall not be necessary to produce or account for more than one such counterpart signed by the party against whom enforcement is sought.

IN WITNESS WHEREOF, and intending to be legally bound hereby, the parties hereto have caused this Agreement to be duly executed as an instrument under seal by their respective duly authorized officers as of the date and year first above written.

PITTSFIELD GENERATING COMPANY, L.P.
By:	PE-Pittsfield, LLC, its General Partner
	/s/ Jack E. Wolf
	Jack E. Wolf Vice-President
COMMONWEALTH ELECTRIC COMPANY
By
	Ellen K. Angley
	Vice President Energy Supply and Transmission

11

EX-10.2.1.1

Exhibit 10.2.1.1

NEW ENGLAND POWER POOL

SECOND RESTATED NEPOOL AGREEMENT

New England Power Pool	Sheet No. 1
Second Restated NEPOOL Agreement
Table of Contents

SECTION 1	DEFINITIONS	6
1.1	Adjusted Sector Voting Share	6
1.2	Adjusted Sub-Sector Voting Share	7
1.3	Agreement	7
1.4	Alternative Resources or AR	7
1.5	Alternative Resources Sector or AR Sector	7
1.6	AR Provider	7
1.7	AR Sector Voting Share	8
1.8	AR Sub-Sector	8
1.9	AR Sub-Sector Quorum Requirement	9
1.10	Balloting Agent	9
1.11	Business Day	9
1.12	Commission	9
1.13	Control Area	9
1.14	Demand Response Resource	9
1.15	Distributed Generation Resource	10
1.16	Distributed Generation Resource Provider	10
1.17	Distributed Generation Sub-Sector	10
1.18	DRP	10
1.19	DRP Group Member	10
1.20	Effective Date	10
1.21	End User Organization	10
1.22	End User Participant	10
1.23	End User Sector	11
1.24	Energy	11
1.25	Energy Efficiency Resource	11
1.26	Entity	11
1.27	First Restated NEPOOL Agreement	11
1.28	Fully Activated Sub-Sector Voting Share	11
1.29	Generation Sector	12
1.30	Good Utility Practice	12
1.31	Governance Load	12
1.32	Governance Only End User Behind-the-Meter Generation	12
1.33	Governance Only Member	12
1.34	Governance Rating	13
1.35	Governance Transmission Owner	13
1.36	Individual RTO Participants	13
1.37	Information Policy	13
1.38	ISO	13
1.39	ISO Operating Documents	13

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 2
Second Restated NEPOOL Agreement
Table of Contents

1.40	Large End User	14
1.41	Load Response Program	14
1.42	Load Response Resource	14
1.43	Load Response Resource Provider	14
1.44	Load Response Sub-Sector	14
1.45	Market Participant End User	14
1.46	Market Participant Service Agreement or MPSA	14
1.47	Market Rule 1	14
1.48	Market Rules	14
1.49	Markets Committee	14
1.50	Member Adjusted Voting Share	15
1.51	Member Fixed Voting Share	15
1.52	Minimum Response Requirement	16
1.53	NECPUC	16
1.54	NEPOOL	16
1.55	NEPOOL Vote	16
1.56	NERC	17
1.57	New England Control Area	17
1.58	New England Markets	17
1.59	New England Transmission System	17
1.60	Non-Participant	17
1.61	NPCC	17
1.62	Participant	17
1.63	Participant Expenses	17
1.64	Participants Agreement	17
1.65	Participants Committee	17
1.66	PTF or Pool Transmission Facilities	17
1.67	Power Year	17
1.68	Principal Committees	18
1.69	Publicly Owned Entity	18
1.70	Publicly Owned Entity Sector	18
1.71	PURPA	18
1.72	Related Person	18
1.73	Related Person Supplier	19
1.74	Reliability Committee	19
1.75	Renewable Generation Resource	19
1.76	Renewable Generation Resource Provider	19
1.77	Renewable Generation Sub-Sector	19
1.78	Review Board	19
1.79	Sector	19
1.80	Sector Quorum	20

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 3
Second Restated NEPOOL Agreement
Table of Contents

1.81	Sector Voting Share	20
1.82	Small End User	20
1.83	Sub-Sector Voting Share	20
1.84	Supplier Sector	20
1.85	System	20
1.86	System Operator	20
1.87	System Rules	20
1.88	Tariff	21
1.89	Technical Committees	21
1.90	Transmission Committee	21
1.91	Transmission Operating Agreement or TOA	21
1.92	Transmission Sector	21
1.93	Winter Capability	21
1.94	Winter Period	21
SECTION 2	PURPOSE; EFFECTIVE DATE	22
2.1	Purpose	22
2.2	Effective Date	22
SECTION 3	MEMBERSHIP	22
3.1	Membership	22
3.2	Lack of Place of Business in New England	23
SECTION 4	STATUS OF PARTICIPANTS	23
4.1	Treatment of Certain Entities as Single Participant	23
4.2	Participants to Retain Separate Identities	23
SECTION 5	OBJECTIVES AND COOPERATION	24
5.1	Objectives	24
5.2	Cooperation by Participants	24
SECTION 6	COMMITTEE ORGANIZATION AND VOTING	25
6.1	Principal Committees	25
6.2	Sector Representation	25
6.3	Appointment of Members and Alternates	30
6.4	Term of Members	30
6.5	Regular and Special Meetings	30
6.6	Notice of Meetings	30
6.7	Attendance	31
6.8	Quorum	31
6.9	Voting On Proposed Actions	31
6.10	Voting On Amendments	31

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 4
Second Restated NEPOOL Agreement
Table of Contents

6.11	Designated Representatives and Proxies	33
6.12	Limits on Representatives	33
6.13	Attendance of Participants at Principal Committee Meetings	33
6.14	Adoption of Bylaws	33
6.15	Joint Meetings of Technical Committees	33
6.16	Appointment of Technical Committee Officers	34
SECTION 7	PARTICIPANTS COMMITTEE	35
7.1	Officers	35
7.2	Adoption of Budgets	35
7.3	Appointment and Compensation of NEPOOL Personnel	35
7.4	Budget & Finance Subcommittee	35
7.5	Appeal of Actions to Review Board	35
SECTION 8	MARKETS COMMITTEE	36
8.1	Officers	36
8.2	Notice to Members and Alternates of Participants Committee	36
8.3	Appeal of Actions	36
8.4	Establishment of Subcommittees and Task Forces	36
SECTION 9	RELIABILITY COMMITTEE	37
9.1	Officers	37
9.2	Notice to Members and Alternates of Participants Committee	37
9.3	Appeal of Actions	37
9.4	Establishment of Subcommittees and Task Forces	37
SECTION 10	TRANSMISSION COMMITTEE	38
10.1	Officers	38
10.2	Notice to Members and Alternates of Participants Committee	38
10.3	Appeal of Actions	38
10.4	Establishment of Subcommittees and Task Forces	38
SECTION 11	REVIEW BOARD	39
11.1	Organization	39
11.2	Composition	39
11.3	Qualifications	39
11.4	Term	40
11.5	Meetings	40
11.6	Bylaws	40
11.7	Procedure on Appeal of Participant Committee Action or Failure to Take Action	40
11.8	Effect of a Review Board Decision	42

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 5
Second Restated NEPOOL Agreement
Table of Contents

11.9	Rights to Seek Further Review	42
SECTION 12	PUBLICLY OWNED ENTITIES	43
12.1	Capacity Obligations of Publicly Owned Entities	43
12.2	Central Dispatch of the Resources of Publicly Owned Entities	43
12.3	Market Transactions of Publicly-Owned Entities	43
12.4	Maintenance and Operation of Publicly Owned Entity Transmission
	Facilities in Accordance with Good Utility Practice	43
12.5	Central Dispatch of Publicly-Owned Entity Transmission Facilities	44
12.6	Maintenance and Repair of Publicly Owned Entity Transmission Facilities	44
12.7	Modification and Termination of Section 12	44
SECTION 13	[RESERVED]	44
SECTION 14	EXPENSES	45
14.1	Annual Fee	45
14.2	Participant Expenses	46
SECTION 15	RELATIONSHIPS WITH THE SYSTEM OPERATOR AND NEW ENGLAND STATE AUTHORITIES	49
15.1	Participants Agreement	49
15.2	New England State Authorities	49
SECTION 16	MISCELLANEOUS PROVISIONS	50
16.1	Payment of Pool Charges; Termination of Status as Participant	50
16.2	Assignment	51
16.3	Force Majeure	51
16.4	Waiver of Defaults	51
16.5	Other Contracts	52
16.6	Liability and Insurance	52
16.7	Records and Information	52
16.8	Construction	52
16.9	Amendment	53
16.10	Termination	53
16.11	Notices to Participants, Committees, or Committee Members	53
16.12	Severability and Renegotiation	55
16.13	No Third-Party Beneficiaries	55
16.14	Counterparts	55

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 6
Second Restated NEPOOL Agreement
Section 1 - Definitions

THIS AGREEMENT dated as of the first day of September, 1971, as amended, was entered into by the signatories thereto for the establishment by them of a bulk power pool to be known as NEPOOL and is restated for a second time by an amendment dated as of August 16, 2004 for the purposes set forth herein.

In consideration of the mutual agreements and undertakings herein, the signatories hereby agree as follows:

SECTION 1

DEFINITIONS

Whenever used in this Agreement, in either the singular or plural number, each of the following terms shall have the following respective meanings:

1.1 Adjusted Sector Voting Share applies only for votes of Technical Committees and shall be determined for each Technical Committee vote in accordance with the following formula:

         A = S + (S * [(100%-P)/P])

Where:

A is the Sector’s Adjusted Sector Voting Share.

S is (i) for each active Sector which has not satisfied its Sector Quorum requirements, the sum of the Member Fixed Voting Shares of the Sector members who vote on the proposed action, or on whose behalf a vote is properly cast, and (ii) for each active Sector which has satisfied its Sector Quorum requirements, that Sector’s Sector Voting Share.

P is the sum of (A) for each active Sector which has not satisfied its Sector Quorum requirements, the Member Fixed Voting Shares of the members who voted on the proposed action or on whose behalf a vote is properly cast and (B) the Sector Voting Shares of all Sectors which have satisfied their Sector Quorum requirements.

The aggregate Adjusted Sector Voting Share for each vote shall equal one hundred percent (100%).

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 7
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.2 Adjusted Sub-Sector Voting Share shall be determined for each Principal Committee vote in accordance with the following formula:

AVS = T + (T * [(AR Sector Voting Share %-Q)/Q])

Where:

AVS is an AR Sub-Sector’s Adjusted Voting Share.

T is (i) for each Sub-Sector which has not satisfied its AR Sub-Sector Quorum Requirement, the sum of the Member Fixed Voting Shares of the Sub-Sector members who vote on the proposed action, or on whose behalf a vote is properly cast, and (ii) for each Sub-Sector which has satisfied its AR Sub-Sector Quorum Requirement, that Sub-Sector’s Sub-Sector Voting Share.

Q is the sum of (A) for each Sub-Sector which has not satisfied its AR Sub-Sector Quorum Requirement, the Member Fixed Voting Shares of the Sub-Sector members who voted on the proposed action or on whose behalf a vote is properly cast and (B) the Sub-Sector Voting Shares of the AR Sub-Sectors which have satisfied their AR Sub-Sector Quorum Requirement.

The aggregate Adjusted Sub-Sector Voting Share for each vote shall equal the sum of the Member Fixed Voting Shares of the AR Sub-Sector voting members.

1.3 Agreement is this second restated contract and attachments as amended and restated from time to time.

1.4 Alternative Resources or AR are Renewable Generation Resources, Distributed Generation Resources, and Load Response Resources.

1.5 Alternative Resources Sector or AR Sector is the Sector established pursuant to Section 6.2(d) of this Agreement.

1.6 AR Provider is a Participant with a “Substantial Business Interest” in Alternative Resources located within the New England Control Area. For the purposes of this Agreement,

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 8
Second Restated NEPOOL Agreement
Section 1 - Definitions

(a) a Participant has a Substantial Business Interest in Alternative Resources if:

(i) either (A) the Participant owns or controls any Alternative Resource and at least 75% of its Energy resources within the New England Control Area are Alternative Resources; or (B) the Participant (1) owns or controls at least 50 MW (or its equivalent) of Alternative Resources within the New England Control Area or (2) has an independently verifiable capital investment in its Alternative Resources in the New England Control Area as of the end of the most recent calendar year of at least $30,000,000, regardless of the percentage of its business interests those Alternative Resources represent; and

(ii) either (A) the quantity of Alternative Resources (in megawatts) and other generation resources in the New England Control Area owned or controlled by the Participant exceeds the highest quantity of hourly Governance Load responsibility held by the Participant in the prior twelve (12) months; or (B) the quantity of generation (in megawatt hours) in the past twelve months from Alternative Resources and other generation resources in the New England Control Area that the Participant owns or controls exceeds the total quantity of Governance Load responsibility held by the Participant in the prior twelve months; or (C) the Participant has not held any Governance Load responsibility in the prior twelve (12) months but otherwise meets one of the tests set forth in (i)(A) or (i)(B) above.

(b) the only Alternative Resources that shall be taken into account for purposes of determining whether an Entity qualifies as an AR Provider are (i) those generating resources that are within the New England Control Area that are (A) currently in operation, (B) under construction, or (C) proposed for operation as generation and that have received approvals under Sections 18.4 and/or 18.5 of the First Restated NEPOOL Agreement between July 1, 2002 and the Effective Date or received approvals on or after the Effective Date under Sections I.3.9 and/or I.3.10 of the Tariff or for which completed environmental air or environmental siting applications have been filed or permits exist; or (ii) Demand Response Resources that are enrolled in the Load Response Program and have not been inactive in that Program for a period exceeding six (6) months; or (iii) Energy Efficiency Resources that have not been inactive in an Energy efficiency program of a New England state for a period exceeding six (6) months.

1.7 AR Sector Voting Share is the sum of the Sub-Sector Voting Shares of the AR Sub-Sectors.

1.8 AR Sub-Sector is the Renewable Generation Sub-Sector, Distributed Generation Sub-Sector, or the Load Response Sub-Sector of the AR Sector created pursuant to the terms of this Agreement.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 9
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.9 AR Sub-Sector Quorum Requirement for an AR Sub-Sector shall be the lesser of (i) fifty percent (50%) or more (rounded to the next higher whole number) of the voting members of the Sub-Sector, or (ii) five (5) or more voting members of the Sub-Sector for the Participants Committee or three (3) or more voting members of the Sub-Sector for the Technical Committees.

1.10 Balloting Agent is the Secretary of the Participants Committee.

1.11 Business Day shall have the meaning set forth in the Tariff.

1.12 Commission is the Federal Energy Regulatory Commission.

1.13 Control Area is an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to:

(a) match, at all times, the power output of the generators within the electric power system(s) and capacity and Energy purchased from entities outside the electric power system(s), with the load within the electric power system(s);

(b) maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice;

(c) maintain the frequency of the electric power system(s) within reasonable limits in accordance with Good Utility Practice and the criteria of the applicable regional reliability council or the NERC; and

(d) provide sufficient generating capacity to maintain operating reserves in accordance with Good Utility Practice.

1.14 Demand Response Resource is for the purposes of this Agreement any resource in the New England Control Area that (a) produces quantifiable and verified, time-specific and location-specific load reductions from implementation of demand response measures for which the Entity that provides or controls the resource receives compensation; or (b) qualifies as a demand response resource, including distributed generation, pursuant to the Load Response Program; or (c) qualifies to receive an Installed Capacity payment pursuant to the Load Response Program; or (d) is determined by the Participants Committee to be a Demand Response Resource.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 10
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.15 Distributed Generation Resource is for the purposes of this Agreement any electric generating facility in the New England Control Area that: (a) generates electricity pursuant to a distributed generation tariff or contract; or (b) is interconnected to the New England Transmission System or a New England distribution system pursuant to a distributed generation agreement; or (c) the Participants Committee determines is a Distributed Generation Resource.

1.16 Distributed Generation Resource Provider is an AR Provider which, together with its Related Persons, owns or controls Distributed Generation Resources.

1.17 Distributed Generation Sub-Sector is the AR Sub-Sector established pursuant to Section 6.2(d)(i)(2) of this Agreement.

1.18 DRP is a Participant that (a) is eligible and has enrolled itself and/or one or more eligible end users to provide a reduction in Energy usage in the New England Control Area (whether through reduced Energy consumption or the operation of on-site generation which when operated does not result in net electric export to the grid) pursuant to the Load Response Program; (b) does not participate in the New England Market other than as permitted or required pursuant to the Load Response Program; (c) elected to be treated as a DRP before it became a Participant; and (d) was a DRP before the Effective Date.

1.19 DRP Group Member has the meaning set forth in Section 6.2(d) of this Agreement.

1.20 Effective Date of this Agreement is the Operations Date that occurs in accordance with Paragraph 1 of the Settlement Agreement Resolving Specified Issues dated August 20, 2004 entered into by and among the Settling Parties (as that term is defined in the Settlement Agreement).

1.21 End User Organization is an End User Participant which is (a) a registered tax-exempt non-profit organization with (i) an organized board of directors and (ii) a membership (A) of at least 100 Entities that buy electricity at wholesale or retail in the New England states or (B) with an aggregate peak monthly demand (non-coincident) for load in New England, including load served by Governance Only End User Behind-the-Meter Generation, of at least ten (10) megawatts or (b) a municipality or other governmental agency located in New England which does not meet the definition of Publicly Owned Entity.

1.22 End User Participant is a Participant which is (a) a consumer of electricity in the New England Control Area that generates or purchases electricity primarily for its own consumption, (b) a non-profit group representing such consumers, or (c) a Related Person of

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 11
Second Restated NEPOOL Agreement
Section 1 - Definitions

another End User Participant and which (i) is licensed as a competitive supplier under the statutes and regulations of the state in which the End User Participant which is its Related Person is located and (ii) participates in the New England Market solely to serve the load of the End User which is its Related Person.

1.23 End User Sector is the Sector established pursuant to Section 6.2(f) of this Agreement.

1.24 Energy is power produced in the form of electricity, measured in kilowatt-hours or megawatt-hours.

1.25 Energy Efficiency Resource is for the purposes of this Agreement any resource in the New England Control Area that is not a generator and either (a) produces quantifiable and verified, time-specific and location-specific load reductions from implementation of measures that reduce the Energy used by end-use devices and systems while maintaining comparable service for which the Entity that provides or controls the resource receives compensation pursuant to an energy efficiency program of a New England state; or (b) is determined by the Participants Committee to be an Energy Efficiency Resource.

1.26 Entity is any person or organization whether the United States of America or Canada or a state or province or a political subdivision thereof or a duly established agency of any of them, a private corporation, a partnership, an individual, an electric cooperative or any other person or organization recognized in law as capable of owning property and contracting with respect thereto that is either:

(a) engaged in the electric power business (the generation and/or transmission and/or distribution of electricity for consumption by the public; or the purchase, as a principal or broker, of installed capability, Energy, operating reserve, or ancillary services; or the ownership or control of Load Response Resources); or

(b) a consumer of electricity in the New England Control Area that generates or purchases electricity primarily for its own consumption or a non-profit group representing such consumers.

1.27 First Restated NEPOOL Agreement is the NEPOOL Agreement as in effect just prior to the Effective Date.

1.28 Fully Activated Sub-Sector Voting Share is eight and one-third percent (8 1/3%) in the case of the Renewable Generation Sub-Sector and four and one-sixth percent (4 1/6%) in the case of each of the Distributed Generation and Load Response Sub-Sectors.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 12
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.29 Generation Sector is the Sector established pursuant to Section 6.2(a) of this Agreement.

1.30 Good Utility Practice shall have the meaning set forth in the Tariff.

1.31 Governance Load (in Kilowatts) of a Participant during any particular hour and solely for purposes of determining eligibility for participation in the AR Sector is the greater of (A) Real-Time Load Obligation (as defined in the Market Rules) for such hour during the period in question, or (B) the total during such hour, of (a) kilowatthours provided by such Participant to its retail customers for consumption, plus (b) kilowatthours of use by such Participant, plus (c) kilowatthours of electrical losses and unaccounted for use by the Participant on its system, plus (d) kilowatthours used by such Participant for pumping Energy for its entitlements in pumped storage hydroelectric generating facilities, plus (e) kilowatthours delivered by such Participant to Non-Participants. The Governance Load of a Participant may be calculated in any reasonable manner which substantially complies with this definition.

1.32 Governance Only End User Behind-the-Meter Generation is for purposes of Sections 1.21 and 1.40 of this Agreement generation that has all three (3) of the following attributes: (i) it is owned by a Governance Only Member; and (ii) it is used to meet that Governance Only Member’s load or, for any hour in which the output of the Governance Only End User Behind-the-Meter Generation owned by the Governance Only Member exceeds its Regional Network Load (as defined in Section II of the Tariff), another Participant or Individual RTO Participant which is not a Governance Only Member is obligated under tariff or contract to report such excess to the System Operator pursuant to the Market Rules; and (iii) it is delivered to the Governance Only Member without the use of PTF or another Entity’s transmission or distribution facilities.

1.33 Governance Only Member is an End User Participant that participates in NEPOOL for governance purposes only; provided, however, that a Governance Only Member may elect to participate in the Load Response Program without losing the benefits of Governance Only Member status for any other purpose under this Agreement. An End User Participant may elect to be a Governance Only Member before its application is approved by NEPOOL or by a written notice delivered to the Secretary of the Participants Committee. Other than for an election made prior to the approval of its application by NEPOOL, the election to be a Governance Only Member shall become effective beginning on the first annual meeting of the Participants Committee following notice of such election.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 13
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.34 Governance Rating is (a) with respect to an electric generating unit or combination of units (other than a Distributed Generation Resource), (i) the Winter Capability of such unit or combination of units, or (ii) if no Winter Capability has been determined by the System Operator, the aggregate name plate rating of such unit or combination of units; (b) with respect to Demand Response Resources, the highest adjusted capability value (determined in accordance with the Load Response Program) for those Demand Response Resources in the prior twelve (12) months; (c) for Distributed Generation Resources not participating in the New England Markets or the Load Response Program, the name plate rating of the Distributed Generation Resource; or (d) for Energy Efficiency Resources, the highest verified co-incident peak savings provided during the hours of the Load Response Program during the prior twelve (12) months. The Governance Rating of a Participant may be determined by the System Operator in any reasonable manner which substantially complies with this definition.

1.35 Governance Transmission Owner for the purposes of this Agreement is an owner of PTF which makes its PTF available under the Tariff and owns a Local Network (as that term is defined in the Tariff) listed in Attachment E to the Tariff which is not a Publicly Owned Entity, including any affiliate of an owner of PTF that owns transmission facilities that are made available as part of such owner’s Local Network; provided that if an owner of PTF was not listed in Attachment E to the NEPOOL Open Access Transmission Tariff as that Tariff was in effect on May 10, 1999, the owner of PTF must also (1) own, or lease with rights equivalent to ownership, PTF with an original capital investment in its PTF as of the end of the most recent year for which figures are available from annual reports submitted to the Commission in Form 1 or any similar form containing comparable annualized data of at least $30,000,000, and (2) provide transmission service to non-affiliated customers pursuant to an open access transmission tariff on file with the Commission.

1.36 Individual RTO Participants are the Entities defined as “Individual Participants” in Section 1 of the Participants Agreement.

1.37 Information Policy is the policy on file with the Commission as part of the Tariff establishing guidelines regarding the information received, created and distributed by Participants and the System Operator in connection with the New England Markets and the New England Transmission System.

1.38 ISO is ISO New England Inc., acting as the regional transmission organization for the New England Control Area.

1.39 ISO Operating Documents shall have the meaning set forth in the Tariff.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 14
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.40 Large End User is an End User Participant which is considered for this purpose to be (a) a single end user with a peak monthly demand (non-coincident) for load in New England, including load served by Governance Only End User Behind-the-Meter Generation, of at least one (1) megawatt, or (b) a group of two or more corporate entities each with a peak monthly demand (non-coincident) for load in New England, including load served by Governance Only End User Behind-the-Meter Generation, of at least 0.35 megawatts that together totals at least one (1) megawatt.

1.41 Load Response Program is the load response program included in the Market Rules.

1.42 Load Response Resource is for the purposes of this Agreement an Energy Efficiency Resource or Demand Response Resource.

1.43 Load Response Resource Provider is an AR Provider which, together with its Related Persons, owns or controls Load Response Resources.

1.44 Load Response Sub-Sector is the AR Sub-Sector established pursuant to Section 6.2(d)(i)(3) of this Agreement.

1.45 Market Participant End User is an End User Participant that participates directly in the New England Markets; provided, however, that a Governance Only End User which participates in the Load Response Program shall not be considered a Market Participant End User.

1.46 Market Participant Service Agreement or MPSA shall have the meaning set forth in the Tariff.

1.47 Market Rule 1 is Market Rule 1 and the appendices and attachments thereto set out in Section III of the Tariff, as modified and amended from time to time.

1.48 Market Rules are the rules defined in the Participants Agreement, including, on the Effective Date, Market Rule 1.

1.49 Markets Committee is the committee whose responsibilities are specified in Section 8.2.2 of the Participants Agreement.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 15
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.50 Member Adjusted Voting Share

(a) for a voting member of each active Sector (other than the AR Sector) which casts an affirmative or negative vote on a proposed action or amendment and which has been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirement for the proposed action or amendment, is the quotient obtained by dividing (i) the Sector Voting Share of that Sector for the Participants Committee or the Adjusted Sector Voting Share of that Sector for the Technical Committees by (ii) the number of voting members appointed by members of that Sector which cast affirmative or negative votes on the matter, adjusted, if necessary, for End User Participants and group voting members as provided in the definition of “Member Fixed Voting Share”; and

(b) for a voting member of an AR Sub-Sector which casts an affirmative or negative vote on a proposed action or amendment and which has been appointed by a Participant or group of Participants which are members of an AR Sub-Sector satisfying its AR Sub-Sector Quorum Requirement for a proposed action or amendment, is the quotient obtained by dividing (i) the Adjusted AR Sub-Sector Voting Share of that Sub-Sector by (ii) the number of voting members appointed by members of that Sub-Sector which cast affirmative or negative votes on the matter.

1.51 Member Fixed Voting Share.

(a) for a voting member of each active Sector (other than the AR Sector), whether or not the member is in attendance, is the quotient obtained by dividing (i) the Sector Voting Share of the Sector to which the Participant or group of Participants which appointed the voting member belongs by (ii) the total number of voting members appointed by members of that Sector, adjusted, if necessary, to take into account (A) the manner in which the voting shares of End User Participants are to be determined while they are members of the Publicly Owned Entity Sector, and (B) any required change in the voting share of the Transmission Group Member, as determined in accordance with Section 6.2(b); and

(b) for a voting member of an AR Sub-Sector whether or not the member is in attendance and until the sum of the Member Fixed Voting Shares of the Sub-Sector voting members equals or exceeds the Fully Activated Sub-Sector Voting Share, is either 1 2/3% if the voting member represents a Participant or Participants which own or control, together with their Related Persons, more than 15 MW (or its equivalent) of Alternative Resources or 1% if the voting member represents less than 15 MW (or its equivalent) of Alternative Resources. When the sum of the Member Fixed Voting Shares of the AR Sub-Sector voting members equals or exceeds the Fully Activated Sub-Sector Voting Share, the Member Fixed Voting Share for the

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 16
Second Restated NEPOOL Agreement
Section 1 - Definitions

voting member whether or not the voting member is in attendance will be the quotient obtained by dividing (i) the Fully Activated Sub-Sector Voting Share by (ii) the total number of voting members appointed by Participants in that Sub-Sector.

1.52 Minimum Response Requirement with respect to a proposed amendment to this Agreement means that the ballots received by the Balloting Agent from Participants relating to the proposed amendment before the end of the appropriate time specified in Section 6.11(c) must satisfy the following thresholds:

(a) the sum of the Member Fixed Voting Shares of the Participant voting members whose ballots are received must equal at least fifty percent (50%); and

(b) the Participants whose voting members timely return ballots for or against the amendment must include Participants that are represented by voting members having at least fifty percent (50%) of the Member Fixed Voting Shares in each of a majority of the activated Sectors.

1.53 NECPUC is the New England Conference of Public Utilities Commissioners, Inc., including any successor organization.

1.54 NEPOOL is the New England Power Pool, the voluntary unincorporated association organized under and governed by this Agreement, and the Entities collectively participating in the New England Power Pool as Participants.

1.55 NEPOOL Vote:

(a) with respect to an amendment or proposed action of the Participants Committee is the sum of (i) the Member Adjusted Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirements and (ii) the Member Fixed Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector which fails to satisfy its Sector Quorum requirements; and

(b) with respect to a proposed action of a Technical Committee is the sum of the Member Adjusted Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 17
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.56 NERC is the North American Electric Reliability Council, including any successor organization.

1.57 New England Control Area shall have the meaning set forth in Section II of the Tariff.

1.58 New England Markets are the markets for Energy, capacity and certain ancillary services within the New England Control Area as set forth in the Market Rules.

1.59 New England Transmission System is the system of transmission facilities within the New England Control Area under the System Operator’s operational jurisdiction.

1.60 Non-Participant is any entity which is not a Participant.

1.61 NPCC is the Northeast Power Coordinating Council, including any successor organization.

1.62 Participant is an eligible Entity (or group of Entities which has elected to be treated as a single Participant pursuant to Section 4.1) which has become a Participant in accordance with Section 3.1 until such time as such Entity’s status as a Participant terminates pursuant to Sections 6.2 or 16.1.

1.63 Participant Expenses are those costs and expenses that are incurred pursuant to authorization of the Participants Committee and are not considered costs and expenses of the System Operator. Participant Expenses shall be allocated in accordance with Section 1.1.

1.64 Participants Agreement is the Participants Agreement among the ISO and the NEPOOL Participants acting by and through the Participants Committee and the Individual Participants (as defined therein), as modified and amended from time to time in accordance with its terms.

1.65 Participants Committee is the committee whose responsibilities are specified in Section 8.1 of the Participants Agreement.

1.66 PTF or Pool Transmission Facilities shall have the meaning set forth in the Tariff.

1.67 Power Year is the twelve (12) month period as defined in the Participants Agreement.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 18
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.68 Principal Committees are the Participants Committee and the Technical Committees.

1.69 Publicly Owned Entity is an Entity which is either a municipality or an agency thereof, or a body politic and public corporation created under the authority of one of the New England states, authorized to own, lease and operate electric generation, transmission or distribution facilities, or an electric cooperative, or an organization of any such entities.

1.70 Publicly Owned Entity Sector is the Sector established pursuant to Section 6.2(e) of this Agreement.

1.71 PURPA is the Public Utility Regulatory Policies Act of 1978.

1.72 Related Person of a Participant is:

(a) for all Participants, either (i) a corporation, partnership, business trust or other business organization 10% or more of the stock or equity interest in which is owned directly or indirectly by, or is under common control with, the Participant, or (ii) a corporation, partnership, business trust or other business organization which owns directly or indirectly 10% or more of the stock or other equity interest in the Participant, or (iii) a corporation, partnership, business trust or other business organization 10% or more of the stock or other equity interest in which is owned directly or indirectly by a corporation, partnership, business trust or other business organization which also owns 10% or more of the stock or other equity interest in the Participant, or (iv) a natural person, or a member of such natural person’s immediate family, who is, or within the last 12 months has been, an officer, director, partner, employee, or representative in NEPOOL activities of, or natural person having a material ongoing business or professional relationship directly related to NEPOOL activities with, the Participant or any corporation, partnership, business trust or other business organization related to the Participant pursuant to clauses (i), (ii) or (iii) of this Section 1.72(a); and

(b) for all End User Participants which are also natural persons, a Related Person is (i) a member of such End User’s immediate family, or (ii) a Participant and any corporation, partnership, business trust, or other business organization related to the Participant pursuant to clauses (i), (ii) or (iii) of Section 1.72(a), of which such End User Participant, or a member of such End User Participant’s immediate family, is, or within the last twelve (12) months has been, an officer, director, partner, or employee of, or with which an individual End User Participant has, or within the last twelve (12) months had, a material ongoing business or professional relationship directly related to NEPOOL activities, or (iii) another Participant which, within the last twelve (12) months, has paid a portion of the End User Participant’s

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 19
Second Restated NEPOOL Agreement
Section 1 - Definitions

expenses under Section 14 of this Agreement or Section 19 of the First Restated NEPOOL Agreement, or (iv) a corporation, partnership, business trust or other business organization in which the End User Participant owns stock and/or equity with a fair market value in excess of $50,000.

(c) Notwithstanding the foregoing, for the purposes of this definition, an individual shall not be deemed to have or had a material on-going business relationship directly related to NEPOOL activities with any corporation, partnership, business trust, other business organization or Publicly Owned Entity solely as a result of being served, as a customer, with electricity or gas.

1.73 Related Person Supplier is a Participant that (i) is represented by a voting member of the Supplier Sector, (ii) participates in the New England Markets solely to serve one or more Related Persons that are not Participants but consume electricity in the New England Control Area and that generate or purchase electricity primarily for their own consumption, and (iii) is licensed as a competitive supplier under the statutes and regulations of each New England state in which it serves any such Related Person.

1.74 Reliability Committee is the committee whose responsibilities are specified in Section 8.2.3 of the Participants Agreement.

1.75 Renewable Generation Resource is for the purposes of this Agreement any electric generating facility in the New England Control Area that: (a) is defined as renewable generation under any New England state renewable portfolio standard; or (b) satisfies the criteria for a Small Power Production Facility under PURPA; or (c) primarily uses one or more of the following fuels, Energy resources, or technologies: solar, wind, hydro, tidal, geothermal, or biomass; or (d) the Participants Committee determines is a Renewable Generation Resource.

1.76 Renewable Generation Resource Provider is an AR Provider which, together with its Related Persons, owns or controls Renewable Generation Resources.

1.77 Renewable Generation Sub-Sector is the AR Sub-Sector that is established pursuant to Section 6.2(d)(i)(1) of this Agreement.

1.78 Review Board is the board whose responsibilities are specified in Section 11.

1.79 Sector is the Generation Sector, the Transmission Sector, the Supplier Sector, the AR Sector, the Publicly Owned Entity Sector, the End User Sector, or any other Sector created pursuant to the terms of this Agreement.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 20
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.80 Sector Quorum for a Sector shall be the lesser of (a) fifty percent (50%) or more (rounded to the next higher whole number) of the voting members of the Sector, or (b) five (5) or more voting members of the Sector for the Participants Committee or three (3) or more voting members of the Sector for the Technical Committees.

1.81 Sector Voting Share is:

(a) for the AR Sector, the sum of the Member Fixed Voting Shares; and

(b) for each active Sector (other than the AR Sector), the quotient obtained by dividing one hundred percent (100%) minus the AR Sector Voting Share by the number of active Sectors (other than the AR Sector). For example, if there are five active Sectors (other than the AR Sector) and the AR Sector Voting Share is sixteen and two-thirds percent (16 2/3%), the Sector Voting Share of each of the other Sectors is also sixteen and two-thirds percent (16 2/3%). The aggregate Sector Voting Shares shall equal one hundred percent (100%).

1.82 Small End User is a End User Participant which does not otherwise meet the definition of Large End User or End User Organization.

1.83 Sub-Sector Voting Share is either (a) the Fully Activated Sub-Sector Voting Share where the sum of the Member Fixed Voting Shares of the voting members of the Sub-Sector is equal to or greater than its Fully Activated Sub-Sector Voting Share or (b) the sum of the Member Fixed Voting Shares of the voting members of that Sub-Sector where such sum is less than the Fully Activated Sub-Sector Voting Share.

1.84 Supplier Sector is the Sector established pursuant to Section 6.2(c) of this Agreement.

1.85 System is the system defined in the Participants Agreement.

1.86 System Operator is the central dispatching agency referred to in this Agreement which has responsibility for the operation of the New England Control Area from the regional control center and the administration of the Tariff. As of the Effective Date, the System Operator is the ISO (the regional transmission organization for New England).

1.87 System Rules are the ISO Operating Documents, the Information Policy, and any other system rules, manuals, procedures, criteria or reliability standards for the operation of the System and administration of the New England Markets, this Agreement, the Participants Agreement or the Tariff.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 21
Second Restated NEPOOL Agreement
Section 1 - Definitions

1.88 Tariff is the ISO’s Transmission, Markets and Services Tariff, as on file with the Commission and as amended from time to time.

1.89 Technical Committees are the Markets Committee, the Reliability Committee, and the Transmission Committee.

1.90 Transmission Committee is the committee whose responsibilities are specified in Section 8.2.4 of the Participants Agreement.

1.91 Transmission Operating Agreement or TOA is the Transmission Operating Agreement among the ISO and the transmission-owning Entities that are parties thereto, as modified and amended from time to time in accordance with its terms.

1.92 Transmission Sector is the Sector established pursuant to Section 6.2(b) of this Agreement.

1.93 Winter Capability is, with respect to an electric generating unit or combination of units, the maximum dependable load carrying ability in kilowatts of such unit or units (exclusive of capacity required for station use) during the Winter Period, as determined by the System Operator.

1.94 Winter Period is for each Power Year the eight-month period from October through May for each Power Year.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 22
Second Restated NEPOOL Agreement
Section 2 - Purpose; Effective Date; Section 3 - Membership

SECTION 2

PURPOSE; EFFECTIVE DATE

2.1 Purpose. This Agreement is intended to (a) provide for certain understandings among the Participants concerning their collective, coordinated interactions with, and responsibilities to, each other and their collective interaction with the System Operator consistent with the Participants Agreement, (b) provide a stakeholder advisory process for the ISO in its role as the regional transmission organization for the New England Control Area, and (c) provide a vehicle for the participation by Publicly Owned Entities in such regional transmission organization.

2.2 Effective Date. The provisions of this Agreement become effective on the Effective Date and replace on that date the provisions of the First Restated NEPOOL Agreement.

SECTION 3

MEMBERSHIP

3.1 Membership.

(a) Those Entities that are Participants in NEPOOL on the Effective Date shall continue to be Participants. The Transmission Owners listed in Schedule 3.1 shall be deemed to have terminated their status as NEPOOL Participants immediately preceding the Effective Date and to have become Participants pursuant to this Agreement on the Effective Date. Any other Entity may, upon compliance with such reasonable conditions as the Participants Committee may prescribe, become a Participant by depositing a counterpart of this Agreement as theretofore amended, duly executed by it, with the Secretary of the Participants Committee, and a check in payment of the application fee described below.

(b) Any such Entity which satisfies the requirements of this Section 3.1 shall become a Participant, and this Agreement shall become fully binding and effective in accordance with its terms as to such Entity, as of the first day of the second calendar month following its satisfaction of such requirements; provided that an earlier or later effective time may be fixed by the Participants Committee with the concurrence of such Entity or by the Commission.

(c) The application fee to be paid by each Entity seeking to become a Participant shall be in addition to the annual fee provided by Section 14.1 and shall be $500 for an applicant which qualifies for membership only as an End User Participant, $1,000 for an applicant which together with its Related Persons owns or controls less than 5 MW (or its equivalent) of Alternative Resources and qualifies for membership as an AR Provider, and $5,000 for all other applicants, or such other amount as may be fixed by the Participants Committee.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 23
Second Restated NEPOOL Agreement
Section 4 - Status of Participants

3.2 Lack of Place of Business in New England. If and for so long as a Participant does not have a place of business located in one of the New England states, the Participant shall be deemed to irrevocably (a) submit to the jurisdiction of any Connecticut state court or United States Federal court sitting in Connecticut (the state whose laws govern this Agreement) over any action or proceeding arising out of or relating to this Agreement that is not subject to the exclusive jurisdiction of the Commission, (b) agree that all claims with respect to such action or proceeding may be heard and determined in such Connecticut state court or Federal court, (c) waive any objection to venue or any action or proceeding in Connecticut on the basis of forum non conveniens, (d) agree that service of process may be made on the Participant outside Connecticut by certified mail, postage prepaid, mailed to the Participant at the address of its member on the Participants Committee as set out in the NEPOOL roster or at the address of its principal place of business and agrees to waive service of a summons in federal court as provided by Rule 4(d) of the Federal Rules of Civil Procedure, and (e) waives the right to contest that service of process as contemplated by Section 1.1(d) is invalid.

SECTION 4

STATUS OF PARTICIPANTS

4.1 Treatment of Certain Entities as Single Participant.

(a) Each Entity that is treated with other Entities collectively as a single Participant under the First Restated NEPOOL Agreement as of the Effective Date shall retain that status until it revokes in writing its election to be treated as part of the single Participant.

(b) In view of the long-standing arrangements in Vermont, Vermont Electric Power Company, Inc. and any other Vermont electric utilities which elect in writing to be grouped with it shall be collectively treated as a single Participant for purposes of this Agreement; provided, however, that any Vermont electric utility which is a Publicly Owned Entity may elect to join the Publicly Owned Entity Sector and be treated as a member of that Sector for purposes of governance, annual fees and Participant Expense allocation, without losing the benefits of single Participant status for any other purpose under this Agreement.

4.2 Participants to Retain Separate Identities. The signatories to this Agreement shall not become partners by reason of this Agreement or their activities hereunder, but as to each other and to third persons, they shall be and remain independent contractors in all matters relating to this Agreement. This Agreement shall not be construed to create any liability on the part of any signatory to anyone not a party to this Agreement. Each signatory shall retain its separate identity and, to the extent not limited hereby, its individual freedom in rendering service to its customers.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 24
Second Restated NEPOOL Agreement
Section 5 - Objectives and Cooperation

SECTION 5

OBJECTIVES AND COOPERATION

5.1 Objectives. The objectives for the market and transmission arrangements for the New England Control Area, as implemented through this Agreement, the Participants Agreement, the Tariff, including but not limited to the Market Rules, the Market Participant Service Agreement, the TOA, and the System Rules are:

(a) to assure the bulk power supply system within the New England Control Area conforms to proper standards of reliability;

(b) to create and sustain open, non-discriminatory, competitive, unbundled, markets for Energy, capacity and ancillary services (including operating reserves) that are (i) economically efficient and balanced between buyers and sellers, and (ii) provide an opportunity for a participant to receive compensation through the market for a service it provides, in a manner consistent with proper standards of reliability and the long-term sustainability of competitive markets;

(c) to provide market rules that (i) promote a market based on voluntary participation, (ii) allow market participants to manage the risks involved in offering and purchasing services, and (iii) compensate at fair value (considering both benefits and risks) any required service, subject to the Commission’s jurisdiction and review;

(d) to allow informed participation and encourage ongoing market improvements;

(e) to provide transparency with respect to the operation of and the pricing in markets and purchase programs;

(f) to provide access to competitive markets within the New England Control Area and to neighboring regions; and

(g) to provide for an equitable allocation of costs, benefits and responsibilities among market participants.

The signatories to this Agreement agree that the preceding objectives are consistent with the Federal Power Act and do not in and of themselves create independent causes of action.

5.2 Cooperation. In furtherance of the objectives set forth in Section 5.1, each Participant shall observe the provisions of this Agreement in good faith.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 25
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

SECTION 6

COMMITTEE ORGANIZATION AND VOTING

6.1 Principal Committees. There shall be four principal NEPOOL Committees (the “Principal Committees”), as follows:

(a) the Participants Committee which shall perform those functions specified in Section 8.1 of the Participants Agreement and shall act in accordance with the provisions of this Agreement in performing those functions;

(b) the Markets Committee which shall perform those functions specified in Section 8.2.2 of the Participants Agreement and shall act in accordance with the provisions of this Agreement in performing those functions;

(c) the Reliability Committee which shall perform those functions specified in Section 8.2.3 of the Participants Agreement and shall act in accordance with the provisions of this Agreement in performing those functions; and

(d) the Transmission Committee which shall perform those functions specified in Section 8.2.4 of the Participants Agreement and shall act in accordance with the provisions of this Agreement in performing those functions.

In addition, there shall be such other committees as may be established from time to time by the Participants Committee.

6.2 Sector Representation. The members of each Principal Committee shall each belong to a single sector for voting purposes (“Sector”). Each Participant shall be obligated to designate in a notice to the Secretary of the Participants Committee a Sector that it or its Related Persons is eligible to join and that it elects to join for purposes of all of the Principal Committees; provided, however, that (i) a Participant shall not be eligible to join the End User Sector if any of its Related Persons which are Participants or Individual RTO Participants are not eligible to join the End User Sector and (ii) a DRP and the Participants which are its Related Persons shall not be represented by the DRP Group Member (as defined below) if any one of them is not a DRP. A Participant and its Related Persons shall together be entitled to join only one Sector and shall have no more than one vote on each Principal Committee, provided that any voting member of a Principal Committee shall be entitled to split its vote.

The Sectors for each Principal Committee, the criteria for eligibility for membership in each Sector and the minimum requirement which a Participant must meet as a member of a Sector in order to appoint a voting member of the Sector and Committee are as follows:

(a) a Generation Sector, which a Participant shall be eligible to join if (i) it (A) owns or leases with rights equivalent to ownership facilities for the generation of Energy that are located within the New England Control Area which are currently in operation, or (B) has

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 26
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

proposed generation for operation within the New England Control Area either which has received approval under Sections 18.4 and/or 18.5 of the First Restated NEPOOL Agreement between July 1, 2002 and the Effective Date or received approval on or after the Effective Date under Sections I.3.9 and/or I.3.10 of the Tariff or for which completed environmental air or environmental siting applications have been filed or permits exist, and (ii) it is not a Publicly Owned Entity. Purchasing all or a portion of the output of a generation facility shall not be sufficient to qualify a Participant to join the Generation Sector.

A Participant which joins the Generation Sector shall be entitled but not required to designate an individual voting member of each Principal Committee, and an alternate to the member, if its operating or proposed generation facilities in the New England Control Area have or will have, when placed in operation, an aggregate Governance Rating of at least 15 MW.

A Participant which joins the Generation Sector but elects not to or is not eligible to designate an individual voting member, shall be represented by a group voting member and an alternate to that member for each Principal Committee (collectively, the “Generation Group Member”). The Generation Group Member shall be appointed by a majority of the Participants in the Generation Sector electing or required to be represented by that member. The Generation Group Member shall have the same percentage of the Sector vote as the individual voting members designated by other Participants in the Generation Sector which meet the 15 MW threshold and designate an individual voting member.

(b) a Transmission Sector, which a Participant shall be eligible to join if it is a Governance Transmission Owner and is not a Publicly Owned Entity. Taking transmission service shall not be sufficient to qualify a Participant to join the Transmission Sector.

A Participant which joins the Transmission Sector shall be entitled to designate an individual voting member of each Principal Committee, and an alternate to the member, if it owns or leases with rights equivalent to ownership PTF with an original capital investment in its PTF as of the end of the most recent year for which figures are available from annual reports submitted to the Commission in Form 1 or any similar form containing comparable annualized data of at least $30,000,000. A Governance Transmission Owner with facilities which were included as PTF prior to December 31, 1998 only pursuant to clause (3) of the definition of PTF in the First Restated NEPOOL Agreement shall be entitled to designate an individual voting member of each Principal Committee, and an alternate to the member, whether or not PTF which it owns or leases with rights equivalent to ownership which has an original capital investment of at least $30,000,000, so long as such Governance Transmission Owner continues to own PTF.

A Participant which joins the Transmission Sector but which is not entitled to designate an individual voting member of each Principal Committee because (i) it, together with all of its Related Persons, does not meet the $30,000,000 threshold or (ii) it no longer owns PTF and it does not have a Related Person that is entitled to designate an individual voting member for each Principal Committee in another Sector, together with the other Participants in the

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 27
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

Transmission Sector which for the same reasons are unable to designate an individual voting member, shall be represented by a group voting member of each Principal Committee (the “Transmission Group Member”), and an alternate to that member. The Transmission Group Member and alternate shall be appointed by a majority vote of all Participants in the Transmission Sector required to be represented by that Member. The Transmission Group Member shall have the same percentage of the Sector vote as the individual voting members designated by other Participants in the Transmission Sector which meet the $30,000,000 threshold unless and until the original capital investment in PTF of the Participants represented by the Transmission Group Member equals or exceeds twice the $30,000,000 threshold amount. If the aggregate original capital investment in PTF equals or exceeds twice the $30,000,000 threshold amount, the percentage of the Sector votes assigned to the Transmission Group Member shall equal the number of full multiples of the $30,000,000 threshold, provided that the Transmission Group Member shall in no event be entitled to more than twenty-five percent (25%) of the Sector vote. For example, if Participants represented by the Transmission Group Member have an aggregate original capital investment in PTF in the New England Control Area totaling $70,000,000, the Transmission Group Member will have the same percentage of such votes as two ($70,000,000/$30,000,000 Threshold = 2.33) individual voting members designated by individual Participants, provided that there are at least six other members in the Sector so the Transmission Group Member does not have more than twenty-five percent (25%) of the Transmission Sector vote.

(c) a Supplier Sector, which a Participant shall be eligible to join if (i) it engages in, or is licensed or otherwise authorized by a state or federal agency with jurisdiction to engage in, power marketing, power brokering or load aggregation within the New England Control Area, or it had been engaged on and before December 31, 1998 solely in the distribution of electricity in the New England Control Area and (ii) it is not a Publicly Owned Entity. A Participant which joins the Supplier Sector shall be entitled to designate a voting member of each Principal Committee, and an alternate to the member.

(d) an Alternative Resources Sector, which an AR Provider shall be eligible to join; provided, however, that a Participant that is eligible to join the End User Sector shall not join the AR Sector.

(i) The Alternative Resources Sector shall be divided into the following three (3) Sub-Sectors:

(1) Renewable Generation Sub-Sector.

(A) A Participant shall be eligible to join the Renewable Generation Sub-Sector if it is a Renewable Generation Resource Provider. A Renewable Generation Resource Provider which joins the Renewable Generation Sub-Sector shall be entitled but not required to designate an individual voting member of each Principal Committee, and an alternate to the member, if it owns or controls Renewable Generation Resources with an aggregate Governance Rating of at least 5 MW. A Renewable Generation Resource Provider

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 28
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

which owns or controls Renewable Generation Resources that have an aggregate Governance Rating of at least 15 MW shall either designate an individual voting member of each Principal Committee, and an alternate to the member, or elect to be represented by a Self-Defined Renewable Group Member as described in the following paragraph.

(B) A Renewable Generation Resource Provider which joins the Renewable Generation Sub-Sector may together with one or more Renewable Generation Resource Providers be represented by a “Self-Defined Renewable Generation Group Member” and an alternate to that member for each Principal Committee if (x) it elects not to or is not eligible to designate an individual voting member and (y) the group voting member represents Renewable Generation Resource Providers that own or control Renewable Generation Resources that in the aggregate have a Governance Rating of more than 5 MW.

(C) A Renewable Generation Resource Provider which joins the Renewable Generation Sub-Sector shall be represented by the “Small Renewable Generation Group Member” if (x) is not entitled to designate an individual voting member of each Principal Committee because it does not own or control Renewable Generation Resources with an aggregate Governance Rating of at least 5 MW, or (y) it has not elected to be represented by an individual voting member or a Self-Defined Renewable Generation Group Member.

(2) Distributed Generation Sub-Sector.

(A) A Participant shall be eligible to join the Distributed Generation Sub-Sector if it is a Distributed Generation Resource Provider or a DRP. A Distributed Generation Resource Provider which joins the Distributed Generation Sub-Sector shall be entitled but not required to designate an individual voting member of each Principal Committee, and an alternate to the member, if it owns or controls Distributed Generation Resources that in the aggregate have a Governance Rating of at least 5 MW.

(B) A Distributed Generation Resource Provider which joins the Distributed Generation Sub-Sector but elects not to or is not eligible to designate an individual voting member may together with one or more Distributed Generation Resource Providers be represented by a “Self-Defined Distributed Generation Group Member” and an alternate to that member for each Principal Committee if the group voting member represents Distributed Generation Resource Providers that own or control Distributed Generation Resources that in the aggregate have a Governance Rating of more than 5 MW.

(C) DRPs shall be represented by a separate group voting member and an alternate to that member for each Principal Committee known as the “DRP Group Member”.

(D) A Distributed Generation Resource Provider which joins the Distributed Generation Sub-Sector shall be represented by the “Small Distributed Generation Group Member” if (x) it is not entitled to designate an individual voting member of

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 29
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

each Principal Committee because it does not own or control Distributed Generation Resources that in the aggregate have a Governance Rating of at least 5 MW, or (y) it has not elected to be represented by an individual voting member or a Self-Defined Distributed Generation Group Member.

(3) Load Response Sub-Sector.

(A) A Participant shall be eligible to join the Load Response Sub-Sector if it is a Load Response Resource Provider. A Load Response Resource Provider which joins the Load Response Sub-Sector shall be entitled but not required to designate an individual voting member of each Principal Committee, and an alternate to the member, if it owns or controls Load Response Resources that in the aggregate have a Governance Rating of at least 5 MW (or its equivalent).

(B) A Load Response Resource Provider which joins the Load Response Sub-Sector may together with one or more Load Response Resource Providers be represented by a “Self-Defined Load Response Group Member” and an alternate to that member for each Principal Committee if (x) it elects not to or is not eligible to designate an individual voting member and (y) the group voting member represents Load Response Resource Providers that own or control Load Response Resources that in the aggregate have a Governance Rating of more than 5 MW (or its equivalent).

(C) A Load Response Resource Provider which joins the Load Response Sub-Sector shall be represented by the “Small Load Response Group Member” if (x) it is not entitled to designate an individual voting member of each Principal Committee because it does not own or control Load Response Resources that in the aggregate have a Governance Rating of at least 5 MW (or its equivalent), or (y) it has not elected to be represented by an individual voting member or a Self-Defined Load Response Group Member.

(ii) A group voting member in the AR Sector shall be appointed or replaced by a majority of the Participants represented by that member.

(e) a Publicly Owned Entity Sector, which all Participants which are Publicly Owned Entities are eligible to join and shall join, and which End User Participants are eligible to join if there is not an activated End User Sector. A Participant which joins the Publicly Owned Entity Sector shall be entitled to designate a voting member of each Principal Committee, and an alternate to the member.

(f) an End User Sector, which an End User Participant is eligible to join provided all of its Related Persons which are either Participants or Individual RTO Participants are also eligible to join the End User Sector. Participants which join the End User Sector shall be entitled to designate an individual voting member of each Principal Committee and an alternate to the member; provided, however, that a voting member, and the alternate to the

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 30
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

member, designated by a Small End User shall not be a Related Person of another Participant in a Sector other than the End User Sector.

All Participants have the right to join and be a member of a Sector. If a Participant ceases to be eligible to be a member of the Sector which it previously joined and is not eligible to join another existing Sector other than the End User Sector, it shall have the right to remain and vote in the Sector in which the Participant is currently a member for up to one (1) year. By the end of such year, either (a) this Agreement shall be amended pursuant to Section 6.10 such that qualifications for an existing Sector are changed so that the Participant qualifies for membership in an existing Sector or a new Sector is created, or (b) the Participants Committee shall seek Commission approval to terminate the Participant status of the Participant.

6.3 Appointment of Members and Alternates. A Participant or group of Participants shall designate, by a written notice delivered to the Secretary of the appropriate Committee, the voting member appointed by it for the Committee and an alternate of the member. In the absence of the member, the alternate shall have all the powers of the member, including the power to vote. A Participant may change the Sector of which it is a member. Other than for Sector changes required by Section 6.4(c), a change in the Sector in which a Participant is a member shall become effective beginning on the first annual meeting of the Participants Committee following notice of such change.

6.4 Term of Members. Each voting member of a Principal Committee shall hold office until either (a) such member is replaced by the Participant or group of Participants which appointed the member, or (b) the appointing Participant ceases to be a Participant, or (c) the appointing Participant (or its Related Person) is no longer eligible to be in the Sector to which it belongs, but is eligible to join a different Sector. Replacement of a member shall be effected by delivery by a Participant or group of Participants of written notice of such replacement to the Secretary of the appropriate Committee.

6.5 Regular and Special Meetings. Each Principal Committee shall hold its annual meeting in December or January at such time and place as the Chair shall designate and shall hold other meetings in accordance with a schedule adopted by the Committee or at the call of the Chair. Five or more voting members of a Principal Committee may call subject to the notice provisions of Section 6.6 a special meeting of the Committee in the event that the Chair fails to schedule such a meeting within three (3) Business Days following the Chair’s receipt from such members of a request specifying the subject matters to be acted upon at the meeting.

6.6 Notice of Meetings.

(a) Written or electronic notice of each meeting of a Principal Committee shall be given to each Participant, whether or not such Participant is entitled to appoint an individual voting member of the Committee, not less than three (3) Business Days prior to the date of the meeting in the case of the Technical Committees and five (5) Business Days prior to the date of the meeting for the Participants Committee.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 31
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

(b) A notice of meeting shall specify the principal subject matters expected to be acted upon at the meeting. In addition, such notice shall include, or specify internet location of, all draft resolutions to be voted at the meeting (which draft resolutions may be subject to amendment of intent but not subject matter during the meeting), and all background materials deemed by the Chair or Secretary to be necessary to the Committee to have an informed opinion on such matters. Motions raised for which no draft resolutions or background materials have been provided may not be acted upon at a meeting and shall be deferred to a subsequent meeting which is properly noticed.

6.7 Attendance. Regular and special meetings may be conducted in person, by telephone, or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other. In order to vote during the course of a meeting, attendance is required in person or by telephone or other real time electronic means by a voting member or its alternate or a duly designated agent who has been given, in writing, the authority to vote for the member on all matters or on specific matters in accordance with Section 6.11.

6.8 Quorum. All actions by a Principal Committee, other than a vote by the Participants Committee by written ballot to amend this Agreement, shall be taken at a meeting at which the members in attendance pursuant to Section 6.7 constitute a Quorum. A Quorum requires the attendance by members which satisfy the Sector Quorum requirements for a majority of the activated Sectors. No action may be taken by a Principal Committee unless a Quorum is present; provided, however, that if a Quorum is not present, the voting members then present shall have the power to adjourn the meeting from time to time until a Quorum shall be present.

6.9 Voting On Proposed Actions. All matters to be acted upon by a Principal Committee shall be stated in the form of a motion by a voting member, which must be seconded. Only one motion and any one amendment to that motion may be pending at one time. Passage of a motion requires a NEPOOL Vote equal to or greater than two thirds of the aggregate Sector Voting Shares. Voting members not in attendance or represented at a meeting as specified in Section 6.7 or abstaining shall not be counted as affirmative or negative votes.

6.10 Voting On Amendments. Subject to Section 16.9, amendments to this Agreement shall be accomplished as follows:

(a) Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a Participant and sent to the Participants Committee for its consideration.

(b) The Participants Committee shall take action pursuant to Section 6.9 to direct the Balloting Agent to circulate ballots for approval of the draft Amendment to each Participant for execution by its voting member or alternate on the Participants Committee or such Participant’s duly authorized officer.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 32
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

(c) In order to be counted, ballots must be executed and returned to the Balloting Agent for NEPOOL in accordance with the following schedule:

(i) If the ballots are delivered to each Participant by regular mail, properly executed ballots must be returned to and received by the Balloting Agent within ten (10) Business Days after deposit of such ballots in the mail by the Balloting Agent, and

(ii) If the ballots are delivered to each Participant by overnight delivery, facsimile, electronic mail or hand delivery, then properly executed ballots must be returned to and received by the Balloting Agent within five (5) Business Days after (A) deposit of such ballots with an overnight delivery courier if delivered by overnight delivery, or (B) transmission of such ballots by the Balloting Agent if delivered by facsimile or electronic mail, or (C) receipt by the Participant if delivered by hand delivery.

(iii) If the Minimum Response Requirement for an amendment has not been received by the Balloting Agent within the schedule identified in subsection (i) or (ii) above, the Balloting Agent shall send notice by overnight delivery, facsimile, electronic mail or hand delivery to all non-responding Participants and shall count any additional properly executed ballots which it receives within five (5) Business Days after such notice. The date by which properly executed ballots must be returned and received by the Balloting Agent shall be specified by the Balloting Agent in the notice accompanying such ballots.

(d) A Participant may appeal to the Review Board a proposed amendment for which ballots have been circulated, provided that such appeal is taken before the end of the fifth (5th) Business Day after the Participants Committee has taken action to direct the Balloting Agent to circulate ballots for approval of the draft amendment, by giving to the Secretary of the Participants Committee a signed and written notice of appeal. The appeal shall be moot if the amendment is not approved in balloting by the Participants Committee. If the amendment is approved, a valid appeal shall stay any filing with the Commission of any amendment to this Agreement until a decision on the appeal by the Review Board.

(e) In order for a proposed amendment to this Agreement to be approved, the following criteria must be satisfied:

(i) The Minimum Response Requirement must be satisfied with respect to the proposed amendment.

(ii) The affirmative ballot votes with respect to the proposed amendment must equal or exceed two-thirds of the aggregate Sector Voting Shares.

(iii) The Board of Directors of the System Operator has approved the proposed amendment if it changes any of the provisions of this Agreement that are also included in the Participants Agreement.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 33
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

6.11 Designated Representatives and Proxies. The vote of any member of a Principal Committee or the member’s alternate, other than a ballot on an amendment, may be cast by another person pursuant to a written, standing designation or proxy; provided, however, that (i) the vote of a member or alternate to that member representing a Small End User may not be cast by a Participant or a Related Person of a Participant in a Sector other than the End User Sector and (ii) the vote of a member or alternate to that member representing an AR Provider which pays less than the lowest amount of Participant Expenses paid by an individual voting Participant in the Generation, Transmission, or Supplier Sectors may not be cast by a Participant or a Related Person of a Participant in a Sector other than the AR Sector. A designation or proxy shall be dated not more than one year previous to the meeting and shall be delivered by the member or alternate to the Secretary of the Committee at or prior to any votes being taken at the meeting at which the vote is cast pursuant to such designation or proxy. A single individual may be the designated representative of or be given the proxy of the voting members representing any number of Participants of any one Sector or Participants from multiple Sectors.

6.12 Limits on Representatives. In the End User Sector, no one person may vote on behalf of more than five (5) Small End Users. Except as otherwise provided herein, other Sectors may by unanimous written agreement elect to impose limits on the voting power any one individual may have in that Sector through being the designated representative of multiple voting members or carrying multiple proxies from voting members of that Sector. Notice of any such limits on voting power must be posted on the System Operator home page and be capable of being accessed by all Participants.

6.13 Attendance of Participants at Principal Committee Meetings. Each Participant which does not have the right to designate an individual voting member of a Principal Committee shall be entitled to attend any meeting of a Principal Committee or any other NEPOOL committee, and shall have a reasonable opportunity to express views on any matter to be acted upon at the meeting.

6.14 Adoption of Bylaws. The Participants Committee shall adopt bylaws, consistent with this Agreement, governing procedural matters including the conduct of its meetings and those of the other Principal Committees. If there is any conflict between such bylaws and this Agreement, this Agreement shall control. A Principal Committee may vote to waive its bylaws for a particular meeting, provided the motion to effect the waiver is approved in accordance with Section 6.9.

6.15 Joint Meetings of Technical Committees. To the extent appropriate and desirable, the Technical Committees are authorized and encouraged to hold meetings, and to conduct studies and exercise responsibilities, jointly with other Technical Committees.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 34
Second Restated NEPOOL Agreement
Section 6 - Committee Organization and Voting

6.16 Appointment of Technical Committee Officers.

(a) The System Operator shall, after its chief executive officer has conferred with the Participants Committee and relevant Technical Committee officers regarding such appointment(s), appoint the Chair and Secretary of each of the Technical Committees. Each individual appointed by the System Operator shall be an independent person not affiliated with any Participant. The System Operator shall seek input from the Technical Committee to which such officer is being appointed on the technical expertise and qualifications needed for such position, and endeavor to appoint a person with such technical expertise and qualifications. Before appointing an individual to the position of Chair or Secretary, the System Operator shall notify the Committee to which such officer is being appointed of the proposed assignment and, consistent with its personnel practices, provide any other information about the individual reasonably requested by the Committee. Each of the Technical Committees shall elect from among its members a Vice-Chair.

(b) If a Technical Committee determines that the performance of its Chair or Secretary is not satisfactory, the Committee shall provide notice to the Chair of the Participants Committee, identifying perceived performance deficiencies of such officer. The Chair of the Participants Committee shall discuss the performance of such officer with the Chief Executive Officer of the System Operator, who shall take such action as he or she deems necessary and appropriate based on such discussions. If the perceived officer performance deficiencies continue for thirty (30) days or more after such discussion between the Participants Committee Chair and the System Operator’s Chief Executive Officer, the Participants Committee Chair may provide notice of the officer performance concerns to the Board of Directors of the System Operator. The Board shall meet with the Participants Committee Chair at its next regularly scheduled meeting following the giving of such notice and shall provide to the Participants Committee Chair a written response to address the concerns with respect to the Committee officer’s performance not later than five (5) Business Days following such meeting. If the perceived performance deficiencies are with the Chair of a Technical Committee, and a written response is not received from the Board within such five (5) Business Day period, the Vice-Chair shall serve as the acting Chair until such response is received.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 35
Second Restated NEPOOL Agreement
Section 7 - Participants Committee

SECTION 7

PARTICIPANTS COMMITTEE

7.1 Officers. At its annual meeting, the Participants Committee shall elect from among its members a Chair and one or more Vice-Chairs; the Participants Committee shall also select a Secretary, who shall not be a member. These officers shall have the powers and duties usually incident to such offices and as may be established by the Participants Committee.

7.2 Adoption of Budgets. At each annual meeting, the Participants Committee shall adopt a NEPOOL budget for the ensuing calendar year. In adopting budgets the Participants Committee shall give due consideration to the budgetary requests of each committee. The Participants Committee may modify any NEPOOL budget from time to time after its adoption.

7.3 Appointment and Compensation of NEPOOL Personnel. The Participants Committee shall determine what personnel and/or consultants are desirable for the effective operation and administration of NEPOOL and shall fix or authorize the fixing of the compensation for such persons. In addition, the Participants Committee shall determine what resources are desirable for the effective operation of the Technical Committees and shall, on its own or pursuant to the recommendation of a Technical Committee, authorize the incurrence of such expenses as may be required to enable the Technical Committee, or its subgroups, to properly perform their duties, including, but not limited to, the retention of a consultant or the procurement of computer time.

7.4 Budget & Finance Subcommittee. There shall be a Budget & Finance Subcommittee of the Participants Committee that shall provide input and advice to the System Operator and the Participants Committee as set forth in Section 8.4 of the Participants Agreement.

7.5 Appeal of Actions to Review Board. Any Participant which is aggrieved by a Participants Committee action or failure to take action under this Agreement may, as provided herein, submit the matter for resolution hereunder. Except as otherwise provided in Section 6.10, such an appeal shall be taken prior to the end of the fifth (5th) Business Day following the meeting of the Participants Committee to which the appeal relates by giving to the Secretary of the Participants Committee and the General Counsel of the System Operator by hand delivery, facsimile, electronic mail or regular mail a signed and written notice of appeal, a copy of which the Secretary shall provide to each Participant. To the extent any appeal relates to the Participants Committee’s action with respect to a rule or procedure which must be filed with the Commission by the System Operator, the Review Board in its sole discretion may request that the System Operator delay any filing regarding the action being appealed from pending a Review Board decision, which request the System Operator in its sole discretion can accept or reject. Nothing in this Section 7.5 shall be construed to require the Commission to delay its decision on any matter before it because an appeal is pending before the Review Board.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 36
Second Restated NEPOOL Agreement
Section 8 - Markets Committee

SECTION 8

MARKETS COMMITTEE

8.1 Officers. The Markets Committee shall have a Chair, Vice-Chair and Secretary. The Chair and Secretary of the Markets Committee shall be appointed by the System Operator from time to time in accordance with the provisions of the Participants Agreement. The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice-Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Markets Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas.

8.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth (5th) Business Day following a meeting of the Markets Committee, the Secretary of the Markets Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Markets Committee at such meeting.

8.3 Appeal of Actions. Any Participant may appeal to the Participants Committee any substantive recommendation or action by the Markets Committee. Such an appeal shall be taken prior to the end of the fifth (5th) Business Day following the meeting of the Markets Committee to which the appeal relates by giving to the Secretary of the Participants Committee and the General Counsel of the System Operator a signed and written notice of appeal, a copy of which the Secretary shall provide to each member and alternate of the Participants Committee. To the extent the vote is decisional as opposed to advisory, pending action on the appeal by the Participants Committee, the giving of a notice of appeal of that decisional vote shall suspend the action appealed from.

8.4 Establishment of Subcommittees and Task Forces. The Markets Committee shall have the authority to establish subcommittees and task forces for particular studies.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 37
Second Restated NEPOOL Agreement
Section 9 - Reliability Committee

SECTION 9

RELIABILITY COMMITTEE

9.1 Officers. The Reliability Committee shall have a Chair, Vice-Chair and Secretary. The Chair and Secretary of the Reliability Committee shall be appointed by the System Operator from time to time in accordance with the provisions of the Participants Agreement. The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice-Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Reliability Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas.

9.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth (5th) Business Day following a meeting of the Reliability Committee, the Secretary of the Reliability Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Reliability Committee at such meeting.

9.3 Appeal of Actions. Any Participant may appeal to the Participants Committee any substantive recommendation or action by the Reliability Committee. Such an appeal shall be taken prior to the end of the fifth (5th) Business Day following the meeting of the Reliability Committee to which the appeal relates by giving to the Secretary of the Participants Committee and the General Counsel of the System Operator a signed and written notice of appeal, a copy of which the Secretary shall provide to each member and alternate of the Participants Committee. To the extent the vote is decisional as opposed to advisory, pending action on the appeal by the Participants Committee, the giving of a notice of appeal of that decisional vote shall suspend the action appealed from.

9.4 Establishment of Subcommittees and Task Forces. The Reliability Committee shall have the authority to establish subcommittees and task forces for particular studies.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 38
Second Restated NEPOOL Agreement
Section 10 - Transmission Committee

SECTION 10

TRANSMISSION COMMITTEE

10.1 Officers. The Transmission Committee shall have a Chair, Vice-Chair and Secretary. The Chair and Secretary of the Transmission Committee shall be appointed by the System Operator from time to time in accordance with the provisions of the Participants Agreement. The Chair will be responsible for presiding at meetings of the Committee and establishing agendas for its meetings in conjunction with the Vice-Chair and shall have the powers and duties as set forth in the Committee bylaws. The Secretary shall have the powers and duties usually incident to such office and as set forth in the Committee bylaws. The Chair and Secretary shall have no voting rights. The Vice-Chair shall be elected by the Transmission Committee from among its voting members from time to time. The Vice-Chair shall have the powers and duties usually incident to such office and such powers and duties as set forth in the Committee bylaws, including, without limitation, the responsibility to develop in conjunction with the Chair, Committee meeting agendas.

10.2 Notice to Members and Alternates of Participants Committee. Prior to the end of the fifth (5th) Business Day following a meeting of the Transmission Committee, the Secretary of the Transmission Committee shall give written notice to the System Operator and each member and alternate of the Participants Committee of any action taken by the Transmission Committee at such meeting.

10.3 Appeal of Actions. Any Participant may appeal to the Participants Committee any substantive recommendation or action by the Transmission Committee. Such an appeal shall be taken prior to the end of the fifth (5th) Business Day following the meeting of the Transmission Committee to which the appeal relates by giving to the Secretary of the Participants Committee and the General Counsel of the System Operator a signed and written notice of appeal, a copy of which the Secretary shall provide to each member and alternate of the Participants Committee. To the extent the vote is decisional as opposed to advisory, pending action on the appeal by the Participants Committee, the giving of a notice of appeal of that decisional vote shall suspend the action appealed from.

10.4 Establishment of Subcommittees and Task Forces. The Transmission Committee shall have the authority to establish subcommittees and task forces for particular studies.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 39
Second Restated NEPOOL Agreement
Section 11 - Review Board

SECTION 11

REVIEW BOARD

11.1 Organization. There shall be a Review Board which shall be responsible for ruling on appeals taken from actions (or the failure to take action) of the Participants Committee and for advising the Participants Committee as to the issues raised on any appeals before it provided that appeals from actions of the System Operator shall not be taken to the Review Board. In ruling on appeals, the Review Board shall consider, among other things, whether the action is consistent with Commission policies. In addition, if the appeal relates to the Participants Committee action (or failure to take action) on an amendment to this Agreement or a vote on a Market Rule, the Review Board shall consider the extent to which such amendment or vote is consistent with the objectives identified in Section 5.1 of this Agreement. The Review Board shall not have the right to review or otherwise participate in actions of the System Operator or to take any action with respect to any matter involving a dispute between the System Operator and either NEPOOL or any Participant.

11.2 Composition. The Review Board shall be composed at the election of the Participants Committee of four (4) or five (5) members. The Review Board Members shall be selected by the Participants Committee. An independent consultant, retained by the Participants Committee, shall prepare a list of persons qualified and willing to serve on the Review Board. A subcommittee appointed by the Participants Committee shall review the list and distribute to the members of the Participants Committee a slate from among the list proposed by the independent consultant, along with information on the background and experience of the persons on the slate appropriate to evaluating their fitness for service on the Review Board. If the Participants Committee fails to select a full Review Board from the slate proposed by the subcommittee, the Committee shall direct the independent consultant to propose a further list of nominees for consideration at the next regular meeting of the Participants Committee. Thereafter, prior to the expiration of a Review Board Member’s term, and upon the occurrence of any vacancy on the Board, the Participants Committee shall select a successor Member.

11.3 Qualifications. The Review Board Members shall be independent experts knowledgeable about issues typically faced by entities engaged in Energy production, transmission, distribution and sale under Federal or State regulation. A Review Board Member shall not be, and shall not have been at any time within five (5) years of election to the Review Board, a director, officer or employee of a Participant or of a Related Person of a Participant. Except as otherwise provided in the Code of Conduct and Ethics Policy of the Review Board adopted by the Participants Committee, while serving on the Review Board, a Review Board Member (a) shall not have a material ongoing business or professional relationship or other affiliation with any Participant or its Related Persons and (b) shall otherwise be subject to the same independence requirements imposed on Directors of the System Operator Board of Directors.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 40
Second Restated NEPOOL Agreement
Section 11 - Review Board

11.4 Term. Each Review Board Member shall have a term of four (4) years.

11.5 Meetings. Meetings of the Review Board may be conducted in person or by telephone or other electronic means by means of which all persons participating in the meeting can communicate in real time with each other.

11.6 Bylaws. To the extent not inconsistent with any provision of this Agreement, the Participants Committee shall adopt bylaws establishing procedures for the Review Board’s activities as it may deem appropriate, including but not limited to bylaws governing the scheduling, noticing and conduct of meetings of the Review Board, a code of conduct, selection of a Chair and Vice-Chair of the Review Board, and action by the Review Board without a meeting. Such bylaws shall not modify or be inconsistent with any of the rights or obligations established by this Agreement.

11.7 Procedure on Appeal of Participant Committee Action or Failure to Take Action.

(a) Submission of an Appeal. A Participant seeking review (“Appealing Party”) by the Review Board of action (or failure to take action) of the Participants Committee shall give written notice of the appeal in accordance with Section 7.5.

(b) Intervenors and Time Limits. Any other Participant that wishes to participate in the appeal proceeding hereunder shall give signed written notice to the Secretary of the Participants Committee no later than five (5) Business Days after the Appealing Party has provided its brief written statement of its complaint and a statement of the remedy or remedies it seeks or such other time as permitted by the Review Board and shall upon the approval of the Review Board be permitted to participate in the appeal.

(c) Procedural Rules. The procedural rules (if any), for the conduct of appeals shall be determined by the Review Board in consultation with the Participants Committee, subject to adjustment by the Review Board on a case-by-case basis if and as the Review Board determines such adjustment to be appropriate.

(d) Pre-hearing Submissions. Each Appealing Party shall provide the Review Board, within the same period for the giving of written notice of the appeal in accordance with Section 7.5, a brief written statement of its complaint and a statement of the remedy or remedies it seeks, accompanied by copies of any documents or other materials it wishes the Review Board to review. The Participants Committee and, as appropriate, any other Participant wishing to participate in the appeal will provide the Review Board, within the same period for the giving of written notice of the request to participate in the appeal in accordance with Section11.7(b), copies of the minutes of all NEPOOL committee meetings at which the matter was discussed and if deemed appropriate by the Participants Committee or otherwise requested by the Review Board a brief description of the action (or failure to act) being appealed and a brief statement explaining the action (or failure to act) of the Participants Committee, together with copies of documents or other materials referenced in such submission for the Review Board to review and

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 41
Second Restated NEPOOL Agreement
Section 11 - Review Board

materials, if any, which interested Participants provide to the Secretary of the Participants Committee and reasonably request be submitted to the Review Board. The Review Board upon motion may grant extensions to file beyond the specified time periods other than the initial notice of appeal for good cause shown provided no party will be disadvantaged and it will not delay the rendering of a decision beyond the deadline in Section 11.7(g).

In addition, each party shall designate one or more individuals to be available to answer questions the Review Board may have on the documents or other materials submitted. The answers to all such questions shall be reduced to writing by the party providing the answer and a copy shall be made available to any requesting Participant.

(e) Request for Deferral of Filing. The Review Board with such consultation as it deems appropriate shall promptly review materials submitted to it and may, in its discretion, request that the System Operator delay the filing with the Commission of any materials that are the subject of the appeal. If such a request is made, the System Operator in its sole discretion may elect to delay or not delay any such filing. If no such request is made or a filing relating to the subject matter of the appeal is made notwithstanding that request, the Commission shall be advised that an appeal for an advisory decision of the Review Board has been filed and is pending.

(f) Hearing. A hearing (if any) will be held as soon as is reasonably practicable.

(g) Decision. The Review Board’s decision on any appeal shall be due within thirty-five (35) Business Days from the giving of the notice of appeal.

(h) Post Decision. If the Review Board grants an appeal and makes a recommendation as to how to address the subject of any appeal, the Secretary of the Participants Committee shall present that decision to the Participants Committee for consideration and the System Operator for a response in accordance with the requirement of the Participants Agreement. If the matter that is the subject of the appeal is pending before or subsequently presented to the Commission in a proceeding, any decision or response to that decision shall be submitted promptly to the Commission for consideration in such proceeding.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 42
Second Restated NEPOOL Agreement
Section 11 - Review Board

11.8 Effect of a Review Board Decision.

(a) Each Review Board Member shall have one vote and an action of the Review Board, either to grant or deny an appeal, shall require affirmative votes by at least three (3) Review Board Members.

(b) The Review Board decision shall state whether the Review Board grants or denies the appeal. If the Review Board denies the appeal, no further action is required by the Participants Committee. If the Review Board grants the appeal, the Review Board may recommend how to address the subject of the appeal. Any such recommendation shall be advisory only.

(c) If the Review Board grants an appeal and makes a recommendation as to how to address the subject of the appeal, the System Operator will respond in writing to any such recommendation as set forth in Section 11.6 of the Participants Agreement.

11.9 Rights to Seek Further Review. Any action taken or failure to take action by the Review Board does not restrict or limit in any way the rights of a Participant to seek review by the Commission, or a review in any other forum available to the Participant and there shall be no requirement to submit an appeal to the Review Board concerning any amendment, action or inaction by the Participants Committee prior to a Participant exercising any such rights to seek review by the Commission or any other forum with jurisdiction.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 43
Second Restated NEPOOL Agreement
Section 12 - Publicly Owned Entities

SECTION 12

PUBLICLY OWNED ENTITIES

The purpose of this Section 12 is to facilitate: (i) the participation of the Publicly Owned Entities in the New England Markets in a manner that is consistent with State laws governing the organization or operation of the Publicly Owned Entities and (ii) the transfer of operating authority for transmission facilities owned or operated by the Publicly Owned Entities to the System Operator pursuant to the Transmission Operating Agreement in a manner that is consistent with State laws governing the organization or operation of the Publicly Owned Entities.

12.1 Capacity Obligations of Publicly Owned Entities. Each Participant that is a Publicly Owned Entity shall have generating capacity (or other resources corresponding to resource adequacy criteria established under the Market Rules) during each hour of each month at least sufficient to satisfy its obligations with respect to resource adequacy under the Market Rules; provided, however, that this Section 12.1 shall not impose any greater obligation than that imposed under the Market Rules.

12.2 Central Dispatch of the Resources of Publicly Owned Entities. Subject to the following sentence, each Participant that is a Publicly Owned Entity shall, to the fullest extent practicable, subject all generating facilities and other resources owned or controlled by it to central dispatch by the System Operator in accordance with and subject to the System Rules; provided, however, that each Participant shall at all times be the sole judge as to whether or not and to what extent safety requires that at any time any of such facilities will be operated at less than full capacity or not at all. Each Participant that is a Publicly Owned Entity may remove from central dispatch a generating facility or other resource(s) owned or controlled by it to the extent such removal is permitted by the System Rules.

12.3 Market Transactions of Publicly-Owned Entities. The rights and obligations of the Participants that are Publicly Owned Entities with respect to their participation in the New England Markets shall be determined in accordance with, and shall be governed by, the Market Rules; provided, however, that this Section 12.3 shall not impose any obligation or create any rights with respect to Publicly Owned Entities other than those obligations that are imposed or those rights that are created with respect to participants in the New England Markets generally under the Market Rules.

12.4 Maintenance and Operation of Publicly Owned Entity Transmission Facilities in Accordance with Good Utility Practice. Each Participant that is a Publicly Owned Entity and which owns or operates PTF or other transmission facilities rated 69 kV or above shall, to the fullest extent practicable, cause all such transmission facilities owned or operated by it to be designed, constructed, maintained and operated in accordance with Good Utility Practice; provided, however, that this Section shall not impose any greater obligation on Participants that

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 44
Second Restated NEPOOL Agreement
Section 12 - Publicly Owned Entities

are Publicly Owned Entities than is imposed on other transmission-owning Entities that are subject to the Transmission Operating Agreement.

12.5 Central Dispatch of Publicly-Owned Entity Transmission Facilities. Each Participant that is a Publicly Owned Entity and which owns or operates PTF or other transmission facilities rated 69 kV or above shall, to the fullest extent practicable, subject all such transmission facilities owned or operated by it to central dispatch by the System Operator in accordance with the terms of the Transmission Operating Agreement; provided, however, that each Participant shall at all times be the sole judge as to whether or not and to what extent safety requires that at any time any of such facilities will be operated at less than their full capability or not at all.

12.6 Maintenance and Repair of Publicly Owned Entity Transmission Facilities. Each Participant that is a Publicly Owned Entity shall, to the fullest extent practicable: (a) cause transmission facilities owned or operated by it to be withdrawn from operation for maintenance and repair only in accordance with maintenance schedules reported to and published by the System Operator in accordance with procedures approved or established by the System Operator pursuant to the Transmission Operating Agreement from time to time, (b) restore such facilities to good operating condition with reasonable promptness, and (c) in emergency situations, accelerate maintenance and repair at the reasonable request of the System Operator in accordance with the System Rules; provided, however, that this Section 12.6 shall not impose any greater obligation on Participants that are Publicly Owned Entities than is imposed on other transmission-owning Entities that are subject to the Transmission Operating Agreement.

12.7 Modification and Termination of Section 12. Notwithstanding Section 16.9 hereof with respect to amending the Second Restated NEPOOL Agreement, this Section 12 of the Second Restated NEPOOL Agreement may not be modified without the express and unanimous consent of the Publicly Owned Entities who are Participants at the time of such modification. Notwithstanding any other provision of this Agreement, this Section 12 of the Second Restated NEPOOL Agreement may be terminated unilaterally by unanimous vote of the Publicly Owned Entities, without any other action by other Participants.

SECTION 13

[RESERVED]

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 45
Second Restated NEPOOL Agreement
Section 14 - Expenses

SECTION 14

EXPENSES

14.1 Annual Fee. Each Participant shall pay to NEPOOL for the first calendar year or portion thereof in which it becomes a Participant and in January of each subsequent calendar year an annual fee, which shall be applied toward Participant Expenses, as follows:

(a) Each End User Participant which is a Small End User or an End User Organization shall pay an annual fee of $500.

(b) Each End User Participant which is a Large End User shall pay an annual fee of $500; plus an additional fee of $500 per megawatt hour of its highest hourly load during any hour in the preceding year (net of any use of on-site generation during such hour) up to a maximum of $5,000; plus an additional fee of $200 per megawatt hour for each megawatt hour by which its highest Energy use during any hour in the preceding year (net of any use of on-site generation during such hour) exceeded 20 megawatt hours.

(c) Each Participant which is a DRP shall pay an annual fee of $5,000; plus an additional fee of $20 per megawatt month for each megawatt month of installed capacity credit given to such DRP in the preceding year pursuant to the Load Response Program.

(d) Each Participant which is an AR Provider but not a DRP shall pay an annual fee of $5,000, except that any AR Provider, which together with its Related Persons owns or controls less than 5 MW (or its equivalent) of Alternative Resources and is represented by the Small Renewable Generation Group Member, Small Distributed Generation Group Member, or Small Load Response Group Member shall pay $1,000.

(e) Each Participant which is a Publicly Owned Entity and a member of the Publicly Owned Entity Sector shall pay an annual fee of $5,000, except that any such Participant which is engaged in electricity distribution and had annual Energy sales of less than 30,000 megawatt hours in the preceding year shall pay an annual fee of $500, and the difference between $5,000 and $500 for each such Participant shall be paid, as an additional fee, by the remaining Participants which are Publicly Owned Entities and members of the Publicly Owned Entity Sector.

(f) Each Participant other than an End User Participant, a DRP, an AR Provider, or a Publicly Owned Entity shall pay an annual fee of $5,000.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 46
Second Restated NEPOOL Agreement
Section 14 - Expenses

14.2 Participant Expenses.

(a) Each Market Participant End User (or each Individual RTO Participant deemed to be such) shall be required to pay monthly a portion of Participant Expenses determined on the basis of such Entity’s highest hourly load in any month in the preceding calendar year (“Peak Load”), in accordance with the following schedule:

Peak Load Obligation of Market Participant End User (or Individual RTO Participant)	Annual Participant Expenses Allocated to Market Participant End User (or Individual RTO Participant)
less than 20 KW	$100
20 KW < X < 100 KW	$250
100 KW < X < 1,000 KW (1 MW)	$1,000
1 MW < X < 5 MW	$1,000 per megawatt
> 5 MW	amount equal to the lowest amount of Participant Expenses paid by an individual voting Participant in the Generation, Transmission, or Supplier Sectors pursuant to Section 1.1 of this Agreement

The annual share of Participant Expenses allocated to an Entity under this Section 14.2(a) whose highest hourly load in any hour for the preceding calendar year was greater or equal to 5 MW shall be reduced, on a dollar-for-dollar basis, by the amount by which the additional fees paid by such Entity pursuant to Section 14.1(b) of this Agreement exceed $5,000.

(b) Each Load Response Resource Provider or Distributed Generation Resource Provider that is represented by a voting member in the Load Response Sub-Sector or Distributed Generation Sub-Sector (or each Individual RTO Participant deemed to be such) shall be required to pay monthly one-twelfth (1/12) of the following amount: (i) if represented by an individual voting member (or an Individual RTO Participant deemed to be a member of the Sub-Sector with 5 MW or more (or its equivalent) of Alternative Resources), each Load Response

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 47
Second Restated NEPOOL Agreement
Section 14 - Expenses

Resource Provider or Distributed Generation Resource Provider (or Individual RTO Participant) shall pay $5,000 plus an additional amount of $267 per MW (or its equivalent) of Alternative Resources up to the amount equal to the lowest amount of Participant Expenses paid by a Participant which designates an individual voting member in the Generation, Transmission, or Supplier Sectors; (ii) if represented by a Self-Defined Load Response Group Member or a Self-Defined Distributed Generation Group Member, the Participants represented by each such self-defined group member shall together pay $5,000 plus an additional amount of $267 per MW (or its equivalent) of Alternative Resources up to the amount equal to the lowest amount of Participant Expenses paid by a Participant in the Generation, Transmission, or Supplier Sectors which designates an individual voting member of each Principal Committee; and (iii) if represented by a Small Load Response Group Member or a Small Distributed Generation Group Member (or an Individual RTO Participant deemed to be a member of the Sub-Sector with less than 5 MW (or its equivalent) of Alternate Resources), each Participant (or Individual RTO Participant) shall pay $1,000 plus an additional amount of $267 per MW (or its equivalent) of Alternative Resources.

(c) Renewable Generation Resource Providers which are represented by a voting member in the Renewable Generation Sub-Sector and which own or control 15 MW or less of Renewable Generation Resources and which are represented either by an individual voting member or a Self-Defined Renewable Generation Group Member whose members own or control 15 MW or less of Renewable Generation Resources or the Small Renewable Generation Group Member (or an Individual RTO Participant deemed to be in the Renewable Generation Sub-Sector which owns or controls 15 MW or less of Alternative Resources) shall be required to pay monthly one-twelfth (1/12) of the following amount: (i) if represented by an individual voting member (or an Individual RTO Participant) or a Self-Defined Renewable Generation Group Member representing Participants which own or control 5 or more MW (but in no event more than 15 MW) of Alternative Resources, $5,000 per voting member (or Individual RTO Participant) plus an additional amount of $267 per MW of Alternative Resources up to the amount equal to the lowest amount of Participant Expenses paid by a Participant in the Generation, Transmission, or Supplier Sectors which designates an individual voting member of each Principal Committee; and (ii) if represented by the Small Renewable Generation Group Member (or Individual RTO Participant deemed to be in the Renewable Generation Sub-Sector with less than 5 MW of Alternative Resources), Renewable Generation Resource Providers (or Individual RTO Participants) shall each pay $1,000 plus an additional amount of $267 per MW of Alternative Resources.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 48
Second Restated NEPOOL Agreement
Section 14 - Expenses

(d) The balance of Participant Expenses remaining to be paid after the application of (i) the annual fees to be paid pursuant to Section 14.1, (ii) the share of Participant Expenses paid pursuant to Sections 1.1(a) through 1.1(c) above and Section 14.3 of the Participants Agreement, and (iii) any fees or other charges for services or other revenues received by NEPOOL, or collected on its behalf by the System Operator, shall be divided into Sector shares as follows:

(1) Renewable Generation Sub-Sector Share shall be the lesser of 10% or 2% times the sum of (A) individual voting members that represent Renewable Generation Resource Providers with 15 MW of Renewable Generation Resources plus (B) Self-Defined Renewable Generation Group Members that represent Renewable Generation Resource Providers with more than 15 MW of Renewable Generation Resources plus (C) Individual RTO Participants deemed to be in the Sub-Sector and which own or control more than 15 MW of Renewable Generation Resources;

(2) Generation, Transmission, Supplier and Publicly Owned Entity Sector Shares shall each be one-fourth of the balance of Participant Expenses minus the Renewable Generation Sub-Sector Share.

(e) The Sector shares shall be allocated and paid as follows:

(1) in the Supplier Sector, Related Person Suppliers shall each pay a portion of the Supplier Sector share in the same proportion as the vote that Participant is entitled to in the Supplier Sector;

(2) the balance of the Supplier Sector share, the Generation Sector share, and the Renewable Generation Sub-Sector Share shall then be aggregated together with the resulting amount allocated equally among all Individual RTO Participants deemed to be in such Sectors and all voting members (other than the Related Person Suppliers) of the Supplier and Generation Sectors, and the Renewable Generation Sub-Sector (other than the Entities whose expense shares are determined pursuant to Section 14.2(c)); and

(3) in the Transmission and Publicly Owned Entity Sectors, the Sector share shall be allocated equally to the Participants in, and the Individual RTO Participants deemed to be in, that Sector;

provided, however, that two (2) or more of such Entities can modify the allocation of the Sector share of Participant Expenses as between or among them pursuant to unanimous agreement of all such Entities whose share of Participant Expenses would be affected by such modified allocation.

(f) Participants in a Sector or Sub-Sector that are represented by, and Individual RTO Participants that if members would be required to be represented by, a group voting member shall subdivide their portion of the Sector’s or Sub-Sector’s share of Participant Expenses in such a manner as they may determine by unanimous agreement; provided that if there is not unanimous agreement among such Entities as to how to allocate their portion of the Sector’s or Sub-Sector’s share of Participant Expenses, such portion shall be allocated among such Entities as follows: (i) for each Participant in the Generation Sector represented by, or Individual RTO Participant that if a member would be required to be represented by, a group voting member, the portion will be allocated in the same proportion that the aggregate Governance Rating of generation owned or controlled by the Participant represents of the total

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 49
Second Restated NEPOOL Agreement
Section 15 - Relationships

aggregate Governance Ratings owned or controlled by such Entities; (ii) for each Participant in the Renewable Generation Sub-Sector represented by a Self-Defined Renewable Generation Group Member that represents Participants with Renewable Generation Resources with an aggregate Governance Rating of more than 15 MW, the portion will be allocated in the same proportion that the Governance Rating of Renewable Generation Resources owned or controlled by the Participants represents of the total aggregate Governance Ratings owned or controlled by Participants represented by the Self-Defined Renewable Generation Group Member; and (iii) for Participants in the Transmission Sector (or Individual RTO Participants deemed to be a member of the Transmission Sector), the portion will be allocated equally among such Entities.

(g) For the purpose of determining the aggregate base MW charges under this Section 14.2 to a member of the AR Sector (or an Individual RTO Participant deemed to be an AR Sector member), “MW” shall mean the aggregate Governance Rating of the Alternative Resources owned or controlled by such Entity and its Related Persons that are not Participants.

SECTION 15

RELATIONSHIPS WITH THE SYSTEM OPERATOR

AND NEW ENGLAND STATE AUTHORITIES

15.1 Participants Agreement. The Participants Committee is authorized and directed to approve the Participants Agreement to be entered into with the System Operator and any amendments to the Participants Agreement which the Committee may deem necessary or appropriate from time to time, and to evidence that approval and agreement through the execution by the Chair of the Participants Committee on behalf of NEPOOL of the Participants Agreement and such amendments. The Participants Agreement shall specify (a) the processes by which Participants will provide input to the System Operator, (b) the processes by which the System Operator will receive, consider and respond to such input, and (c) such other rights and obligations of the Participants and the System Operator with respect to the System Operator as shall be agreed to and set forth therein. Each Participant shall comply with the terms and conditions of the Participants Agreement as amended, modified, and restated from time to time, to the same extent as if the Participant were an Individual RTO Participant.

15.2 New England State Authorities. NEPOOL and its committees shall consult and coordinate from time to time with the relevant state regulatory, siting and other authorities of the six New England states.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 50
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

SECTION 16

MISCELLANEOUS PROVISIONS

16.1 Payment of Pool Charges; Termination of Status as Participant.

(a) Any Participant shall have the right to terminate its status as a Participant upon no less than sixty (60) days’ prior written notice given to the Secretary of the Participants Committee.

(b) If at any time during the term of this Agreement a receiver or trustee of a Participant is appointed or a Participant is adjudicated bankrupt or an order for relief is entered under the Federal Bankruptcy Code against a Participant or if there shall be filed against any Participant in any court (pursuant to the Federal Bankruptcy Code or any statute of Canada or any state or province) a petition in bankruptcy or insolvency or for reorganization or for appointment of a receiver or trustee of all or a portion of the Participant’s property, and within ninety (90) days after the filing of such a petition against the Participant, the Participant shall fail to secure a discharge thereof, or if any Participant shall file a petition in voluntary bankruptcy or seeking relief under any provision of any bankruptcy or insolvency law or shall make an assignment for the benefit of creditors, the Participants Committee may terminate such Participant’s status as a Participant as of any time thereafter.

(c) Each Participant is obligated to pay when due all amounts invoiced to it by NEPOOL, or by the System Operator on its own behalf or on behalf of NEPOOL, in accordance with ISO Operating Documents. If a Participant fails to meet its obligations hereunder, NEPOOL may terminate such member’s status as a Participant. If a Participant disputes an invoice with respect to charges hereunder, it shall be entitled to continue to remain a member so long as the Participant (i) continues to make all payments not in dispute, and (ii) pays into an independent escrow account the portion of the invoice in dispute, pending resolution of the dispute.

(d) In the event a Participant fails, for any reason other than a billing dispute as described in subsection (c) of this Section 16.1, to pay when due all amounts invoiced to it by NEPOOL, or by the System Operator on its own behalf or on behalf of NEPOOL (a “Payment Default”), or the Participant fails to perform any other obligation under this Agreement, and such failure continues for at least five (5) days in the case of a Payment Default and for at least ten (10) days in the case of any other default, NEPOOL, or the System Operator on behalf of NEPOOL, may (but shall not be required to) notify such Participant in writing, electronically and by first class mail sent in each case to such Participant’s member or alternate on the Participants Committee or billing contact, that it is in default, and NEPOOL may initiate a proceeding before the Commission to terminate such Participant’s status as a Participant. Simultaneously with the giving of the notice described in the preceding sentence in the case of a Payment Default and within ten (10) days after the giving of such notice in the case of any other default (unless the

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 51
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

default giving rise to such notice is cured during such period), NEPOOL, or the System Operator on behalf of NEPOOL, shall notify each other member and alternate on the Participants Committee and each Participant’s billing contact of the identity of the Participant receiving such notice, whether such notice relates to a Payment Default, or to another failure to perform obligations under this Agreement, and the actions NEPOOL and/or the System Operator on behalf of NEPOOL plans to take and/or has taken in response to such default. Pending Commission action on such termination, NEPOOL may suspend the Participant’s rights under this Agreement on or after fifty (50) days after the giving of such notice and the initiation of such proceeding, in accordance with Commission policy, unless the Participant cures the default within such period. Nothing set forth in this Section 16.1 is intended to limit the additional provisions of the Information Policy, or the financial assurance or billing policies attached to the Tariff relating to defaults. Each Participant that fails to perform any of its obligations under this Agreement shall reimburse NEPOOL and the System Operator for all of the fees, costs and expenses that they incur as a result of such failure, including without limitation all fees, costs and expenses related to proceedings to terminate such Participant.

(e) No such termination of a Participant’s status as a Participant shall affect any obligation of, or to, such former Participant incurred prior to the effective time of such termination.

The provisions of this Section 16.1 shall not be amended without the consent of the System Operator.

16.2 Assignment. This Agreement shall inure to the benefit of, and shall be binding upon, the successors and assigns of the respective signatories hereto, but no assignment shall be made to an Entity that is not a Participant without the written consent of the Participants Committee.

16.3 Force Majeure. A Participant shall not be considered to be in default in respect of any obligation hereunder if prevented from fulfilling such obligation by an event of Force Majeure. An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any Curtailment, any order, regulation or restriction imposed by a court or governmental military or lawfully established civilian authorities, or any other cause beyond a Participant’s control, provided that no event of Force Majeure affecting any Participant shall excuse that Participant from making any payment that it is obligated to make under this Agreement. A Participant whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement, and shall promptly notify the Participants Committee of the commencement and end of any event of Force Majeure.

16.4 Waiver of Defaults. No waiver of the performance by a Participant of any obligation under this Agreement or with respect to any default or any other matter arising in

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 52
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

connection with this Agreement shall be effective unless given by the Participants Committee. Any such waiver by the Participants Committee in any particular instance shall not be deemed a waiver with respect to any subsequent performance, default or matter.

16.5 Other Contracts. No Participant shall be a party to any other agreement which in any manner is inconsistent with its obligations under this Agreement.

16.6 Liability and Insurance.

(a) Each Participant will indemnify and save each of the other Participants, its officers, directors and Related Persons (each an “Indemnified Party”) harmless from and against all actions, claims, demands, costs, damages and liabilities asserted by a third party against the Indemnified Party seeking indemnification and arising out of or relating to bodily injury, death or damage to property caused by or sustained in connection with the participation by such Participant in the committee processes that are the subject of this Agreement, except (i) to the extent that such liabilities result from the negligence or willful misconduct of the Participant seeking indemnification, and (ii) each Participant shall be responsible for all claims of its own employees, agents and servants growing out of any workmen’s compensation law. The amount of any indemnity payment under the provisions of this Section 16.6 shall be reduced (including, without limitation, retroactively) by any insurance proceeds or other amounts actually recovered by the Indemnified Party in respect of the indemnified action, claim, demand, cost, damage or liability. Notwithstanding the foregoing, no Participant shall be liable to any Indemnified Party for any claim for loss of profits or revenues, attorneys’ fees or costs arising from the foregoing or for any other indirect, incidental, special, consequential, punitive, or multiple damages or loss; provided, however, that nothing herein shall reduce or limit the obligations of any Participant to Non-Participants.

(b) Each Participant shall furnish, at its sole expense, such insurance coverage as the Participants Committee may reasonably require with respect to its obligation pursuant to Section 16.6(a).

16.7 Records and Information. Each Participant shall make reasonable efforts to furnish to a NEPOOL committee such records, reports and information as such NEPOOL committee may reasonably request for the administration of this Agreement, provided the confidentiality thereof is protected in accordance with the Information Policy. Each Participant shall also provide records, reports and information to the System Operator in accordance with the terms and conditions of the Participants Agreement, the MPSA, and the TOA, and subject to the terms and conditions of the Information Policy.

16.8 Construction.

(a) The Table of Contents contained in this Agreement and the headings of the Sections of this Agreement are intended for convenience only and shall not be deemed to be part of this Agreement or considered in construing it.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 53
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

(b) This Agreement shall be interpreted, construed and governed in accordance with the laws of the State of Connecticut.

16.9 Amendment.

(a) Subject to the provisions of this Section 16.9, this Agreement and any attachment or exhibit hereto may be amended from time to time by vote of the Participants in accordance with Section 6.10 and approval by the Board of Directors of the System Operator for amendments to any Sections requiring such approval. Any amendment to this Agreement so approved shall be in writing and shall bind all Participants regardless of whether they have executed a ballot in favor of such amendment. An Amendment shall become effective on the date specified in the amendment; provided that no provision of such an amendment that conflicts with the Participants Agreement shall become effective. Nothing herein shall be construed to prevent any Participant from challenging any proposed amendment before a court or regulatory agency on the ground that the proposed amendment or its application to the Participant is in violation of law or of this Agreement.

(b) This Agreement shall not be amended or construed to include any provision which conflicts with or modifies any provision of the Tariff, TOA, the MPSA or the Participants Agreement, or which expands, diminishes or otherwise affects any rights or obligations of any party to such agreements, and no Participant shall make a filing with the Commission that is inconsistent with the foregoing.

16.10 Termination. This Agreement shall continue in effect until terminated, in accordance with the Commission’s regulations, by Participants represented by members of the Participants Committee having Member Fixed Voting Shares equal to at least 70% of the Member Fixed Voting Shares of all Participants. No such termination shall relieve any party of any obligation arising prior to the effective time of such termination. Further, no such termination shall relieve any party of its obligations under the Participants Agreement or Tariff, which shall continue under each until the party’s status thereunder is separately terminated as provided in that Agreement or Tariff.

16.11 Notices to Participants, Committees, or Committee Members.

(a) Any notice, demand, request or other communication required or authorized by this Agreement to be given to any Participant shall be in writing, and shall be (i) personally delivered to the Participants Committee member or alternate representing that Participant; (ii) mailed, postage prepaid, to the Participant at the address of its member on the Participants Committee as set out in the NEPOOL roster; (iii) sent by facsimile (“faxed”) to the Participant at the fax number of its member on the Participants Committee as set out in the NEPOOL roster; or (iv) delivered electronically to the Participant at the electronic mail address of its member on the Participants Committee or at the address of its principal office. The designation of any such address may be changed at any time by written notice delivered to the

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 54
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

Secretary of the Participants Committee, who shall cause such change to be reflected in the NEPOOL roster.

(b) Any notice, demand, request or other communication required or authorized by this Agreement to be given to any NEPOOL committee shall be in writing and shall be delivered to the Secretary of the committee. Each such notice shall either be personally delivered to the Secretary, mailed, postage prepaid, or sent by facsimile (“faxed”) to the Secretary at the address or fax number set out in the NEPOOL roster, or delivered electronically to the Secretary. The designation of such address may be changed at any time by written notice delivered to each Participant.

(c) Any notice, demand, request or other communication required or authorized by this Agreement to be given to the Review Board shall be in writing and shall be delivered to the Board’s administrative office set out in the Review Board’s Rules of Procedure. Each such notice shall either be personally delivered to the Board’s administrative office, or mailed, postage prepaid, to the Board or delivered electronically to the Board at the address set out in the Review Board’s Rules of Procedure. The designation of such address may be changed at any time by written notice delivered to each Participant.

(d) Any notice, demand, request or other communication required or authorized by this Agreement to be given to a member or alternate to that member of a Principal Committee (for the purposes of this Section 16.11, individually or collectively, the “Committee Member”) shall be (i) personally delivered to the Committee Member; (ii) mailed, postage prepaid, to the Committee Member at the address of the Committee Member set out in the NEPOOL roster; (iii) faxed to the Committee Member at the fax number of the Committee Member set out in the NEPOOL roster; or (iv) delivered electronically to the Committee Member at the electronic mail address of the Committee Member set out in the NEPOOL roster. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Principal Committee on which the Committee Member serves, who shall cause such change to be reflected in the NEPOOL roster.

(e) To the extent that the Participants Committee is required to serve upon any Participant a copy of any document or correspondence filed with the Commission under the Federal Power Act or the Commission’s rules and regulations thereunder, by or on behalf of any Principal Committee, such service may be accomplished by electronic delivery to the Participant at the electronic mail address of its Participants Committee member and alternate. The designation of any such address may be changed at any time by written notice delivered to the Secretary of the Participants Committee.

(f) Any such notice, demand or request so addressed and mailed by registered or certified mail shall be deemed to be given when so mailed. Any such notice, demand, request or other communication sent by regular mail or faxed or delivered electronically shall be deemed

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 55
Second Restated NEPOOL Agreement
Section 16 - Miscellaneous Provisions

given when received by the Participant, Committee Member, or Secretary of the NEPOOL committee, whichever is applicable.

16.12 Severability and Renegotiation.

(a) If any provision of this Agreement is held by a court or regulatory authority of competent jurisdiction to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions of this Agreement shall continue in full force and effect and shall in no way be affected, impaired or invalidated, except as otherwise explicitly provided in this Section.

(b) If any provision of this Agreement is held by a court or regulatory authority of competent jurisdiction to be invalid, void or unenforceable, or if this Agreement is modified or conditioned by a regulatory authority exercising jurisdiction over this Agreement, the Participants shall endeavor in good faith to negotiate such amendment or amendments to this Agreement as will restore the relative benefits and obligations of the Participants under this Agreement immediately prior to such holding, modification or condition. If after sixty (60) days such negotiations are unsuccessful the Participants may exercise their withdrawal or termination rights under this Agreement.

16.13 No Third-Party Beneficiaries. This Agreement is intended to be solely for the benefit of the Participants and their respective successors and permitted assigns and, unless expressly stated herein, is not intended to and shall not confer any rights or benefits on any third party (other than successors and permitted assigns) not a signatory hereto.

16.14 Counterparts. This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages.

IN WITNESS WHEREOF, the signatories have caused this Agreement to be executed by their duly authorized officers or representatives.

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

New England Power Pool	Sheet No. 56
Second Restated NEPOOL Agreement
Schedule 3.1 - Participant Transmission Owners

Schedule 3.1

Participant Transmission Owners

Bangor Hydro-Electric Company

Boston Edison Company

Cambridge Electric Light Company

Canal Electric Company

Central Maine Power Company

Commonwealth Electric Company

The Connecticut Light and Power Company

Holyoke Power and Electric Company

Holyoke Water Power Company

New England Power Company

Public Service Company of New Hampshire

The United Illuminating Company

Vermont Electric Power Company

Western Massachusetts Electric Company

Issued by:	David T. Doot, Secretary	Effective:	February 1, 2005
Issued on:	September 13, 2004

EX-10.2.1.2

Exhibit 10.2.1.2

TRANSMISSION OPERATING AGREEMENT

TABLE OF CONTENTS

ARTICLE I. DEFINITIONS; INTERPRETATIONS	2
1.01. Definitions; Interpretations	2
ARTICLE II. TRANSMISSION FACILITIES	3
2.01. Transmission Facilities	3
2.02. New Transmission Facilities and Transmission Upgrades	5
2.03. Merchant Facilities	6
2.04. Excluded Assets	6
2.05. Connection with Non-Parties	8
2.06. Review of Transmission Plans	10
2.07. Condemnation	11
ARTICLE III. OPERATING AUTHORITY	11
3.01. Grant of Operating Authority	11
3.02. Definition of ISO Operating Authority	12
3.03. Transmission Services and OATT Administration	16
3.04. Application Authority	20
3.05. The ISO’s Responsibilities	32
3.06. Each PTO’s Responsibilities	33
3.07. Reserved Rights of the PTOs	37
3.08. Repair and Maintenance of Transmission Facilities	39
3.09. Planning and Expansion	41
3.10. Invoicing, Collection and Disbursement of Customer Payments	41
3.11. Grandfathered Transmission Agreements	44

Page No. i

3.12. Subcontractors	44
3.13. Municipal/Tax-Exempt Utilities	45
3.14. No Impairment of the ISO’s Other Legal Rights and Obligations	46
ARTICLE IV. REPRESENTATIONS AND WARRANTIES	46
4.01. Representations and Warranties of Each PTO	46
4.02. Representations and Warranties of the ISO	47
ARTICLE V. COVENANTS OF THE PTOS	48
5.01. Covenants of Each PTO	48
5.02. Financial Statements and Filings	48
5.03. Expenses	48
5.04. Consents and Approvals	48
5.05. Notice and Cure	49
ARTICLE VI. COVENANTS OF THE ISO	49
6.01. Covenants of the ISO	49
6.02. Financial Statements and Filings	49
6.03. Expenses	50
6.04. Consents and Approvals	50
6.05. Notice and Cure	50
6.06. Other PTOs	50
6.07. Management Agreements	51
6.08. ISO Line of Business; Non-Profit Status	52
ARTICLE VII. TAX MATTERS	52
7.01. Responsibility for PTO Taxes	52
7.02. Responsibility for ISO Taxes	52

Page No. ii

ARTICLE VIII. RELIANCE; SURVIVAL OF AGREEMENTS	52
8.01. Reliance; Survival of Agreements	52
ARTICLE IX. INDEMNIFICATION; INSURANCE; ASSUMPTION OF LIABILITIES	53
9.01. Indemnification	53
9.02. Notice of Proceedings	53
9.03. Defense of Claims	54
9.04. Subrogation	55
9.05. Insurance	55
9.06. Assumption of Liability	56
ARTICLE X. TERM; DEFAULT AND TERMINATION	57
10.01. Term; Termination Date	57
(a) Term	57
(b) PTO Withdrawal During The Term	58
(c) Remaining PTOs	59
(d) Termination by the ISO	59
(e) Actions Prior to Withdrawal or Termination	60
(f) Approvals	60
(g) Continuing Obligations	60
10.02. Release of Operating Authority	61
10.03. Events of Default of the ISO	61
(a) Events of Default of the ISO	61
(b) Remedies for Default	62
10.04. Events of Default of a PTO	63

Page No. iii

(a) Events of Default of a PTO	63
(b) Remedies for Default	64
ARTICLE XI. MISCELLANEOUS	65
11.01. Notices	65
11.02. Supersession of Prior Agreements	65
11.03. Waiver	65
11.04. Amendment; Limitations on Modifications of Agreement	65
11.05. Additional Participating Transmission Owners	69
11.06. Integration Charges	70
11.07. No Third Party Beneficiaries	70
11.08. No Assignment; Binding Effect	70
11.09. Further Assurances; Information Policy; Access to Records	71
11.10. Business Day	72
11.11. Governing Law	72
11.12. Consent to Service of Process	72
11.13. Specific Performance; Force Majeure	73
11.14. Dispute Resolution	73
11.15. Invalid Provisions	74
11.16. Headings and Table of Contents	74
11.17. Liabilities; No Joint Venture	74
11.18. Counterparts	74
11.19. Conditions Precedent	75
11.20. Preserved Rights	75

Page No. iv

Schedules

Schedule 1.01. Schedule of Definitions

Schedule 2.01(a). List of Each PTO’s Category A Facilities

Schedule 2.01(b). List of Each PTO’s Category B Facilities

Schedule 3.02(b). List of Interconnection Agreements with neighboring Control Areas and Tariff(s) Applicable to External Transactions

Schedule 3.02(d). List of Existing Operating Procedures

Schedule 3.09(a). Planning and Expansion – Participating Transmission Owner Rights and Obligations

1. PTOs Rights and Obligations to Build and Associated Conditions Including Cost Recovery

2. PTO Obligations

Schedule 3.09(b). List of Existing Planning Procedures

Schedule 3.11(b). List of Grandfathered Intertie Agreements

Schedule 3.11(c). List of Grandfathered Interconnection Agreements

Schedule 4.01(d). PTO New England Transmission Facilities Not Subject to this Agreement

Schedule 11.01. Notices

Schedule 11.02. Superseded Agreements

Schedule 11.04. PTO Administrative Committee

Schedule 11.19(c). Additional Conditions Precedent

Page No. v

TRANSMISSION OPERATING AGREEMENT

This Transmission Operating Agreement (this “TOA” or this “Agreement”), dated as of [            ], 2004, is made and entered into by and among [The names of the Initial PTOs will be submitted in a compliance filing prior to the Operations Date.] (herein collectively referred to as the “Initial Participating Transmission Owners”), and the Initial Participating Transmission Owners along with any Additional Participating Transmission Owners (as defined in Section 11.05 of this Agreement), are collectively referred to herein as the “PTOs” and individually each is referred to as a “PTO”), and ISO New England Inc. (“ISO”), a Delaware corporation (all PTOs and the ISO are collectively referred to herein as the “Parties”).

WHEREAS, each of the PTOs owns and/or operates certain transmission facilities that are interconnected with the transmission facilities of certain other PTOs within the New England Transmission System or otherwise provides transmission service within the New England Transmission System;

WHEREAS, the ISO is a regional transmission organization (“RTO”) authorized by the Federal Energy Regulatory Commission (“FERC”) to exercise the functions required of RTOs pursuant to FERC’s Order No. 2000 (“Order 2000”) and FERC’s RTO regulations;

WHEREAS, in accordance with the requirements of Order 2000, the ISO will be the transmission provider under the ISO Open Access Transmission Tariff (the “ISO OATT”) of non-discriminatory, open access transmission services over the transmission facilities of the PTOs (“Transmission Service”);

WHEREAS, the ISO OATT will be designed to provide for the payment by transmission customers for Transmission Service at rates designed to recover the revenue requirements of the PTOs in supporting the provision of such transmission service by the ISO under the ISO OATT;

WHEREAS, the ISO will be responsible for system planning within the ISO region subject to certain rights and obligations of the PTOs, all as set forth in this Agreement;

WHEREAS, the functions to be performed by the ISO and Order 2000 require that the ISO have the requisite operational authority over the PTOs’ transmission facilities;

WHEREAS, in accordance with the terms set forth herein, the PTOs desire for the ISO to exercise, and the ISO desires to exercise, Operating Authority (as defined in Section 3.02 of this Agreement) over the PTOs’ Transmission Facilities (as defined in this Agreement) consistent with the requirements of Order 2000;

WHEREAS, the PTOs will, among other things, continue to own, physically operate, and maintain their Transmission Facilities and Local Control Centers; and

WHEREAS, each PTO reserves the right to transfer certain rights and obligations to an Independent Transmission Company in accordance with Attachment M to the ISO OATT.

Page No. 1

NOW, THEREFORE, in consideration of the promises, and the mutual representations, warranties, covenants and agreements hereinafter set forth, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, each of the PTOs and the ISO agree as follows:

ARTICLE I

DEFINITIONS; INTERPRETATIONS

1.01 Definitions; Interpretations. Each of the capitalized terms and phrases used in this Agreement (including the foregoing recitals) and not otherwise defined herein shall have the meaning specified in Schedule 1.01. In this Agreement, unless otherwise provided herein:

(a) words denoting the singular include the plural and vice versa;

(b) words denoting a gender include all genders;

(c) references to a particular part, clause, section, paragraph, article, exhibit, schedule, appendix or other attachment shall be a reference to a part, clause, section, paragraph, or article of, or an exhibit, schedule, appendix or other attachment to, this Agreement;

(d) the exhibits, schedules and appendices attached hereto are incorporated herein by reference and shall be construed with and as an integral part of this Agreement to the same extent as if they were set forth verbatim herein;

(e) a reference to any statute, regulation, proclamation, ordinance or law includes all statutes, regulations, proclamations, amendments, ordinances or laws varying, consolidating or replacing the same from time to time, and a reference to a statute includes all regulations, policies, protocols, codes, proclamations and ordinances issued or otherwise applicable under that statute unless, in any such case, otherwise expressly provided in any such statute or in this Agreement;

(f) a reference to a particular section, paragraph or other part of a particular statute shall be deemed to be a reference to any other section, paragraph or other part substituted therefor from time to time;

(g) a definition of or reference to any document, instrument or agreement includes any amendment or supplement to, or restatement, replacement, modification or novation of, any such document, instrument or agreement unless otherwise specified in such definition or in the context in which such reference is used;

(h) a reference to any Person (as hereinafter defined) includes such Person’s successors and permitted assigns in that designated capacity;

(i) any reference to “days” shall mean calendar days unless “Business Days” (as hereinafter defined) are expressly specified;

Page No. 2

(j) if the date as of which any right, option or election is exercisable, or the date upon which any amount is due and payable, is stated to be on a date or day that is not a Business Day, such right, option or election may be exercised, and such amount shall be deemed due and payable, on the next succeeding Business Day with the same effect as if the same was exercised or made on such date or day (without, in the case of any such payment, the payment or accrual of any interest or other late payment or charge, provided such payment is made on such next succeeding Business Day);

(k) words such as “hereunder”, “hereto”, “hereof” and “herein” and other words of similar import shall, unless the context requires otherwise, refer to this Agreement as a whole and not to any particular article, section, subsection, paragraph or clause hereof;

(l) a reference to “include” or “including” means including without limiting the generality of any description preceding such term, and for purposes hereof the rule of ejusdem generis shall not be applicable to limit a general statement, followed by or referable to an enumeration of specific matters, to matters similar to those specifically mentioned; and

(m) neither this Agreement nor any other agreement, document or instrument referred to herein or executed and delivered in connection herewith shall be construed against any Person as the principal draftsperson hereof or thereof.

ARTICLE II

TRANSMISSION FACILITIES

2.01 Transmission Facilities. As to any PTO, the transmission facilities over which the ISO shall exercise Operating Authority in accordance with the terms set forth herein shall be:

(a) those facilities of such PTO listed in Schedule 2.01(a) (hereinafter “Category A Facilities”), as such list of facilities may be added to or deleted from in accordance with Sections 2.01(d) and 2.02 below;

(b) those facilities of such PTO listed in Schedule 2.01(b) (hereinafter “Category B Facilities”), as such list of facilities may be added to or deleted from, in accordance with Sections 2.01(d) and 2.02 below; and

(c) those transmission facilities of such PTO within the New England Transmission System with a voltage level of less than 69 kV and all transformers that have no Category A Facilities or Category B Facilities connected to the lower voltage side of the transformer that are not listed on Schedule 2.01(a) and Schedule 2.01(b) (hereinafter “Local Area Facilities”), provided that any excluded facilities of such PTO listed on Schedule 4.01(d) shall not be Local Area Facilities.

(d) As to each PTO, the transmission facilities included on any of the lists of the Category A Facilities or the Category B Facilities contained in Schedule 2.01(a) and

Page No. 3

Schedule 2.01(b), respectively, as of the Operations Date may be redesignated on another of these two lists, deleted from such list, or redesignated as a Local Area Facility without the necessity of an amendment to this Agreement, but only in the following manner:

(i) at the direction of a Governmental Authority with jurisdiction over the Transmission Facilities in question, provided that the ISO and all PTOs shall be provided prior written notice of such changes;

(ii) as agreed between the ISO and the PTO or PTOs owning the transmission facilities; or

(iii) where the operational characteristics of a transmission facility have been materially modified after the Operations Date (including a change from a radial transmission facility to a looped transmission facility that contributes to the parallel carrying capability of the New England Transmission System) in accordance with Section 2.01(e); provided that any such changes shall also be subject to ISO review consistent with Section 2.06.

(e) All transmission facilities to be redesignated as Category A Facilities, Category B Facilities, or Local Area Facilities or deleted from the lists in Schedule 2.01(a) and Schedule 2.01(b) in accordance with Section 2.01(d)(iii), and all transmission facilities to be added to the lists in Schedule 2.01(a) and Schedule 2.01(b) in accordance with Section 2.02 shall be classified in accordance with the following standards:

(i) Category A Facilities shall consist of: all transmission lines with a voltage level of 115 kV and above, except for those 115 kV transmission facilities specifically designated as Category B Facilities in accordance with Section 2.01(e)(ii); all transmission interties between Control Areas; all transformers that have Category A Facilities connected to the lower voltage side of the transformer; all transformers that require a Category A Facility to be taken out of service when the transformer is taken out of service; and all breakers and disconnects connected to, and all shunts, relays, reclosing and associated equipment, dynamic reactive resources, FACTS controllers, special protection systems, PARS, and other equipment specifically installed to support the operation of such transmission lines, interties, and transformers.

(ii) Category B Facilities shall consist of: all 115 kV radial transmission lines and all 69 kV transmission lines that are not interties between Control Areas; all transformers that have any Category B Facilities and no Category A Facilities connected to the lower voltage side of the transformer except to the extent such transformers are designated as Category A Facilities in accordance with Section 2.01(e)(i); and all breakers and disconnects connected to, and all shunts, relays, reclosing and associated equipment, dynamic reactive resources, FACTS controllers, special protection systems, PARS, and other equipment specifically installed to support the operation of such Category B Facilities.

Page No. 4

(iii) Local Area Facilities shall consist of all transmission facilities with a voltage level of less than 69 kV and all transformers that have no Category A Facilities or Category B Facilities connected to the lower voltage side of the transformer.

(iv) To the extent there is any dispute between the ISO and a PTO or PTOs owning a transmission facility concerning classification of such transmission facility under these standards, such disagreement shall be subject to the dispute resolution provisions of this Agreement, provided that the ISO’s classification of a transmission facility under the standards shall govern pending resolution of the dispute.

(f) Collectively, all Category A Facilities, Category B Facilities, and Local Area Facilities shall hereinafter be referred to as the “Transmission Facilities,” provided that “Transmission Facilities” shall not include Excluded Assets as defined in Section 2.04 of this Agreement or Merchant Facilities. The ISO shall maintain on its OASIS a posting of the current versions of Schedule 2.01(a) and Schedule 2.01(b), in each instance, reflecting each such change promptly after such change is made.

(g) The classifications set forth in this Section 2.01 are for operational purposes. Rate treatment of Transmission Facilities shall be governed by the ISO OATT, provided that filings for rate treatment under the ISO OATT shall be subject to Section 3.04 of this Agreement.

2.02 New and Acquired Transmission Facilities and Transmission Upgrades.

(a) Any New Transmission Facility, any Transmission Upgrade, and any Acquired Transmission Facility shall be considered a “Transmission Facility” under this Agreement once it is placed into commercial operation by the applicable PTO(s); shall be designated as a Category A Facility, Category B Facility, or Local Area Facility in accordance with Section 2.01(e) unless otherwise agreed by the ISO and the PTO(s) owning the Transmission Facility; and shall be subject to the Operating Authority of the ISO in accordance with the terms of this Agreement.

(b) The designation of an Acquired Transmission Facility as a Category A, Category B or Local Area Facility shall not require the abrogation or modification of existing contractual arrangements for such Acquired Transmission Facility.

(c) Any Merchant Facility interconnected to or within the New England Transmission System shall not be the subject of this Agreement. Any Merchant Facility interconnected to or within the New England Transmission System constructed and placed in commercial operation after the Operations Date shall be subject to the authority of the ISO under a separate agreement in accordance with Section 2.03 and any applicable provisions of the ISO OATT.

Page No. 5

2.03 Merchant Facilities. The terms and conditions under which a PTO, an Affiliate of a PTO, or any other entity grants authority over any Merchant Facilities to the ISO shall not be governed by this Agreement, it being understood that such entities shall enter into operating agreements relating to their Merchant Facilities directly with the ISO in accordance with applicable provisions of the ISO OATT. Nothing in this Agreement is intended to limit or expand the right of a PTO, the Affiliate of a PTO, or any other entity to propose, construct, or own Merchant Facilities interconnected to the New England Transmission System.

2.04 Excluded Assets. The “Excluded Assets” of a PTO shall consist of those assets and/or facilities of a PTO set forth in Section 2.04(a) and (b). These Excluded Assets are expressly excluded from the definition of Transmission Facilities under this Agreement, and the ISO shall not have Operating Authority over a PTO’s Excluded Assets. Nothing in this Section 2.04 is intended to address the rate treatment of a PTO’s Transmission Facilities or any other asset of a PTO. Rate treatment of Transmission Facilities shall be governed by the ISO OATT, provided that filings for rate treatment under the ISO OATT shall be subject to Section 3.04 of this Agreement:

(a) Any assets, facilities, and/or portions of facilities owned by such PTO that are connected with or associated with those facilities defined as Category A Facilities, Category B Facilities or Local Area Facilities to the extent specifically excluded pursuant to the following items (i) through (vii) of this Section 2.04(a):

(i) proceeds from the use or disposition of Transmission Facilities;

(ii) any payment, refund or credit (1) relating to Taxes in respect of the Transmission Facilities of such PTO, (2) arising under any contracts or tariffs of such PTO and relating to services provided prior to the beginning of the Term, (3) arising under any contract or tariff that provides for rates that are subject to regulation by an agency other than FERC, or (4) relating to a Grandfathered Transmission Agreement;

(iii) any rights, ownership, title or interest any PTO may have with respect to telecommunications assets and equipment, provided that the ISO shall continue to have the right to use such telecommunication assets and equipment attached to or associated with Transmission Facilities solely to the extent needed for the exercise of the ISO’s Operating Authority in accordance with practice prior to the Operations Date and further provided that such use right shall not be assignable by the ISO;

(iv) any existing contracts or contract rights of the PTOs related in any manner to Transmission Facilities unless such PTO agrees to assign or transfer such contracts to the ISO, provided that the PTOs shall exercise their rights and

Page No. 6

responsibilities under Grandfathered Transmission Agreements in accordance with Section 3.11 and the applicable provisions of this Agreement;

(v) any assets, property rights, licenses, permits or facilities that are used for or in (1) the distribution, generation, trading or marketing of electricity (except for facilities specifically defined as Category A Facilities, Category B Facilities or Local Area Facilities that are used for such activities), (2) gas transportation, gas, water, petroleum, chemical, real estate development, or cable business, or (3) any other activity unrelated to the transmission of electricity located on, or making use of, the Transmission Facilities;

(vi) any causes of action or claims related to Transmission Facilities, provided, that, upon the written agreement of the PTO and the ISO to the assumption by the ISO of the management of such claims under mutually agreed terms and conditions, the ISO may manage a PTO’s causes of action or claims against a third party relating to such Transmission Facilities, and provided further that the ISO shall have the right to pursue causes of action or claims against third parties to the extent necessary for the ISO to fulfill its responsibilities for invoicing, collection and disbursement of customer payments in accordance with Section 3.10; and

(vii) any asset or facility for which Operating Authority may not be lawfully transferred or assigned.

(b) Any assets or facilities of such PTO that are not specifically defined as Category A Facilities, Category B Facilities or Local Area Facilities, including without limitation the facilities or portions of facilities described in items (i) through (xii) of this Section 2.04(b):

(i) all cash, cash equivalents, bank deposits, accounts receivable, and any income, sales, payroll, property or other Tax receivables;

(ii) proceeds from the use or disposition of any facilities or assets owned by the PTO;

(iii) certificates of deposit, shares of stock, securities, bonds, debentures, and evidences of indebtedness;

(iv) any rights or interest in trade names, trademarks, service marks, patents, copyrights, domain names or logos;

(v) any payment, refund or credit (1) relating to Taxes, (2) arising under any contracts or tariffs of such PTO and relating to services provided prior to the beginning of the Term, or (3) arising under any contract or tariff that provides for rates that are subject to regulation by an agency other than FERC;

Page No. 7

(vi) any facilities, including transmission facilities, located outside the New England Transmission System;

(vii) any rights, ownership, title or interest any PTO may have with respect to telecommunications assets and equipment;

(viii) any existing contracts or contract rights of the PTOs unless such PTO agrees to assign or transfer such contracts to the ISO;

(ix) any assets, property rights, licenses, permits or facilities that are used for or in (1) the distribution, generation, trading or marketing of electricity or (2) gas transportation, gas, water, petroleum, chemical, real estate development, or cable business, or (3) any other activity unrelated to the transmission of electricity whether or not located on, or making use of, the Transmission Facilities;

(x) any causes of action or claims;

(xi) any asset or facility for which Operating Authority may not be lawfully transferred or assigned; and

(xii) any interests of any kind in each PTO’s real property, provided that nothing in this Section 2.04 shall: (a) supersede the rights and obligations of the Parties as set forth in the Control Center Lease or Back-up Control Center Lease or (b) restrict the PTOs from conveying interests in real property in any future written agreement into which the ISO and any PTO or group of PTOs may, in their sole discretion, enter.

2.05 Connection with Non-Parties.

(a) On or after the Operations Date, each PTO shall connect its Transmission Facilities with the facilities of any entity that is not a Party, including the facilities of a current or proposed Transmission Customer, and shall install (or cause to be installed) and construct (or cause to be constructed) any transmission facilities required to connect the facilities of a non-Party to a PTO’s Transmission Facilities to the extent such connection or construction is required by applicable law, including the Federal Power Act and any applicable regulations issued by FERC and provided that the construction of any such transmission facilities shall be subject to the conditions associated with the PTOs’ obligation to build set forth in Schedule 3.09(a). Any such connection shall be subject further to: (1) the receipt of any necessary regulatory approvals, (2) compliance with the procedures set forth in the ISO OATT for review of the reliability and operational impacts of a proposed interconnection (including the procedures for interconnection of a Generating Unit under the Interconnection Standard); and (3) execution of an Interconnection Agreement with such entity containing provisions for the safe and reliable operation of each interconnection with respect to such entity’s facilities in accordance with Good Utility Practice, applicable NERC/NPCC Requirements, and applicable Law (including the Federal Power Act); provided that

Page No. 8

(i) Except as provided in 2.05(a)(ii) below, each PTO shall engage in good faith negotiations as to the terms and conditions of such Interconnection Agreement with any such non-Party, but, except as may be required pursuant to regulations issued by FERC, a PTO shall not be required to enter into any Interconnection Agreement containing terms and conditions unacceptable to such PTO and shall reserve the right to resolve any disputes, and/or make any filings with FERC, with respect thereto.

(ii) With respect to the interconnection of a Large Generating Unit to any Transmission Facility of a PTO the Interconnection Agreement shall be a three-party agreement among the PTO, the ISO, and the interconnecting non-Party based on the pro forma Large Generator Interconnection Agreement in the ISO OATT. With respect to the interconnection of other Generating Units to any Transmission Facility of a PTO, the ISO shall be a party to Interconnection Agreements if and to the extent that FERC regulations require the ISO to be a party. Either the ISO or the PTOs, acting jointly in accordance with the Disbursement Agreement among them, may initiate a filing to amend the pro forma Large Generator Interconnection Agreement under Section 205 of the Federal Power Act and shall include in such filing the views of the ISO and the PTOs, as applicable, provided that the standard applicable under Section 205 of the Federal Power Act shall apply only to the PTOs’ position on any financial obligations of the PTOs or the interconnecting non-Party, and any provisions related to physical impacts of the interconnection on the PTOs’ Transmission Facilities or other assets. If the PTO, the ISO and the interconnecting non-Party agree to the terms and conditions of a specific Large Generator Interconnection Agreement for a Large Generating Unit, or any amendments to such an Interconnection Agreement, then the PTO and the ISO shall jointly file the executed Interconnection Agreement, or amendment thereto, with FERC under Section 205 of the Federal Power Act. To the extent the PTO, the ISO and such interconnecting non-Party cannot agree to proposed variations from the pro forma Large Generator Interconnection Agreement applicable to a specific Large Generating Unit or cannot otherwise agree to the terms and conditions of the Interconnection Agreement for such Large Generating Unit, or any amendments to such an Interconnection Agreement, then the PTO and the ISO shall jointly file an unexecuted Interconnection Agreement, or amendment thereto, with FERC under Section 205 of the Federal Power Act and shall identify the areas of disagreement in such filing, provided that, in the event of disagreement on terms and conditions of the Interconnection Agreement related to the costs of upgrades to such PTO’s Transmission Facilities, the anticipated schedule for the construction of such upgrades, any financial obligations of the PTO, and any provisions related to physical impacts of the interconnection on the PTO’s Transmission Facilities or other assets, then the standard applicable under Section

Page No. 9

205 of the Federal Power Act shall apply only to the PTO’s position on such terms and conditions.

The costs of interconnection facilities shall be allocated in the manner specified in the ISO OATT.

(b) Each PTO shall also connect its Transmission Facilities with the facilities of any entity that is not a Party upon satisfaction of the “Elective Transmission Upgrade” provisions of the ISO OATT, provided that the PTO shall only connect the facilities of such entity (the “Elective Transmission Upgrade Applicant”) upon satisfaction of the following conditions:

(i) The Elective Transmission Upgrade Applicant shall enter into an Interconnection Agreement with the affected PTO(s) and, to the extent necessary and appropriate, enter into support agreements with the affected PTO(s), provided that the Elective Transmission Upgrade Applicant may request, upon providing the security, credit assurances, and/or deposits required by the affected PTO, the filing with the Commission by the PTO of unexecuted Interconnection Agreements and support agreements.

(ii) The Elective Transmission Upgrade Applicant shall obtain all necessary legal rights and approvals for the construction and maintenance of the upgrade and shall cooperate with the PTO(s) in obtaining all necessary legal rights and approvals for the construction and maintenance of additions or modifications, if any, required in conjunction with the upgrade.

(iii) The Elective Transmission Upgrade Applicant shall be responsible for 100% of all of the costs of said upgrade and of any additions to or modifications of the Transmission Facilities that are required to accommodate the Elective Transmission Upgrade. A request for rate treatment of an Elective Transmission Upgrade, if any, shall be determined by FERC in the appropriate proceeding.

2.06 Review of Transmission Plans. Each PTO shall submit to the ISO in such form, manner and detail as the ISO may reasonably prescribe: (i) any new or materially changed plans for retirements of or changes in the capacity of such PTO’s Transmission Facilities rated 69 kV or above or plans for construction of New Transmission Facilities or Transmission Upgrades rated 69 kV or above; and (ii) any new or materially changed plan for any other action to be taken by the PTO which may have a significant effect on the stability, reliability or operating characteristics of the PTO’s Transmission Facilities, the facilities of any Transmission Owner, or the system of a Participant. The ISO shall provide notification of any such PTO submissions to the appropriate Technical Committee(s). Unless prior to the expiration of ninety (90) days, the ISO notifies the PTO in writing that it has determined that implementation of the plan will have a significant adverse effect upon the reliability or operating characteristics of the PTO’s

Page No. 10

Transmission Facilities, the facilities of any Transmission Owner, or the system of a Participant, the PTO shall be free to proceed. If the ISO notifies the PTO that implementation of such plan has been determined to have a significant adverse effect upon the reliability or operating characteristics of the PTO’s Transmission Facilities, the facilities of any Transmission Owner, or the system of a Participant, the PTO shall not proceed to implement such plan unless the PTO takes such action or constructs such facilities as the ISO determines to be reasonably necessary to avoid such adverse effect.

2.07 Condemnation. If, at any time, any Governmental Authority commences any process to acquire any Transmission Facilities or any other interest in Transmission Facilities then held by a PTO through condemnation or otherwise through the power of eminent domain, (i) such PTO shall provide the ISO with written notice of such process, (ii) such PTO shall, at its cost, direct any litigation or proceeding regarding such condemnation or eminent domain matter, (iii) such PTO shall have the right to settle any such proceeding without the consent of the ISO, and (iv) any award in condemnation or eminent domain shall be paid to such PTO without any claim to such award by the ISO.

ARTICLE III

OPERATING AUTHORITY

3.01 Grant of Operating Authority.(a) Subject to the terms set forth in this Agreement, including Article III and Article X hereof, effective as of the Operations Date, and with respect to Publicly-Owned PTOs, to the extent permitted by, or in a manner consistent with the laws of any State governing the organization or operation of such Publicly-Owned PTOs, each PTO hereby authorizes the ISO, through its officers, employees, consultants, independent contractors and other personnel, to exercise Operating Authority over the Transmission Facilities, including provision of Transmission Service over the Transmission Facilities under the ISO OATT, and the ISO hereby agrees to assume and exercise Operating Authority over such PTOs’ Transmission Facilities in accordance with this Agreement.

(b) The grant by the PTOs to the ISO and the assumption by the ISO of Operating Authority over the Transmission Facilities are solely for the purposes of allowing the ISO to fulfill the functions of an RTO as specified herein (including provision of Transmission Service under the ISO OATT) and do not constitute an assumption by the ISO of any liabilities with respect to the Transmission Facilities except as otherwise specifically provided herein (including as provided in Article IX of the Agreement).

(c) Nothing herein or elsewhere contained shall be construed as requiring or effecting a transfer of any PTO’s responsibility (or the assumption thereof by the ISO) for the physical control of the Transmission Facilities, including the physical operation, repair, maintenance and replacement of such Transmission Facilities, or as conveying to the ISO: (x) any right, ownership, title or interest in or to a PTO’s Transmission Facilities; (y) any right of access to any PTO’s real property, except as specified in Section 3.02(i); or (z) any rights or authority with respect to a PTO’s Excluded Assets, except as specifically provided herein.

Page No. 11

3.02 Definition of ISO Operating Authority. Consistent with the provisions of this Agreement, including Section 3.02(a) below, “Operating Authority” shall mean those functions set forth in Sections 3.02, 3.03, and 3.08 and those responsibilities set forth in Section 3.05, and shall not include those rights, responsibilities and functions set forth in Sections 3.06 and 3.07. Subject to the first sentence of this Section 3.02, the ISO shall exercise such Operating Authority in accordance with applicable Operating Procedures as specified in Section 3.02(d) below.

(a) The ISO shall perform the following functions with respect to each PTO’s Transmission Facilities, consistent with applicable NERC/NPCC Requirements and other applicable regulatory standards, including (as needed) issuing instructions to, or coordinating with, each PTO’s Local Control Center(s):

(i) centrally dispatch generation (and dispatchable and interruptible load) and implement real-time balancing, including meeting NERC control performance criteria;

(ii) determine Operating Limits based on forecasted or real-time system conditions and in accordance with the facility ratings established by the PTOs in collaboration with the ISO pursuant to Section 3.06;

(iii) take such actions as may be necessary to plan and maintain short-term (including real-time) reliability and system security (including curtailment of external transactions in accordance with FERC-accepted or -approved Market Rules and the applicable transmission tariff or transmission agreement);

(iv) consistent with the ISO Information Policy, exchange security information with applicable PTOs, non-PTO transmission operators and other neighboring systems and regional entities; and

(v) provide for an ISO Control Center and an independent Back-up Control Center, as the ISO deems necessary to comply with applicable NERC/NPCC Requirements and any applicable regulatory requirement.

(b) The ISO shall receive, confirm and schedule External Transactions for the New England Transmission System; enter into Coordination Agreements and operating arrangements with the operators of neighboring Control Areas; coordinate system operation and emergency procedures with neighboring Control Areas; and administer each PTO’s Interconnection Agreements with neighboring Control Areas and scheduling provisions of the tariff(s) applicable to External Transactions, in accordance with the terms of those agreements and tariffs; provided that as of the Operations Date, the applicable agreements and tariffs shall be set forth in Schedule 3.02(b).

(c) The ISO shall act as the Reliability Authority for the New England Transmission System. The ISO may intercede and direct appropriate near-term operational actions in order to protect reliability, provided that nothing in this Section 3.02(c) shall require

Page No. 12

any PTO to undertake an action contrary to applicable Law or shall limit the right of each PTO pursuant to Section 3.07 to take any action(s) that it deems necessary to prevent loss of human life, injury to persons and/or damage to property.

(d) The ISO shall utilize the Operating Procedures relating to the exercise of Operating Authority over the Transmission Facilities. The Operating Procedures shall initially consist of the Operating Procedures in existence on the Operations Date (hereinafter “Existing Operating Procedures”). Such Existing Operating Procedures shall consist of those Operating Procedures listed in Schedule 3.02(d). The ISO shall develop any modifications to Operating Procedures (including Existing Operating Procedures) and any new Operating Procedures that it may deem necessary or appropriate: (i) in coordination with those PTOs (or their Local Control Centers, as applicable) whose Transmission Facilities will be operated in accordance with such Operating Procedures so as to ensure that that the PTO’s (or Local Control Center’s) knowledge of their Transmission Facilities is given due consideration in the development or modification of the transmission-related portions of such Operating Procedures and (ii) in consultation with other stakeholders. The ISO shall have the authority to modify Operating Procedures or develop new Operating Procedures without such coordination or consultation when the ISO does not have sufficient time to undertake such coordination or consultation due to emergent and unanticipated circumstances. In the event that the ISO and the applicable PTO(s) disagree about modifications to the transmission-related portions of Operating Procedures or any new Operating Procedures related to the operation of such PTOs’ Transmission Facilities, the affected PTO(s) will have the opportunity to submit the dispute for resolution in accordance with the dispute resolution provisions set forth in Section 11.14 herein. Pending such resolution, the ISO shall have the authority, as the system operator with ultimate authority for the real-time operation of the New England Transmission System, to implement any such new Operating Procedures or modified Operating Procedures. Notwithstanding anything in the foregoing, Operating Procedures related to the establishment of ratings for a PTO’s New Transmission Facilities and Acquired Transmission Facilities or related to changes to existing ratings of a PTO’s Transmission Facilities (collectively “Rating Procedures”) shall be developed and placed into effect pursuant to Section 3.06(a)(v).

To the extent the PTOs will be required to physically operate their Transmission Facilities in accordance with any operational documents in effect as of the Operations Date or as subsequently developed or amended by the ISO (other than the Operating Procedures), the ISO shall develop such operational documents and amendments thereto in coordination with those PTOs (or their Local Control Centers, as applicable) whose Transmission Facilities will be operated in accordance with such documents, provided that stakeholders shall have the right to consult in the development of such documents, subject to any limitations associated with the confidential nature of such documents consistent with confidentiality, that the ISO will have the right to place such operating documents into effect in the event of a dispute concerning such documents, and that the affected PTO(s) shall have the right to submit any such dispute for resolution in accordance with the dispute resolution provisions set forth in Section 11.14 herein. Any such coordination between any PTO and the ISO pursuant to this Section 3.04(d) shall be subject to applicable standards of conduct consistent with FERC Order No. 889.

Page No. 13

(e) The ISO shall seek agreement with the PTOs, where time limitations do not make it impracticable to do so, on real-time operational decisions affecting the Transmission Facilities not otherwise specified in the Operating Procedures developed in accordance with Section 3.02(d). In the absence of such agreement, or if time limitations do not permit reaching agreement, the ISO shall implement its operational decision. If such ISO decision is disputed, the ISO’s position shall control pending resolution of the dispute.

(f) The ISO shall develop, maintain, and, if needed, implement the System Restoration Plan for the New England Transmission System, which shall include the existing PTO Local Restoration Plans. The ISO shall develop any modifications to the System Restoration Plan in consultation with the PTOs and shall incorporate into the System Restoration Plan any modifications developed by each PTO to their PTO Local Restoration Plans, provided that any modifications to the PTO Local Restoration Plans are subject to the ISO’s approval in order to coordinate and promote the reliability of the Restoration Plans.

(g) The ISO shall coordinate voltage and reactive dispatch of facilities to the extent normal schedules are unable to be maintained by Local Control Centers.

(h) The ISO shall direct the implementation of emergency procedures, including Load Shedding and voltage reduction, in coordination with the PTO Local Control Centers.

(i) The ISO shall have the authority to perform the following tasks in relation to compliance with current or future PTO responsibilities:

(i) perform all compliance and monitoring responsibilities of the ISO, including the issuance of sanction letters, with respect to existing or successor NERC or NPCC compliance programs associated with standards, criteria and measurements for which the PTOs are responsible and accountable to the ISO. To the extent that the ISO receives a sanction letter from NERC or NPCC that is substantially related to the actions of a PTO, the ISO may issue a sanction letter to such PTO;

(ii) perform all compliance and monitoring responsibilities of the ISO associated with Operating Procedures relating to standards, criteria and measurements that the PTOs are responsible for and accountable to the ISO. Such responsibilities shall include audits of PTOs for compliance with Operating Procedures to the extent the ISO determines such audits are necessary, and the issuance of sanction letters;

(iii) perform periodic audits of each Local Control Center’s and PTO’s performance of the functions listed in Sections 3.06 (a)(i), (ii), (iv), (vi), (vii), (viii), (ix) and (x) in accordance with applicable Operating Procedures and applicable reliability standards, including audits to monitor compliance of the Local Control Center (and PTO employees

Page No. 14

interacting with the Local Control Centers) with the ISO Information Policy and applicable standards of conduct consistent with FERC Order No. 889 in performing these functions. Such Local Control Center audits shall generally be conducted no more frequently than once every three years, provided that the ISO shall have the authority to conduct an audit more frequently if it determines that circumstances so require.

All audits conducted pursuant to this Section 3.02(i) shall be conducted by the ISO or by an independent third party, with expenses of the ISO (or the third-party auditor) borne by the ISO and recovered through its administrative tariff. The PTO shall bear its own expenses in complying with the audit. Such audits shall be conducted during normal business or operational hours and with reasonable notice. The general scope of each audit and the general process for conducting the audit will be discussed with the affected PTO in advance. Nothing in this Section 3.02(i) shall imply that a sanction letter shall include any financial or other penalties. Nothing in this Section 3.02(i) shall limit the right of the ISO to separately file proposals at FERC to assess financial or other penalties against any entity or shall limit the right of the PTOs to comment on or protest any such proposals.

(j) In addition to the functions set forth in Sections 3.02(a) - (i), Operating Authority shall also consist of the following functions that the ISO shall perform with respect to each PTO’s Category A Facilities; provided, however, that the ISO (in the absence of the PTO’s consent) is not authorized to perform such functions with respect to any PTO’s Category B Facilities or Local Area Facilities, unless the outages of such facilities reasonably could be expected to result in a violation of reliability criteria:

(i) monitor and control, in accordance with the facility ratings established by the PTOs in collaboration with the ISO pursuant to Section 3.06, on a real-time basis, power flows on the system, voltage and system frequency; and

(ii) coordinate with the Local Control Centers on the settings for dynamic reactive resources, FACTS controllers, special protection systems, PARS, and other similar dynamic equipment that affects power flows, and approve or direct changes to such settings.

(k) If at any time, any Party provides notice to all of the other Parties that it believes NERC and NPCC documents that are not NERC/NPCC Requirements have been modified so as to expand the scope of the functions to be performed by the ISO or the PTOs, the Parties shall consider in good faith changes to this Agreement that will allow the Parties to follow such guidelines; provided, however, that, the Parties shall have no obligation to agree to such changes. If the Parties cannot agree to such changes, the dispute resolution procedures of Section 11.14 shall be utilized. Nothing in this Section 3.02(k) shall be construed to excuse any Party from complying with applicable NERC/NPCC Requirements.

Page No. 15

3.03 Transmission Services and OATT Administration.

(a) The ISO shall administer the ISO OATT in the manner specified in this Section 3.03. The ISO’s OATT administration responsibilities shall include those enumerated below:

(i) The ISO shall receive, post on OASIS as required by Commission regulations, and respond to all Transmission Service requests and requests to be interconnected to the New England Transmission System under the ISO OATT, including the Local Service Schedules. Except as provided in Section 3.03(a)(ii), the ISO shall perform the system impact studies and facilities studies (and execute and administer agreements for such studies) in connection with such requests; provided, however, that: (A) the ISO shall consult with a PTO prior to completion of system impact studies and facilities studies in connection with requests that affect such PTO’s Transmission Facilities and shall include in any such studies the PTO’s reasonable estimates of the costs of upgrades to such PTO’s Transmission Facilities needed to implement the conclusions of such studies and the PTO’s reasonable anticipated schedule for the construction of such upgrades; (B) nothing in this Agreement shall preclude the ISO from entering into an agreement(s) with a PTO for such studies, pursuant to the ISO’s supervision and the ISO’s authority to require modifications to such studies, to perform system impact studies and facilities studies in connection with requests that affect such PTO’s Transmission Facilities; (C) except as provided in Section 3.03(a)(ii) with respect to interconnection of Generating Units that would not have an impact on facilities used for the provision of regional transmission service, nothing in this Agreement shall preclude the performance of studies related to the interconnection of Generating Units by a third party consultant to the extent permitted by applicable procedures in the ISO OATT (including procedures governing the treatment of confidential information) and provided that such studies performed by any third party consultant must include the PTO’s reasonable estimates of the costs of upgrades to such PTO’s Transmission Facilities needed to implement the conclusions of such studies and the PTO’s reasonable anticipated schedule for the construction of such upgrades; and (D) each PTO shall, upon request by the ISO, conduct any necessary studies related to such PTO’s Transmission Facilities, including system impact studies and facilities studies, and shall assist in the performance of any such studies, including the provision of information and data in accordance with Section 11.09 of this Agreement.

(ii) The ISO shall forward to the appropriate PTO(s) applications for Local Service. The ISO shall review applications for Local Service or requests to be interconnected to the New England Transmission System to determine whether the service or interconnection would have an impact on facilities used for the provision of regional transmission service. If so, the ISO will perform a system

Page No. 16

impact study and facilities study, as necessary to address the impacts on facilities used for the provision of regional transmission service. The PTO shall be responsible for reviewing and responding to requests for Local Service not having an impact on facilities used for the provision of regional transmission service and for interconnections not having an impact on facilities used for the provision of regional transmission service, and shall perform all system impact studies and facilities studies regarding such requests; provided, however, that the PTO shall consult with the ISO prior to completion of such system impact studies and facilities studies and further provided that the ISO will use reasonable efforts to assist the PTO and interconnecting party in resolving disputes arising regarding the performance of such studies. The PTOs shall provide the ISO with information necessary to evaluate any such dispute in accordance with Section 11.09 of this Agreement, and shall include provisions in each of their study agreements providing for reimbursement of the ISO’s costs incurred in these efforts.

(iii) The ISO shall calculate the TTC and ATC for all interties on the New England Transmission System and determine the TTC and ATC calculation methodologies for interties on the New England Transmission System (consistent with applicable NERC/NPCC Requirements and applicable regulatory standards), provided that modifications to calculation methodologies as they exist on the Operations Date shall be developed by the ISO in consultation with the PTOs and other interested stakeholders. To the extent that TTC and ATC on a PTO’s Local Network must be calculated in connection with the provision of Local Service, then the PTO shall calculate such TTC and ATC.

(iv) The ISO shall operate and maintain the OASIS (or a successor system) as required by FERC, including posting of TTC/ATC for interties on the New England Transmission System; provided, however, that such system shall conform to the requirements for such systems as specified by FERC. The PTOs shall provide updates to PTO-specific Local Service pages on the OASIS site, subject to the ISO’s review of such updates. The ISO shall have the authority to direct any changes to such PTO-specific Local Service pages that it deems appropriate to conform to FERC requirements and the terms and conditions of the ISO OATT.

(v) The ISO shall procure and act as supplier of last resort of Ancillary Services (including arranging for the sale and purchase of emergency capacity and energy with neighboring Control Areas), in accordance with the ISO OATT and FERC-accepted or -approved Market Rules.

(vi) The ISO shall provide regional Transmission Service to Transmission Customers over the Transmission Facilities in accordance with the

Page No. 17

rates, terms and conditions of the ISO OATT, subject to Section 3.03(c) with respect to Local Service.

(vii) The ISO shall track inadvertent energy and administer inadvertent energy payback/accounting with neighboring Control Areas in accordance with the terms and conditions of the Interconnection Agreements or Coordination Agreements with neighboring Control Areas and applicable tariff provisions.

(viii) The ISO shall make informational filings with the Commission that are required of an RTO, provided that the relevant PTOs shall provide the ISO with all necessary information to make such filings, in such manner as the ISO shall reasonably prescribe and in accordance with Section 11.09 of this Agreement.

(b) Notwithstanding Section 3.03(a), generators requesting to interconnect with the distribution facilities of a PTO or a PTO’s distribution company Affiliate and retail load customers shall submit service requests to the applicable distribution company or the PTO, where applicable. The distribution company or, where applicable, the PTO shall execute and administer the agreements, and shall be responsible for billing, collections, dispute resolution and the performance of system impact studies and facilities studies, in coordination with the ISO as necessary, in connection with such requests.

(c) Local Service. Each PTO authorizes the ISO to act as its agent in the performance of its Transmission Service and OATT administration duties with regard to Local Service, including all ISO responsibilities with respect to Local Service and Local Area Facilities as set forth in Section 3.03(a) above. Each PTO agrees to perform all tasks and undertake all responsibilities necessary and appropriate to facilitate the provision of Local Service in accordance with its Local Service Schedule. Each PTO shall, in accordance with Section 11.09 of this Agreement, provide the ISO with information and data requested by the ISO to perform its Transmission Service and OATT administration duties with regard to Local Service, Each PTO shall maintain its Local Service Schedules in accordance with FERC regulations governing filed rate schedules, shall provide the ISO with copies of proposed changes to its Local Service Schedules when filed with the FERC, and shall notify the ISO when FERC approves or accepts changes to such Local Service Schedules. Each PTO shall be responsible for sending all invoices for Local Service to Transmission Customers and pursuing collections for outstanding payments due for Local Service. The ISO, by the execution of this Agreement, shall not assume any liability in connection with the provision of Local Service other than the liability which may result from an act or omission of the ISO related to the ISO’s rights and responsibilities under this Agreement, including an ISO directive and/or instruction to a Party. Nothing in this Section 3.03(c) shall affect the relative rights and responsibilities of the Parties pursuant to Article IX of this Agreement.

Page No. 18

(d) Transmission Service Agreements. The ISO and the applicable PTOs shall enter into all agreements for Transmission Service over the Transmission Facilities that commence on or after the Operations Date; provided that:

(i) A pro forma service agreement (or service agreements) shall be attached to the ISO OATT and such pro forma service agreement(s) shall set forth the respective rights and responsibilities of the Transmission Customer, the ISO, and the PTOs. After the Operations Date, the ISO shall have the authority, pursuant to Section 205 of the Federal Power Act, to amend the pro forma service agreement(s) or the Market Participant Service Agreement (“MPSA”) or executed service agreements related to the terms and conditions of regional Transmission Service. After the Operations Date, the PTOs, acting jointly in accordance with the Disbursement Agreement among them, shall have the authority, pursuant to Section 205 of the Federal Power Act, to amend the pro forma service agreement(s) related to the terms and conditions of Local Service and each PTO shall have the authority, pursuant to Section 205 of the Federal Power Act, to amend executed service agreements related to the terms and conditions of Local Service.

(ii) On or after the Operations Date, the ISO shall be responsible for filing with the FERC, or electronically reporting to the FERC as applicable, all new agreements for Transmission Service over the Transmission Facilities. Such filings with respect to Local Service will be made by the ISO as agent for the applicable PTO. In the event of any dispute between the ISO or a PTO and a Transmission Customer concerning the terms and conditions of such service agreements, the ISO shall file an unexecuted copy of the pro forma service agreement set forth in the ISO OATT and shall include in such filing any statement provided by the affected PTO(s) and the Transmission Customers concerning their respective positions on any proposed changes or additions to the pro forma service agreement.

(iii) Notwithstanding the foregoing, the PTOs (or their affiliated distribution companies) shall be solely authorized to enter into service agreements for retail service and service to generators connected at the distribution facility level.

Nothing in this Section 3.03(d) shall limit the ISO’s obligations with respect to Grandfathered Transmission Agreements in accordance with Section 3.11 of this Agreement. The PTOs shall submit all required electronic reports with respect to such Grandfathered Transmission Agreements. If and to the extent that FERC regulations require the ISO to submit such electronic reports for the Grandfathered Transmission Agreements, the PTOs shall provide the ISO with assistance in developing and submitting such required reports.

Page No. 19

(e) Local Networks. A “Local Network” shall consist of those networks of Transmission Facilities identified on Attachment E of the ISO OATT as of the Operations Date. The Local Networks shall only be changed to reflect the effectuation of a merger, acquisition, or consolidation and reorganization, to add a new PTO from outside of the New England Control Area, or to reflect the withdrawal from the ISO of a PTO.

3.04 Application Authority.

(a) Each PTO other than a Publicly-Owned PTO shall have the authority to submit filings under Section 205 of the Federal Power Act, and each Publicly-Owned PTO shall have the authority to the extent permitted by, or in a manner consistent with state law applicable to Publicly-Owned PTOs, to establish and to revise:

(i) the revenue requirements for all Transmission Facilities of such PTO used for the provision of Transmission Service (including Transmission Facilities leased to the PTO or to which the PTO has contractual entitlements);

(ii) any rates or charges for transmission services that are based solely on the revenue requirements of the Transmission Facilities of a single PTO (including Transmission Facilities leased to the PTO or to which the PTO has contractual entitlements) under such PTO’s FERC-accepted or -approved Local Service Schedule to the ISO OATT;

(iii) any terms and conditions for Local Network Service or Local Point-to-Point Transmission Service under such PTO’s Local Service Schedule to the ISO OATT;

(iv) any rates or charges for the recovery of such PTO’s investment in a New Transmission Facility or Transmission Upgrade that enters commercial service after the effective date of the ISO OATT and the construction of which was not required by, or approved in, an ISO System Plan; provided, however, that if the ISO OATT utilizes a formula-type transmission rate, the revenue requirement for such Transmission Facility shall not be rolled into such rate without a FERC order expressly permitting such roll-in;

(v) any terms and conditions for such PTO’s or such PTO’s affiliated distribution company’s retail access plans, whether such terms and conditions are included in the ISO OATT or in any other tariff applicable to that PTO filed with FERC, and including any such terms and conditions in the ISO OATT or in any other tariff applicable to that PTO that protect against bypass of any provision of that PTO’s retail access plan;

(vi) any rates or charges for the recovery of such PTO’s wholesale or retail stranded costs and any terms and conditions in the ISO OATT or in any

Page No. 20

other tariff applicable to that PTO filed with FERC that protect against bypass of rates or charges for the recovery of that PTO’s wholesale or retail stranded costs;

(vii) any rates or charges, and terms and conditions related thereto, that implement an incentive or performance-based rate proposal made by one or more (but fewer than all) PTOs, applicable only to service provided by such PTO(s) under their Local Service Schedules; and

(viii) subject to the provisions of Section 2.05, any terms and conditions of Interconnection Agreements with any entities connecting with such PTO’s Transmission Facilities, provided that such Interconnection Agreements shall not include any operating arrangements and Coordination Agreements that the ISO may enter into with operators of neighboring Control Areas in accordance with Section 3.02(b).

A PTO shall not have the authority to revise such rates, terms and conditions in a manner that would abridge the rights granted to the ISO in Section 3.04(c). The PTO shall provide written notification to the ISO and stakeholders of any filing described in sub-paragraph (ii) through (viii), above, which notification shall include a detailed description of the filing, at least 30 days in advance of a filing. The PTO shall consult with interested stakeholders upon request. The PTO shall retain the right to modify aspects of any filing authorized by this Section 3.04(a) after it provides written notification to the ISO and stakeholders, and shall provide notification to the ISO and stakeholders of any material modification to such filings.

With respect to any filing described in sub-paragraph (ii) through (viii), above, the PTO shall include in any filing a statement that, in the good faith judgment of the PTO, the proposal will not be inconsistent with the design of the New England Markets, as accepted or approved by FERC. In the event the ISO believes that a proposed filing described in sub-paragraph (ii) through (viii), above, would have such an inconsistency, it shall so advise the PTO and such PTO and the ISO shall consult in good faith to resolve any ISO concerns, but, if such disagreement cannot be resolved, the PTO may submit a filing under Section 205, provided that the PTO’s filing (including the transmittal letter for such filing) to FERC shall include any written statement provided by the ISO setting forth the basis for the ISO’s concerns. With respect to any PTO whose transmission rates and revenue requirements are not subject to FERC jurisdiction under Section 205 or otherwise, such PTO shall have the right to establish its revenue requirements, and, where applicable, its rates and charges, in accordance with applicable law and submit such revenue requirements, rates and charges to FERC for a determination that inclusion of such revenue requirements, rates and charges in the ISO OATT will yield rates and charges for Transmission Service that satisfy the applicable standard under Section 205.

A PTO shall consult with the ISO to determine whether the ISO will need to make any software modifications in order to implement any filing authorized by this Section 3.04(a) and when any needed software modifications could reasonably be expected to be implemented. The PTO’s filing to FERC (and the transmittal letter for such a filing) shall include any written statement provided by the ISO setting forth the basis for any software-related implementation concerns

Page No. 21

raised by the ISO. The ISO shall make Commercially Reasonable Efforts to implement any needed software modifications by the effective date accepted by the FERC for a filing authorized by this Section 3.04(a), provided that, if the ISO has exercised such Commercially Reasonable Efforts, a failure to implement needed software modifications by the FERC-accepted effective date shall not constitute an event of default by the ISO under this Agreement or subject the ISO to financial damages, and further provided that the ISO shall run retroactive settlements consistent with the FERC-accepted effective date for a filing authorized by this Section 3.04(a) once such software modifications have been implemented.

(b) The PTOs, acting jointly in accordance with the Disbursement Agreement among them, shall have the authority to submit filings under Section 205 of the Federal Power Act to establish and to revise:

(i) the rates and charges for Transmission Service pursuant to which the revenue requirements for all Transmission Facilities of the PTOs used for the provision of Transmission Service are recovered; including the design of any rates or charges for: (A) regional Transmission Service on the New England Transmission System involving the use of more than one PTO’s Transmission Facilities; (B) Transmission Service between the New England Transmission System and any other transmission system; (C) Transmission Service through the New England Transmission System between other transmission systems; (D) the recovery of any portion of the revenue requirements of the PTOs attributable to the elimination of any rates or charges (e.g., border charges) for any such Transmission Service; (E) the methodology by which the costs of Transmission Upgrades related to generator interconnections are allocated under the ISO OATT and (F) the methodology by which the costs of New Transmission Facilities and Transmission Upgrades are allocated under the ISO OATT.

(ii) the methodology for the recovery and allocation of the line losses on the New England Transmission System, if and to the extent that the calculation of locational marginal prices for energy is not designed to recover such losses; and

(iii) any rates or charges, and terms and conditions related thereto, that implement an incentive or performance-based rate proposal, applicable to the entire New England Transmission System.

The PTOs shall not have the authority to revise such rates, terms and conditions in a manner that would abridge the rights granted to the ISO in Section 3.04(c). The PTOs shall provide written notification of any proposed filing under this Section 3.04(b) to the ISO and stakeholders, which notification shall include a detailed description of the proposed filing, at least 30 days prior to the filing. The PTOs shall retain the right to modify aspects of any filing authorized by this Section 3.04(b) after they provide written notification to the ISO and stakeholders, and shall provide notification to the ISO and stakeholders of any material modification to such filings. If less than

Page No. 22

all of the PTOs support the filing, the PTOs will advise the ISO and stakeholders of that fact and the dissenting PTOs shall advise the ISO and stakeholders of their concerns.

The PTOs and the ISO shall make every reasonable effort to agree upon the PTOs’ proposed filing under this Section. In the event the PTOs and the ISO are unable to agree on the PTOs’ filing under this Section, and the ISO in its good faith judgment concludes that the PTOs’ filing will:

(A) be inconsistent with the design of the New England Markets, including the congestion pricing methodology for the ISO region, as accepted or approved by FERC;

(B) have a material adverse effect on the efficiency or competitiveness of the New England Markets, or on the ability of the ISO to provide transmission access on a not unduly discriminatory or preferential basis; or

(C) have a material adverse effect on the reliability of the ISO bulk power system;

then, except as provided in the next sentence, the PTOs’ filing will not become effective until such time as FERC issues an order determining the proposal set forth in the filing to be consistent with the standard applicable under Section 205 of the Federal Power Act, and such a filing (including the transmittal letter for such a filing) shall include any written statement provided by the ISO setting forth the basis for the ISO’s concerns. In the case of a filing described in sub-paragraph (iii), above, the PTOs may request that FERC permit the filing to go into effect on an interim basis, notwithstanding the conclusion of the ISO. If FERC grants the PTOs’ request to permit the filing to go into effect on an interim basis, the filing will become effective, subject to refund, on the date specified in FERC’s order.

The PTOs shall consult with the ISO to determine whether the ISO will need to make any software modifications in order to implement any filing authorized by this Section 3.04(b) and when any needed software modifications could reasonably be expected to be implemented. The PTOs’ filing to FERC (and the transmittal letter for such a filing) shall include any written statement provided by the ISO setting forth the basis for any software-related implementation concerns raised by the ISO. The ISO shall make Commercially Reasonable Efforts to implement any needed software modifications by the effective date accepted by the FERC for a filing authorized by this Section 3.04(b), provided that, if the ISO has exercised such Commercially Reasonable Efforts, a failure to implement needed software modifications by the FERC-accepted effective date shall not constitute an event of default by the ISO under this Agreement or subject the ISO to financial damages, and further provided that the ISO shall run retroactive settlements consistent with the FERC-accepted effective date for a filing authorized by this Section 3.04(b) once such software modifications have been implemented.

Page No. 23

(c) The ISO shall have the authority to submit filings under Section 205 of the Federal Power Act to establish and to revise:

(i) any terms and conditions of the ISO Tariff, and any separate ISO tariffs, relating to Transmission Service and/or the New England Markets , provided that: (A) the ISO shall not have the authority to revise such terms and conditions in a manner that would abridge the rights granted to the PTOs in Section 3.04(a) or Section 3.04(b); (B) the ISO shall not have the authority to eliminate Local Network Service or Local Point-to-Point Transmission Service provided under the Local Service Schedules; (C) the ISO shall not file to change the state or federally-accepted or -approved terms and conditions of any PTO’s retail access plan or the terms and conditions of any retail access plans of a PTO’s affiliated distribution company’s (including any such terms and conditions that protect against bypass of any provision of a PTO’s retail access plan) or the state or federally-accepted or -approved rates and other mechanisms for the recovery of a PTO’s wholesale or retail stranded costs in effect as of the Operations Date; and (D) the ISO shall not have the authority to transfer to any third party the ISO’s Section 205 rights to revise the terms and conditions of Transmission Service or the authority to enter into agreements with any group of stakeholders to submit filings under Section 205 of the Federal Power Act to change the terms and conditions of Transmission Service where such proposed changes are not supported by the ISO but are approved by a vote of the stakeholder group.

The ISO shall provide written notification of any proposed filing under this Section 3.04(c) to the PTOs and stakeholders, which notification shall include a detailed description of the proposed filing, at least 30 days prior to the filing. The ISO shall consult with the PTOs and stakeholders and will consider any comments any PTO or stakeholder provides in developing its filing. The ISO shall retain the right to modify aspects of any filing authorized by this Section 3.04(c) after it provides written notification to the PTOs and stakeholders and shall provide notification to the PTOs and stakeholders of any material modification to such filings. In addition, the ISO shall consult with the PTOs to determine whether the filing will have any adverse impact on any PTO’s revenue requirements, or on the ability of any PTO to recover its revenue requirements, or have a material adverse impact on the ability of any PTO to implement an incentive rate plan then in effect. If the affected PTOs conclude in their good faith judgment that the filing will have any of such effects, the ISO and the affected PTOs will make every reasonable effort to resolve the concerns of the affected PTOs. In the event that the affected PTOs’ concerns cannot be resolved, the ISO may, nevertheless, make a filing under Section 205 provided that, except as provided in the next sentence, such a filing will not become effective until such time as the Commission issues an order determining the proposal set forth in the filing to be consistent with the standard applicable under Section 205 of the Federal Power Act. The ISO may request that FERC permit a filing authorized by this Section 3.04(c) to go into effect on an interim basis, notwithstanding the conclusion of the affected PTOs, provided that the ISO shall include in such a filing (and the transmittal letter for such a filing) any written statement provided by the affected PTOs setting forth the basis for the affected PTOs’ concerns. If FERC grants the ISO’s request

Page No. 24

to permit the filing to go into effect on an interim basis, the filing will become effective, subject to refund, on the date specified in FERC’s order. Notwithstanding the foregoing, in Exigent Circumstances , the ISO shall have the unilateral authority, upon written notice to the PTOs, the Participants Committee, and the individual Participants, to submit any filing under Section 205 of the Federal Power Act to modify any provision of the ISO Tariff as authorized in this Section 3.04(c), provided that such filing shall be subject to all conditions set forth in this Section 3.04(c) except for those conditions that would limit the ISO from submitting or implementing such an ISO unilateral filing on an expedited basis or that would require the consultation otherwise specified herein.

(d) Except as explicitly set forth in Section 3.04(e), with respect to certain items listed in Sections 3.04(a) and 3.04(b), the ISO shall have no authority to submit a filing under Section 205 of the Federal Power Act to modify any provision of the ISO OATT that implements any of the items listed in Section 3.04(a) or Section 3.04(b). The PTOs shall have no authority to submit a filing under Section 205 of the Federal Power Act to modify any provision of the ISO OATT that implements any of the items listed in Section 3.04(c). The ISO reserves its rights to intervene in, comment on or protest any filing made by the PTOs, and to submit proposals for the consideration of the PTOs and the PTOs reserve their rights to intervene in, comment on or protest any filing made by the ISO, and to submit proposals for the consideration of the ISO.

(e) In the event the ISO determines that a change in the design of any provision of the ISO OATT described in Section 3.04(a)(ii), (iii), (iv) or (vii) or 3.04(b) is required because the existing design of any rates or charges for Transmission Service is inconsistent with the design of the New England Markets, and such inconsistency will, if not remedied before relief would be available in a proceeding under Section 206 of the Federal Power Act, either: (i) substantially and adversely affect the efficiency or competitiveness of the New England Markets, or (ii) substantially and adversely affect the reliability of the ISO bulk power system, a senior officer of the ISO shall notify the affected PTO(s) of its determination. Upon receipt of such notification, the affected PTO(s) and the ISO shall diligently work together to arrive at appropriate changes in the rates to alleviate the conditions that led to this notification being given, while protecting the rights of the affected PTO(s) to fully recover their revenue requirements and the amount of incentive payments associated with FERC-accepted or -approved incentive arrangements for the PTO(s). If the affected PTO(s) and the ISO agree on a solution to this issue, the affected PTO(s) shall make a filing at FERC under Section 205 consistent with such agreement.

If the affected PTO(s) and the ISO cannot agree on a mutually acceptable Section 205 filing to address this issue within a period of thirty (30) days, and the affected PTO(s) do not make a Section 205 filing within the thirty (30) day period, then the ISO shall have the authority to submit a filing under Section 205 of the Federal Power Act as permitted herein. provided that such a Section 205 filing shall not be submitted until the PTOs have an opportunity to meet with representatives of the ISO Board of Directors if requested by any PTO with reasonable notice, and the ISO may, with the approval of FERC, place a replacement for such rate design into

Page No. 25

effect, while the proceeding on the ISO’s filing is pending before FERC, for a period no longer than fifteen (15) months, provided that such filing shall not propose a modification that adversely affects the rights of the affected PTO(s) to fully recover their FERC-allowed revenue requirements and the amount of incentive payments associated with FERC-allowed incentive arrangements for the PTO(s) or that would result in any costs previously approved or accepted for recovery under either a federal or state-jurisdictional rate thereafter becoming unrecoverable under either a federal or state-jurisdictional rate, and the replacement rate design proposal of the ISO is subject to refund and surcharge, as necessary to restore the status quo ante if FERC does not ultimately approve that proposal. To place its replacement rate design proposal into effect, the ISO shall bear the burden of persuading FERC that: (i) the ISO’s replacement proposal is consistent with the standard applicable under Section 205 of the Federal Power Act; (ii) the ISO’s determination regarding the inconsistency of the existing rate design with the design of the New England Markets and the impact of that inconsistency, as set forth in the first sentence of this subsection, is correct; and (iii) the ISO’s proposal will not adversely affect the rights of the affected PTO(s) to fully recover their FERC-allowed revenue requirements or the amount of incentive payments associated with FERC-allowed incentive arrangements for the PTO(s) or to fully recover costs previously approved or accepted for recovery under either a federal or state-jurisdictional rate. Notwithstanding the foregoing, in Exigent Circumstances , the ISO shall have the unilateral authority, upon written notice to the PTOs, the Participants Committee and the individual Participants, to submit a filing under Section 205 of the Federal Power Act to modify any provision of the ISO Tariff described in this Section 3.04(e), provided that such filing shall be subject to all conditions set forth in this Section 3.04(e) except for those conditions that would limit the ISO from submitting or implementing such an ISO unilateral filing on an expedited basis or that would require the consultation otherwise specified herein.

(f) In the event the ISO concludes that a filing to establish or to revise the terms and conditions listed in Section 3.04(c) is required and that providing the notification or consultation required under Section 3.04(c) for such filing would result in an unanticipated material adverse effect on the efficiency or competitiveness of the New England Markets or the reliability of the ISO bulk power system in the circumstances, the ISO: (i) shall provide such notification to the PTOs and stakeholders or undertake such consultation with the PTOs and stakeholders as is possible under the circumstances; and (ii) may submit a filing under Section 205 to establish or to revise the terms and conditions listed in Section 3.04(c) upon issuance of a written statement setting forth the circumstances that do not permit such notification or consultation.

(g) In the event the PTO(s) conclude that a filing to establish or to revise the rates, terms and conditions listed in Section 3.04(a) or 3.04(b) is required and that providing the notification or consultation required under Section 3.04(a) or Section 3.04(b) for such filing would result in an unanticipated material under-recovery of the PTO(s)’ revenue requirements or other material adverse financial effect on the PTO(s), the PTO(s): (i) shall provide such notification to the ISO and stakeholders or undertake such consultation with the ISO as is possible under the circumstances; and (ii) may make a Section 205 filing to establish or to revise

Page No. 26

the rates, terms and conditions listed in Section 3.04(a) or 3.04(b) upon issuance of a written statement setting forth the circumstances that do not permit such notification or consultation.

(h) Cost Allocation Moratorium

(i) During the five (5) year period commencing on the Operations Date (the “Moratorium Period”), neither the PTOs, pursuant to Section 3.04(b), nor the ISO, pursuant to Section 3.04(e), shall submit filings under Section 205 of the Federal Power Act to modify:

(A) the provisions and schedules of the ISO OATT governing the split between PTF and Non-PTF transmission facilities in effect prior to the Operations Date for purposes of allocating costs to Transmission Customers;

(B) the provisions and schedules of the ISO OATT establishing the methodology by which the costs of Transmission Upgrades and New Transmission Facilities related to generator interconnections are allocated under the ISO OATT; and

(C) the provisions and schedules of the ISO OATT establishing the methodology by which the costs of New Transmission Facilities and Transmission Upgrades are allocated under the ISO OATT;

(ii) The Parties’ agreement to forego submission of Section 205 filings during the Moratorium Period with respect to the items listed in Section 3.04(h)(i) (A) through (C) above shall not restrict in any way the rights of the PTOs, pursuant to and in accordance with Sections 3.04(b) or 3.04(a), to submit Section 205 filings to modify any elements of the rates applicable to Transmission Service other than those items listed in Section 3.04(h)(i) (A) through (C). Nothing in this Section 3.04(h) shall restrict in any way the rights of the PTOs to submit Section 205 filings to establish incentive or performance-based rates in accordance with Section 3.04(b)(iii) or to submit Section 205 filings to establish formula or stated rates in accordance with Section 3.04(b)(i), provided that such filings do not propose to modify the items listed in Section 3.04(h)(i) (A) through (C). Nothing in this Section 3.04(h) shall restrict in any way the rights of the ISO, pursuant to and in accordance with Section 3.04(e), to submit Section 205 filings to modify any elements of the rates applicable to Transmission Service other than, provided that such filings do not propose to modify the items listed in Section 3.04(h)(i) (A) through (C).

(iii) Notwithstanding Section 3.04(h)(i)(B) above, to the extent that the requirements for any New Transmission Facilities or Transmission Upgrades associated with new or existing generation set forth in the ISO OATT are modified during the Moratorium Period in a manner that creates a new or

Page No. 27

modified category of generator-related transmission costs, the PTOs shall have the authority, in accordance with Section 3.04(b), to submit Section 205 filings during the Moratorium Period to establish the methodology by which such new or modified generator-related transmission costs are allocated.

(iv) Nothing in this Section 3.04(h) shall supersede or alter the effect of any FERC orders concerning the allocation of costs for specific transmission facilities in the New England region.

(v) Nothing in this Section 3.04(h) shall restrict in any way the rights of the ISO or of any PTO during the Moratorium Period to submit a filing under Section 206 of the Federal Power Act to modify the provisions and schedules described in Section 3.04(h)(i) (A) through (C).

(vi) After the end of the Moratorium Period, the PTOs may exercise their rights in accordance with Section 3.04(b)to submit Section 205 filings to modify the provisions and schedules described in Section 3.04(h)(i) (A) through (C); provided that:

(A) The PTOs must provide the ISO, the Regional State Committee established by the states in the ISO region (the “Regional State Committee”), and stakeholders no less than 90 days advance notification of the proposed filing, including a detailed description of any proposed change to the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto). The PTOs, the ISO and the Regional State Committee shall engage in a process of consultation and negotiation in order to attempt to reach consensus on such filing.

(B) At least 30 days prior to the proposed filing date the Regional State Committee may inform the PTOs that the Committee opposes the PTOs’ proposal to change the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto).

(C) If the Regional State Committee opposes the PTOs’ proposal to change the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto), the PTOs may make the Section 205 filing to modify the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto); provided that: (1) such filing may not go into effect until FERC has approved the filing; (2) the Regional State Committee will have the right to provide the PTOs with an alternative proposal to change the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the

Page No. 28

successors thereto) which the PTOs will include in their Section 205 filing and which will be considered on an equal footing with the PTOs’ proposal in the FERC proceeding, and (3) such alternative proposal shall not adversely affect the rights of the affected PTO(s) to fully recover their FERC-allowed revenue requirements and the amount of incentive payments associated with FERC-allowed incentive arrangements for the PTO(s) or result in any costs previously approved or accepted for recovery under either a federal or state-jurisdictional rate thereafter becoming unrecoverable under either a federal or state-jurisdictional rate.

(D) If, notwithstanding the requirements of Section 3.04(h)(vi)(C), the Regional State Committee submits an alternative proposal to change the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto) that any PTO believes causes an under-recovery of costs when used in conjunction with the other elements of the rate design for transmission rates filed by the PTOs (or the one already in effect if the PTOs’ filing does not propose to change the rate design), the PTO(s) will have the right: (1) to include in such filing an explanation of why the PTO or PTOs believe the Regional State Committee proposal causes an under-recovery of costs contrary to the requirements of Section 3.04(h)(vi)(C); and (2) to file a modified rate design that eliminates such under-recovery (or a rate mechanism filed by one or more PTOs individually for that purpose, when the under-recovery affects them uniquely) in the event that the alternative proposal to change the cost allocation provisions set forth in Schedules 11 or 12 of the ISO OATT as of the Operations Date (or the successors thereto) is approved by the FERC placed into effect coincident with the effective date of such proposal.

(E) Any requirements established by this Section 3.04(h)(vi) with respect to the Regional State Committee shall not subject any PTO or ISO-NE to the jurisdiction or authority of any agent or agency of any state participating in the Regional State Committee.

(vii) After the end of the Moratorium Period, the ISO may exercise its rights in accordance with Section 3.04(e) to submit Section 205 filings to modify the provisions and schedules described in Section 3.04(h)(i) (A) through (C) if the PTOs fail to alleviate the conditions specified in Section 3.04(e).

(i) The ISO shall have sole authority to submit Section 205 filings to recover its administrative, capital and other costs (including the collection of funds from Transmission Customers to support payment of FERC annual charges with respect to transmission service for which the ISO is the Transmission Provider as defined in FERC rules and orders) including the design of any charges therefore (the “ISO Administrative Charge” ).

Page No. 29

(j) Nothing in this Agreement shall restrict in any way the rights of the ISO or of any PTO to submit an application under Section 206 of the Federal Power Act for revisions to the rates, terms and conditions of service under the ISO OATT. Nothing in this Agreement shall subject any Publicly-Owned PTO to regulation of rates and charges applicable to its transmission facilities under Sections 205 or 206 of the Federal Power Act; provided, however, that the justness and reasonableness of regional transmission rates or charges may be evaluated in light of the levels of, and manner in which, the costs of Publicly-Owned PTOs’ transmission facilities are recovered under regional transmission rates.

(k) Nothing in this Agreement shall restrict in any way the rights of any PTO to submit a proposal under Section 205 of the Federal Power Act to participate in, join, or become an ITC pursuant to Attachment M to the ISO OATT and, upon approval of such proposal, to withdraw from this Agreement in accordance with Section 10.01 of this Agreement.

(l) Stakeholder Process for Regional Rate Filings.

(i) Absent unanticipated circumstances, every PTO proposal to modify regional rates in accordance with Section 3.04(b) shall be presented by the PTOs to the appropriate stakeholder Technical Committee(s) for consideration and an advisory vote. The Technical Committee, at its next meeting following the one at which the intial presentation is made (which shall be no later than 30 days after any proposal is made), shall: (i) vote on the merits of the proposal as presented or with changes accepted by the PTOs; or (ii) by motion and vote of 66-2/3%, defer action on any proposal presented if it reasonably determines that additional information should and could be provided to more adequately inform the members of such Technical Committee before a vote on the merits is taken. Any deferral shall be for no more than 30 days, after which the PTOs may move for an advisory vote upon their proposal at the next meeting of the Technical Committee (which shall be held within 30 days of the start of the deferral). At that time, the Technical Committee may vote on the merits of the proposal as presented or with changes approved by the Committee, or may vote to oppose the proposal on the grounds that sufficient information has still not been provided, but may not defer consideration of the proposal for any further period without the consent of the PTOs. Failure of the Technical Committee to vote within the time frames set forth in this paragraph shall advance the process to the next step, and in no event shall a period of longer than 60 days be required for the PTOs to submit a proposal to modify regional rate design in accordance with Section 3.04(b) to the Participants Committee.

(ii) Absent unanticipated circumstances and after the fulfillment of the procedures outlined in Section 3.04(l)(i), every PTO proposal to modify regional rates in accordance with Section 3.04(b) shall be presented by the PTOs to the stakeholder Participants Committee for an advisory vote, along with a report of any action, failure to act or advisory vote taken by any Technical Committee(s).

Page No. 30

Such report shall be considered by the Participants Committee no later than the first regularly scheduled meeting following notification of that presentation. The Participants Committee shall: (i) vote on the merits of the proposal as presented or with changes accepted by the PTOs; or (ii) by motion and vote defer action on any proposal if it reasonably determines that the proposal presented is materially different from the proposal presented to the Technical Committee, and was not voted on by the Technical Committee. Any deferral shall result in a repeat of the processes outlined above. Notwithstanding the foregoing, the Participants Committee may, at its discretion, consider and vote upon any proposal submitted to it and such a vote shall have the same effect as if the proposal had first been voted upon by a Technical Committee. The Participants Committee may not defer action on any item that has been voted on by a Technical Committee and presented to the Participants Committee for an advisory vote unless the PTOs consent to such deferral. If the Participant Committee has not scheduled a meeting to vote on the merits of a PTO proposal to modify regional rates in accordance with Section 3.04(b) prior to date that the PTOs intend to submit such a proposal to the FERC, then the PTOs shall request that the Participants Committee schedule a special meeting to conduct an advisory vote on the merits of such proposal. In no event shall the PTOs be required to wait for a Participant Committee advisory vote for a period of longer than 90 days after initial notification of such proposal to stakeholders prior to submitting a proposal to modify regional rate design in accordance with Section 3.04(b) to the FERC.

(iii) An advisory vote by the Participants Committee on the merits of any proposal, whether in favor of or in opposition, terminates the stakeholder proceedings absent voluntary resubmission of the same or a modified proposal by the PTOs, at a future time. The PTOs shall report the results of such advisory vote in any relevant filing made by the PTOs with the FERC. A failure by the Participants Committee to vote within the time frames outlined above terminates the Participant proceedings absent voluntary resubmission of the same or a modified proposal by the PTOs at a future time.

(iv) Nothing in this Section 3.04(l) shall limit the ability of the PTOs to submit a filing pursuant to Section 3.04(g) to modify regional rates in the event the PTOs conclude that a filing to modify regional rates is required due to unanticipated circumstances, provided that the PTOs shall provide such notification to the stakeholder Participant Committee or undertake such consultation with the stakeholder Technical Committee(s) and Participant Committee as is possible under the circumstances and shall provide the Participants Committee with a written statement setting forth the circumstances that do not permit the notification or consultation otherwise required by this Section 3.04(l).

Page No. 31

(v) The process set forth in this Section 3.04(l) shall not apply to filings related to regional rates submitted to the FERC on an informational basis. The applicable process for review of such informational filings shall be set forth in the ISO OATT.

(m) Highgate Transmission Facilities (HTF).

(i) The costs of the HTF shall be included in the transmission rates for Regional Network Service on a phased- in basis, in accordance with Appendix B to the Attachment F Implementation Rule of the ISO OATT, provided that:

(A) the costs of the HTF shall be fully phased into the transmission rates for Regional Network Service in year 5 as defined in Appendix B to the Attachment F Implementation Rule of the ISO OATT;

(B) the HTF shall not be classified as PTF for rate purposes under the ISO OATT; and

(C) the rate treatment of the HTF shall establish no precedent or presumption concerning rate treatment of any other HVDC transmission facilities.

(ii) the HTF shall be classified as Category A Facilities, provided, however, that the classification of the HTF as Category A facilities under this Agreement shall establish no binding precedent or presumption concerning the operational and other terms and conditions for other HVDC facilities over which the ISO may obtain operational and other authority under this TOA or other ISO operating agreements in the future.

3.05 The ISO’s Responsibilities.

(a) In addition to its other obligations under this Agreement, in performing its obligations and responsibilities hereunder, and in accordance with Good Utility Practice, the ISO shall:

(i) maintain system reliability;

(ii) in all material respects, act in accordance with applicable Laws and conform to, and implement, all applicable reliability criteria, policies, standards, rules, regulations, orders, license requirements and all other applicable NERC/NPCC Requirements, and other applicable reliability organizations’ reliability rules, and all applicable requirements of federal or state laws or regulatory authorities; and

(iii) act without undue preference to any Party.

Page No. 32

(b) The ISO shall obtain and retain all necessary authorizations of FERC and other regulatory authorities to function as the New England RTO and shall possess the characteristics and perform the functions required for that purpose.

3.06 Each PTO’s Responsibilities.

(a) From and after the Operations Date, each PTO shall, in accordance with Good Utility Practice:

(i) direct, physically operate, repair, and maintain its Transmission Facilities and Local Control Centers in accordance with this Agreement, applicable Law, and applicable Operating Procedures;

(ii) operate and maintain, or arrange for a third party, approved by such PTO, in its sole discretion, to operate and maintain, one or more suitable Local Control Centers (including any Local Control Centers maintained as backup for a PTO’s primary Local Control Centers). Each PTO shall provide the ISO with reasonable notice of any change to its Local Control Center(s) and shall coordinate with the ISO to ensure that such a change will not adversely affect the reliable operation of the New England Transmission System. Each PTO shall have the responsibility to ensure that its Local Control Center(s) will: operate PTO Transmission Facilities on a 24 hour basis, implement the instructions, orders and directions received from the ISO in the exercise of its Operating Authority in accordance with Section 3.02, and perform the following functions in accordance with applicable Operating Procedures:

(A) switching and tagging;

(B) on- line monitoring;

(C) security analysis;

(D) dispatch voltage and reactive power, provided that the ISO shall dispatch voltage and reactive power to the extent the Local Control Centers are unable to maintain normal voltage schedules;

(E) coordinate the development of settings for dynamic reactive resources, FACTS controllers, special protection systems, PARS, and other similar dynamic equipment that affects power flows;

(F) implementation of the PTO Local Restoration Plan and development of modifications to such PTO Local Restoration Plans, subject to the approval of the ISO in

Page No. 33

order to coordinate and promote the reliability of the Restoration Plans;

(G) operation and maintenance of communication systems and software;

(H) implementation of voltage reduction measures;

(I) implementation of Load Shedding;

(J) coordinate with the ISO and the other PTOs with respect to congestion management efforts and, to the extent applicable, demand-side management and distributed generation efforts, provided that a PTO employee who is engaged in such coordination and who is not a Local Control Center employee shall be subject to the same standards of conduct and applicable provisions of the ISO Information Policy as a Local Control Center employee; and

(K) coordinate with other entities interconnected with the New England Transmission System.

(iii) cooperate with the ISO’s performance of the monitoring and audits in connection with all monitoring and compliance provisions detailed in Section 3.02(i) of this Agreement;

(iv) consistent with practice prior to the Operations Date, designate its Local Control Centers to serve as back up to the ISO reliability functions until the ISO re-establishes operational control at its own Back- up Control Center; provided that, in such situations, necessary information will be made available to such Local Control Centers to facilitate the continued operation of the New England Transmission System and that each PTO will comply with Section 11.09 and the ISO Information Policy on file with FERC to prevent such information from reaching any unauthorized person or entity;

(v) collaborate with the ISO with respect to:

(A) the development of Rating Procedures,

(B) the establishment of ratings for each PTO’s New Transmission Facilities;

Page No. 34

(C) the establishment of ratings for each PTO’s Acquired Transmission Facilities that do not have an existing rating as of the Operations Date, and

(D) the establishment of any changes to existing ratings for Transmission Facilities in effect as of the Operations Date.

To the extent there is any disagreement between the ISO and any PTO or PTOs concerning Rating Procedures or the rating of a Transmission Facility owned by such PTO or PTOs, such disagreement shall be the subject of good faith negotiations between the applicable PTO or PTOs and the ISO, provided that; (x) the applicable PTOs’ position concerning such Rating Procedures or Transmission Facility ratings shall govern until the applicable PTOs and the ISO agree on a resolution to such disagreement; and (y) nothing in this Section 3.06(a)(v) shall limit the rights of the ISO or of any PTO to submit a filing under Section 206 of the Federal Power Act with respect to Transmission Facility ratings or Rating Procedures. During any collaboration or discussions concerning Transmission Facility ratings, the PTOs shall continue to provide the ISO with up-to-date ratings information in accordance with the applicable Rating Procedures.

(vi) undertake operating actions in accordance with any tariffs or rate schedules approved or accepted by FERC;

(vii) provide the ISO with the right to use a level of communications capacity (and maintain the equipment associated with this capacity in accordance with Good Utility Practice) on its telecommunication assets and equipment attached to or associated with Transmission Facilities consistent with practice prior to the Operations Date in order to supply reliability-related data including meter, voice and data communications; continue to receive and send (for Regulation purposes) telemetry to and from existing generators and transmission substations; provide for the receipt of such information from generators and substations, and provide metering data and/or telemetry to the ISO (including providing the infrastructure for Regulation and Frequency Response Service), as reasonably necessary for the ISO to perform its obligations under this Agreement and the ISO OATT; provided that a PTO shall have the unfettered right to use communications capacity on its telecommunication assets and equipment attached to or associated with Transmission Facilities for other business purposes to the extent such capacity is not being used by the ISO as of the Operations Date; and provided further that: (1) as required by the pro forma Large Generator Interconnection Agreement in the ISO OATT, each PTO shall include provisions in its Interconnection Agreements with generators after the Operations Date providing for the installation and maintenance of sufficient communications capability to allow the ISO to exercise its Operating Authority with respect to

Page No. 35

such generators, and (2) the ISO may include the installation of additional communications capacity as an identified need in the regional transmission expansion plan, in which case such installation may be included within the PTO obligation to build set forth in, and subject to the terms and conditions in, Section 7 of Schedule 3.09(a).

(viii) notify the ISO prior to making changes to the operational status of such PTO’s Category B Facilities and provide information on the operational status of Category B Facilities consistent with practice prior to the Operations Date;

(ix) operate or cause to be operated its Local Area Facilities in a manner that does not result in the violation of reliability standards applicable to the New England Transmission System;

(x) provide the ISO with revenue metering data or cause the ISO to be provided with such revenue metering data;

(xi) in all material respects, comply with all applicable laws, regulations, orders and license requirements, and with all applicable requirements, and with all applicable NERC/NPCC Requirements, other applicable reliability organizations’ local reliability rules, and all applicable requirements of federal or state laws or regulatory authorities.

(b) Operation of Transmission Facilities During A System Failure. Existing Operating Procedures for use during a System Failure shall be utilized by the ISO and the PTOs. Any modifications to the Existing Operating Procedures for use during a System Failure or new Operating Procedures for use during a System Failure shall be developed by the ISO in the manner specified in Section 3.02(d). The procedures for use during a System Failure shall provide that, in situations where immediate action is required, each PTO’s Local Control Center(s) shall have the authority to take the following reliability actions at a minimum, provided that each PTO shall coordinate with the ISO as soon as practicable upon taking such action:

(i) Undertake those operational functions with respect to Transmission Facilities undertaken by the ISO under non-System Failure conditions;

(ii) Re-energize transmission facilities following breaker trips;

(iii) Implement emergency Load Shedding and voltage reduction measures and subsequent restoration;

(iv) Implement Voltage/VAR control;

(v) Adjust PARS settings;

Page No. 36

(vi) Dispatch generation as necessary to preserve system reliability; in accordance with applicable NERC/NPCC Requirements and ISO directives; and

(vii) Take such other measures necessary, consistent with Good Utility Practice, to respond to a System Failure.

Nothing in this Section 3.06(b) shall limit the right of each PTO pursuant to Section 3.07 to take any action(s) that it deems necessary to prevent loss of human life, injury to persons and/or damage to property.

3.07 Reserved Rights of the PTOs.

(a) Notwithstanding any other provision of this Agreement to the contrary, each PTO shall retain all of the rights set forth in this Section 3.07; provided, however, that such rights shall be exercised in a manner consistent with applicable NERC/NPCC Requirements and applicable regulatory standards. This Section 3.07 is not intended to reduce or limit any other rights of a PTO as a signatory to this Agreement or under the ISO OATT.

(i) Nothing in this Agreement shall restrict any rights: (A) of each PTO that is a party to a merger, acquisition or other restructuring transaction to make filings under Section 205 of the Federal Power Act with respect to such PTO’s reallocation or redistribution of revenues or the assignment of such PTO’s rights or obligations, to the extent the Federal Power Act requires such filings; or (B) of any PTO to terminate its participation in this Agreement pursuant to Article X of this Agreement, notwithstanding any effect its termination from the ISO may have on the distribution of transmission revenues among other PTOs.

(ii) Except as expressly provided in the grant of Operating Authority to the ISO, each PTO retains all rights that it otherwise has incident to its ownership of, and legal and equitable title to, its assets, including its Transmission Facilities and all land and land rights, including the right to build, acquire, sell, lease, merge, dispose of, retire, use as security, or otherwise transfer or convey all or any part of its assets, subject to the PTO’s compliance with Section 2.06 of this Agreement. Subject to Article X, a PTO may, directly or indirectly, by merger, sale, conveyance, consolidation, recapitalization, operation of law, or otherwise, transfer all or any portion of such PTO’s Transmission Facilities subject to this Agreement but only if such transferee or successors shall agree in writing to be bound by terms of this Agreement.

(iii) Any expansion or modification by a PTO of its Transmission Facilities, any facilities constructed by a PTO to connect the facilities of a current or proposed Transmission Customer to such Transmission Facilities, and/or any new transmission facilities constructed by a PTO pursuant to the ISO Planning Process shall be subject to such PTO’s right to recover, pursuant to appropriate financial arrangements and tariffs or contracts, all costs prudently incurred or

Page No. 37

prudently committed to be incurred, plus a return on invested equity and other capital, associated with constructing and owning or financing such facilities, expansions or modifications to its Transmission Facilities, in accordance with Schedule 3.09(a) hereof.

(iv) The responsibilities granted to the ISO under this Agreement shall not affect the rights of a PTO to modify or expand its Transmission Facilities, nor confer upon the ISO any authority to direct a PTO to modify or expand its Transmission Facilities except as provided in Schedule 3.09(a), and each PTO shall retain all rights and responsibilities specifically assigned to PTOs pursuant to Schedule 3.09(a).

(v) Each PTO shall have the right to adopt and implement, consistent with Good Utility Practice, procedures and to take such actions it deems necessary to protect its facilities from physical damage or to prevent injury or damage to persons or property.

(vi) Each PTO retains the right to take whatever actions, consistent with Good Utility Practice, it deems necessary to fulfill its obligations under applicable Law.

(vii) Nothing in this Agreement shall be construed as limiting in any way the rights of a PTO to make any filing with any applicable state or local regulatory authority.

(viii) Each PTO may request that the ISO commit additional generators (including specific output levels), or each PTO may take other actions permitted under the ISO OATT and Market Rules (including self-scheduling), if the PTO determines that additional generation is needed to ensure local area reliability, provided that the ISO shall make the final determination whether to commit additional generation in accordance with applicable provisions of the ISO OATT and Market Rules

(ix) Subject to Section 2.05, each PTO shall retain the right to enter into Interconnection Agreements with transmission owners, generators and other entities connecting with such PTO’s transmission facilities (including Transmission Facilities) and to file such agreements for approval or acceptance by FERC.

(x) Each PTO shall have the right to retain one or more subcontractors to perform any or all of its obligations under this Agreement. The retention of a subcontractor pursuant to the terms of this Section 3.07 shall not relieve the PTO of its primary liability for the performance of any of its obligations under this Agreement.

Page No. 38

(b) Any and all other rights and responsibilities of a PTO related to the ownership or operation of its Transmission Facilities not expressly assigned to the ISO under this Agreement will remain with such PTO.

(c) Nothing in this Agreement shall be deemed to impair or infringe on any rights or obligations of the PTOs under the Federal Power Act and FERC’s rules and regulations thereunder, provided that any such rights are not inconsistent with the express terms of this Agreement. Nothing contained in this Agreement shall be construed to limit in any way the right of any PTO to take any position, including opposing positions, in any administrative or judicial proceeding or filing by other PTOs or the ISO, notwithstanding that such proceeding or filing may be undertaken or made, explicitly or implicitly, pursuant to this Agreement.

(d) Nothing in this Agreement shall be deemed to impair or infringe on the exemption of Publicly-Owned PTOs, under Section 201(f) of the Federal Power Act, from the obligations and requirements of the Federal Power Act. Notwithstanding anything to the contrary in this Agreement, nothing contained herein shall subject any Publicly-Owned PTO to any requirement or obligation imposed by the Federal Power Act that would not apply to such Publicly-Owned PTO in the absence of this Agreement.

3.08 Repair and Maintenance of Transmission Facilities.

(a) Planning, Scheduling, and Approval of Transmission Facility Outages.

(i) Each PTO shall submit to the ISO long-term plans for Transmission Facility outages, shall submit to the ISO schedules for Transmission Facility outages, and shall obtain ISO approval for Transmission Facility outages in accordance with, and to the extent required by, Market Rule 1.

(ii) Notwithstanding any of the foregoing, nothing in this Section 3.08 shall be construed to require a PTO to reschedule an outage of a Transmission Facility or to require a PTO to refrain from initiating switching and tagging procedures to take a Transmission Facility out of service or place it back into service to the extent a PTO determines that such outage or actions are necessary to prevent injury or damage to persons or property or to protect its facilities from physical damage, in accordance with Section 3.07(a)(v) of this Agreement.

(b) Recovery of Transmission Outage Rescheduling Costs. The PTO(s) shall have the right, either collectively pursuant to and in accordance with Section 3.04(b), or individually pursuant to and in accordance with Section 3.04(a), to file a schedule to the ISO OATT that will provide for reimbursement to the affected PTO(s) for any direct costs incurred by the PTO(s) due to the ISO’s rescheduling or revocation of a previously scheduled or approved Transmission Facility outage to the extent the ISO reschedules or revokes a previously scheduled or approved Transmission Facility outage in accordance with Market Rule 1.

Page No. 39

(c) Annual Assessment of Outage Coordination Efforts. The ISO shall prepare and issue annual public reports on the scheduling and coordination of transmission outages. Each such annual report shall: (i) assess the accuracy of the ISO’s estimation of congestion and RMR cost impacts and the accuracy of PTO and other inputs used in such estimation; (ii) assess any long term impacts of the ISO’s exercise of its authority to require the rescheduling of transmission maintenance outages and (iii) include analyses and data which could allow a PTO to identify potential opportunities for incentives based on efficient coordination of outages and other operational measures that will reduce congestion costs or increase operational flexibility. The ISO shall provide a draft of each such annual report to the PTOs and interested stakeholders prior to issuing a final report and shall consider the input of the PTOs and interested stakeholders in preparing such reports, subject to any applicable restrictions set forth in the ISO Information Policy on file with FERC.

(d) Development of Incentive Proposals. Notwithstanding any other provision in this Agreement, the ISO will apply reasonable efforts to work actively with any interested PTO(s) to analyze alternatives including incentives adopted in other markets and to provide input for use by the interested PTO(s) in developing the design of incentive rates or mechanisms for regional congestion cost reduction. The ISO will work with other stakeholders in a similar fashion if so requested. Any such incentive proposal shall be filed by a PTO or PTOs with FERC in accordance with Section 3.04(a) or Section 3.04(b) as applicable. Such incentive mechanisms shall be designed to further improve coordination of outages or operational measures in a manner that will reduce overall congestion or RMR costs. Any PTO incentive must be approved or accepted by FERC. Each PTO developing an incentive proposal shall attempt to reach agreement with the ISO before filing an incentive proposal with FERC. The ISO may submit filings to the FERC (including a protest or a complaint under Section 206 of the Federal Power Act) raising any questions or concerns that it may have concerning a specific incentive proposal, provided that the ISO shall not contend that an incentive proposal is inappropriate or oppose the proposal on the ground that the PTOs have agreed to the provisions of Section 3.08 of this Agreement.

(e) Market Monitoring of Outage Scheduling. The Market Monitoring Unit of the ISO shall monitor the outage scheduling activities of the PTOs. The Market Monitoring Unit of the ISO shall have the right to request that each PTO provide information to the Market Monitoring Unit concerning the PTO’s scheduling of Transmission Facility outages, including the rescheduling or cancellation of any Planned, Scheduled or Approved Outage, and the PTO shall provide such information to the Market Monitoring Unit in accordance with Section 11.09(c) of this Agreement.

Page No. 40

(f) Damage or Destruction of Transmission Facilities.

(i) If, at any time during the Term, any of a PTO’s Transmission Facilities are damaged or destroyed, then, such PTO shall determine, in its sole discretion, consistent with Good Utility Practice and applicable Law, whether or not (and if so, in what manner) to restore or cause the restoration of such damaged or destroyed Transmission Facilities to substantially the same condition, character or use as existed before the damage or destruction, if at all, provided that such PTO shall consult with the ISO prior to making such determination and shall comply with the requirements specified in Section 2.06.

(ii) Nothing in this Section 3.08(f) shall limit the authority of the ISO to direct a PTO to modify or expand its Transmission Facilities in accordance with the ISO Planning Process, subject to the terms and conditions of Schedule 3.09(a) hereof.

3.09 Planning and Expansion.

(a) Each PTO shall perform all of its responsibilities, and exercise each of its rights, with respect to the planning and expansion of the New England Transmission System in accordance with the ISO OATT and Schedule 3.09(a) hereto. The ISO shall perform all of its responsibilities pursuant to the ISO Planning Process set forth in the ISO OATT. Each PTO shall engage in planning for its Local Area Facilities in a manner that is consistent with applicable NERC/NPCC Requirements, Good Utility Practice and the ISO OATT. The ISO and each PTO shall perform all such responsibilities in accordance with applicable Laws and Good Utility Practice. Nothing in this Agreement shall be construed to impose on any PTO an obligation to build transmission facilities except as provided in Schedule 3.09(a) hereto.

(b) The ISO shall utilize the Planning Procedures relating to the planning and expansion of the New England Transmission System. The Planning Procedures shall initially consist of the Planning Procedures in existence on the Operations Date (hereinafter “Existing Planning Procedures”). Such Existing Planning Procedures shall consist of those Planning Procedures listed in Schedule 3.09(b). The ISO shall develop any modifications to Planning Procedures (including Existing Planning Procedures) and any new Planning Procedures that it may deem necessary or appropriate in coordination with the PTOs and other stakeholders. In the event that the ISO and the applicable PTO(s) disagree about modifications to the portions of the Planning Procedures related to the planning and expansion of Transmission Facilities or any new Planning Procedures related to the planning and expansion of Transmission Facilities, the affected PTO(s) will have the opportunity to submit the dispute for resolution in accordance with the dispute resolution provisions set forth in Section 11.14 herein. Pending such resolution, the ISO shall have the authority to implement any such new Planning Procedures or modified Planning Procedures.

3.10 Invoicing, Collection and Disbursement of Customer Payments.

(a) Invoicing as of Operations Date. Except as provided in Section 3.10(a)(ii) and beginning on the Operations Date, the ISO will administer its current net settlement system,

Page No. 41

including invoicing of charges to Transmission Customers for Transmission Services on the Transmission Facilities as follows:

(i) The charges invoiced by the ISO shall include the following (each, an “Invoiced Amount”):

(A) any and all revenue requirements, rates, charges, fees and/or penalties for Transmission Service under the ISO OATT and related service agreements which the PTOs have filed with FERC pursuant to Section 3.04(b) and which have been accepted by FERC, including without limitation recovery of wholesale or retail stranded costs, other than amounts billed directly by PTOs pursuant to Section 3.10(a)(ii) below; and

(B) any and all rates, charges, fees and/or penalties under interconnection agreements which have been filed with and accepted by FERC, other than amounts billed directly by PTOs pursuant to Section 3.10(a)(ii) below.

(ii) Payments relating to Grandfathered Transmission Agreements, all services provided by a PTO pursuant to its Local Service Schedule on or after the Operations Date, interconnection agreements that provide for payment to PTOs, and any other payments made directly to the PTOs prior to the Operations Date shall continue to be invoiced by the PTOs and shall not be invoiced by the ISO; provided that, notwithstanding the foregoing, each PTO and the ISO may enter into separate agreements such that the ISO provides invoicing services for such payments.

(iii) The ISO shall remit or credit to the PTOs, consistent with the ISO Tariff and the net settlement system, any and all payments received or collected from Transmission Customers for Invoiced Amounts in accordance with this Agreement and directions provided to the ISO by the PTO Administrative Committee. The PTO Administrative Committee shall provide such directions to the ISO in accordance with the Disbursement Agreement among the PTOs. The PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose) shall also respond to any ISO questions or requests for clarification concerning such directions; provided that the ISO shall be able to rely upon the decision of the PTO Administrative Committee unless and until it receives notification from the PTO Administrative Committee or from a Governmental Authority of reversal of such direction by any Governmental Authority with jurisdiction over this Agreement.

(b) Changes to the ISO OATT After Operations Date. After the Operations Date, the ISO may file with FERC proposed amendments to the ISO OATT in accordance with Section 3.04 to effect changes in the invoicing and collection of the charges specified in

Page No. 42

Section 3.10(a)(i), provided that the proposed amendments to the ISO OATT will not, without the consent of the PTOs:

(i) effect any changes relating to the ISO OATT requirements of letters of credit, deposits, and/or other financial assurances (collectively, the “Financial Assurances”) to be provided by any party providing payments to the ISO in connection with the purchase of any goods or services provided by PTOs or any Market Participants (such parties, collectively, “ISO Customers”) or the ISO that would in any way, individually or in the aggregate, materially reduce the level of collateral protection provided by Financial Assurances for Invoiced Amounts from that on the date of execution of this Agreement;

(ii) change the reallocation provisions under the ISO Tariff (including the ISO’s billing policy thereunder) for payment defaults for Transmission Service;

(iii) change any reallocation provisions under the ISO Tariff (including the ISO’s billing policy thereunder) for payment defaults for any services or products under the ISO Tariff other than Transmission Service in any way that imposes any obligation on the PTOs, in their capacity as owners of Transmission Facilities, to bear any costs of that reallocation of payment defaults;

(iv) lower the PTO’s priority in payments for amounts collected by the ISO; or

(v) be inconsistent with any provision of this Agreement.

(c) The ISO’s Collection Obligations and Application of Financial Assurances Policies.

(i) If a Transmission Customer defaults on any payment of any PTO Invoiced Amount (the “Owed Amounts”), the ISO shall take all necessary actions to execute or call upon any Financial Assurances held by the ISO attributable to such Transmission Customer.

(ii) In connection with a default on payment of an Invoiced Amount by a Transmission Customer, the ISO shall, upon the request of the PTO AC, take those actions necessary to suspend Transmission Services to such defaulting Transmission Customer, including making a filing under Section 205 of the Federal Power Act to seek consent to suspend such Transmission Services; provided that the ISO need not suspend Transmission Services until FERC approval is first obtained. This provision shall not preclude the ISO from suspending service or making a filing under Section 205 of the FPA to seek to suspend Transmission Services or other services under the Tariff in any other circumstances.

Page No. 43

(d) No Pledge of Invoiced Amounts. The ISO shall not create, incur, assume or suffer to exist any lien, pledge, security interest or other change or encumbrance, or any other type of preferential arrangement (including a banker’s right of set off) against any Invoiced Amounts, any accounts receivables representing Invoiced Amounts, the settlement account maintained by the ISO into which payments on Invoiced Amounts are made and from which remittances are made to the PTOs or any Financial Assurances.

3.11 Grandfathered Transmission Agreements.

(a) Notwithstanding any other provision of this Agreement, Excepted Transactions will remain in effect for the terms of such agreements. Consistent with practice prior to the Operations Date, the ISO shall exercise its Operating Authority and otherwise fulfill its responsibilities under this Agreement in a manner that is consistent with and does not modify or abrogate the terms and conditions of such Excepted Transactions.

(b) Notwithstanding any other provision of this Agreement, Grandfathered Intertie Agreements, as set forth in Schedule 3.11(b), will remain in effect for the terms of such agreements. Consistent with practice prior to the Operations Date, the ISO shall exercise its Operating Authority and otherwise fulfill its responsibilities under this Agreement in a manner that is consistent with and that does not modify or abrogate the terms and conditions of such Grandfathered Intertie Agreements.

(c) Nothing in this Agreement shall require the modification or abrogation of Grandfathered Interconnection Agreements, as set forth in Schedule 3.11(c). Consistent with practice prior to the Operations Date, the PTOs agree to exercise their rights under Grandfathered Interconnection Agreements with generators to direct or request that generators take certain actions as needed to facilitate the exercise of Operating Authority by the ISO and the reliable operation of the New England Transmission System.

(d) All payments due to the PTOs under Grandfathered Transmission Agreements shall continue to be invoiced and collected by the PTOs in accordance with the terms of those agreements and shall not be invoiced or collected by the ISO. Notwithstanding the foregoing, each PTO and the ISO may enter into separate agreements such that the ISO provides invoicing services for such payments.

(e) Nothing in this Agreement shall alter the standards, procedures or requirements applicable to the modification of any Grandfathered Transmission Agreement.

3.12 Subcontractors. Each PTO acknowledges and agrees that, subject to the terms set forth herein, including Section 6.07, the ISO has the right to retain one or more subcontractors to perform any or all of its obligations under this Agreement. The retention of a subcontractor pursuant to the terms of this Section 3.12 shall not relieve the ISO of its primary liability for the performance of any of its obligations under this Agreement.

Page No. 44

3.13 Municipal/Tax-Exempt Utilities.

(a) The Parties to this Agreement hereby recognize the tax-exempt status of any tax-exempt bonds or other evidence of indebtedness of Publicly-Owned PTOs used to finance any Publicly-Owned PTO’s Transmission Facilities. Nothing in this Agreement is intended to, and nothing in this Agreement should be construed in a manner that would, jeopardize the tax-exempt status of any tax-exempt bonds or other debt used to finance any Publicly Owned PTO’s Transmission Facilities. The Parties to this Agreement contemplate that, as to Publicly-Owned PTOs, this Agreement will be deemed to be a “contract for the operation of an electric transmission facility by an independent entity” which “does not constitute private business use” of their Transmission Facilities under regulations of the Internal Revenue Service appearing, inter alia, in 26 C.F.R. § 1.141-7(g)(1)(ii) and subsequently adopted regulations of similar intent and coverage.

(b) In the event of a change in the nature of this Agreement that would jeopardize the tax-exempt status of any tax-exempt bonds or other debt used to finance Publicly-Owned PTO’s Transmission Facilities, or a change in the state or federal income tax treatment of the arrangements contemplated by this Agreement, or any other set of circumstances, the effect of which would be to render the participation of Publicly-Owned PTOs in the arrangements established by this Agreement inconsistent with the maintenance of the tax-exempt status of bonds or other debt used to finance any Publicly-Owned PTO’s Transmission Facilities, the Parties agree, if so requested, to undertake Commercially Reasonable Efforts to develop revised or replacement arrangements that will enable the Publicly-Owned PTOs to authorize the ISO to exercise Operating Authority over the Publicly-Owned PTOs’ Transmission Facilities without incurring adverse state or federal income tax treatment of their outstanding bonds or other debt used to finance any Publicly-Owned PTO’s Transmission Facilities, and will otherwise maintain the tax-exempt status of Publicly-Owned PTOs’ outstanding bonds or other debt used to finance any Publicly-Owned PTO’s Transmission Facilities. If, and to the extent that, the Parties to this Agreement are not able to accommodate the changes described in this subparagraph (b), the Parties will undertake Commercially Reasonable Efforts to develop an alternative means for Publicly-Owned PTOs to (i) transfer Operating Authority as to its Transmission Facilities to ISO-NE, and (ii) recover the costs of its PTF facilities in the same manner and by the same means as PTOs under this Agreement.

(c) In the event that an electric cooperative or membership corporation that owns PTF and has debt financed or guaranteed by the Rural Utilities Service (“RUS”) of the United States Department of Agriculture (a “Cooperative TO”) becomes a signatory to this Agreement, this Agreement shall become effective as to that Cooperative TO only upon approval of such participation by the RUS, to the extent required by RUS regulations, including those regulations currently codified at 7 C.F.R. § 1717.608 and subsequently adopted regulations of similar intent and coverage. Should such approval be denied or conditioned by the RUS in a manner unacceptable to the Cooperative TO, the other PTOs or the ISO, the other PTOs and the ISO will consult with the affected Cooperative TO and, if so requested, will undertake Commercially Reasonable Efforts to resolve to the extent practicable the objections articulated (and/or

Page No. 45

conditions imposed) by the RUS to the participation of the Cooperative TO in the arrangements contemplated by this Agreement. If, and to the extent that, the Parties to this Agreement are not able to accommodate the concerns expressed by the RUS as to the participation of such Cooperative TO, the Parties will undertake Commercially Reasonable Efforts to develop an alternative means for such Cooperative TO to (i) transfer Operating Authority as to its Transmission Facilities to ISO-NE, and (ii) recover the costs of its PTF facilities in the same manner and by the same means as PTOs under this Agreement.

(d) Nothing in this TOA or any other ISO agreement shall require any PTO on whose behalf Tax-Exempt Debt has been or will be issued, or which will issue Tax-Exempt Debt, to refund prior Tax-Exempt Debt or to violate restrictions applicable to facilities financed with Tax-Exempt Debt including contractual restrictions and covenants regarding use of such facilities.

(e) Nothing contained in this Agreement shall be construed to require any Publicly-Owned PTO: (i) to act in contravention of, or (ii) to refrain from acting where failure to act would be in contravention of, or (iii) to constitute consent or acquiescence by any Publicly-Owned PTO to any action or failure to act of any other Party in contravention of the laws of any State governing the organization or operation of the Publicly-Owned PTO.

3.14 No Impairment of the ISO’s Other Legal Rights and Obligations.

Nothing in this Agreement shall be deemed to impair or infringe on any rights or obligations of the ISO under the Federal Power Act and FERC’s rules and regulations thereunder, including the ISO’s rights and obligations to submit filings to recover its administrative, capital, and other costs, provided that any such rights are not inconsistent with the express terms of this Agreement. During the Term of this Agreement, the ISO shall:

(a) have the rights and obligations to design, develop, operate, maintain and administer the New England Markets and congestion pricing mechanisms (including the exclusive right to make Section 205 filings relating to the Market Rules in accordance with Section 3.04),

(b) have the rights to undertake actions relating to congestion pricing and management in accordance with this Agreement, ISO Market Rules, and applicable FERC orders.

Nothing in this Agreement shall be deemed to impair or infringe on such rights and obligations.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF THE PARTIES

4.01 Representations and Warranties of Each PTO. As of the time of execution of this Agreement, each PTO, severally, represents and warrants to the ISO and each other PTO as follows:

(a) Organization. It is duly organized, validly existing and in good standing under the laws of the state of its organization.

Page No. 46

(b) Authorization. It has all requisite power and authority to execute, deliver and perform this Agreement; the execution, delivery and performance by such PTO of this Agreement have been duly authorized by all necessary and appropriate action on the part of such PTO; and this Agreement has been duly and validly executed and delivered by such PTO and constitutes the legal, valid and binding obligations of such PTO, enforceable against such PTO in accordance with its terms; provided, however, that as to Massachusetts Publicly-Owned PTOs, this representation and warranty shall not be binding unless and until they shall have first obtained a finally adjudicated declaratory ruling from the Massachusetts courts that the transfer of Operating Authority over their Transmission Facilities is lawful and permissible under the Massachusetts General Laws.

(c) No Breach. The execution, delivery and performance by such PTO of this Agreement will not result in a breach of any terms, provisions or conditions of any agreement to which such PTO is a party which breach has a reasonable likelihood of materially and adversely affecting such PTO’s performance under this Agreement.

(d) Transmission Facilities. Except as set forth on Schedule 4.01(d), such PTO has listed on one of Schedule 2.01(a) or Schedule 2.01(b), all of the transmission facilities with a voltage level of 69 kV or greater that it owns in the New England Control Area as of the Operations Date and all of the transmission facilities leased to it with a voltage level of 69 kV or greater in the New England Control Area as of the Operations Date.

(e) NO WARRANTY REGARDING EACH PTO’S TRANSMISSION FACILITIES. IN CONNECTION WITH EACH PTO’S GRANT OF OPERATING AUTHORITY TO THE ISO OVER SUCH PTO’S TRANSMISSION FACILITIES PURSUANT TO THE TERMS OF THIS AGREEMENT, SUCH PTO’S TRANSMISSION FACILITIES ARE BEING MADE AVAILABLE PURSUANT TO THIS AGREEMENT TO THE ISO “AS IS, WHERE IS,” AND SUCH PTO IS NOT MAKING ANY REPRESENTATIONS OR WARRANTIES, WRITTEN OR ORAL, STATUTORY, EXPRESS OR IMPLIED, CONCERNING SUCH TRANSMISSION FACILITIES, INCLUDING, IN PARTICULAR, ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, ALL OF WHICH ARE HEREBY EXPRESSLY EXCLUDED AND DISCLAIMED. THE FOREGOING PROVISION IS NOT INTENDED TO LIMIT OR CONDITION ANY OBLIGATIONS OF THE PTOS EXPRESSLY PROVIDED FOR ELSEWHERE IN THIS AGREEMENT.

4.02 Representations and Warranties of the ISO. As of the time of execution of this Agreement, the ISO represents and warrants to each PTO as follows:

(a) Organization. It is duly organized, validly existing and in good standing under the laws of the state of its organization.

Page No. 47

(b) Authorization. It has all requisite power and authority to execute, deliver and perform this Agreement; the execution, delivery and performance by the ISO of this Agreement have been duly authorized by all necessary and appropriate action on the part of the ISO; and this Agreement has been duly and validly executed and delivered by the ISO and constitutes the legal, valid and binding obligation of the ISO, enforceable against the ISO in accordance with its terms.

(c) No Breach. The execution, delivery and performance by the ISO of this Agreement will not result in a breach of any of the terms, provisions or conditions of any agreement to which the ISO is a party which breach has a reasonable likelihood of materially and adversely affecting the ISO’s performance under this Agreement.

ARTICLE V

COVENANTS OF THE PTOS

5.01 Covenants of Each PTO. Each PTO covenants and agrees that during (i) the Term, or (ii) the period expressly specified herein, as applicable, such PTO shall comply with all covenants and provisions of this Article V, except to the extent the ISO and the number of PTOs necessary to amend this Agreement pursuant to Section 11.04(a) consent in writing to waive such covenants or performance is excused pursuant to Section 11.13(b).

5.02 Financial Statements and Filings. If a PTO’s financial statements, permit applications or any other filing with any Governmental Authority are publicly available, such PTO shall, upon request by the ISO, provide the ISO information sufficient to allow the ISO to locate such financial statements, permit applications or other filings, including the date and place of the filing of the relevant documents.

5.03 Expenses. Except to the extent specifically provided herein, all costs and expenses incurred by a PTO in connection with the negotiation of this Agreement shall be borne by such PTO; provided that nothing herein shall prevent such PTO from recovering such expenses in accordance with applicable law.

5.04 Consents and Approvals.

(a) Each PTO shall exercise Commercially Reasonable Efforts to promptly prepare and file all necessary documentation to effect all necessary applications, notices, petitions, filings and other documents, and shall exercise Commercially Reasonable Efforts to obtain (and will cooperate with each other in obtaining) any consent, acquiescence, authorization, order or approval of, or any exemption or nonopposition by, any Governmental Authority required to be obtained or made by such PTO in connection with this Agreement or the taking of any action contemplated by this Agreement.

(b) Each PTO shall exercise Commercially Reasonable Efforts to obtain consents of all other third parties necessary to the performance of this Agreement by such PTO.

Page No. 48

Each PTO shall promptly notify the ISO of any failure to obtain any such consents and, if requested by the ISO, shall provide copies of all such consents obtained by such PTO.

(c) Nothing in this Section 5.04 shall require any PTO to pay any sums to a third party, including any Governmental Authority, excluding filing fees paid to any Governmental Authority in connection with a filing necessary or appropriate to further action.

5.05 Notice and Cure. Each PTO shall notify the ISO and each other PTO in writing of, and contemporaneously provide the ISO and each other PTO with true and complete copies of any and all information or documents relating to, any event, transaction or circumstance, as soon as practicable after it becomes Known to such PTO, that causes or shall cause any covenant or agreement of such PTO under this Agreement to be breached or that renders or shall render untrue any representation or warranty of such PTO contained in this Agreement as if the same were made on or as of the date of such event, transaction or circumstance. The PTO shall use all Commercially Reasonable Efforts to cure such event, transaction or circumstance as soon as practicable after it becomes Known to such PTO. No notice given pursuant to this Section 5.05 shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein or shall in any way limit the ISO’s or any other PTO’s right to seek indemnity under Article IX.

ARTICLE VI

COVENANTS OF THE ISO

6.01 Covenants of the ISO. The ISO covenants and agrees that during (i) the Term, or (ii) the period expressly specified herein, as applicable, the ISO shall comply with all covenants and provisions of this Article VI, except to the extent the Parties consent in writing to a waiver of such covenants or performance is excused pursuant to Section 11.13(b).

6.02 Financial Statements and Filings.

(a) To the extent not provided to stakeholders generally or made publicly available by the ISO, the ISO shall make available to each PTO: (i) quarterly unaudited financial statements within sixty (60) days after each quarter end and (ii) annual audited financial statements within one hundred twenty (120) days after each fiscal year end. In each instance, the financial statements made available by the ISO pursuant to (i) and (ii) above shall be prepared in accordance with Generally Accepted Accounting Principles and shall be true and correct in all material respects.

(b) If financial statements, permit applications or any other filing with any Governmental Authority are publicly available, the ISO shall, upon request by a PTO, provide such PTO information sufficient to allow such PTO to locate such financial statements, permit applications or other filings including the date and place of the filing of the relevant documents.

Page No. 49

6.03 Expenses. Except to the extent specifically provided herein, all costs and expenses incurred by the ISO in connection with the negotiation of this Agreement shall be borne by the ISO; provided that nothing herein shall prevent the ISO from recovering such expenses in accordance with applicable law.

6.04 Consents and Approvals.

(a) The ISO shall exercise Commercially Reasonable Efforts to promptly prepare and file all necessary documentation to effect all necessary applications, notices, petitions, filings and other documents, and shall exercise Commercially Reasonable Efforts to obtain (and will cooperate with each PTO in obtaining) any consent, acquiescence, authorization, order or approval of, or any exemption or nonopposition by, any Governmental Authority required to be obtained or made by the ISO in connection with this Agreement or the taking of any action contemplated by this Agreement.

(b) The ISO shall exercise Commercially Reasonable Efforts to obtain consents of all other third parties necessary to performance of this Agreement by the ISO. The ISO shall promptly notify each PTO of any failure or anticipated failure to obtain any such consents and, if requested by such PTO, shall provide copies of all such consents obtained by the ISO.

(c) Nothing in this Section 6.04 shall require the ISO to pay any sums to a third party, including any Governmental Authority, excluding filing fees paid to any Governmental Authority in connection with a filing necessary or appropriate to discharge its obligations hereunder.

6.05 Notice and Cure. The ISO shall notify each PTO in writing of, and contemporaneously shall provide each PTO with true and complete copies of any and all information or documents relating to, any event, transaction or circumstance, as soon as practicable after it becomes Known to the ISO, that causes or shall cause any covenant or agreement of the ISO under this Agreement to be breached or that renders or shall render untrue any representation or warranty of the ISO contained in this Agreement as if the same were made on or as of the date of such event, transaction or circumstance. The ISO shall use all Commercially Reasonable Efforts to cure such event, transaction or circumstance as soon as practicable after it becomes Known to the ISO. No notice given pursuant to this Section 6.05 shall have any effect on the representations, warranties, covenants or agreements contained in this Agreement for purposes of determining satisfaction of any condition contained herein or shall in any way limit any right of a PTO to seek indemnity under Article IX.

6.06 Other PTOs.

(a) The ISO shall not perform, or enter into an agreement to perform, any Operating Authority or other RTO functions set forth in Section 3.02 or any other portion of this Agreement for any transmission utility in the New England Control Area subject to the jurisdiction of FERC unless such transmission utility enters into and becomes a Party to this

Page No. 50

Agreement pursuant to Section 11.05; provided, however, that this Section 6.06 shall not apply to agreements with owners of ties to other Control Areas, agreements with owners of Merchant Facilities, agreements with generators (to the extent the ISO obtains operating authority over transmission tie lines owned by generators through such agreements), or agreements with Independent Transmission Companies.

(b) The ISO may enter into agreements to perform Operating Authority or other RTO functions for one or more transmission utilities in a Control Area outside of New England. If the ISO enters into an agreement to perform Operating Authority or other RTO functions for one or more transmission utilities in an area contiguous to the New England Control Area, such agreement shall not: (i) materially and adversely affect the ISO’s ability to perform Operating Authority for any PTO, or (ii) be unduly preferential to any transmission utility similarly situated to any PTO; provided that, if a PTO believes that a proposed agreement to perform Operating Authority or other RTO functions for one or more transmission utilities in a Control Area contiguous to the New England Control Area violates the immediately foregoing proviso, such PTO may notify the ISO, within thirty (30) days after the receipt of the proposed agreement, of its desire to negotiate the additional or modified terms and conditions of this Agreement necessary to relieve said adverse effect or undue preference and if such negotiation is not concluded within thirty (30) days after said notice, either Party may seek to resolve the dispute in accordance with Section 11.14 of this Agreement and may file the additional or modified terms and conditions of this Agreement necessary to relieve said adverse effect or undue preference for approval by the FERC. Notwithstanding anything else in this agreement, including Section 11.04, the PTO proposing any additional or modified terms and conditions of this Agreement shall not be required to demonstrate that the existing terms and conditions of this Agreement are unjust and unreasonable if the ISO has agreed to or the FERC approves the proposed additional or modified terms and conditions in an agreement with transmission utilities in a Control Area contiguous to the New England Control Area. The limitations and procedures in this Section 6.06(b) shall not apply to the ISO’s execution and performance of Coordination Agreements (or amendments thereto) with the operators of neighboring Control Areas, to the administration of Interconnection Agreements with neighboring Control Areas, or to the ISO’s provision of reliability services to New Brunswick Power Corporation.

(c) Nothing in this Agreement shall be construed as granting any FERC-jurisdictional Initial PTO or Additional PTO the right to recover the costs of its Transmission Facilities pursuant to the ISO OATT or any other regulated tariff absent approval or acceptance by the FERC for such cost recovery. The Parties hereto expressly reserve their rights to oppose a request for such cost recovery for any potential PTO that is not recovering its transmission costs pursuant to FERC regulated transmission tariffs prior to the Operations Date.

6.07 Management Agreements. The ISO shall not enter into any management agreement relating to the provision of transmission services with any Person, including a transmission-owning utility, unless such agreement: (a) has been approved by FERC; (b) does not violate the ISO’s Code of Conduct and is on an arms- length basis; or (c) if for an aggregate amount of $1,000,000 or more for a contract with any Participant in the New England Markets,

Page No. 51

including PTOs, is the result of a competitive solicitation process, the outcome of which is based on factors that include, among others, skill, qualifications, costs, reputation, and associated risks.

6.08 ISO Line of Business; Non-Profit-Status. The ISO shall not be operated on a for-profit basis. This provision is not intended to require the ISO to maintain its status as an entity not subject to federal or state taxes, to require the ISO to remain a Delaware not-for-profit corporation or to assure that in any particular year that the ISO’s revenues do not exceed its expenses. The ISO shall not pay dividends or use its net earnings other than to offset ISO operating and capital expenses and maintain reasonable reserves.

ARTICLE VII

TAX MATTERS

7.01 Responsibility for PTO Taxes. Each PTO shall prepare and file all Tax Returns and other filings related to its Transmission Business and Transmission Facilities and pay any Tax liabilities related to its Transmission Business and Transmission Facilities. The ISO shall not be responsible for, or required to file, any Tax Returns or other reports for any PTO and shall have no liability for any Taxes related to any PTO’s Transmission Business or Transmission Facilities. No PTO shall be responsible for, or required to file, any Tax Returns or other reports for any other PTO and shall have no liability for any Taxes related to any other PTO’s Transmission Business or Transmission Facilities. The ISO and each PTO hereby agree that, for tax purposes, a PTO’s Transmission Facilities shall be deemed to be owned by such PTO.

7.02 Responsibility for ISO Taxes. The ISO shall prepare and file all Tax Returns and other filings related to its operations and pay any Tax liabilities related to its operations. No PTO shall be responsible for, or required to, file any Tax Returns or other reports for the ISO and shall have no liability for any Taxes related to the ISO’s operations.

ARTICLE VIII

RELIANCE; SURVIVAL OF AGREEMENTS

8.01 Reliance; Survival of Agreements. Notwithstanding any right of any Party (whether or not exercised) to investigate the accuracy of any of the matters subject to indemnification by any other Party contained in this Agreement, each of the Parties has the right to rely fully upon the representations, warranties, covenants and agreements of each other Party contained in this Agreement. The provisions of Sections 11.01, 11.09, 11.13 and 11.17 and Articles VII and IX shall survive the termination of this Agreement. With respect to Section 3.10 of this Agreement, the ISO will perform final billing consistent with Section 3.10 of this Agreement for all services provided until the Termination Date.

Page No. 52

ARTICLE IX

INDEMNIFICATION; INSURANCE; LIMITATION OF LIABILITIES

9.01 Indemnification.

(a) Subject to Section 9.06(b) through 9.06(e), (i) each PTO shall severally release, indemnify, and hold harmless the ISO from and against any and all damages, losses, liabilities, obligations, claims, demands, suits, proceedings, recoveries, judgments, settlements, costs and expenses, court costs, attorney fees, and all other obligations (each, an “Indemnifiable Loss”) asserted against the ISO by a Person that is not a Party to this Agreement (a “Third Party”) including but not limited to any action by a PTO employee, to the extent alleged to result from, arise out of or be related to such PTO’s acts or omissions that give rise to such Indemnifiable Loss; and (ii) the ISO shall release, indemnify, and hold harmless each PTO from and against any Indemnifiable Loss asserted against such PTO by a Third Party, including but not limited to any action by an ISO employee, to the extent alleged to result from, arise out of or be related to the ISO’s acts or omissions that give rise to such Indemnifiable Loss, including an ISO directive and/or instructions to a Party.

(b) The indemnification by the ISO set forth in Section 9.01(a)(ii) above shall be limited to the extent that the liability of a PTO seeking indemnification would be limited by any applicable Law and arises from a claim by (i) such PTO in such PTO’s role as a Transmission Customer or (ii) a customer of such PTO.

(c) Each PTO shall severally release, indemnify, and hold harmless the ISO from and against any Environmental Damages that the ISO becomes subject to as a result of its exercise of Operational Authority over such PTO’s Transmission Facilities, to the extent such Environmental Damages arose prior to the Operations Date or did not result from the ISO’s acts or omissions.

(d) Each PTO and/or the ISO each hereby (i) waives any defense or immunity it might otherwise have under applicable workers’ compensation laws or any other statute, or judicial decision, disallowing or limiting such indemnification and (ii) consents to a cause of action for indemnity and/or contribution in connection with such indemnification.

9.02 Notice of Proceedings. Each party entitled to receive indemnification under this Agreement (each, an “Indemnitee”) shall promptly notify the party who holds an indemnification obligation hereunder (in each case, the “Indemnifying Party”) of any Indemnifiable Loss in respect of which such Indemnitee is or may be entitled to indemnification pursuant to Section 9.01. Such notice shall be given as soon as reasonably practicable after the Indemnitee becomes aware of the Indemnifiable Loss and that any such claim or proceeding may give rise to an indemnification obligation hereunder. Such notice shall describe the nature of the loss or proceeding in reasonable detail and shall indicate, if practicable, the estimated amount of the Indemnifiable Loss that has been or may be sustained by the Indemnitee. The delay or failure of such Indemnitee to provide the notice required pursuant to this Section 9.02 shall not release the

Page No. 53

Indemnifying Party from any indemnification obligation which it may have to such Indemnitee except (a) to the extent that such failure or delay materially and adversely affects the Indemnifying Party’s ability to defend such action or increases the amount of the Indemnifiable Loss, and (b) that the Indemnifying Party shall not be liable for any costs or expenses of the Indemnitee in the defense of the claim, suit, action or proceeding during such period of failure or delay.

9.03 Defense of Claims.

(a) Unless and until the Indemnifying Party (i) acknowledges in writing its obligation within ten (10) calendar days of the Indemnitee’s notice of a claim, suit, action or proceeding, and (ii) assumes control of the defense of such claim, suit, action or proceeding in accordance with Section 9.03(b), the Indemnitee shall have the right, but not the obligation, to contest, defend and litigate, with counsel of its own selection, any claim, action, suit or proceeding by any third party alleged or asserted against such Indemnitee in respect of, resulting from, related to or arising out of any matter for which it is entitled to be indemnified hereunder, and the reasonable costs and expenses thereof shall be subject to the indemnification obligations of the Indemnifying Party hereunder.

(b) Upon acknowledging in writing its obligation to indemnify an Indemnitee to the extent required pursuant to this Article IX and paying all reasonable costs incurred by such Indemnitee in its defense, including reasonable attorney’s fees, the Indemnifying Party shall be entitled, at its option (subject to Section 9.03(d)), to assume and control the defense of such claim, action, suit or proceeding at its expense with counsel of its selection, subject to the prior reasonable approval of the Indemnitee.

(c) Neither the Indemnifying Party nor the Indemnitee shall be entitled to settle or compromise any such claim, action, suit or proceeding without the prior written consent of the other; provided, however, that such consent shall not be unreasonably withheld.

(d) Following the acknowledgment of the indemnification and the assumption of the defense by the Indemnifying Party pursuant to Section 9.03(b), the Indemnitee shall have the right to employ its own counsel and such counsel may participate in such action, but the fees and expenses of such counsel shall be at the expense of such Indemnitee, when and as incurred, unless: (i) the employment of counsel by such Indemnitee has been authorized in writing by the Indemnifying Party; (ii) the Indemnitee shall have reasonably concluded and specifically notified the Indemnifying Party that there may be a conflict of interest between the Indemnifying Party and the Indemnitee in the conduct of the defense of such action; (iii) the Indemnifying Party shall not in fact have employed independent counsel reasonably satisfactory to the Indemnitee to assume the defense of such action and shall have been so notified by the Indemnitee; (iv) the Indemnitee shall have reasonably concluded and specifically notified the Indemnifying Party that there may be specific defenses available to it which are different from or additional to those available to the Indemnifying Party or that such claim, action, suit or proceeding involves or could have a material adverse effect upon the Indemnitee beyond the scope of this Agreement; or (v) the Indemnifying Party shall not have taken reasonable steps necessary to defend diligently

Page No. 54

such action within twenty (20) calendar days after receiving notice from the Indemnitee that the Indemnitee believes the Indemnifying Party has failed to take such steps. If clause (ii), (iii), (iv) or (v) of the preceding sentence shall be applicable, then counsel for the Indemnitee shall have the right to direct the defense of such claim, action, suit or proceeding on behalf of the Indemnitee and the reasonable fees and disbursements of such counsel shall constitute indemnifiable legal or other expenses hereunder.

(e) If the amount of any Indemnifiable Loss incurred by an Indemnitee, at any time subsequent to the making of an indemnity payment by an Indemnifying Party in respect thereof, is reduced by recovery, settlement or otherwise under or pursuant to any insurance coverage, or pursuant to any claim, recovery, settlement or payment by or against any other entity, the amount of such reduction, less any costs, expenses or premiums incurred in connection therewith (together with interest thereon from the date of payment thereof at the Prime Rate) shall promptly be repaid by the Indemnitee to the Indemnifying Party. In the event that the claim, demand or suit giving rise to an Indemnifiable Loss is ultimately adjudicated, if a Final Order confirms that the Indemnitee was not entitled to indemnification hereunder, then the amount advanced by the Indemnifying Party in respect of such Indemnifiable Loss (together with interest thereon from the date of payment thereof at the Prime Rate) shall promptly be paid by the Indemnitee to the Indemnifying Party.

9.04 Subrogation. Upon payment of any indemnification by a party pursuant to this Article IX, the Indemnifying Party, without any further action, shall be subrogated to any and all claims that the Indemnitee may have relating thereto, and such Indemnitee shall at the request and expense of the Indemnifying Party cooperate with the Indemnifying Party and give at the request and expense of the Indemnifying Party such further assurances as are necessary or advisable to enable the Indemnifying Party vigorously to pursue such claims.

9.05 Insurance.

(a) The ISO shall at all times, at its own cost and expense, carry and maintain or cause to be carried and maintained throughout the Term: (i) liability and errors and omissions insurance (including blanket coverage for contractual liability), insuring the ISO against liability for injury or death to persons, damage to property and environmental restoration, (ii) worker’s compensation insurance, (iii) property insurance and (iv) directors’ and officers’ insurance. The amount of the insurance coverages and deductibles shall generally be comparable to other independent system operators or RTOs, taking into consideration the relative size of the ISO and its contractual and tariff liabilities as compared to the other system operators or RTOs administering similar market structures. In assessing the comparable coverages and deductibles, the ISO may rely on the advice of its insurance consultants.

(b) Each PTO will maintain property insurance on its Transmission Facilities and liability insurance in accordance with good utility practice. Each PTO may self insure such amount to the extent it currently self insures similar policies and amounts.

Page No. 55

(c) All insurance required under this Section 9.05 by outside insurers shall be maintained with insurers qualified to insure the obligations or liabilities under this Agreement and having a Best’s rating of at least B+ VIII (or an equivalent Best’s rating from time to time of B+ VIII), or in the event that from time to time Best’s ratings are no longer issued with respect to insurers, a comparable rating by a nationally recognized rating service or such other insurers as may be agreed upon by the PTOs and the ISO.

(d) The PTOs shall be listed as additional insured parties on the liability and errors and omissions insurance required to be maintained by the ISO and the ISO shall be listed as an additional insured party on the liability insurance maintained by each PTO. Upon execution of this Agreement, and when requested thereafter, each Party shall furnish each other Party with certificates of all such insurance policies setting forth the amounts of coverage, policy numbers, and date of expiration for such insurance in conformity with the requirements of this Agreement.

(e) The insurance policies maintained by the ISO hereunder shall not be canceled, terminated or the terms thereof modified or amended without at least thirty (30) days’ prior notice to the PTOs.

(f) If any insurance policy required to be maintained by the ISO hereunder shall not be available to the ISO on a commercially reasonable basis (taking into account both terms and premiums), the ISO shall obtain a written report of an independent insurance advisor of recognized national standing, chosen by the PTOs and reasonably acceptable to the ISO, confirming in reasonable detail that such insurance policy, in respect of amount or scope of coverage, is not available on a commercially reasonable basis from insurers of recognized standing. During any period with respect to which any insurance policy required by this Agreement is not commercially available, the ISO shall nevertheless maintain insurance that approximates such required insurance policy as closely as commercially practical, to the extent it is available on a commercially reasonable basis from insurers of recognized standing. If any insurance policy which was previously not held or discontinued because of its commercial unavailability later becomes available on a commercially reasonable basis, the ISO shall obtain or reinstate such insurance.

9.06 Assumption of Liability.

(a) (i) Each PTO shall be severally liable to the ISO, and the ISO shall be liable to each PTO, for losses, liabilities, damages, diminution in value, obligations, claims, proceedings, fines, deficiencies and expenses (collectively, “Losses”) caused by such Party’s grossly negligent acts or omissions or willful misconduct (including the grossly negligent acts or omissions or willful misconduct of such Party’s directors, Affiliates, members, officers, employees, agents, and contractors) in connection with the performance of such Party of its obligations under this Agreement; and (ii) no Party shall be liable to another Party for any incidental, indirect, special, exemplary, punitive or consequential damages, including lost revenues or profits, even if such damages are foreseeable or the damaged Party has advised such Party of the possibility of such damages and regardless of whether any such damages are deemed

Page No. 56

to result from the failure or inadequacy of any exclusive or other remedy. The foregoing limitations shall not apply to the right of the Parties to seek indemnification under this Agreement in accordance with Section 9.01.

(b) Nothing in this Agreement shall be deemed to affect the right of the ISO to recover its costs due to liability under this Article IX through the ISO Participants Agreement or the ISO Administrative Tariff.

(c) The ISO shall not be liable to any PTO with respect to any damages incurred by such PTO that are directly attributable to the ISO’s reliance on facility ratings established by such PTO.

(d) No PTO shall be liable to any other PTO and/or the ISO by reason of this Agreement (whether based on contract, indemnification, warranty, tort, strict liability or otherwise) for: (i) any acts or omissions taken or done in compliance with, or good faith attempts to comply with, the directives and/or instructions of the ISO, except in cases of the gross negligence or willful misconduct of such PTO; and/or (ii) any costs and expenses relating to the operation, repair, maintenance or improvement of any Transmission Facility of the ISO or any other PTO.

(e) Notwithstanding any of the foregoing, the ISO shall be liable in actual damages for failure to make payments or transfer sums under Section 3.10 of this Agreement if the ISO fails to discharge its obligation to prepare and send bills or to perform its obligations pursuant to Section 3.10 of this Agreement.

ARTICLE X

TERM; DEFAULT AND TERMINATION

10.01 Term; Termination Date.

(a) Term and Operations Date.

(i) Term. Subject to the terms set forth in this Section 10.01, the initial term of this Agreement (the “Initial Term”) shall commence on the Operations Date and shall continue for a period of five years. Subject to the terms set forth in this Section 10.01, the Initial Term shall be extended automatically for additional two-year periods (each, an “Additional Term”). Any one or more PTOs may withdraw from this Agreement effective at the end of the Initial Term or the end of any Additional Term by providing no less than 180 days’ prior notice of such withdrawal to the other Parties. Together, the Initial Term and the Additional Term(s), if any, shall constitute the term (the “Term”) of this Agreement.

Page No. 57

(ii) Operations Date. The “Operations Date” shall be the date on which the ISO and the Initial Participating Transmission Owners unanimously agree to place this Agreement, the ISO OATT, and related agreements and documents into effect. The ISO and the Initial Participating Transmission Owners shall jointly issue a written notice (the “Notice of Operations Date”) at least thirty (30) calendar days in advance of the Operations Date. The Notice of Operations Date shall be posted on the ISO website and filed with FERC on an informational basis.

(b) PTO Withdrawal During The Term. Subject to Section 10.01(e), any one or more PTOs may withdraw from this Agreement at any time during the Term if any of the following shall have occurred:

(i) upon an ISO event of default in accordance with Section 10.03(a), provided that the PTOs shall exercise this right in accordance with Section 10.03(b)(i).

(ii) if a Final Order of FERC, a Final Order of a Federal court or a Federal law sets forth a change in policy stating that: (A) the federal government no longer encourages the participation of transmission owners in RTOs and such Final Order or law affirmatively states that transmission owners participating in an RTO may withdraw therefrom, or (B) that the recovery of costs for existing Transmission Facilities will be subject to any change in policy which would prevent a PTO from recovering the costs of existing Transmission Facilities on a regulated cost-of-service basis; provided that withdrawal pursuant to (A) or (B) of this provision shall require notice to the other Parties not less than 180 days prior to the Termination Date established pursuant to Section 10.01(e).

(iv) FERC issues an order putting into effect changes to the relative rights and responsibilities of the PTOs and the ISO under this Agreement, including changing the scope and definition of Operating Authority, so as to materially adversely affect the interests of one or more PTOs, unless the PTOs have agreed to such changes in accordance with Section 11.04; provided that: (A) only the PTO(s) affected by such FERC order shall have the right to withdraw pursuant to this provision; (B) withdrawal pursuant to this provision shall require notice to the other Parties not less than 180 days prior to the Termination Date established pursuant to Section 10.01(e); and (C) a PTO providing a notice of withdrawal pursuant to this provision shall be required to rescind such notice if FERC issues a subsequent order prior to the Termination Date so as to eliminate the changes to the relative rights and responsibilities of the PTOs and the ISO under this Agreement.

(v) the withdrawing PTO has entered into an agreement to form an ITC in accordance with Attachment M to the ISO OATT which has been accepted

Page No. 58

for filing by the FERC, provided that withdrawal pursuant to this provision shall be effective concurrent with the effective date of such agreement.

(vi) the withdrawing PTO has obtained authorization from the FERC to join another RTO or other similar organization (such as an Independent System Operator) in connection with a merger with or acquisition by another entity other than another PTO.

(c) Remaining PTOs. In the event that one or more, but less than all, PTOs withdraw from this Agreement in accordance with Section 10.01(a) or (b), this Agreement shall remain in full force and effect with respect to all other PTOs; provided that in the event of a withdrawal under Section 10.01(a), the remaining PTOs shall have a period of twenty days from the date of the notice provided in accordance with Section 10.01(a) to notify the other Parties that it intends to withdraw from this Agreement at the end of the Initial Term or any Additional Term, as applicable. The “Termination Date” shall mean the date of termination established in accordance with Section 10.01(e).

(d) Termination By the ISO. The ISO may terminate its obligations under this Agreement and surrender its Operating Authority over the Transmission Facilities if any of the following shall have occurred:

(i) the withdrawal of one or more PTOs from this Agreement and as a result of such withdrawal the ISO cannot maintain system reliability or administer efficient and competitive markets.

(ii) FERC issues an order putting into effect material changes in the liability and indemnification protections afforded to the ISO under this Agreement or the ISO OATT, provided that: (A) withdrawal pursuant to this provision shall require notice to the other Parties not less than 180 days prior to the Termination Date established pursuant to Section 10.01(e); and (B) the ISO shall be required to rescind such notice if FERC issues a subsequent order prior to the Termination Date so as to eliminate the material changes to such liability and indemnification protections.

(iii) FERC issues an order putting into effect an amendment or modification of this Agreement that materially adversely affects the ISO’s ability to carry out its responsibilities under this Agreement, unless the ISO has agreed to such changes in accordance with Section 11.04, provided that: (A) withdrawal pursuant to this provision shall require notice to the other Parties not less than 180 days prior to the Termination Date established pursuant to Section 10.01(e); and (B) the ISO shall be required to rescind such notice if FERC issues a subsequent order prior to the Termination Date so as to eliminate the material adverse effect to the ISO’s ability to carry out its responsibilities under this Agreement.

Page No. 59

(iv) upon a PTO event of default in accordance with Section 10.04(a), provided that the ISO shall exercise this right in accordance with Section 10.04(b)(i).

(e) Actions Prior To Withdrawal or Termination. Upon submission of a written notice of termination or withdrawal by a Party or Parties, the Party or Parties submitting such notice shall commence the development of a plan under which Operating Authority shall be transferred from the ISO to another entity. The Termination Date with respect to any PTO or the ISO shall not occur until both: (a) the ISO and all affected PTOs have agreed upon a plan addressing the technical, operational and market issues associated with the transfer of Operating Authority in connection with such termination or withdrawal and such plan has been implemented, provided that: (i) if the Parties are unable to reach agreement on such plan, any affected Party shall have the right to submit the matter to FERC for resolution without additional negotiation under Section 11.14; (ii) with respect to a withdrawal pursuant to Section 10.01(a), no PTO shall be required to remain a Party to this Agreement for longer than one year after providing notice of withdrawal; and (iii) in the event of a default by the ISO, the affected PTOs may require that the ISO immediately make arrangements for the orderly transfer of the ISO’s invoicing and collection functions with respect to such PTOs prior to the Termination Date in accordance with Section 10.03(b); and (b) all required regulatory approvals, if any, have been obtained for such withdrawal or termination, including any approvals required pursuant to Section 10.01(f).

(f) Approvals. Notwithstanding any other provision contained herein or in any other document to the contrary, any termination or withdrawal requested under this Section 10.01 shall be effective: (1) unless a party to this Agreement seeking to challenge the request demonstrates that the requested termination or withdrawal is contrary to the public interest under the Mobile-Sierra Doctrine and (ii) subject to the FERC’s determination under Section 205 of the Federal Power Act that the termination or withdrawal is just, reasonable and not unduly discriminatory or preferential. Each PTO exercising its right to withdraw or terminate in accordance with this Section 10.01 shall file with the FERC, pursuant to Section 205 of the FPA, the tariffs and rate schedules applicable to transmission service over such PTO’s Transmission Facilities to become effective upon such termination or withdrawal.

(g) Continuing Obligations. Each withdrawing or terminating Party shall have the following continuing obligations following withdrawal from this Agreement

(i) All financial obligations incurred and payments applicable to the time period prior to the Termination Date shall be honored by the terminating or withdrawing Party and each other Party in accordance with the terms of this Agreement, and each Party shall remain liable for all obligations arising hereunder prior to the Termination Date.

Page No. 60

(ii) Any withdrawing PTO that is not a Publicly-Owned PTO shall file a replacement transmission tariff to replace the ISO OATT, unless FERC rules no longer require the filing of such a tariff. Any withdrawing Publicly-Owned PTO shall adopt the Order No. 888 pro forma tariff.

10.02 Release of Operating Authority.

(a) Upon the Termination Date, the ISO’s right and obligation to exercise Operating Authority over the Transmission Facilities of a PTO with whom this Agreement has terminated shall promptly cease, and, in accordance with Section 10.01, the ISO shall be deemed to have released and returned, and such PTO (or its designee) shall have assumed, Operating Authority over such Transmission Facilities on the Termination Date.

(b) After the Termination Date, the ISO shall take Commercially Reasonable Efforts to assist the terminating PTO or such PTO’s designee in resuming performance of the functions comprising Operating Authority.

(c) The expenses associated with any termination under Section 10.01 shall be at the PTO’s expense unless (1) the termination is by the ISO pursuant to Section 10.01(d)(ii) or (iii), or (2) pursuant to Section 10.03 in the event of an ISO default.

10.03 Events of Default of the ISO.

(a) Events of Default of the ISO. Subject to the terms and conditions of this Section 10.03, the occurrence of any of the following events shall constitute an event of default of the ISO under this Agreement:

(i) Failure by the ISO to perform any material obligation set forth in this Agreement and continuation of such failure for longer than thirty (30) days after the receipt by the ISO of written notice of such failure from a PTO; provided, however, that if the ISO is diligently pursuing a remedy during such thirty (30) day period, said cure period shall be extended for an additional thirty (30) days or as otherwise agreed by all affected Parties

(ii) If there is a dispute between the ISO and a PTO as to whether the ISO has failed to perform a material obligation, the cure period(s) provided in Section 10.03(a)(i) above shall run from the point at which a finding of failure to perform has been made by a Governmental Authority;

(iii) Any attempt (not including consideration of strategic options or entering into exploratory discussions) by the ISO to transfer an interest in, or assign its obligations under, this Agreement, except as otherwise permitted hereunder;

Page No. 61

(iv) Failure of the ISO (if it has received the necessary corresponding funds from ISO customers) to pay when due any and all amounts payable to any PTO by the ISO as part of the settlement process pursuant to Section 3.10 within three (3) Business Days;

(v) Failure of the ISO to pay when due any other amounts payable to any PTO by the ISO pursuant to this Agreement within thirty (30) days of the due date;

(vi) The exercise of Operating Authority or other responsibilities under this Agreement in a manner that results in a material amount of damage to or the destruction of a PTO’s Transmission Facilities due to the willful misconduct or gross negligence of the ISO or the repeated and persistent exercise by the ISO of its Operating Authority in a manner that subjects Transmission Facilities to the significant risk of a material amount of damage, provided that exercise by the ISO of its Operating Authority over any Transmission Facility both in accordance with the Operating Procedures and within the ratings established by a PTO for such Transmission Facility shall not be considered to subject such Transmission Facility to risk of damage and further provided that nothing in this Section 10.03(a)(v) shall be deemed to excuse the ISO from complying with its obligations under this Agreement or to limit the other events of default specified in this Section 10.03(a).

(vii) With respect to the ISO, (A) the filing of any petition in bankruptcy or insolvency, or for reorganization or arrangement under any bankruptcy or insolvency laws, or voluntarily taking advantage of any such laws by answer or otherwise or the commencement of involuntary proceedings under any such laws, (B) assignment by the ISO for the benefit of creditors; or (C) allowance by the ISO of the appointment of a receiver or trustee of all or a material part of its property if such receiver or trustee is not discharged within thirty (30) days after such appointment.

(b) Remedies for Default. If an event of default by the ISO occurs, each affected PTO shall have the right to avail itself of any or all of the following remedies, all of which shall be cumulative and not exclusive:

(i) To terminate its participation in this Agreement with respect to such PTO in accordance with Section 10.01(e); provided that if the ISO contests such allegation of an ISO event of default, this Agreement shall remain in effect pending resolution of the dispute, but any applicable notice period shall run during the pendency of the dispute;

(ii) To demand that the ISO shall immediately make arrangements for the orderly transfer of Operating Authority over such PTO’s Transmission Facilities and assist such PTO or such PTO’s designee in resuming performance

Page No. 62

of the functions comprising Operating Authority, provided that: (A) such PTO shall not be liable for the reimbursement of the ISO for any costs and expenses incurred by the ISO in connection therewith; (B) the ISO and all affected PTOs shall agree upon a plan addressing the technical and operational issues associated with such transfer of Operating Authority, and such plan has been implemented; and (C) if the Parties are unable to reach agreement on such plan, any affected Party shall have the right to submit the matter to FERC for resolution without additional negotiation under Section 11.14;

(iii) To demand that the ISO shall terminate any right of the ISO, immediately make arrangements for the orderly transfer of the ISO’s invoicing and collection functions with respect to such PTO and assist such PTO or such PTO’s designee in resuming performance of the functions the later of 20 days from the date of making such demand or the start of the next billing cycle. Without limiting the generality of the foregoing, the ISO agrees to deliver all information and files necessary to perform billing for regional transmission service (the “Regional Billing”), including but not limited to transferring all files then used by the ISO to prepare rate calculations and billing to a billing representative designated by the PTOs. The PTOs will provide the ISO, within 30 days of the Operations Date, with a list of the specific information and files necessary if the PTOs were to perform the Regional Billing;

(iv) To make any payment or perform or comply with any agreement that the ISO shall be obligated to pay, perform or comply with under this Agreement and the amount of reasonable expenses (including attorneys’ fees and any other reasonable professionals’ fees and expenses) of such PTO incurred in connection with such payment or the performance of or compliance with any such agreement shall be payable by the ISO upon demand;

(v) To obtain such specific performance and/or an injunction to prevent breaches of this Agreement and to enforce specifically the terms and conditions hereof; and/or

(vi) To obtain damages pursuant to the indemnity provisions of Sections 9.01 and 9.06 and for non-performance of invoicing/payment obligations under Section 3.10 of this Agreement.

10.04 Events of Default of a PTO.

(a) Events of Default of a PTO. Subject to the terms and conditions of this Section 10.04, the occurrence of any of the events listed below shall constitute an event of default of such PTO under this Agreement (in each instance, a “PTO Default”):

(i) Failure by such PTO to perform any material obligation set forth in this Agreement and continuation of such failure for longer than thirty (30) days

Page No. 63

after the receipt by such PTO of written notice of such failure from the ISO, provided, however, that if such PTO is diligently pursuing a remedy during such thirty (30) day period, said cure period shall be extended for an additional thirty (30) days or as otherwise agreed by all affected Parties;

(ii) If there is a dispute between a PTO and the ISO as to whether the PTO has failed to perform a material obligation, the cure period(s) provided in Section 10.04(a)(i) above shall run from the point at which a finding of failure to perform has been made by a Governmental Authority;

(iii) With respect to such PTO, (A) the filing of any petition in bankruptcy or insolvency, or for reorganization or arrangement under any bankruptcy or insolvency laws, or voluntarily taking advantage of any such laws by answer or otherwise or the commencement of involuntary proceedings under any such laws, (B) assignment by such PTO for the benefit of creditors; or (C) allowance by such PTO of the appointment of a receiver or trustee of all or a material part of its property if such receiver or trustee is not discharged within thirty (30) days after such appointment; or

(iv) Failure of the PTO to pay when due any amounts payable to the ISO by such PTO pursuant to this Agreement within thirty (30) days of the due date.

(b) Remedies for Default. If an event of default by a PTO occurs, the ISO shall have the following remedies, all of which shall be cumulative and not exclusive:

(i) terminate this Agreement with respect to such PTO in accordance with Section 10.01(e); provided that if such PTO contests such allegation of a PTO event of default, this Agreement shall remain in effect pending resolution of the dispute, but any applicable notice period shall run during the pendency of the dispute;

(ii) such specific performance and/or an injunction to prevent breaches of this Agreement and to enforce specifically the terms and conditions hereof; or

(iii) obtain damages pursuant to the indemnity provisions of Sections 9.01 and 9.06.

(c) Notwithstanding anything to the contrary herein, nothing in this Section 10.04 shall be deemed to give the ISO or any ISO agent or designee the right to exercise any functions other than those enumerated as Operating Authority in Section 3.02 or the right to take physical control of any PTO facilities.

Page No. 64

ARTICLE XI

MISCELLANEOUS

11.01 Notices. Unless otherwise expressly specified or permitted by the terms hereof, all communications and notices provided for herein shall be in writing and any such communication or notice shall become effective (a) upon personal delivery thereof, including by overnight mail or courier service, (b) in the case of notice by United States mail, certified or registered, postage prepaid, return receipt requested, upon receipt thereof, or (c) in the case of notice by facsimile, upon receipt thereof; provided that such transmission is promptly confirmed by either of the methods set forth in clauses (a) or (b) above, in each case addressed to each party and copy party hereto at its address set forth in Schedule 11.01 or, in the case of any such party or copy party hereto, at such other address as such party or copy party may from time to time designate by written notice to the other parties hereto; further provided that a notice given in connection with this Section 11.01 but received on a day other than a Business Day, or after business hours in the situs of receipt, will be deemed to be received on the next Business Day.

11.02 Supersession of Prior Agreements. With respect to the subject matter hereof, this Agreement (together with all schedules and exhibits attached hereto) constitutes the entire agreement and understanding among the Parties with respect to all subjects covered by this Agreement and supersedes all prior discussions, agreements and understandings among the Parties with respect to such matters, including those agreements set forth on Schedule 11.02 attached hereto. To the extent that such other agreements address subjects addressed in this Agreement, this Agreement shall govern.

11.03 Waiver. Any term or condition of this Agreement may be waived at any time by the Party that is entitled to the benefit thereof, but no such waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the Party waiving such term or condition. No waiver by any Party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. All remedies, either under this Agreement or by Law or otherwise afforded, shall be cumulative and not alternative.

11.04 Amendment; Limitations on Modifications of Agreement.

(a) Except as otherwise specifically provided herein, this Agreement shall only be subject to modification or amendment as follows:

(i) Establishment of Committee. The PTOs shall form a PTO Administrative Committee (“PTO AC”) which shall meet periodically (1) to consider recommendations to the ISO regarding actions, policies and rules of the ISO affecting the PTOs’ Transmission Facilities; (2) to consider and vote upon proposed amendments to this Agreement; (3) to consult with the ISO as may be provided for under this Agreement; and (4) to consider any other matters relating

Page No. 65

to the administration of this Agreement by the PTOs. The PTO AC shall be organized in the manner described in Schedule 11.04.

(ii) Amendments to Section 11.04(a)(iii) and Schedule 11.04. Notwithstanding anything in this Agreement which may be construed to the contrary, the PTOs may unilaterally amend or revise Sections 11.04(a)(iii)(B) and 11.04(a)(iii)(C) of this Agreement and Schedule 11.04 to this Agreement through a vote of the PTO AC as set forth in Section 12 of Schedule 11.04, without the consent of the ISO, and may submit such amended Agreement under Section 205 of the Federal Power Act. Notwithstanding anything in this Agreement which may be construed to the contrary, the ISO may unilaterally amend or revise section 11.04(a)(iii)(A) of this Agreement through the process set forth in that subsection, without the consent of the PTOs, and may submit such amended Agreement under Section 205 of the Federal Power Act.

(iii) Amendments to this Agreement. Except as set forth in section 11.04(a)(ii), this Agreement may be amended by mutual agreement of the PTOs and the ISO and the acceptance of any such amendment by FERC.

(A) ISO Agreement to Amendments. The ISO shall be deemed to have agreed to such amendment upon execution of the amendment.

(B) PTO Agreement to General Amendments. Except as otherwise provided in sections 11.04(a)(iii)(C) and 11.04(a)(iii)(D), the PTOs will be deemed to have agreed to such amendment upon a vote of the PTOs meeting all of the following criteria:

(1) Weighted Voting. A vote to approve an amendment to this Agreement under this Section 11.04(a)(iii)(B) shall be cast by a number of the Individual Votes of the PTOs equal to or greater than sixty-five (65) percent of the aggregate Individual Votes of all the PTOs;

(2) Support of Non-Affiliated PTOs. In addition to the Individual Votes satisfying Section 11.04(a)(iii)(B)(i), a vote of the PTOs to approve an amendment to this Agreement under this Section 11.04(a)(iii)(B) shall be cast by a number of Non-Affiliated PTOs that have Supporting Votes-that are equal to or greater than (x) fifty (50) percent of such Non-Affiliated PTOs or (y) four (4), whichever is less; and;

Page No. 66

(3) Limits on a Single PTO Veto. The negative vote of a single PTO with Individual Votes equal to thirty-five (35) but not more than fifty (50) percent of the aggregate Individual Votes of the PTOs shall not cause the amendment to fail if the combined Individual Votes of the PTOs voting in favor of the amendment are equal to or greater than ninety-five (95) percent of the Individual Votes of all the remaining PTOs. The negative vote of a single PTO with Individual Votes greater than fifty (50) percent of the aggregate Individual Votes of the PTOs voting shall cause the amendment to fail.

(C) PTO Agreement Requiring a Super Majority Vote. The PTOs will be deemed to have agreed to an amendment to Section 3.04(b) of this Agreement upon a vote of the PTOs meeting both of the following criteria:

(1) Weighted Voting. A vote to approve an amendment to section 3.04(b) of this Agreement shall be cast by a number of the Individual Votes of the PTOs equal to or greater than ninety-five (95) percent of the aggregate Individual Votes of all the PTOs; and

(2) Support of Non-Affiliated PTOs. In addition to the Individual Votes satisfying Section 11.04(a)(iii)(C)(i), a vote of the PTOs to approve an amendment to section 3.04(b) of this Agreement shall be cast by a number of Non-Affiliated PTOs that have Supporting Votes-that are equal to or greater than (x) seventy (70) percent of such Non-Affiliated PTOs or (y) five (5), whichever is less.

(D) PTO Agreement Requiring Consent of Affected Party. Notwithstanding anything in this Agreement which may be construed to the contrary, the PTO rights and privileges contained in sections 2.01, 3.04(a), 3.04(j), 3.04(k), 3.07, 3.13, 10.01(a), 10.01(b), and 11.04 of this Agreement and sections 12 and 13 of Schedule 11.04 to this Agreement shall not be modified or diminished by amendment to this Agreement or in any other way without the prior written consent of each PTO that may be affected thereby.

(E) Amendments to PTO Voting Provisions to Reflect Additional Participating Transmission Owners. If an

Page No. 67

unaffiliated transmission utility from outside the New England Control Area becomes or is about to become an Additional Participating Transmission Owner pursuant to Section 11.05 of this Agreement, and if any initial PTO’s Individual Vote will change by more than 20 percent as a result, the PTOs shall enter into good faith negotiations to consider appropriate modifications to Sections 11.04(a)(iii)(B) and 11.04(a)(iii)(C) of this Agreement and Schedule 11.04 to this Agreement. The PTOs may unilaterally amend or revise Sections 11.04(a)(iii)(B) and 11.04(a)(iii)(C) of this Agreement and Schedule 11.04 to this Agreement through a vote of the PTO AC as set forth in Section 11.04(a)(iii)(D), without the consent of the ISO, and may submit such amended Agreement to the FERC under Section 205 of the Federal Power Act.

(F) Supporting Votes. Each PTO that has a minimum of one (1) percent of the aggregate Individual Votes of all the PTOs at the time of the applicable PTO AC meeting shall have a single “Supporting Vote.” The Individual Votes of any group of two or more PTOs that each have an Individual Vote of less than one (1) percent may be combined and voted so that if the combined Individual Votes of such PTOs are equal to or greater than one (1) percent of the aggregate Individual Votes of all the PTOs at the time of the applicable PTO AC meeting, such combined Individual Votes shall be counted as a single Supporting Vote. Subject to a sufficient number of Publicly-Owned PTOs executing this Agreement, as of the Operations Date the combined Individual Votes of all of the Publicly-Owned PTOs is expected to be greater than one (1) percent of the aggregate Individual Votes of all the PTOs. In the event that the combined Individual Votes of all of the Publicly-Owned PTOs as of the Operations Date is greater than one (1) percent of the aggregate Individual Votes of all the PTOs, if at any time after the Operations Date, all of the Publicly-Owned PTOs have Individual Votes of less than one (1) percent of the aggregate Individual Votes of all of the PTOs due to the addition of new transmission assets and the depreciation of existing transmission assets, then the combined Individual Votes of all of the Publicly Owned PTOs shall nonetheless be counted as a single Supporting Vote.

Page No. 68

(b) In light of the foregoing, the Parties agree that they shall not rely to their detriment on any purported amendment, waiver or other modification of any rights under this Agreement unless the requirements of this Section 11.04 are satisfied and further agree not to assert equitable estoppel or any other equitable theory to prevent enforcement of this provision in any court of law or equity, arbitration or other proceeding.

(c) Absent the agreement of the Parties to any proposed change hereof or an amendment hereof pursuant to Section 11.04(a), the standard of review for changes to the following sections of this Agreement (or changes to any schedules associated with such sections) proposed by a Party, a non-party or the Federal Energy Regulatory Commission acting sua sponte shall be the “public interest” standard of review under the Mobile-Sierra Doctrine: 2.01, 2.04, 3.01, 3.02, 3.03, 3.04, 3.05, 3.06, 3.07, 3.09, 3.10, 3.11, 3.13, 3.14, 4.01(e), 6.06, 6.07, 6.08, 9.01, 9.06, 10.02, 10.03, 10.04, 11.04(a) - (d), 11.05, 11.06, 11.08, 11.17, 11.19(d), and Article I, as it applies to the foregoing sections. Absent the agreement of the Parties to any proposed change hereof or an amendment hereof pursuant to Section 11.04(a), with respect to changes to the remaining provisions of this Agreement proposed by a Party, a non-party or the Federal Energy Regulatory Commission acting sua sponte, the standard of review shall be that provided under Section 206 of the Federal Power Act.

(d) Notwithstanding the Parties’ rights under Section 3.04 hereof, neither the ISO nor any PTO shall propose to modify or amend the ISO OATT nor any other tariff, rate schedule, procedure, protocol, or agreement applicable to the ISO or the PTOs in any manner that would limit, alter, or adversely affect the rights and responsibilities of the non-proposing Parties under this Agreement or that would otherwise be inconsistent with the provisions of this Agreement unless: (i) the PTOs and the ISO have entered into a prior written agreement to make corresponding modifications to this Agreement in accordance with this Section 11.04, or (ii) if corresponding modifications to the provisions of this Agreement enumerated in Section 11.04(c) above are required, the proposing Party also requests FERC to find (or FERC has already so found) that the corresponding modifications are required under the “public interest” standard of review under the Mobile-Sierra Doctrine or (iii) if corresponding modifications to the remainder of the Agreement are required, the proposing Party also requests FERC to find (or FERC has already so found) that the corresponding modifications are required under the standard of review under Section 206 of the Federal Power Act.

(e) The Parties shall notify stakeholders of proposed amendments to this Agreement by posting such amendments on the ISO website prior to the filing of such amendments with FERC and shall consider stakeholder input concerning such proposed amendments.

11.05 Additional Participating Transmission Owners. After the Operations Date, subject to the terms set forth herein, including Section 6.06, any owner of transmission facilities may become a PTO under this Agreement and a Party to this Agreement by executing and delivering a counterpart to this Agreement with the consent or approval of the ISO, such consent or approval not to be unreasonably withheld. Owners of transmission facilities that become

Page No. 69

PTOs pursuant to the terms of this Section 11.05 shall be referred to herein as “Additional Participating Transmission Owners”; provided, however, that, notwithstanding any other provision contained herein to the contrary, Independent Transmission Companies shall not be deemed to be Additional Participating Transmission Owners hereunder. Notwithstanding Section 11.04 or any other provision contained herein to the contrary, Additional Participating Transmission Owners may become parties to this Agreement without any consent or approval of the other PTOs and without any amendment to this Agreement, except that this Agreement may be amended pursuant to Section 11.04(a)(iii)(E) if an unaffiliated transmission utility from outside the Control Area becomes or is about to become an Additional Participating Transmission Owner.

11.06 Integration Charges. Each Additional Participating Transmission Owner that enters into this Agreement after the Operations Date shall pay upon joining or shall promptly reimburse the ISO and each affected PTO for (a) all incremental costs, expenses and charges (including those incurred by the ISO or other PTOs) that, as determined by the ISO, result from the integration of such PTO’s transmission system into the Transmission Facilities over which the ISO exercises Operating Authority and produce an increase in ISO Administrative Charges assessed against users of the New England Transmission System; and (b) such PTO’s Pro Rata Share of the aggregate start-up costs recovered up to that date by the ISO. The ISO shall not implement any integration until it has received from the Additional Participating Transmission Owner payment in full for all such payments or secured a binding agreement that obligates the Additional Participating Transmission Owner to pay all such costs, expenses and other charges as they come due.

11.07 No Third Party Beneficiaries. Except as provided in Article IX, it is not the intention of this Agreement or of the Parties to confer a third party beneficiary status or rights of action upon any Person or entity whatsoever other than the Parties and nothing contained herein, either express or implied, shall be construed to confer upon any Person or entity other than the Parties any rights of action or remedies either under this Agreement or in any manner whatsoever.

11.08 No Assignment; Binding Effect. Neither this Agreement nor any right, interest or obligation hereunder may be assigned by a Party (including by operation of law) without the prior written consent of each other Party in its sole discretion and any attempt at assignment in contravention of this Section 11.08 shall be void. Any PTO may assign or transfer any or all of its rights, interests and obligations hereunder upon the transfer of its assets through sale, reorganization, or other transfer, provided that:

(a) the PTO’s successors and assigns shall agree to be bound by the terms of this Agreement except that PTO’s successors and assigns shall not be required to be bound by any obligations hereunder to the extent that the PTO has agreed to retain such obligations; and

(b) notwithstanding (a), the PTO shall assign or transfer to any new owner of Transmission Facilities subject to this Agreement all of the rights, responsibilities and obligations associated with the physical operation of such Transmission Facilities as well as all

Page No. 70

of the rights, responsibilities and obligations associated with the ISO’s Operating Authority with respect to such Transmission Facilities, further provided that the new owner shall have the right to retain one or more subcontractors to perform any or all of its responsibilities or obligations under this Agreement.

Subject to the foregoing, this Agreement is binding upon, inures to the benefit of and is enforceable by the Parties and their respective permitted successors and assigns. No assignment shall be effective until the PTO receives all required regulatory approvals for such assignment.

11.09 Further Assurances; Information Policy; Access to Records.

(a) Each Party agrees, upon another Party’s request, to make Commercially Reasonable Efforts to execute and deliver such additional documents and instruments, provide information, and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions, and conditions of this Agreement and of the transactions contemplated hereby.

(b) The ISO shall, upon a PTO’s request, make available to such PTO any and all information within the ISO’s custody or control that is necessary for such PTO to perform its responsibilities and obligations or enforce its rights under this Agreement, provided that such information shall be made available to such PTO only to the extent permitted under the ISO Information Policy and subject to any applicable restrictions in the ISO Information Policy, including provisions of the ISO Information Policy governing the confidential treatment of non-public information, and provided further that any PTO employee or employee of a PTO’s Local Control Center shall comply with such ISO Information Policy and any applicable standards of conduct to prevent the disclosure of such information to any unauthorized Person. Any dispute concerning what information is necessary for a PTO to perform its responsibilities and obligations or enforce its right under this Agreement shall be subject to dispute resolution under Section 11.14 of this Agreement.

(c) Each PTO shall, upon the ISO’s request, make available to the ISO any and all information within the PTO’s custody or control that is necessary for the ISO to perform its responsibilities and obligations or enforce its rights under this Agreement, provided that such information shall be shall be made available to the ISO only to the extent permitted under the ISO Information Policy and subject to any applicable restrictions in the ISO Information Policy, including provisions of the ISO Information Policy governing the confidential treatment of non-public information, and provided further that any ISO employee shall comply with such ISO Information Policy and any applicable standards of conduct to prevent the disclosure of such information to any unauthorized Person. Any dispute concerning what information is necessary for the ISO to perform its responsibilities and obligations or enforce its right under this Agreement shall be subject to dispute resolution under Section 11.14 of this Agreement.

(d) If, in order to properly prepare its Tax Returns, other documents or reports required to be filed with Governmental Authorities or its financial statements or to fulfill its obligations hereunder, it is necessary that the ISO or any PTO be furnished with additional

Page No. 71

information, documents or records not referred to specifically in this Agreement, and such information, documents or records are in the possession or control of the ISO or a PTO, the ISO or such PTO shall use its best efforts to furnish or make available such information, documents or records (or copies thereof) at the ISO’s or such PTO’s request, cost and expense. Any information obtained by the ISO or a PTO in accordance with this paragraph shall be subject to any applicable provisions of the ISO Information Policy.

(e) Notwithstanding anything to the contrary contained in this Section 11.09:

(i) no Party shall be obligated by this Section 11.09 to undertake studies or analyses that such Party would not otherwise be required to undertake or to incur costs outside the normal course of business to obtain information that is not in such Party’s custody or control at the time a request for information is made pursuant to this Section 11.09;

(ii) if any PTO and the ISO are in an adversarial relationship in litigation or arbitration (other than with respect to litigation or arbitration to enforce this Section 11.09), the furnishing of information, documents or records by the ISO or such PTO in accordance with this Section 11.09 shall be subject to applicable rules relating to discovery;

(iii) no Party shall be compelled to provide any privileged and/or confidential documents or information that are attorney work product or subject to the attorney/client privilege; and

(iv) no Party shall be required to take any action that impairs or diminishes its rights under this Agreement, diminishes any other Party’s obligations under this Agreement or otherwise lessens the value of this Agreement to such Party.

11.10 Business Day. Notwithstanding anything herein to the contrary, if the date on which any payment is to be made pursuant to this Agreement is not a Business Day, the payment otherwise payable on such date shall be payable on the next succeeding Business Day with the same force and effect as if made on such scheduled date and, provided such payment is made on such succeeding Business Day, no interest shall accrue on the amount of such payment from and after such scheduled date to the time of such payment on such next succeeding Business Day.

11.11 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware including all matters of construction, validity and performance without regard to the conflicts-of-laws provisions thereof.

11.12 Consent to Service of Process. Each of the Parties hereby consents to service of process by registered mail, Federal Express or similar courier at the address to which notices to it are to be given, it being agreed that service in such manner shall constitute valid service upon such party or its respective successors or assigns in connection with any such action or

Page No. 72

proceeding; provided, however, that nothing in this Section 11.12 shall affect the right of any such Parties or their respective successors and permitted assigns to serve legal process in any other manner permitted by applicable Law or affect the right of any such Parties or their respective successors and assigns to bring any action or proceeding against any other one of such Parties or its respective property in the courts of other jurisdictions.

11.13 Specific Performance; Force Majeure. (a) Specific Performance. The Parties specifically acknowledge that a breach of this Agreement, whether or not an Event of Default, and notwithstanding any cure period in Section 10.03(b), would cause each of the non-breaching Parties to suffer immediate and irreparable harm due to the unique relationship among the Parties. The Parties hereto shall be entitled to seek specific performance and/or an injunction or injunctions to prevent breaches of the provisions of this Agreement and to enforce specifically the terms and conditions hereof in any court of competent jurisdiction, such remedy being in addition to any other remedy to which any Party may be entitled at law or in equity.

(b) Force Majeure. A Party shall not be considered to be in default or breach under this Agreement, and shall be excused from performance or liability for damages to any other party, if and to the extent it shall be delayed in or prevented from performing or carrying out any of the provisions of this Agreement, except the obligation to pay any amount when due, in consequence of any act of God, labor disturbance, failure of contractors or suppliers of materials (not including as a result of non-payment), act of the public enemy or terrorists, war, invasion, insurrection, riot, fire, storm, flood, ice, explosion, breakage or accident to machinery or equipment or by any other cause or causes (not including a lack of funds or other financial causes) beyond such Party’s reasonable control, including any order, regulation, or restriction imposed by governmental, military or lawfully established civilian authorities. Any Party claiming a force majeure event shall use reasonable diligence to remove the condition that prevents performance, except that the settlement of any labor disturbance shall be in the sole judgement of the affected Party.

11.14 Dispute Resolution. The Parties agree that any dispute arising under this Agreement shall be the subject of good-faith negotiations among the affected Parties and affected market participants, if any. Each affected Party and each affected market participant shall designate one or more representatives with the authority to negotiate the matter in dispute to participate in such negotiations. The affected Parties and affected market participants shall engage in such good- faith negotiations for a period of not less than 60 calendar days, unless: (a) a Party or market participant identifies exigent circumstances reasonably requiring expedited resolution of the dispute by FERC or a court or agency with jurisdiction over the dispute; or (b) the provisions of this Agreement otherwise provide a Party the right to submit a dispute directly to FERC for resolution. Any other dispute that is not resolved through good- faith negotiations may, by any Party or any market participant, be submitted for resolution by FERC or a court or agency with jurisdiction over the dispute upon the conclusion of such negotiations. Any Party or market participant may request that any dispute submitted to FERC for resolution be subject to FERC settlement procedures. Notwithstanding the foregoing, any dispute arising under this Agreement may be submitted to arbitration or any other form of alternative dispute resolution

Page No. 73

upon the agreement of all affected Parties and all affected market participants to participate in such an alternative dispute resolution process.

11.15 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future Law, and if the rights or obligations of any Party under this Agreement shall not be materially and adversely affected thereby, (a) such provision shall be fully severable, (b) this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, (c) the remaining provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom, and (d) the court holding such provision to be illegal, invalid or unenforceable may in lieu of such provision add as a part of this Agreement a legal, valid and enforceable provision as similar in terms to such illegal, invalid or unenforceable provision as it deems appropriate; provided that nothing in this Section 11.15 shall limit a Party’s right to appeal conditions to regulatory approval in accordance with Section 11.20(d).

11.16 Headings and Table of Contents. The headings of the sections of this Agreement and the Table of Contents are inserted for purposes of convenience only and shall not be construed to affect the meaning or construction of any of the provisions hereof.

11.17 Liabilities; No Joint Venture.

(a) The obligations and liabilities of the ISO and each PTO arising out of or in connection with this Agreement shall be several, and not joint, and each Party shall be responsible for its own debts, including Taxes. No Party shall have the right or power to bind any other Party to any agreement without the prior written consent of such other Party. The Parties do not intend by this Agreement to create nor does this Agreement constitute a joint venture, association, partnership, corporation or an entity taxable as a corporation or otherwise. No express or implied term, provision or condition of this Agreement shall be deemed to constitute the parties as partners or joint venturers.

(b) To the extent any Party has claims against any other Party, such Party may only look to the assets of the other Party for the enforcement of such claims and may not seek to enforce any claims against the directors, members, officers, employees, affiliates, or agents of such other Party who, each Party acknowledges and agrees, have no liability, personal or otherwise, by reason of their status as directors, members, officers, employees, affiliates, or agents of that Party, with the exception of fraud or willful misconduct.

11.18 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all of which together shall constitute but one and the same instrument. The parties hereto agree that any document or signature delivered by facsimile transmission shall be deemed an original executed document for all purposes hereof.

Page No. 74

11.19 Conditions Precedent. Notwithstanding anything to the contrary in this Agreement, this Agreement shall not be effective with respect to any Party unless all of the conditions precedent set forth in this Section 11.19 shall have been satisfied or waived.

(a) Required Regulatory Approvals. All final required regulatory approvals shall have been obtained and be in full force and effect and shall not be subject to the satisfaction of any condition or conditions that, if accepted, would: (i) in the case of a PTO, in the reasonable judgment of such PTO, in the aggregate have a material adverse effect on the value of the PTO’s Transmission Facilities, its expected level of transmission revenues, or its electric utility business, revenues, or financial condition, unless such PTO waives said condition, provided however, that with respect to any required regulatory approval obtained from a Governmental Authority of a State, the condition set forth in this clause shall apply only if such PTO operates its Transmission Business within such State; and (ii) in the case of the ISO, in its reasonable judgment, have a material adverse effect on the ISO’s ability to perform its obligations under this or any other agreement to which it is subject, unless the ISO waives such condition.

(b) Board Consent. The board of directors of each Party, in its sole discretion, shall have authorized and approved such Party’s executing, delivering and performing this Agreement.

(c) Additional Conditions Precedent. Additional conditions precedent are listed on Schedule 11.19(c).

(d) PTOs That Own Facilities Financed by Local Furnishing Bonds or Other Tax-Exempt Debt. As indicated in Section 3.13, each PTO that owns Transmission Facilities financed through Local Furnishing Bond(s) or other Tax-Exempt Debt shall have adequate assurance, in the opinion of each such PTO, that execution and performance of its obligations under this Agreement will not jeopardize the tax-exempt status of their respective Tax-Exempt Debt or the ability of such PTOs to secure future tax-exempt financing.

(e) Right to Appeal Conditions to Regulatory Approval. In the event that a Governmental Authority conditions its regulatory approval of this Agreement on acceptance of a contractual provision, contractual modification, or any other condition or ruling related to formation of the New England RTO that is not acceptable to any Party, such Party shall have the option of agreeing to permit this Agreement to become effective with the condition or ruling to which it objects and appeal the propriety of the condition or ruling to courts of competent jurisdiction; provided that, in the event a Final Order requires a vacation or modification of such objectionable condition or ruling, this Agreement shall thereupon be modified consistent with that Final Order; provided, however, that other Parties may exercise their rights to withdraw from or terminate this Agreement pursuant to Section 10.01(b) or Section 10.01(d), as applicable.

11.20 Preserved Rights. No Party, by executing this Agreement, shall waive any rights to seek rehearing of a Commission order or to appeal a Commission order, including

Page No. 75

Commission orders concerning the terms and conditions of the NEPOOL tariff and market rules in effect prior to the Operations Date to the extent such terms and conditions have been incorporated into the ISO Tariff. The Parties expressly reserve the rights to pursue all pending requests for rehearing or appeals of such orders, and to file pleadings relating to such requests for rehearing or appeals, to the same extent as if the NEPOOL tariff were still in effect. Changes to the ISO Tariff shall be made to the extent necessary to comply with the results of a Commission rehearing order or judicial appeal concerning the terms and conditions of the NEPOOL tariff and market rules in effect prior to the Operations Date to the extent such terms and conditions have been incorporated into the ISO Tariff. The foregoing sentence shall not be deemed to prevent a Party from expressing its views to the Commission or a court regarding the foregoing compliance filing.

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the duly authorized officer of each party as of the date first above written.

[The names of the Initial PTOs will be submitted in a compliance filing prior to the Operations Date.]

Page No. 76

Schedule 1.01

Schedule of Definitions

Acquired Transmission Facilities. Any transmission facility acquired within the New England Control Area by one or more PTOs after the Operations Date that meets the classification standards set forth in Section 2.01(e).

Additional Participating Transmission Owners. “Additional Participating Transmission Owners” shall have the meaning ascribed thereto in Section 11.05 of this Agreement.

Additional Term. “Additional Term” shall have the meaning ascribed thereto in Section 10.01(a) of this Agreement.

Affiliate. Any person or entity which controls, is controlled by, or is under common control by another person or entity. For purposes of this definition, “control” shall mean the possession, directly or indirectly and whether acting alone or in conjunction with others, of the authority to direct the management or policies of a person or entity. A voting interest of ten percent or more shall create a rebuttable presumption of control.

Agreement. This Transmission Operating Agreement, as it may be amended from time to time.

Ancillary Service. Those services that are necessary to support the transmission of electric capacity and energy from resources to loads while maintaining reliable operation of the transmission system in accordance with Good Utility Practice.

Approved Outages. “Approved Outages” shall have the meaning ascribed thereto in Section 3.08(a)(iv) of this Agreement.

ATC. Available Transfer Capability.

Back-up Control Center. The control center established by the ISO as a back-up to the ISO Control Center.

Back-up Control Center Lease. The lease for premises in Newington, Connecticut entered into by ISO New England Inc. and Rocky River Realty Company for an initial term ending July 31, 2005, and subject to the right of the tenant to four three-year extensions.

Best’s. The A.M. Best Company.

Business Day. Any day other than a Saturday or Sunday or an ISO holiday, as posted by the ISO on its website.

Category A Facilities. Those transmission facilities listed in Schedule 2.01(a) of the Agreement, as that list may be modified from time to time in accordance with the terms of this Agreement.

Category B Facilities. Those transmission facilities listed in Schedule 2.01(b) of the Agreement, as that list may be modified from time to time in accordance with the terms of this Agreement.

CBM. Capacity Benefit Margin.

Commercially Reasonable Efforts: A level of effort which in the exercise of prudent judgment in the light of facts or circumstances known, or which should reasonably be known, at the time a decision is made, can be expected by a reasonable person to accomplish the desired result in a manner consistent with Good Utility Practice and which takes the performing party’s interests into consideration. “Commercially Reasonable Efforts” will not be deemed to require a Person to undertake unreasonable measures or measures that have a significant adverse economic affect on such Person, including the payment of sums in excess of amounts that would be expended in the ordinary course of business for the accomplishment of the stated purpose.

Commission. The Federal Energy Regulatory Commission.

Control Area. An electric power system or combination of electric power systems, bounded by metering, to which a common automatic generation control scheme is applied in order to:

(a) match, at all times, the power output of the generators within the electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load within the electric power system(s);

(b) maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice;

(c) maintain the frequency of the electric power system(s) within reasonable limits in accordance with Good Utility Practice and applicable NERC/NPCC Requirements; and

(d) provide sufficient generating capacity to maintain operating reserves in accordance with Good Utility Practice.

Control Center Lease. The Master Leasing Agreement, dated as of May 31, 1990, by and between Bankers Leasing corporation, as lessor, and State Street Bank and Trust Company of Connecticut, N.A., not in its individual capacity, but solely as Successor Nominee Trust under a Declaration of Trust, dated as of June 14, 1990, for beneficiaries listed in schedule 1 thereto, and as agent for the NEPOOL participants, as lessee.

Cooperative PTO. A PTO that has loans financed or guaranteed by the Rural Utilities Service.

Cooperative TO. A transmission owner has loans financed or guaranteed by the Rural Utilities Service.

Coordination Agreement. An agreement between the ISO and the operator(s) of one or more neighboring Control Areas addressing issues including interchange scheduling, operational arrangements, emergency procedures, energy for emergency and reliability needs, the exchange of information among Control Areas, and other aspects of the coordinated operation of the Control Areas.

Disbursement Agreement The Rate Design and Funds Disbursement Agreement among the PTOs, as amended and restated from time to time.

Elective Transmission Upgrade. A Transmission Upgrade constructed by any Person which is not required to be constructed pursuant to any applicable requirement of this Agreement, but which may be subject to applicable requirements set forth in the ISO OATT and this Agreement.

Elective Transmission Upgrade Applicant. “Elective Transmission Upgrade Applicant” shall have the meaning ascribed thereto in Section 2.05 of this Agreement.

Emergent and Unanticipated Event. For purposes of Section 3.08, “Emergent and Unanticipated Event” shall have the meaning ascribed thereto in Section 3.08(b)(ii)(B) of this Agreement.

Environment. Soil, land surface or subsurface strata, surface waters (including navigable waters, ocean waters, streams, ponds, drainage basins, and wetlands), groundwaters, drinking water supply, stream sediments, ambient air (including indoor air), plant and animal life, and any other environmental medium or natural resource.

Environmental Damages. “Environmental Damages” shall mean any cost, damages, expense, liability, obligation or other responsibility arising from or under Environmental Law consisting of or relating to:

(a) any environmental matters or conditions (including on-site or off-site contamination, occupational safety and health, and regulation of chemical substances or products);

(b) fines, penalties, judgments, awards, settlements, legal or administrative proceedings, damages, losses, claims, demands and response, investigative, remedial or inspection costs and expenses arising under Environmental Law;

(c) financial responsibility under Environmental Law for cleanup costs or corrective action, including any investigation, cleanup, removal, containment or other remediation or response actions (“Cleanup”) required by applicable Environmental Law (whether or not such Cleanup has been required or requested by any Governmental Authority or any other Person) and for any natural resource damages; or

(d) any other compliance, corrective, investigative, or remedial measures required under Environmental Law.

Environmental Laws. Any Law now or hereafter in effect and as amended, and any judicial or administrative interpretation thereof, including any judicial or administrative order, consent decree or judgment, relating to pollution or protection of the Environment, health or safety or to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.

Excepted Transactions. “Excepted Transactions” shall have the meaning ascribed thereto in the ISO OATT.

Excluded Assets. “Excluded Assets” shall have the meaning ascribed thereto in Section 2.04 of this Agreement.

Exigent Circumstances. “Exigent Circumstances” shall mean circumstances such that the ISO determines in good faith that (i) failure to immediately implement a proposed Tariff filing authorized under Sections 3.04(c) and 3.04(e) of this Agreement would substantially and adversely affect (A) System reliability or security, or (B) the competitiveness or efficiency of the New England Markets, and (ii) invoking the procedures set forth in Sections 3.04(c) and 3.04(e) of this Agreement would not allow for timely redress of the ISO’s concerns.

Existing Operating Procedures. “Existing Operating Procedures” shall have the meaning ascribed thereto in Section 3.02(d) of this Agreement.

External Transactions. Interchange transactions between the New England Transmission System and neighboring Control Areas.

FACTS. Flexible AC Transmission Systems.

FERC. The Federal Energy Regulatory Commission.

Final Order. An order issued by a Governmental Authority in a proceeding after all opportunities for rehearing are exhausted (whether or not any appeal thereof is pending) that has not been revised, stayed, enjoined, set aside, annulled or suspended, with respect to which any required waiting period has expired, and as to which all conditions to effectiveness prescribed therein or otherwise by law, regulation or order have been satisfied.

Financial Assurances. “Financial Assurances” shall have the meaning ascribed thereto in Section 3.10(b) of this Agreement.

FPA. The Federal Power Act.

FTR. A Financial Transmission Right, as defined in the ISO OATT.

Generally Accepted Accounting Principles. The widely accepted set of rules, conventions, standards, and procedures for reporting financial information, as established by the Financial Accounting Standards Board.

Generating Unit. A device for the production of electricity.

Good Utility Practice. Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather includes all acceptable practices, methods, or acts generally accepted in the region.

Governmental Authority. The government of any nation, state or other political subdivision thereof, including any entity exercising executive, military, legislative, judicial, regulatory, or administrative functions of or pertaining to a government, not including any PTO or the ISO.

Grandfathered Interconnection Agreement. An agreement or agreements for the interconnection of any entity to the Transmission Facilities of a PTO that has been executed or approved by an applicable Governmental Authority prior to the Operations Date and that is set forth in Schedule 3.1l(c) to this Agreement.

Grandfathered Intertie Agreement. An agreement or agreements for the provision of transmission service over a Control Area intertie or for the interconnection of the Transmission Facilities of a PTO with facilities outside the New England Control Area that has been executed or approved by an applicable Governmental Authority prior to the Operations Date and that is set forth in Schedule 3.11 (b) of this Agreement.

Grandfathered Transmission Agreements. “Grandfathered Transmission Agreements” shall consist of all Excepted Transactions, Grandfathered Interconnection Agreements and Grandfathered Intertie Agreements.

Hazardous Materials. Any waste or other substance that is listed, defined, designated, or classified as, or otherwise determined to be, hazardous, radioactive, or toxic or a pollutant or a contaminant under or pursuant to any Environmental Law, including any admixture or solution thereof, and specifically including petroleum and all derivatives thereof or synthetic substitutes therefor and asbestos or asbestos-containing materials.

Highgate Transmission Facility (HTF). “Highgate Transmission Facility (HTF) shall consist of existing U.S.-based transmission facilities covered under the Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection dated as of August 1, 1984 including (1) the whole of a 200 megawatt high-voltage, back-to-back, direct-current converter facility located in Highgate, Vermont and (2) a 345 kilovolt transmission line within Highgate and Franklin, Vermont (which connects the converter facility at the U.S.-Canadian border to a Hydro-Quebec 120 kilovolt line in Bedford, Quebec). The HTF include any upgrades associated with increasing the capacity or changing the physical characteristics of these facilities as defined in the above stated agreement dated August 1, 1984 until the Operations

Date, as defined in this Agreement. The current HTF rating is a nominal 225 MW. The HTF are not defined as PTF. Coincident with the Operations Date and except as stipulated in Schedules 9, 12, and Attachment F to the ISO OATT, HTF shall be treated in the same manner as PTF for purposes of the ISO OATT and all references to PTF in the ISO OATT shall be deemed to apply to HTF as well. The treatment of the HTF is not intended to establish any binding precedent or presumption with regard to the treatment for other transmission facilities within the New England Transmission System (including HVDC, MTF, or Control Area Interties) for purposes of the ISO OATT.

Indemnifiable Loss. “Indemnifiable Loss” shall have the meaning ascribed thereto in Section 9.01(a)(i) of this Agreement.

Indemnified Person. “Indemnified Person” shall have the meaning ascribed thereto in Section 9.0l(b) of this Agreement.

Indemnified PTO. “Indemnified PTO” shall have the meaning ascribed thereto in Section 9.01(a)(i) of this Agreement.

Indemnifying Party. “Indemnifying Party” shall have the meaning ascribed thereto in Section 9.02 of this Agreement.

Indemnifying PTO. “Indemnifying PTO” shall have the meaning ascribed thereto in Section 9.0l(b) of this Agreement.

Indemnitee. “Indemnitee” shall have the meaning ascribed thereto in Section 9.02 of this Agreement.

Independent Transmission Company or ITC. A transmission entity that assumes certain responsibilities in accordance with Attachment M to the ISO OATT, subject to the acceptance or approval of the FERC and a finding of the FERC that the transmission entity satisfies applicable independence requirements.

Individual Votes. “Individual Votes” shall have the meaning ascribed thereto in Section 13 of Schedule 11.04 to this Agreement.

Initial Participating Transmission Owners. The transmission owners listed in the opening paragraph of the Agreement that are signatories to this Agreement as of the Operations Date.

Initial Term. “Initial Term” shall have the meaning ascribed thereto in Section 10.01(a) of this Agreement.

Interconnection Agreement. An agreement or agreements for the interconnection of any entity to the Transmission Facilities of a PTO.

Interconnection Standard. The applicable interconnection standards set forth in the ISO OATT.

Invoiced Amount. “Invoiced Amount” shall have the meaning ascribed thereto in Section 3.10(a)(i) of the Agreement.

ISO. ISO New England Inc., the RTO for New England authorized by the Federal Energy Regulatory Commission to exercise the functions required pursuant to FERC’s Order No. 2000 and FERC’s corresponding regulations.

ISO Administrative Charge. “ISO Administrative Charge” shall have the meaning ascribed thereto in Section 3.04(h) of this Agreement.

ISO Control Center. The primary control center established by the ISO for the exercise of its Operating Authority and the performance of functions as an RTO.

ISO Customers. “ISO Customers” shall have the meaning ascribed thereto in Section 3.10(b) of this Agreement.

ISO Default. “ISO Default” shall have the meaning ascribed thereto in Section 10.03(a) of this Agreement.

ISO Information Policy. The information policy set forth in the ISO OATT.

ISO-NE. ISO New England, Inc.

ISO OATT. The ISO Open Access Transmission Tariff, as in effect from time to time.

ISO Participants Agreement. The agreement among the ISO and stakeholder participants addressing, inter alia, the stakeholder process for the ISO.

ISO Planning Process. The process set forth in the ISO OATT, for the coordinated planning and expansion of the New England Transmission System with provision for the participation of all state regulatory authorities with jurisdiction over retail rates in the ISO region acceptable to those authorities, which process shall be subject to certain terms and conditions set forth in Schedule 3.09(a).

ISO System Plan. The regional system expansion plan for the New England Transmission System.

ISO Tariff. The ISO Transmission, Markets and Services Tariff, as amended from time to time, on file with FERC.

Knowledge. With respect to a Party, the collective actual knowledge of the directors and members of management of such Party, after reasonable inquiry by them of selected employees of such Party whom they believe, in good faith, to be the persons generally responsible for the subject matters to which the knowledge is pertinent. “Known” shall have the meaning correlative to “Knowledge.”

Large Generating Unit. “Large Generating Unit” shall have the meaning ascribed thereto in the ISO OATT.

Law. Any federal, state, local or foreign statute, law, ordinance, regulation, rule, code, order, other requirement or rule of law.

Load Shedding. The systematic reduction of system demand by temporarily decreasing load.

Local Area Facilities. “Local Area Facilities” shall have the meaning ascribed thereto in Section 2.01 of this Agreement.

Local Control Center. Those control centers now in existence (including the CONVEX, REMVEC, Maine and New Hampshire control centers) or established by the PTOs in accordance with Section 3.06(a) of this Agreement that are separate from the ISO Control Center and perform certain functions in accordance with this Agreement.

Local Furnishing Bonds. Tax-exempt bonds utilized to finance facilities for the local furnishing of electric Energy, as described in section 142(f) of the Internal Revenue Code, 26 U.S.C. §142(f). Local Furnishing Bonds do not include Municipal Tax-Exempt Debt.

Local Networks. “Local Networks” shall have the meaning ascribed thereto in Section 3.03(e) of this Agreement.

Local Network Service. Network Transmission Service over the facilities of a single PTO (including facilities leased to the PTO or to which the PTO has contractual entitlements) provided under a FERC-accepted or -approved Local Service Schedule.

Local Point-to-Point Transmission Service. Point-to-point Transmission Service over the facilities of a single PTO (including facilities leased to the PTO or to which the PTO has contractual entitlements) provided under a FERC-accepted or -approved Local Service Schedule.

Local Service. Transmission Service over the facilities of a single PTO (including facilities leased to the PTO or to which the PTO has contractual entitlements) provided under a FERC-accepted or -approved Local Service Schedule.

Local Service Schedule. A PTO-specific rate schedule to the ISO OATT setting forth rates, charges, terms and conditions applicable only to service provided over the Transmission Facilities of such PTO.

Long-Term Transmission Outage Plan. “Long-Term Transmission Outage Plan” shall have the meaning ascribed thereto in Section 3.08(a)(i) of this Agreement.

Major Transmission Outage. “Major Transmission Outage” shall have the meaning ascribed thereto in Section 3.08(a)(ii) of this Agreement.

Market Monitoring Unit. Any market monitoring unit established by the ISO, including any internal market monitoring unit of the ISO and any independent market monitoring unit of the ISO.

Market Participant Service Agreement. The agreement among the ISO and market participants addressing, inter alia, the requirements for participating in the New England Markets.

Market Rules. The rules describing how the New England Markets are administered.

Merchant Facility. A transmission facility constructed by an entity that assumes all market risks associated with the recovery of costs for the facility and whose costs are not recovered through traditional cost-of-service based rates, but instead are recovered either through negotiated agreements with customers or through market revenues.

Mobile-Sierra Doctrine. The “Mobile-Sierra Doctrine” shall mean the public interest standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956).

Moratorium Period. “Moratorium Period” shall have the meaning ascribed thereto in Section 3.04(h)(i) of this Agreement.

NERC. The North American Electric Reliability Council.

Municipal Tax-Exempt Debt. An obligation the interest on which is excluded from gross income for federal tax purposes pursuant to Section 103(a) of the Internal Revenue Code of 1986 or the corresponding provisions of prior law without regard to the identity of the holder thereof. Municipal Tax-Exempt Debt does not include Local Furnishing Bonds.

Municipal Tax-Exempt PTO. A PTP that has issued Municipal Tax-Exempt Debt with respect to any facilities, or rights associated therewith.

Municipal Tax-Exempt TO. A transmission owner that has issued Municipal Tax-Exempt Debt with respect to any facilities, or rights associated therewith.

NERC/NPCC Requirements. NPCC criteria, guides, and procedures, NERC reliability standards, and NERC operating policies and planning standards (until such time as they are replaced by NERC reliability standards) and any successor documents.

New England Control Area. The Control Area consisting of the interconnected electric power system or combination of electric power systems in the geographic region consisting of Vermont, New Hampshire, Maine, Massachusetts, Connecticut and Rhode Island.

New England Markets. Markets or programs (including congestion pricing and design and implementation of FTRs) for the purchase of energy, capacity, ancillary services, demand response services or other related products or services that are offered in the New England

Control Area and that are administered by the ISO pursuant to rules, rates, or agreements on file from time to time with the Commission.

New England Transmission System. The system comprised of the transmission facilities over which the ISO has operational jurisdiction, including the Transmission Facilities of the PTOs and the transmission system of any ITC formed pursuant to Attachment M to the ISO OATT.

New Transmission Facility. Any new transmission facility constructed within the New England Transmission System that is owned by one or more PTO(s) and that goes into commercial operation after the Operations Date.

Non-Affiliated PTOs. Two or more PTOs that are not Affiliates.

Non-PTF. “Non-PTF” shall have the meaning ascribed thereto in the ISO OATT.

Notice of Operations Date. “Notice of Operations Date” shall have the meaning ascribed thereto in Section 10.01 (a)(ii) of this Agreement.

NPCC. The Northeast Power Coordinating Council.

OASIS. The Open Access Same-Time Information System of the ISO.

Operating Authority. “Operating Authority” shall have the meaning ascribed thereto in Section 3.02 of this Agreement and shall include the responsibilities set forth in Section 3.05.

Operating Limits. The transfer limits for a transmission interface or generation facility.

Operating Procedures. The operating manuals, procedures, and protocols relating to the exercise of Operating Authority over the Transmission Facilities, as such manuals, procedures, and protocols may be modified from time to time in accordance with this Agreement.

Operations Date. “Operations Date” shall have the meaning ascribed thereto in Section 10.01(a)(ii) of this Agreement.

Order 2000. FERC’s Order No. 2000, i.e., Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (January 6, 2000), FERC Stats. & Regs, ¶31,089 (1999), order on reh’g, Order No. 2000-A, 65 Fed. Reg. 12,088 (March 8, 2000), FERC Stats. & Regs. ¶31,092 (2000), petitions for review pending sub nom., Public Utility District No. 1 of Snohomish County, Washington v. FERC, Nos. 00-1174, et al. (D.C. Cir).

Owed Amounts. “Owed Amounts” shall have the meaning ascribed thereto in Section 3.10(c) of this Agreement.

PARS. Phase angle regulators.

Participant. A participant in the New England Markets, Transmission Customer, or other entity that has entered into the ISO Participants Agreement.

Participants Committee. “Participants Committee” shall mean the stakeholder participants committee established pursuant to the ISO Participants Agreement.

Party or Parties. A “Party” shall mean the ISO or any PTO, as the context requires. “Parties” shall mean all PTOs and the ISO.

Person. An individual, partnership, joint venture, corporation, business trust, limited liability company, trust, unincorporated organization, government or any department or agency thereof, or any other entity.

Planned Outages. “Planned Outages” shall have the meaning ascribed thereto in Section 3.08(a)(i) of this Agreement.

Planning Procedures. The manuals, procedures and protocols for planning and expansion of the New England Transmission System, as such manuals, procedures, and protocols may be modified from time to time in accordance with this Agreement.

Prime Rate. The interest rate that commercial banks charge their most creditworthy borrowers, as published in the most recent Wall Street Journal in its “Monday Rates” column.

Pro Rata Share. A PTO’s proportional share of the ISO’s Administrative Charges during such PTO’s first year as a PTO under this Agreement.

PTF. “PTF” shall have the meaning ascribed thereto in the ISO OATT.

PTO or Participating Transmission Owner. “PTO” shall have the meaning ascribed thereto in the opening paragraph of the Agreement. “Participating Transmission Owner” shall have the same meaning as “PTO.”

PTO AC or PTO Administrative Committee. “PTO AC” or “PTO Administrative Committee” shall have the meaning ascribed thereto in Section 11.04(a)(i) of this Agreement.

PTO Default. “PTO Default” shall have the meaning ascribed thereto in Section 10.04(a) of this Agreement.

PTO Joint Account. The joint account established in the name, and for the benefit, of the PTOs, in which each PTO shall own an undivided interest in a proportion equal to the proportion of that PTO’s right of distribution from the deposited Invoiced Amounts.

PTO Local Restoration Plan. The restoration plan developed by each PTO with respect to such PTO’s Transmission Facilities.

Publicly-Owned PTO. A “Publicly-Owned PTO” shall mean a PTO that is exempt, under Section 201 (f) of the Federal Power Act, from the obligations and requirements of the Federal Power Act.

Rating Procedures. “Rating Procedures” shall have the meaning ascribed thereto in Section 3.02(d) of this Agreement.

Regulation and Frequency Response Service. An Ancillary Service as defined in the ISO OATT.

Reliability Authority. “Reliability Authority” shall have the meaning established by NERC, as such definition may change from time to time, provided such definition of Reliability Authority shall not be inconsistent with the specific rights and responsibilities of the ISO and the PTOs under this Agreement.

Restoration Plans. The System Restoration Plan and all PTO Local Restoration Plans.

RFAP. “RFAP” shall have the meaning ascribed thereto in Section 6 of Schedule 3.09(a) to this Agreement.

RMR. Reliability must run resources.

RTO. An independent entity that complies with Order No. 2000 and FERC’s corresponding regulations (or an entity that complies with all such requirements except for the scope and regional configuration requirements), as determined by the FERC.

Scheduled Outages. “Scheduled Outages” shall have the meaning ascribed thereto in Sections 3.08(a)(ii) and 3.08(a)(iii) of this Agreement.

Supporting Votes. “Supporting Votes” shall have the meaning ascribed thereto in Section 11.04(a)(iii)(F) of this Agreement.

System Failure. Widespread telecommunication, hardware or software failure or systemic the ISO hardware or software failures that makes it impossible to receive or process bid information, dispatch resources, or exercise Operating Authority over the Transmission Facilities.

Tax or Taxes. All taxes, charges, fees, levies, penalties or other assessments imposed by any United States federal, state or local or foreign taxing authority, including, but not limited to, income, excise, property, sales, transfer, franchise, payroll, withholding, social security or other taxes, including any interest, penalties or additions attributable thereto.

Tax-Exempt Debt. Municipal Tax-Exempt Debt or Local Furnishing Bonds.

Tax Return. Any return, report, information return, or other document (including any related or supporting information) required to be supplied to any authority with respect to Taxes.

Technical Committees. “Technical Committee” shall mean the stakeholder technical committees established pursuant to the ISO Participants Agreement.

Term. “Term” shall have the meaning ascribed thereto in Section 10.01(a)(i) of this Agreement.

Termination Date. “Termination Date” shall have the meaning ascribed thereto in Section 10.01(c) of this Agreement.

TOA. This Transmission Operating Agreement, as it may be amended from time to time.

Transmission Business. The business activities of each PTO related to the ownership, operation and maintenance of its Transmission Facilities.

Transmission Customer. Any entity taking Transmission Service under the ISO OATT.

Transmission Facilities. “Transmission Facilities” shall have the meaning ascribed thereto in Section 2.01 of this Agreement.

Transmission Owner. “Transmission Owner” shall have the meaning ascribed thereto in the ISO OATT.

Transmission Provider. The ISO, in its capacity as the provider of transmission services over the Transmission Facilities of the PTOs in accordance with FERC’s Order No. 2000 and FERC’s RTO regulations.

Transmission Service. The non-discriminatory, open access, wholesale transmission services provided to customers by the ISO in accordance with the ISO OATT.

Transmission Upgrade. Any upgrade to an existing Transmission Facility owned by any PTO that goes into commercial operation after the Operations Date

TRM. Transmission Reliability Margin.

TTC. Total Transfer Capability.

VAR. Volt-Amps Reactive.

Workers Compensation. Any financial award or settlement provided to employees or their dependents under state or federal law due to the occurrence of an employment-related accident, disease or injury.

Workers Compensation Insurance. The insurance, procured by the ISO in accordance with Section 9.05(a), covering losses that the ISO is subject to as an employer under state or federal worker’s compensation laws.

Schedule 2.01(a)

Bangor Hydro-Electric Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
60	Boggy Brook-Betts Road	115
65	Orrington-Bucksport	115
66	Graham-Rebel Hill	115
67	Boggy Brook-Rebel Hill	115
205	Orrington-Betts Road-Bucksport	115
246	Graham-Orrington	115
248	Graham-Orrington	115
249	Graham-Orrington	115
Transformer #	Station	Voltage (kV)
T2	Orrington	345/115

Schedule 2.01 (a)

Central Maine Power Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
374	Surowiec-Buxton	345
375	Maine Yankee-Buxton	345
377	Maine Yankee-Surowiec	345
378	Maine Yankee-Mason	345
385	Buxton-Deerfield	345
386	Buxton-South Gorham-Yarmouth 4	345
391	Buxton-Scobie	345
60	Bowman Street-Browns Crossing-Maxcy’s	115
61	Norway-Hotel Road Tap-Gulf Island	115
61A	Hotel Road Tap-Hotel Road	115
62	Crowleys-Surowiec	115
	Livermore Falls-Sturtevant-Madison Tap-Williams Tap-Bigelow Tap-Wyman
63	Hydro	115
64	Gulf Island-Surowiec	115
65	Orrington-Bucksport	115
66	Wyman Hydro-Gorbell-Hartland-Detroit	115
67	Detroit-Rice Rips Tap-Maxcy’s	115
68	Maxcy’s-Mason	115
69	Bath-Topsham-Surowiec	115
75	Hotel Road-Challenger Drive-Lewiston Lower	115
80	Maxcy’s-Highland	115
81	Mason-Topsham Tap-Surowiec	115
83	Wyman Hydro-Lakewood Tap-Scott Tap-Winslow	115
84	Winslow-Maxcy’s	115
86	Bucksport-Belfast Tap-Meadow Road Tap-Lincolnville-Highland	115
87	Norway-Kimball Road	115
88	Maxcy’s-Augusta East Side	115
89	Riley-Livermore Falls	115
140	Sanford-Maguire Rd-P&W Tap-Quaker Hill	115

Schedule 2.01(a)

Central Maine Power Company

Category A Facilities

160	Cape-Hinckley-Pleasant Hill	115
161	Moshers-Sewall	115
162	Moshers-South Gorham	115
164	Yarmouth-Elm Street-Spring Street	115
165	Yarmouth-Moshers	115
166	Spring Street-Surowiec	115
167	Moshers-Prides Tap-Surowiec	115
169	South Gorham-Westbrook	115
197	Quaker Hill-Three Rivers	115
200	Livermore Falls-AEI Livermore Tap-Gulf Island	115
201	Gulf Island-Crowleys	115
202	Lewiston Lower-Crowleys	115
203	Bucksport-Detroit	115
204	Mason-Newcastle	115
205	Betts Road-Bucksport	115
207	Mason-Maine Yankee-Bath	115
208	Raymond-Surowiec	115
209	Kimball Road-Raymond	115
210	Kimball Road-Woodstock	115
211	Woodstock-Rumford	115
212	Gulf Island-Bowman Street	115
213	Bowman Street-Puddledock Road-North Augusta-Augusta East Side	115
217	Rumford Industrial Park-Kimball Road	115
219	South Gorham-Louden	115
220	South Gorham-Louden	115
223	South Gorham-West Buxton	115
224	West Buxton-Waterboro	115
225	Waterboro-Sanford	115
226	Highland-Newcastle	115
228	Rumford-Rumford Industrial Park	115
229	Riley-Rumford Industrial Park	115
230	Riley-Jay IP	115
231	South Gorham-Westbrook	115

Schedule 2.01(a)

Central Maine Power Company

Category A Facilities

232	Westbrook-Spring Street	115
233	Westbrook-Spring Street	115
234	Spring Street-Red Brook-Pleasant Hill	115
250	Louden-Biddeford IP Tap-Maguire Rd -Three Rivers	115
275	Sewall St-Cape	115
Transformer #	Station	Voltage (kV)
T9	Mason	345/115
T3	Maxcys	345/115
T1	South Gorham	345/115
T1	Surowiec	345/115

Schedule 2.01(a)

Fitchburg Gas and Electric Light Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
	Flagg Pond Ring bus	115

Schedule 2.01(a)

Florida Power & Light Company – New England Division

Category A Facilities

Circuit #	Stations	Voltage (kV)
363	Seabrook-Scobie	345
369	Seabrook-Timber Swamp Road-Newington	345
394	Seabrook-Ward Hill- Tewksbury	345

Schedule 2.01(a)

New England Power Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
301	Ludlow-Carpenter Hill	345
302	Carpenter Hill-Millbury	345
303	Brayton Point-ANP Bellingham	345
314	Sandy Pond-Millbury	345
315	Brayton Point-West Farnum	345
323	Millbury-West Medway	345
326	Scobie Pond-Lawrence Road-Sandy Pond	345
328	Sherman Road-West Farnum	345
331	Carver-West Walpole	345
332	West Farnum-Kent County	345
333	Ocean State-Sherman Road	345
335	Holbrook-Auburn Street	345
3361	Sherman Road-ANP Blackstone	345
337	Sandy Pond-Tewksbury	345
338	Tewksbury-Woburn	345
339	Tewksbury-Golden Hills	345
342	Auburn-Pilgrim-Canal	345
343	Sandy Pond-Millbury	345
344	West Medway-Bridgewater	345
347	Sherman Road-Lake Road	345
349X&Y	Golden Hills-Mystic	345
355	Pilgrim-Bridgewater	345
357	Millbury-West Medway	345
394	Seabrook-Ward Hill-Tewksbury	345
3520	West Meday-ANP Bellingham	345
A201	Comerford-North Litchfield	230
B202N/S/A253	Comerford-Merrimack-North Litchfield	230
C203	Comerford-Moore	230
D204	Comerford-Littleton-Moore	230

Schedule 2.01(a)

New England Power Company

Category A Facilities

E205E	Pratts Junction-Bear Swamp	230
E205W	Bear Swamp-Rotterdam	230
F206	Comerford-Granite	230
N214	North Litchfield-Tewksbury	230
0215	North Litchfield-Tewksbury	230
1870S	Mystic-Wood River	115
1870	Wood River-Kenyon	115
1870N	Kenyon-West Kingston	115
A127	Harriman-French King-Wendall Depot-Barre-Paxton-Webster St Tap	115
A127	Webster St Tap-Millbury	115
A179	Revere-GE River-Lynn	115
A94	Auburn Street-Parkview	115
B128	Harriman-Montague(Cabot)-French King-Barre-Webster St Tap(n.o.)-Millbury	115
B154N	South Danvers-lpswich River-Middleton-Woodchuck Hill-King St-Ward Hill	115
B154S	Salem Harbor-N.River Tap-Waters River-S.Danvers	115
C129N (201-502)	Beaver Pond-Milford-Depot St-Rocky Hill-Hopkinton-Millbury	115
C129	Beaver Pond-Union Street	115
C129S	Union Street-South Wrentham	115
C155N	South Danvers-Middleton-King St-Ward Hill	115
C155S	Salem Harbor-N.River Tap-Waters River-S.Danvers	115
C181N	South Wrentham-North Attleboro-Mansfield-Chartley Pond	115
C181S	Chartley Pond-Brayton Pond	115
C2	Auburn Street-Dupont	115
D130 (201-501)	Medway-Milford-Depot St-Hopkinton-Millbury	115
D130	Milford-Depot	115
D156	Northboro Road-West Framingham	115
D182S	South Wrentham-North Attleboro-Mansfield-Brayton Pond	115
D21	Bell Rock-High Hill	115
E105	Hartford Avenue-Franklin Square	115
E131	Adams-Harriman-Bear Swamp	115
E157	Millbury-Wyman Gordon(n.o.)-East Main Street-Northboro Road	115

Schedule 2.01(a)

New England Power Company

Category A Facilities

E183E	Brayton Point-Warren-Mink Street-Wampanoag	115
E183W	Wampanoag-Philipsdale-Franklin Square	115
E20/L1	Bridgewater-East Bridgewater-Auburn Street	115
F106	Hartford Avenue-Franklin Square	115
F132	Adams-Partridge Jct-Lanesboro-Doreen	115
F158N	Golden Hills-Maplewood	115
F158S	Maplewood-Everett	115
F184	Brayton Point-Warren-Bristol-Mink Street-Read Street	115
F19/S1	Auburn-Belmont-Bridgewater	115
G133W	East Methuen-Golden Rock-West Methuen	115
G133E	East Methuen-Ward Hill	115
G18	Dupont-Bridgewater	115
G185N	Drumrock-Kent County	115
G185S	Kent County-West Kingston	115
H17	Riverside-Farnum-West Farnum	115
I135N	Bellows Falls-Monadnock-East Winchendon Tap(n.o.)-Ashburnham-Flagg Pond	115
I135S	Flagg Pond-Pratts Junction	115
J136N	Bellows Falls-East Winchendon Tap-Ashburnham-Flagg Pond	115
J136S	Flagg Pond-Litchfield Street Tap-Pratts Jct	115
J16	Riverside-Staples	115
K137	Sandy Pond-Ayer	115
K137E	Sandy Pond-Littleton-Westford-Billerica-Tewksbury	115
K137W	Ayer-Pratts Junction	115
K15	Robinson Avenue-Swansea	115
K189	Drumrock-Kent County	115
L138E	Sandy Pond-Littleton-Westford-Tewksbury	115
L138W	Sandy Pond-Laurel Circle-Pratts Junction	115
L14	Bell Rock-Tiverton Tap-Tiverton	115
M13	Somerset-Tiverton Tap-Tiverton	115
M139 (211 - 503)	Woburn-Reading-North Woburn(Dragon Court)-Pinehurst-Billerica-Tewksbury	115
N12	Somerset-Sykes Road-Bell Rock	115
N140 (211 - 504)	Woburn-Reading-North Woburn(Dragon Court)-Pinehurst-Tewksbury	115

Schedule 2.01(a)

New England Power Company

Category A Facilities

O141N	Pratts Junction-Sterling-Greendale	115
0141	Greendale-Nashua	115
O141S	Millbury-Nashua	115
0167 (423-515)	Everett-Mystic	115
P11	Pawtucket-Valley-Robinson Ave	115
P142N	Pratts Junction-Sterling-Wachusett-W.Boylston	115
P142	W.Boylston-Rolfe Avenue	115
P142S	Rolfe Avenue-Bloomingdale-Wyman Gordon-Millbury	115
P168 (128-518)	Revere-Chelsea	115
Q10	Staples-Robinson Avenue	115
Q117 (K4)	Adams-Bennington	115
Q143N	Millbury-Whitins Pond-Uxbridge	115
Q143S	Uxbridge-Woonsocket-Clarkson St. (n/o)	115
Q169	Lynn-GE River-Resco Saugus-Melrose-Golden Hills	115
Q195	Moore-Littleton(n.o.)-Whitefield	115
R144	Millbury-Woonsocket-Clarkson St.(n.o.)	115
R9	Riverside-Valley	115
S145	Salem-Railyard-West Salem-Bartholomew St-Wakefield Jct-N.Reading-Burtt Road-E.Tewksbury-Tewksbury	115
S145 (cont’d)	Wakefield Jct-Wakefield-Melrose-Golden Hills	115
S171N	Woonsocket-West Farnum-Farnum Pike-Wolf Hill-Putnam Pike-Hartford Ave.	115
S171S	Hartford Ave.-Johnston Tap-Rise Tap-W.Cranston-Drumrock	115
S8	Bridgewater-Cleary-Somerset	115
T146	Salem-Railyard-West Salem-Bartholomew St-Wakefield Jct-N.Reading-Burtt Road-E.Tewksbury-Tewksbury	115
T146 (cont’d)	Wakefield Jct-Wakefield-Melrose-Golden Hills	115
T172N	Woonsocket-West Farnum-Farnum Pike-Wolf Hill(n.o.)-Putnam Pike-Hartford Ave.	115
T172S	Hartford Ave.-Johnston Tap-Rise Tap-W.Cranston-Drumrock	115
T7	Somerset-Pawtucket	115
U2	Belmont-Stoughton-Parkview	115
U6	Bridgewater-Dighton Tap-EMI Dighton-Somerset	115
V148N	Washington-Woonsocket	115

Schedule 2.01(a)

New England Power Company

Category A Facilities

V148S	Read Street-Robinson Avenue-Washington	115
V174	Millbury-North Oxford-Carpenter Hill	115
V5	Bridgewater-Taunton (Cleary) Tap-Dighton-Somerset	115
W149N	Wilder-Mt. Support Tap-Slayton Hill	115
W149S (K149)	Slayton Hill-Ascutney-Bellows Falls	115
W175	Carpenter Hill-West Charlton-Little Rest Rd-Palmer	115
W4	Swansea-Somerset	115
X176	Palmer-Thorndike-Ludlow	115
X3	Somerset-Philipsdale Tap(Blackstone Jct)-Philipsdale-Pawtucket	115
Y151	Hudson-Bridge St-Pelham-W.Methuen-Dracut Jct-E.Dracut-W.Andover Tap-Tewksbury	115
Y177	Harriman-Sherman-Montague	115
Transformer #	Station	Voltage (kV)
210X	Auburn St	345/115
3A	Brayton Point	345/115/20
3B	Brayton Point	345/115/20
161X	Bridgewater	345/115
162X	Bridgewater	345/115
1X	Carpenter Hill	345/115/13
1X	Golden Hills	345/115/23
2X	Golden Hills	345/115/23
3X	Kent County	345/115
1X	Sandy Pond	345/115/23
2X	Sandy Pond	345/115/23
3X	Ward Hill	345/115/23
174X	West Farnum	345/115/23
175X	West Farnum	345/115
4X	Bear Swamp	230/115
5	Comerford	230/34
6	Comerford	230/34
8	Pratts Junction	230/115
8A	Pratts Junction	230/115

Schedule 2.01(a)

New England Power Company

Category A Facilities

2X	Tewksbury	230/115/13
3X	Tewksbury	230/115/13
4X	Tewksbury	230/115/13

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
310	Millstone-Manchester	345
321	Long Mountain-Plumtree	345
329	Southington-Frost Bridge	345
330	Card-Lake Road	345
347	Lake Road-Sherman Road	345
348	Millstone-Manchester	345
352	Frost Bridge-Long Mountain	345
353	Scovill Rock-Manchester	345
362	Southington-Haddam Neck	345
364	Montville-Haddam Neck	345
368	Manchester-Card	345
371	Millstone-Montville	345
376	Haddam Neck-Scovill Rock	345
383	Millstone-Card	345
384	Scovill Rock-Middletown	345
387	Scovill Rock-Halversson-East Shore	345
395	Ludlow-North Bloomfield-Manchester	345
398	Long Mountain-Pleasant Valley	345
1385	Norwalk Harbor-Northport	115
1000	Montville-Dudley Tap	115
1050	Middletown-Dooley	115
1070	Fort Hill Farms-Stockhouse	115
1080	Montville-Card-Lisbon-Tunnel	115
1090	Montville-Fort Hill Farms	115
1130	Pequonnock-Compo	115
1163	Frost Bridge-Noera-Todd	115
1191	Frost Bridge-Campville	115
1207	Manchester-East Hartford	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category A Facilities

1208	Southington-Wallingford	115
1222	Old Town-Hawthorne	115
1235	Montville-Uncasville	115
1238	Carmel Hill-Frost Bridge	115
1261	Haddam-Bokum	115
1272	Shaws Hill-Bunker Hill	115
1280	Montville-Buddington-Mystic	115
1342	Green Hill-Bokum	115
1355	Southington-Hanover-Colony	115
1389	Norwalk-Flax Hill	115
1394	Scitico-Franconia	115
1416	Darien-Compo	115
1430	Sasco Creek-Ash Creek	115
1440	Glenbrook-Waterside	115
1443	Middletown-Portland	115
1445	Frost Bridge-Shaws Hill	115
1450	Southend-Glenbrook	115
1460	Eastshore-Branford RR	115
1466	North Wallingford-East Meriden	115
1470	Norwalk-Ridgefield-Peaceable	115
1490	Stockhouse-Card	115
1508	Branford-Green Hill	115
1515	Ludlow-Scitico	115
1537	Branford-Branford RR	115
1545	Devon-Trap Falls	115
1550	Frost Bridge-Noera-Canal	115
1560	Stevenson-Ansonia-Trap Falls	115
1565	Peaceable-Ridgefield-Plumtree	115
1570	Devon-Indian Well-Beacon Falls	115
1572	Middletown-Pratt & Whitney	115
1575	Bunker Hill-Baldwin-Beacon Falls	115
1580	South Naugatuck-Devon	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category A Facilities

1585	Bunker Hill-South Naugatuck	115
1588	North Wallingford-Colony	115
1610	Southington-Mix Avenue-June Street	115
1618	Rocky River-West Brookfield	115
1620	Middletown-Bokum	115
1622	Shepaug-Bates Rock	115
1630	Wallingford-Walrec-North Haven	115
1637	Norwalk-Weston	115
1640	Wallingford-Devon	115
1655	Branford-North Haven	115
1668	Bunker Hill-Freight Street	115
1670	Southington-Black Rock-Berlin	115
1675	Bean Hill-Tunnel	115
1685	Devon-June Street	115
1690	Southington-Hanover-Devon	115
1704	South Meadow-Southwest Hartford	115
1710	Pequonnock-Old Town-Devon	115
1720	Norwalk-Hawthorne	115
1721	Freight Street-Frost Bridge	115
1722	Northwest Hartford-CDEC-Southwest Hartford	115
1726	North Bloomfield-Farmington	115
1730	Pequonnock-Weston-Devon	115
1732	Canton-Franklin Drive-Campville	115
1740	Waterside-Cos Cob	115
1750	Cos Cob-Tomac-Southend	115
1751	Northwest Hartford-North Bloomfield-Manchester	115
1752	Rocky Hill-Berlin	115
1756	Bloomfield-Northwest Hartford	115
1759	Portland-Hopewell	115
1760	Plumtree-Newtown	115
1765	Westside-Berlin	115
1766	Dooley-Westside	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category A Facilities

1767	Manchester-Hopewell	115
1768	North Bloomfield-Southwick	115
1769	Berlin-East New Britain	115
1770	Plumtree-Stony Hill-Bates Rock	115
1771	Southington-Berlin	115
1772	Haddam-Connecticut Yankee-Pratt & Whitney	115
1773	South Meadow-Rocky Hill	115
1775	South Meadow-Riverside-Manchester	115
1777	North Bloomfield-Bloomfield	115
1779	South Meadow-Bloomfield	115
1780	Devon-Devon Tie	115
1783	Farmington-Newington-East New Britain	115
1784	North Bloomfield-Northeast Simsbury-Canton	115
1785	Berlin-Newington	115
1786	East Hartford-Riverside-South Meadow	115
1788	Franklin Drive-Torrington Terminal	115
1790	Devon-Devon RR(n.o.)-Devon Tie	115
1800	Southington-United Technologies Tap-Forestville	115
1810	Southington-United Technologies Tap-Bristol-Chippen Hill	115
1813	Rocky River-Carmel Hill	115
1821	North Bloomfield-South Agawam	115
1825	Forestville-Bristol	115
1835	Chippen Hill-Thomaston	115
1836	North Bloomfield-South Agawam	115
1858	South Agawam-Franconia	115
1867	Norwalk Harbor-Flax Hill-Glenbrook	115
1870S	Mystic-Wood River	115
1876	Newtown-Sandy Hook-Stevenson	115
1880	Norwalk Harbor-Norwalk-Glenbrook	115
1887	West Brookfield-Stoney Hill-Shepaug	115
1890	Norwalk Harbor-Glenbrook-Sasco Creek	115
1900	Campville-Torrington Terminal	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category A Facilities

1910	Southington-Todd	115
1921	Campville-Thomaston	115
1950	Southington-Canal	115
1975	East Meriden-Haddam	115
1977	Southend-Glenbrook-Darien	115
1990	Frost Bridge-Baldwin-Stevenson	115
667	Falls Village-Salisbury	69
689	Falls Village-Torrington Terminal	69
690	Salisbury-Smithfield	69
693	Falls Village-Torrington Terminal	69
Transformer #	Station	Voltage (kV)
5X	Card	345/115
1X	Frost Bridge	345/115
4X	Manchester	345/115
5X	Manchester	345/115
6X	Manchester	345/115
18X	Montville	345/115
19X	Montville	345/115
5X	North Bloomfield	345/115
8X	Norwalk Harbor	138/115
1X	Plumtree	345/115
2X	Plumtree	345/115
1X	Southington	345/115
2X	Southington	345/115
3X	Southington	345/115
4X	Southington	345/115
1X	Torrington Terminal	115/69

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

Holyoke Water Power Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
1039	Mount Tom-Midway	115
1292	Holyoke-lngleside	115
1327	Pineshed-Fairmont North	115
1428	Mount Tom-Fairmont South	115
1447	Mount Tom-Pineshed	115
1525	Fairmont South-Holyoke	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

Public Service Company of New Hampshire

Category A Facilities

Circuit #	Stations	Voltage (kV)
307	Deerfield-Newington	345
326	Scobie-Lawrence Road-Sandy Pond	345
361	Newington Energy-Newington	345
363	Seabrook-Scobie	345
369	Seabrook-Timber Swamp Road-Newington	345
373	Scobie-Deerfield	345
379	Amherst-Vermont Yankee	345
380	Scobie-Amherst	345
381	Vermont Yankee-Northfield	345
385	Buxton-Deerfield	345
391	Buxton-Scobie	345
394	Seabrook-Ward Hill-Tewksbury	345
B202N/S/A253	Merrimack-Comerford-N.Litchfield	230
A111	Pemigewassett-Webster	115
A152	Keene-Swanzey-Westport-Chestnut Hill	115
B143	Greegs-Reeds Ferry	115
C129	Deerfield-Rochester Tap-Madbury	115
C196	Greggs-Merrimack	115
D118	Pine Hill-Deerfield	115
D121	Merrimack-Eddy	115
E115	Beebe-Ashland-Pemigewassett	115
E194	Schiller Ocean-Road	115
F162	Greggs-Jackman	115
G146	Garvins-Deerfield	115
H137	Garvins-Merrimack	115
H141	Scobie-Chester-Great Bay-Ocean Road	115
I135N	Monadnock-Monadnock Tap	115
J114	Eddy-Rimmon_Greggs	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

Public Service Company of New Hampshire

Category A Facilities

K105	Watts Brook-Greggs	115
K165	Reeds Ferry-S.Milford Tap-Anheuser Busch-Bridge Street Tap-Hudson	115
K174	North Road-Ascutney	115
L163	Jackman-Keene	115
L175	Deerfield-Madbury	115
M127	Webster-North Road	115
M183	Madbury-Dover	115
N133	Schiller-Bolt Hill-Three Rivers	115
N186	Chestnut Hill-Vernon Rd Tap-Vernon Road	115
O161	Greggs-Pine Hill	115
P145	Webster-Oak Hill Tap-Merrimack	115
Q171	Greggs-Merrimack	115
Q195	Moore-Whitefield	115
R169	Dover-Three Rivers	115
R187	Watts Brook-Mammouth Road Tap-Scobie	115
R193	Scobie-Kingston Tap-Ocean Road	115
T198	Keene-Monadnock	115
U181	Schiller-Ocean Road	115
U199	U199 Tap-Littleton	115
V182	Webster-Garvins	115
X116	Scobie-Hudson	115
X178	Beebe-Woodstock_U199 Tap-Whitefield	115
Y151	Hudson-Bridge Street Tap-Pelham	115
Transformer #	Station	Voltage (kV)
TB14	Deerfield	345/115
TB41	Littleton	230/115
A253	Merrimack	230/115
TB30	Scobie	345/115
TB90	Scobie	345/115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

Western Massachusetts Electric Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
301	Ludlow-Carpenter Hill	345
312	Northfield-Berkshire	345
354	Northfield-Ludlow	345
381	Northfield-Vermont Yankee	345
393	Berkshire-Alps	345
395	Ludlow-N.Bloomfield-Manchester	345
B128	Harriman-Indeck(Montague)-French King-Barre-Webster St Tap(n.o.)-Millbury	115
F132	Doreen-Lanesboro-Partridge Jct-Adams	115
X176	Ludlow-Thorndike	115
Y177	Montague-Sherman-Harriman	115
1007	Agawam-Elm	115
1039	Midway-Mt.Tom	115
1161	Doreen-Oswald-Woodland Road	115
1211	Doreen-Oswald	115
1230	Agawam-Piper	115
1231	Berkshire-Plainfield-Ashfield-Cumberland	115
1242	Berkshire-Plainfield-Ashfield-Montague	115
1254	Shawinigan-Chicopee-Fairmont South	115
1302	Agawam-Pochassic-Buck Pond	115
1311	West Springfield-Agawam	115
1314	Agawam-Chicopee	115
1322	E.Springfield-Breckwood	115
1361	Montague-Cumberland	115
1371	Pleasant-Woodland	115
1394	Franconia-Scitico	115
1412	W.Springfield-Agawam	115
1421	Pleasant-Blanford	115
1426	E.Springfield-Orchard	115

Schedule 2.01(a)

Northeast Utilities Service Company on behalf of

Western Massachusetts Electric Company

Category A Facilities

1433	Breckwood-W.Springfield	115
1481	E.Springfield-Ludlow	115
1512	Blanford-Elm-Southwick	115
1515	Ludlow-Scitico	115
1525	Fairmont South-Holyoke	115
1551	Doreen-Berkshire	115
1552	Orchard-Ludlow	115
1657	Buck Pond-Gunn-Ingleside	115
1662	Doreen-Berkshire	115
1723	E.Springfield-Fairmont North-Piper	115
1768	Southwick-N.Bloomfield	115
1781	Agawam-Silver-South Agawam	115
1782	Agawam-Silver-South Agawam	115
1821	South Agawam-N.Bloomfield	115
1836	South Agawam-N.Bloomfield	115
1845	Ludlow-Shawinigan	115
1858	South Agawam-Franconia	115
1962	Midway-Gunn	115
Transformer #	Station	Voltage (kV)
1X	Berkshire	345/115
1X	Ludlow	345/115
3X	Ludlow	345/115

Schedule 2.01(a)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
316	West Walpole-Holbrook	345
319	Woburn-Lexington	345
322	Carver-Canal	345
323	West Medway-Millbury	345
324	Mystic-Kingston St	345
325	West Medway-West Walpole	345
331	West Walpole-Carver	345
335	Auburn-Holbrook	345
336	West Medway-NEA Bellingham-ANP Blackstone	345
338	Tewksbury-Woburn	345
342	Pilgrim-Canal-Auburn St	345
344	West Medway-Bridgewater	345
346	North Cambridge-Woburn	345
351	Mystic-North Cambridge	345
355	Pilgrim-Bridgewater	345
357	West Medway-Millbury	345
358	Mystic-North Cambridge	345
365	North Cambridge-Woburn	345
372	Mystic-Kingston St	345
389	West Medway-West Walpole	345
3361	ANP Bellingham-Sherman Road	345
3520	West Medway-ANP Bellingham	345
349XY	Mystic-Golden Hills	345
240-601	West Medway-Framingham	230
282-602	West Medway-Waltham	230
110-510	Kingston St-Brighton-Baker St	115
110-511	Kingston St-Brighton-Baker St	115

Schedule 2.01(a)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category A Facilities

110-522	Needham-Baker St	115
128-518
(P168)	Chelsea-Revere	115
148-522X&Y	West Walpole-Dover-Needham	115
201-501
(D130)	Medway-Milford-Depot St-Hopkinton-Millbury	115
201-502
(C129N)	Beaver Pond-Milford-Depot St-Rocky Hill-Hopkinton-Millbury	115
211-503
(M139)	Woburn-Reading-North Woburn(Dragon Court)-Pinehurst-Billerica-Tewksbury	115
211-504
(N140)	Woburn-Reading-North Woburn(Dragon Court)-Pinehurst-Tewksbury	115
211-508	Burlington-Woburn	115
211-514	Mystic-Woburn	115
240-508	Framingham(Leland Street)-Sherborn	115
240-510	Framingham(Leland Street)-Needham-Baker Street	115
250-516	Mystic-Hawkins Street-Chatham Street-K Street	115
250-517	Mystic-Hawkins Street-Chatham Street-K Street	115
274-509	Sherborn-Medway	115
282-507	Sudbury-Waltham	115
282-520	Brighton-Watertown-Waltham	115
282-521	Brighton-Watertown-Waltham	115
320-507	Waltham-Lexington-Trapelo Road	115
320-508	Waltham-Lexington-Trapelo Road	115
329-510	Mystic-Somerville-Brighton	115
329-511	Mystic-Somerville-Brighton	115
329-512	Kingston St-Carver St-Scotia St-Brighton	115
329-513	Kingston St-Carver St-Scotia St-Brighton	115
329-530	Brighton-North Cambridge	115
329-531	Brighton-North Cambridge	115
342-507	Speen Street-Sudbury	115
385-510	K Street-High Street-Kingston AB-Kingston Street	115

Schedule 2.01(a)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category A Facilities

385-511	K Street-High Street-Kingston AB-Kingston Street	115
385-512	K Street-Kingston Street	115
385-513	K Street-Kingston Street	115
391-508	Hartwell Avenue-Burlington	115
398-537	Holbrook-East Holbrook	115
423-515
(0167)	Mystic-Everett	115
433-507	Framingham(Leland St)-Speen Street	115
447-508	Holbrook-South Randolph(n.o)-Canton-Sharon Amtrack-Norwood-Walpole-W.Walpole	115
447-509	Holbrook-South Randolph-Canton-Sharon Amtrack-Norwood-Walpole-W.Walpole	115
451-536	Auburn-East Holbrook-Holbrook	115
455-507	Sherborn-West Framingham	115
478-502(115-16-11)	Holbrook-Swift’s Beach Tap-Edgar	115
478-503	Holbrook-East Weymouth-Hobart Street Tap-Edgar	115
478-508	Holbrook-East Weymouth-Hobart Street Tap-Edgar	115
478-509	Holbrook-Grove Street-Mid Weymouth-Edgar	115
488-518	Mystic-Chelsea	115
513-507
(D156)	West Framingham-Northboro Road	115
533-508	Lexington-Hartwell Avenue	115
65-502	West Walpole-Medway	115
65-508	West Walpole-Medway	115
831-536	N.Cambridge-Putnam	115
831-537	N.Cambridge-Putnam	115
191	Kingston-Auburn Street	115
117	Kingston-Brook Street	115
116	Brook Street-Carver	115
127	Carver-SEMASS Tap	115
128	SEMASS Tap-Tremont	115
108	Tremont-Wareham-Valley-Horsepond Tap-Bourne	115
109	High Hill-Fisher Rd-Cross Rd-111 Tie (n.o.)	115

Schedule 2.01(a)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category A Facilities

113	Tremont-Wareham(n.o.)-Valley-Horsepond Tap(n.o.)-Bourne	115
112	Tremont-Rochester-Mendall Rd-Crystal Spring(n.o.)-lndustrial Park-Acushnet-Pine St-Arsene	115
114	Tremont-Rochester-Mendall Rd-Crystal Spring-Wing Lane-Acushnet Tap-Achushnet-Pine St	115
111	Industrial Park-High Hill-Dartmouth-Cross Rd-109 tie (n.o.)	115
D21	High Hill-Bell Rock	115
121	Canal-Bourne	115
120	Canal-Barnstable	115
122	Bourne-Pave Paws-Sandwich-Oak St-Barnstable	115
107	Bourne-Otis-Falmouth Tap	115
115	Barnstable-Mashpee-Hatchville-Falmouth Tap	115
126	Canal-Bourne	115
130	Acushnet Tap-Pine Street	115
Transformer #	Station	Voltage (kV)
121X	Canal	345/115
120X	Canal	345/115
126X	Canal	345/115
345A	Carver	345/115
345A	Kingston St	345/115
345B	Kingston St	345/115
345A	Mystic	345/115
345A	North Cambridge	345/115
345B	North Cambridge	345/115
345A	Woburn	345/115
110D	Waltham PAR	115
110E	Waltham PAR	115
110F	Waltham PAR	115
230A	Waltham	230/115
230A	Framingham	230/115
345A	Lexington	345/115

Schedule 2.01(a)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category A Facilities

110D	Baker Street PAR	115
110C	Baker Street PAR	115
345A	Walpole	345/115
345A	Holbrook	345/115
345A	W.Medway	345/115
345B	W.Medway	345/115

Schedule 2.01(a)

The United Illuminating Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
387	Scovill Rock-Halversson-East Shore	345
1710	Pequonnock-Old Town-Devon	115
1730	Pequonnock-Weston-Devon	115
8809A	Pequonnock-Congress-Baird	115
8909B	Pequonnock-Congress-Baird	115
88006A	Baird-Barnum-Devon Tie	115
89006B	Baird-Barnum-Devon Tie	115
88005A	Devon Tie-Milvon-Woodmont	115
89005B	Devon Tie-Milvon-Woodmont	115
8804A	Woodmont-Allings Crossing	115
8904 B	Woodmont-Allings Crossing	115
88003A	Allings Crossing-Elm West-West River-Grand Avenue	115
89003B	Allings Crossing-Elm West-West River-Grand Avenue	115
8400	Sackett-Grand Avenue	115
84004	Sackett-Mix Avenue	115
1610	Southington-Mix Avenue-June Street	115
91001	Pequonnock-Bridgeport RESCO-Ash Creek	115
1430	Ash Creek-Sasco Creek	115
1130	Pequonnock-Compo	115
1685	Devon-June Street	115
1560	Stevenson-Ansonia-Trap Falls	115
1570	Devon-Indian Well-Beacon Falls	115
1594	Indian Well-Ansonia	115
8500	Grand Avenue-Water Street	115
8700	Water Street-West River	115
8100	Grand Avenue-English-East Shore	115
8200	Grand Avenue-East Shore	115
8301	Mill River-Grand Avenue	115
9502	Mill River-Broadway	115

Schedule 2.01(a)

The United Illuminating Company

Category A Facilities

9500	Broadway-Water Street	115
8300	Quinnipiac-Mill River	115
8600	Quinnipiac-North Haven	115
1460	East Shore-Branford RR	115
1537	Branford RR-Branford	115
1630	North Haven-Walrec	115
1655	North Haven-Branford	115
Transformer #	Station	Voltage (kV)
8X	East Shore	345/115
9X	East Shore	345/115

Schedule 2.01(a)

Vermont Electric Power Company

Category A Facilities

Circuit #	Stations	Voltage (kV)
340	Vermont Yankee-Coolidge	345
350	Coolidge-West Rutland	345
379	Amherst-Vermont Yankee	345
381	Vermont Yankee-Northfield	345
F206	Comerford-Granite	230
K149 (W149S)	Ascutney-Ascutney Tap	115
K174	Ascutney-North Road	115
K186(N186)	Vermont Yankee-Vernon Road Tap-Vernon Road-Chestnut Hill	115
K19	Georgia-East Fairfax Tap-Sandbar	115
PV-20	Plattsburgh-S.Hero-Sandbar	115
K21	Georgia-IBM Tap-Essex	115
K22	Essex-Sandbar	115
K23	Williston-Essex	115
K24E	Berlin-Barre	115
K24W	Essex-IBM Tap-Middlesex-Berlin	115
K26	Granite-Chelsea-Hartford-Wilder	115
K26	Barre-Granite	115
K30	Middlebury-Florence Tap-West Rutland	115
K31	Coolidge-Ascutney	115
K32	Coolidge-Cold River	115
K34	West Rutland-Blissville	115
K35	Cold River-North Rutland	115
K37	North Rutland-West Rutland	115
K4(Q117)	Bennington-Adams	115
K43	New Haven-Williston	115
K50	Highgate Converter-Highgate Tap-St. Albans Tap-Georgia	115
K6	Hoosic -Bennington	115
K63	Middlebury-New Haven	115
K7	Blissville-Whitehall	115
1429	Highgate Converter & HVDC Line to Bedford	55 (DC)

Schedule 2.01(a)

Vermont Electric Power Company

Category A Facilities

Transformer #	Station	Voltage (kV)
K36X	Coolidge	345/115
T1	West Rutland	345/115
T2	West Rutland	345/115
1X	Granite	230/115

Schedule 2.01(b)

Bangor Hydro-Electric Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
62	Keene Road-Powersville Road	115
63	Keene Road-Chester	115
64	Graham-Enfield-Keene Road	115
66	Rebel Hill-Deblois-Harrington Tap-Washington Cty	115
68	Boggy Brook-Ellsworth	115
69	Harrington Tap-Harrington	115
247	Orrington-Chemical	115

Schedule 2.01(b)

Central Maine Power Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
63A	Williams Tap-Williams	115
63B	Madison Tap-Madison	115
81A	Topsham Tap-Topsham	115
67A	Rice Rips Tap-Rice Rips	115
83B	Lakewood Tap-Lakewood	115
83C	Scott Tap-Scott	115
85	Detroit-Guilford	115
86A	Belfast Tap-Belfast	115
86B	Meadow Road Tap-Meadow Road	115
140 A	P&W Tap-P&W	115
163	Louden-Branch Brook-Maguire Rd (n.o.)	115
167A	Prides Corner Tap-Prides Corner	115
200A	AEI Livermore Tap-AEI Livermore	115
206	Highland-Dragon Cement Tap-Park Street	115
206A	Dragon Cement Tap-Dragon Cement	115
214	Kimball Road-Harrison-Lovell-Saco Valley	115
215	Bigelow Tap-Bigelow	115
215A	Stratton Tap-SEA Stratton	115
222	Wyman-Moscow Tap-Harris	115
218	Rumford-Boise Cascade	115
222A	Moscow Tap-Moscow	115
227	Riley-AEC	115
250A	Biddeford-Biddeford Tap	115

Schedule 2.01(b)

Fitchburg Gas and Electric Light Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
Line 01	Flagg Pond - Summer St.	69
Line 02	Flagg Pond - Summer St.	69
Line 03	Flagg Pond - Princeton Rd. - River St.	69
Transformer #	Station	Voltage (kV)
T1	Flagg Pond	115/69
T2	Flagg Pond	115/69

Schedule 2.01(b)

New England Power Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
N266	Comerford-Mclndoes	230
K211	North Litchfield-Granite Ridge	230
L212	North Litchfield-Granite Ridge	230
S197	Bear Swamp-Deerfield 4	115
1819	Midway-Florence	115
517-533S	Edgar-Field Street	115
517-533N	Field Street-N.Quincy	115
517-532S	Edgar-Field Street	115
517-532N	Field Street-N.Quincy	115
517-525	N.Quincy-Dewar Street(n.o)	115
517-524	N.Quincy-Dewar Street(n.o)	115
A127	Webster St Tap-Webster St	115
B128	Webster St Tap-Webster St	115
A153	Tewksbury-Meadowbrook-N.Chelmsford	115
B23	West Farnum-Nasonville	115
C3	Auburn Street-Plymouth St-Hanover Tap(n.o.)-Norwell-Water St.-N. Abington	115
C3-99	Plymouth St-North Abington	115
D911	Ames Street-Dupont	115
E1	Bridgewater-Easton-Middleboro	115
G185S	Davisville Tap-Old Baptist Road Tap-Davisville	115
H1	Hanover Tap-Water Street	115
H160	Northboro Rd-Hudson Rd	115
I161	Sandy Pond-Meadowbrook-N.Chelmsford	115
I135N	E.Winchendon Tap-E.Winchendon(n.o.)	115
J136N	E.Winchendon Tap-E.Winchendon	115
J136S	Litchfield Street Tap-Litchfield	115
I187	Drumrock-Kilvert St.-Blackbum-Pontiac Avenue-Lincoln Avenue-Sockanosset	115
J162	Tewksbury-L’Energia-Perry Street	115
J188	Drumrock-Kilvert St.-Blackbum-Pontiac Avenue-Lincoln Avenue-Sockanosset	115
L14	Tiverton Tap-Bates Street-Cononicus-Dexter	115

Schedule 2.01(b)

New England Power Company

Category B Facilities

L164	Tewksbury-Tewksbury Tap-N.Dracut-W.Andover-S. Broadway	115
L190	Kent County-Davisville Tap-Old Baptist Road Tap-Davisville	115
M1	East Bridgewater-Mill Street-Middleboro	115
M13	Tiverton Tap-Bates Street-Cononicus-Dexter?	115
M165	Millbury-WMI Millbury-Vernon Hill	115
M191	North River Tap-E.Beverly-Beverly	115
N166	Northboro Road-N.Marlboro-Hudson	115
N192	North River Tap-E.Beverly	115
Q143	Clarkson(n.o.)-Admiral Street-Franklin Square-South St.	115
R144	Clarkson(n.o.)-Admiral Street-Franklin Square	115
S171S	Rise Tap-Rise	115
S171S	Johnston Tap-Johnston	115
T172S	Rise Tap-Rise	115
T172S	Johnston Tap-Johnston	115
S9	Auburn Street-Plymouth-Hanover Tap-Philips Lane-Norwell-Scituate	115
T2 Tap	Franklin Sq-South St.-Point St	115
U6	Dighton Tap-Dighton	115
U173	Carpenter Hill-Snow Street	115
W123	Carpenter Hill-Millenium-Snow Street	115
Y2	Somerset-Hathaway Street	115
Z1	Somerset-Hathaway Street	115
Y151	W.Andover Tap-W.Andover-S. Broadway	115
3761	Dexter-Jepson	69
3762	Dexter-Jepson	69
3763	Jepson-Navy-Gate 2	69
#1 Attlebo Tap	Read St - West St.	69
#2 Attlebo Tap	Read St - West St.	69
	Pratts Jct-E.Westminster-Westminster (n.o.)-Gardner Tower-Park St-Otter River (Gardner
A1	Tower-Park St n.o., both taps)	69
A1	Otter River - Templeton Muni.	69
A1	Otter River-Royalston Tower-Royalston-Chestnut Hill	69
A1	Chestnut Hill-Vernon	69
A53	Wachusetts-Oakdale-Chaffins-Cooks Pond	69

Schedule 2.01(b)

New England Power Company

Category B Facilities

B2	Pratts Jct-E.Westminster (n.o.)-Westminster-Gardner Tower-Park St	69
	Park St-Otter River (n.o.)-Royalston Tower-Royalston-Chestnut Hill-Vernon (Royalston Tower-
B2	Royalston-Chestnut Hill n.o., both taps)	69
B54	Wachusetts-Chaffins-Cooks Pond	69
B69	Quabbin Tower-Belchertown	69
D4	Deerfield 4-Vernon	69
E5	Ware-Lashaway (n.o.)-Meadow St	69
E5E	Meadow St.-Leicester-Pondville-Millbury	69
E5W	Ware-Quabbin Tower (n.o.)-Shutesbury	69
E5D	Deerfield 4-Deerfield 3-Deerfield 2 (n.o.)-Shutesbury	69
F6	Ware-Lashaway-Meadow St	69
F6E	Meadow St.-Leicester (n.o.)-Pondville-Millbury	69
F6W	Deerfield 4-Deerfield 3 (n.o.)-Deerfield 2-Quabbin Tower-Belchertown-Ware	69
G33	Bellows Falls-Westminster (GMP)-Putney-Ferry Rd (n.o.)	69
	Ferry Rd (n.o.)-Fibermark (CVPS)-Brundies Rd (CVPS)-Fulflex (CVPS)-N.Brattleboro
G33	(n.o.,CVPS)-S.Brattleboro tap-S.Brattleboro (CVPS)-Vernon Rd	69
G33	Vernon-S.Brattleboro tap (n.o.)	69
G7	Northboro Rd-S.Marlboro-Marlboro	69
135	Millbury-N.Grafton Tower (n.o.)-Shrewsbury	69
J10	Adams-Deerfield 5	69
L38	Wachusetts-Temple St.	69
M39	Wachusett-Fitch Road	69
N14S	Palmer-Wilbraham-E. Longmeadow-Kibbe Rd-Shaker Rd-Milton Bradley	69
N40	Pratts Junction-Fitch Road	69
O15S	Palmer-Hampden-E. Longmeadow-Kibbe Rd (n.o.)	69
O15N	Palmer-Ware	69
042	Ayer-Groton Muni-Dunstable (n.o.)-Pepperell Power-Groton St-Pepperell Paper	69
R43	Ayer-Groton Muni-Dunstable	69
S19	Millbury-E. Webster	69
T20	Meadow St-E. Webster (n.o.)	69
U21S	Pratts Junction-Prospect St-Devens	69
U21E	Ayer-Devens	69
V22E	Ayer-Prospect St (n.o.)	69

Schedule 2.01(b)

New England Power Company

Category B Facilities

V22S	Pratts Jct-Litchfield St-Prospect St	69
W23W	Northboro Rd-S.Marlboro(n.o.)-Marlboro-MWRA-Woodside	69
W23W	Woodside (n.o.)-Fitch Rd	69
X24W	Millbury-N.Grafton Tower-N.Grafton-Westboro	69
X24E	Westboro-Northboro Road	69
Y25S	Deerfield 5-Harriman	69
	Harriman-Searsburg-Wilmington (GMP)-Mt Snow Dover (GMP)-Sleepy Hollow (GMP)-
Y25N	Bennington (CVPS)	69
Transformer #	Station	Voltage (kV)
3	Adams	115/69/23
5	Adams	115/69/23
4	Ayer	115/69/13
6	Ayer	115/69/13
1	Bellows Falls	115/69
2	Bellows Falls	115/69
3	Bellows Falls	115/69/6
3	Deerfield 4	115/69/13
8	Harriman	115/69/6
1	Millbury	115/69
2	Millbury	115/69
3	Millbury	115/69/13
1	Northboro Road	115/69/13
2	Northboro Road	115/69/13
3	Northboro Road	115/69/13
4	Northboro Road	115/69/13
3	Palmer	115/69/13
4	Palmer	115/69/13
5	Palmer	115/69/23/13
6	Palmer	115/69/23
4	Pratts Junction	115/69/13
6	Pratts Junction	115/69/13
7	Pratts Junction	115/69/13

Schedule 2.01(b)

New England Power Company

Category B Facilities

1	Read Street	115/69
2	Read Street	115/69/23
2	Wachusett	115/69/13

Schedule 2.01(b)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
1060	Plumtree-Triangle	115
1100	Barbour Hill-Enfield	115
1120	AES Thames-Montville	115
1165	Plumtree-Triangle	115
1200	Barbour Hill-Windsor Locks	115
1210	Card-Willimantic	115
1220	Card-Willimantic	115
1250	Montville-E.Haddam Jct(n.o.)-Uncaseville	115
1270	Plumtree-Middle River	115
1300	Enfield-Dexter Tap-Windsor Locks	115
1300	Dexter Tap-Dexter	115
1310	Manchester-South Windsor	115
1337	Middle River-Triangle	115
1350	Devon-Milford	115
1365	Williams-New London RR	115
1410	Montville-Buddington	115
1500	Montville-Williams-Flanders	115
1505	Tunnel-Fry Brook-Brooklyn-Tracy	115
1555	Rocky River-Bulls Bridge	115
1605	Montville-Williams-Flanders	115
1606	Barbour Hill-Rockville	115
1607	Tunnel-Fry Brook-Exeter Tap-Tracy	115
1607	Exeter Tap-Exeter	115
1635	South Windsor-Barbour Hill	115
1650	Devon-Devon RR	115
1724	Barbour Hill-Rockville	115
1753	Glenbrook-Cedar Heights	115
1763	Manchester-Barbour Hill	115

Schedule 2.01 (b)

Northeast Utilities Service Company on behalf of

The Connecticut Light and Power Company

Category B Facilities

1790	Devon RR Tap-Devon RR	115
1792	Glenbrook-Cedar Heights	115
1800	United Technologies Tap-United Technologies	115
1810	United Technologies Tap-United Technologies	115
1820	Southington-Black Rock	115
1830	Southington-Black Rock	115
1840	Black Rock-GE	115
1985	Williams-New London RR	115
100	Montville-Gales Ferry	69
400	Gales Ferry-Buddington-Tunnel	69
500	Tunnel-SECREC	69
680	Black Rock-Burritt	69
694	Falls Village-North Canaan	69
800	Card-Mansfield	69
900	Card-Skungamaug-Mansfield	69
Transformer #	Station	Voltage (kV)
	Card	115/69
16X	Montville	115/69
11X	Shepaug	115/69
4X	Black Rock	115/69
1X	Tunnel	115/69
8X	Card	115/69
9X	Card	115/69

Schedule 2.01 (b)

Northeast Utilities Service Company on behalf of

Holyoke Water Power Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
	Fairmont North-Prospect	115
	Fairmont South-Prospect	115

Schedule 2.01(b)

Northeast Utilities Service Company on behalf of

Public Service Company of New Hampshire

Category B Facilities

Circuit #	Stations	Voltage (kV)
60(K29)	Littleton-St. Johnsbury	115
B112	Beebe-Tamworth-White Lake	115
C106	Saco Valley-Intervale	115
C131	Kingston Tap-Kingston	115
D142	Whitefield-Lost Nation	115
F117	Rochester Tap-Rochester	115
G192	Hudson-Bridge Street	115
I158	Scobie-Huse Road	115
J125	Webster-Laconia	115
K165	Bridge Street Tap-Bridge Street (N.O.)	115
K1214	Saco Valley-Lovell-Harrison-Kimball Road	115
L109	Watts Brook-Granite Ridge	115
L176	Webster-Laconia	115
P145	Oak Hill Tap-Oak Hill	115
P134	Hudson-Long Hill	115
PN2A	Schiller-Newington Station	115
PN1B	Schiller-Newington Station	115
Q195	Littleton Tap-Littleton (N.O.)	115
S136	Whitefield-Berlin	115
R187	Mammouth Road Tap-Mammouth Road	115
T13	Schiller-Resistance	115
Z156	Schiller-Resistance	115
W157	S.Milford Tap-S.Milford	115
Y138	White Lake-Saco Valley(n.o.)	115
W179	Berlin-Pontook Hydro-Lost Nation	115
Z177	Smith-Berlin	115

Schedule 2.01(b)

Northeast Utilities Service Company on behalf of

Western Massachusetts Electric Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
F132	Partridge-Partridge Jct	115
1034	Montague-Amherst	115
1113	Podick-Five Corners-Fairmont North	115
1134	Amherst-Five Corners-Fairmont South	115
1413	Doreen-Silver Lake	115
1544	W.Springfield-Clinton	115
1614	Doreen-Silver Lake	115
1632	Montague-Podick	115
1715	Doreen-GE-Altresco	115
1755	W.Springfield-Clinton	115
1816	Doreen-GE-Altresco	115
1819*	Midway-Florence	115
1905	S.Agawam-Berkshire Power	115
1930	Shawinigan-Masspower	115
1935	Shawinigan-Masspower	115
1940	Shawinigan-Masspower	115
637	Pochassic-Cobble Mt.	115
Transformer #	Station	Voltage (kV)
	Pochassic	115/69

Schedule 2.01(b)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
65-507	Medway-Medway J3	115
146-502	W.Walpole-Walpole(n.o.)	115
219-532	Maynard-Concord	115
219-533	Maynard-Concord	115
496-528	Baker Street-Hyde Park	115
496-529	Baker Street-Hyde Park	115
292-522	Baker Street-Newton Highlands	115
292-523	Baker Street-Newton Highlands	115
416-526	Sudbury-Maynard	115
416-527	Sudbury-Maynard	115
483-524	K Street-Andrew Square-Dewar Street	115
483-525	K Street-Andrew Square-Dewar Street	115
517-524	Dewar St (n.o.)-No. Quincy	115
517-525	Dewar St (n.o.)-No. Quincy	115
831-538	Putnam-Kendall	115
108	Horsepond Tap-Manomet	115
113	Horsepond Tap-Manomet	115
116	Brook Street-West Pond	115
117	Brook Street-West Pond	115
117	Kingston-Duxbury	115
129	SEMASS Tap-SEMASS	115
191	Kingston-Duxbury-Marshfield	115
107W	Falmouth Tap-Falmouth	115
112	Pine Street-Cannon Street	115
114	Pine Street-Cannon Street	115
115E	Falmouth Tap-Falmouth	115
478-503	Hobart Street Tap-Hobart Street	115

Schedule 2.01(b)

NSTAR Electric & Gas Corporation on behalf of:

Boston Edison Company, Cambridge Electric Light Company,

and Commonwealth Electric Company

Category B Facilities

478-508	Hobart Street Tap-Hobart Street	115
132-538	K Street-Deer Island	115
576-534	K-Street-MBTA	115
576-535	K-Street-MBTA	115

Schedule 2.01(b)

The United Illuminating Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
P-B Tie Line 2	Bridgeport Harbor 2 GSU - Pequonnock	115
P-B Tie Line 3	Bridgeport Harbor 3 GSU - Pequonnock	115
ES-NNH Tie
Line	New Haven Harbor GSU - E.Shore	115
9R	Bridgeport Resco	115
48G	Bridgeport Energy	115

Schedule 2.01(b)

Vermont Electric Power Company

Category B Facilities

Circuit #	Stations	Voltage (kV)
25-00	Woodford Road-Searsburg	69
67-00	Vernon Road-Ferry Road	69
	Vernon Road-South Brattleboro	69
K15	Ascutney-Windsor	115
1591(K21)	IBM Tap-IBM	115
1592(K24)	IBM Tap-IBM	115
1593(K21)	IBM Tap-IBM	115
1594(K24)	IBM Tap-IBM	115
K25	East Avenue-Essex	115
K60	Littleton-St.Johnsbury	115
K30	Florence Tap-Florence	115
K33	Queen City-Williston	115
K28	St.Johnsbury-Irasburg	115
K42	Highgate Tap-Highgate	115
K42	St.Albans Tap-St.Albans	115
K80	East Fairfax Tap-East Fairfax	115
K41	Highgate-Newport	115
K48	Newport-Border	115
Y25N	Harriman-Searsburg-Wilmington (GMP)-Mt Snow Dover (GMP)-Sleepy Hollow (GMP)-Bennington (CVPS)	69
Transformer #	Station	Voltage (kV)
Y25	Bennington	115/69

Schedule 3.02(b)

NORTHEAST UTILITIES SERVICE COMPANY ON BEHALF OF ITS

OPERATING COMPANIES

List of Interconnection Agreements with neighboring Control Areas and

Tariff(s) Applicable to External Transactions

• Long Island Power Authority 10/31/67 Agreement between The Connecticut Light and Power Company and (formally Long Island Lighting Company) Long Island Lighting Company, as amended or superseded.

Schedule 3.02(b)

VERMONT ELECTRIC POWER COMPANY

List of Interconnection Agreements with neighboring Control Areas and

Tariff(s) Applicable to External Transactions

• Interconnection Agreement of 2/23/87, between the Highgate Joint Owners and Hydro- Quebec.

Schedule 3.02(d)

LIST OF EXISTING OPERATING PROCEDURES

1. ISO New England Manual No. 6 – Financial Transmission Rights

2. ISO New England Manual 11 – Market Operations

3. ISO New England Manual 20 – Installed Capacity

4. ISO New England Manual 27 – Tariff Accounting

5. ISO New England Manual 28 – Market Rule 1 Accounting

6. ISO New England Manual 29 – Billing

7. ISO New England Manual 35 – Definitions and Abbreviations

8. ISO New England Manual 37- Forward Reserve

9. ISO New England Manual – ISO-NE Load Response Program

10. ISO New England Operating Procedure No. 1 “Central Dispatch Operating Responsibility and Authority of ISO New England, the Local Control Centers and Market Participants”

11. ISO New England Operating Procedure No. 2 “Maintenance Of Communications, Computers, Metering, and Computer Support Equipment”

12. ISO New England Operating Procedure No. 3 “Transmission Outage Scheduling”

13. ISO New England Operating Procedure No. 4 “Action During a Capacity Deficiency”

14. ISO New England Operating Procedure No. 5 “Generation Maintenance and Outage Scheduling”

15. ISO New England Operating Procedure No. 6 “System Restoration”

16. ISO New England Operating Procedure No. 7 “Action In An Emergency”

17. ISO New England Operating Procedure No. 8 “Operating Reserve and Regulation”

18. ISO New England Operating Procedure No. 9 “Scheduling and Dispatch of External Transactions”

19. ISO New England Operating Procedure No. 10 “Analysis and Reporting of Power System Emergencies”

20. ISO New England Operating Procedure No. 11 “Black Start Capability Testing Requirements”

21. ISO New England Operating Procedure No. 12 “Voltage and Reactive Control”

22. ISO New England Operating Procedure No. 13 “Standards For Voltage Reduction and Load Shedding Capability”

23. ISO-NE Operating Procedure No. 14 “Technical Requirements for Generation, Dispatchable and Interruptible Loads”

24. ISO New England Operating Procedure No. 16 “Transmission System Data”

25. ISO New England Operating Procedure No. 17 “Load Power Factor Correction”

26. ISO New England Operating Procedure No. 18 “Metering and Telemetering Criteria”

27. ISO New England Operating Procedure No. 19 “Transmission Operations”

28. ISO New England Operating Procedure No. 20 “Cold Weather Event Operations”

29. ISO New England Compliance Procedure

30. ISO New England Compliance and Enforcement Process For Enhanced NPCC Reliability and NERC Standards

31. Master/Local Control Center Procedure #1 “Nuclear Plant Transmission Operations”

32. Master/Local Control Center Procedure #2 “Abnormal Conditions Alert”

33. Master/Local Control Center Procedure No. 3 “Test Procedure For Local Control Center Satellite Phone Communications”

34. Master/Local Control Center Procedure #4 “Rules for Generator Unit Control Modes, Limits and Dispatch Terminology”

35. Master/Local Control Center Procedure #5 “Procedure for Millstone Point Station Generation Reduction”

36. Master/Local Control Center Procedure #6 “Procedure for Evacuation of ISO New England Control Room”

37. Master/Local Control Center Procedure #7 “Processing Transmission Outage Applications”

38. Master/Local Control Center Procedure #8 “Coordination of Generation Voltage Regulator Outages”

39. Master/Local Control Center Procedure #9 “Operation of the Chester Static VAR Compensator (SVC)”

40. Master/Local Control Center Procedure #10 “Generator Governor Control and Operation”

41. Common Operating Instructions for Hydro-Québec TransÉnergie and the New England Asset Owners for the ± 450Kv DC Lines Radisson - Nicolet - Sandy Pond (Phase II) and ± 450Kv DC Lines Des Cantons - Monroe (Phase I)

42. Common System Dispatch Instructions for Hydro-Québec TransÉnergie and ISO New England Inc. for the ± 450Kv DC Lines Radisson - Nicolet - Sandy Pond (Phase II) and ± 450 kV DC Lines Des Cantons - Monroe (Phase I)

Schedule 3.09(a)

Planning and Expansion – Participating Transmission Owner Rights and Obligations

1. PTOs’ Rights and Obligations to Build and Associated Conditions Including Cost Recovery:

1.1 The following provisions shall apply to any New Transmission Facility or Transmission Upgrade designated in the ISO System Plan other than a Merchant Transmission Facility except as provided in Section 1.3 of this Schedule:

(a) Subject to the requirements of applicable law, government regulations and approvals, including requirements to obtain any necessary federal, state or local siting, construction and operating permits; the availability of required financing; the ability to acquire necessary rights-of-way; and satisfaction of the other conditions set forth in this Section 1.1, each PTO shall have the obligation to own and construct (or cause to be constructed) any New Transmission Facility or Transmission Upgrade that is designated in the ISO System Plan as necessary and appropriate for system reliability or economic efficiency. The PTO may enter into appropriate contracts to fulfill any obligations associated with the ownership and construction of such New Transmission Facilities or Transmission Upgrades.

(b) Each PTO subject to the obligation to build New Transmission Facilities and Transmission Upgrades under Section 1.1 (a), shall have the right to own and construct (or cause to be constructed) any New Transmission Facility or Transmission Upgrade located within or connected to its existing electric system which is included in the ISO System Plan, other than a Merchant Transmission Facility. This right shall not affect any rights that an entity may have to construct a Merchant Transmission Facility in response to a need identified by the ISO in the ISO Planning Process.

(c) (i) Each PTO’s assumption of an obligation to build New Transmission Facilities and Transmission Upgrades under Section 1.1 (a) shall be subject to the right of such PTO to recover, pursuant to appropriate financial arrangements and tariffs or contracts, all prudently incurred costs associated with a New Transmission Facility or Transmission Upgrade that has been included in the ISO System Plan, plus a return on invested equity and other capital.

(ii) If a PTO incurs costs associated with a New Transmission Facility or Transmission Upgrade that has been included in the ISO System Plan, such PTO shall have the right, by filing in accordance with Section 3.04 of this Agreement, to recover all of its costs associated with such New Transmission Facility or Transmission Upgrade that are prudently incurred or prudently committed to be incurred, including costs prudently incurred or prudently committed to be incurred by such PTO in connection with the planning, design, engineering, permitting, procuring and other preparation for construction, and/or construction of the New Transmission Facility or Transmission Upgrade, plus a return on invested equity and other capital.

(d) If a New Transmission Facility or Transmission Upgrade is included in an approved ISO System Plan and the ISO has indicated that the PTO is to commence planning, designing or constructing such New Transmission Facility or Transmission Upgrade, then a PTO that incurs costs in order to implement the ISO System Plan (and satisfy its obligation to build hereunder) by commencing to plan, design or construct such New Transmission Facility or Transmission Upgrade shall be permitted to recover all of its prudently incurred costs as set forth in Section 1.1(c) even if the ISO subsequently determines that the New Transmission Facility or Transmission Upgrade is no longer required and removes it from the ISO System Plan, notwithstanding any contrary FERC policy or rule relating generally to the recovery of the costs of abandoned plant.

(e) If a New Transmission Facility or Transmission Upgrade included in an approved ISO System Plan is not constructed because any of the conditions set forth in this Section 1.1 have not been satisfied or for any other reason, the ISO shall submit a report to the FERC addressing such non-construction, which report shall include a report from the PTO responsible for the planning, design or construction of such New Transmission Facility or Transmission Upgrade.

1.2 The PTO shall promptly seek siting and any other required regulatory approvals for which such PTO is designated as the appropriate entity to construct and own or finance facilities included in the ISO System Plan. If requested by the PTO, the ISO shall undertake reasonable efforts (consistent with its technical judgment) to assist the PTO in obtaining required regulatory approvals for New Transmission Facilities or Transmission Upgrades included in the ISO System Plan and approved by the ISO. The assistance may include the provision of testimony, witnesses, and similar assistance. The ISO shall not, in any manner, be precluded from similarly assisting, at its discretion, other projects that address a need identified by the ISO in the ISO System Plan.

1.3 The ISO shall ensure that the ISO Planning Process includes opportunities for state regulatory authorities, including the agency with authority over the retail electricity rates of a PTO with the obligation under Section 1.1(a) to build a New Transmission Facility or Transmission Upgrade, to provide their views to the ISO with respect to need for the New Transmission Facility or Transmission Upgrade.

2. PTO Obligations:

2.1 Each PTO shall support the planning process as described in the ISO OATT and any interregional planning coordination. As requested by the ISO, such support may include conducting any necessary studies, including system impact studies and facilities studies for the PTO’s Transmission Facilities, assisting in the performance of such studies or any additional studies, and supplying any information and data reasonably required to prepare a ISO System Plan or to perform transmission enhancement and expansion studies.

2.2 Each PTO shall make reasonable efforts to provide information and support in response to the ISO’s requests within the ISO’s requested time frames and shall comply with all deadlines set forth in the ISO Planning Process, as specified in the ISO OATT.

2.3 Each PTO shall comply with the ISO’s Planning Procedures (which are supplemental to the ISO Planning Process, as specified in the ISO OATT), provided that any modifications to existing Planning Procedures and any new Planning Procedures shall be developed in accordance with the process set forth for the development of new or modified Planning Procedures in Section 3.09(b) to the TOA.

Schedule 3.09(b)

LIST OF EXISTING PLANNING PROCEDURES

ISO New England Planning Procedure No. 3

Reliability Standards for the New England Area Bulk Power Supply System

ISO New England Planning Procedure No. 4

Procedure for Pool-Supported PTF Cost Review

ISO New England Planning Procedure No. 4-1

Cost Responsibility For Transmission Upgrades With Multiple Needs

ISO New England Planning Procedure No. 5

Procedure for Reporting Notice of Intent to Construct, Retire or Change Facilities in Accordance with Section I.3.9 of the ISO New England Tariff (Proposed Plan Application Procedure)

ISO New England Planning Procedure No. 5-1

Procedure For Review Of Governance Participant’s Proposed Plans (Section I.3.9 Applications: Requirements, Procedures And Forms)

ISO New England Planning Procedure No. 5-3

Guidelines for Conducting and Evaluating Proposed Plan Application Analyses

ISO New England Planning Procedure No. 5-4

Subordinate Proposed Plan Application Policy

ISO New England Planning Procedure No. 5-5

Special Protection Systems Application Guidelines

ISO New England Planning Procedure No. 5-6

Scope Of Study For System Impact Studies Under The Minimum Interconnection Standard

ISO New England Planning Procedure No. 6

Procedures for the Establishment and Study of New England Interconnection

ISO New England Planning Procedure No. 8

Construction Sequencing

Schedule 3.11(b)

NORTHEAST UTILITIES SERVICE COMPANY ON BEHALF OF ITS

OPERATING COMPANIES

List of Grandfathered Intertie Agreements

• Long Island Power Authority 10/31/67 Agreement between The Connecticut Light and Power Company and (formally Long Island Lighting Company) Long Island Lighting Company, as amended or superseded.

Schedule 3.11(b)

VERMONT ELECTRIC POWER COMPANY

List of Grandfathered Intertie Agreements

• Interconnection Agreement of 2/23/87, between the Highgate Joint Owners and Hydro-Quebec.

Schedule 3.11(c)

BANGOR HYDRO-ELECTRIC COMPANY

List of Grandfathered Interconnection Agreements

• I/A between Great Northern Paper/Great Lakes Hydro America and BHE (dated 5/23/03)

• I/A between Penobscot Hydro, LLC (PPL) and BHE (dated 5/27/99)

• Special Facilities Agreement between Babcock-Ultrapower West Enfield (BUWE) and BHE (dated 6/30/95)

• Construction and Procurement Agreement between BHE and CASCO Bay Energy Co, LLC dated 11/5/99

• I/C Agreement between BHE and CASCO Bay Energy Co, LLC dated 9/4/98 (revised I/C agreement filed with Commission on 1/22/99)

• Construction Agreement between Brascan Energy Marketing Inc. and BHE (dated 5/23/03)

• I/C Agreement between Katahdin Paper Co, LLC and BHE dated 5/16/03

• West Enfield Purchased Power Agreement, June 9, 1986

• Hydro Associates Penobscot Energy Purchased Power Agreement, as amended through June 26, 1998

• Recovery Company Pumpkin Hill Power - Purchased Power Agreement, as amended through December 4, 1984

• Green Lake Hydro Purchased Power Agreement, as amended through April 18, 2000

• Sebec Hydro Purchased Power Agreement, as amended through March 19, 1984

• Milo Hydro Purchased Power Agreement, as amended through June 1, 1985

Schedule 3.11(c)

CENTRAL MAINE POWER COMPANY

List of Grandfathered Interconnection Agreements

• I/C Agreement between Abbotts Mill Hydro and CMP (5/22/02)

• I/C Agreement between Androscoggin Energy, LLC (AELLC) and CMP (10/21/98)

• I/C Agreement between Androscoggin Reservoir Company (ARCO) and CMP

• I/C between Boralex Livermore Falls and CMP (4/1/01)

• I/C Agreement between Boralex Stratton Associates and CMP (4/1/98)

• I/C Agreement between Bucksport Energy LLC and CMP (6/13/00)

• I/C Agreement between Calpine Construction Finance Company, LP and CMP (dated 4/12/01-amended 12/12/01)

• I/C Agreement between Casco Bay Energy Company LLC and CMP (construction, procurement and continuing obligations agreement 5/1/00)

• I/C Agreement between city of Lewiston and CMP (3/1/00)

• Continuing Site/Interconnection Agreement between FPL Energy Maine, Inc. and CMP (dated 1/6/98-amended 6/16/98 and 7/24/02)

• I/C Agreement between Gardner Brook Hydro and CMP (2/1/02)

• I/C Agreement Amendment to Gardner Brook Hydro (3/20/02)

• I/C Agreement between Greenville Steam Company and CMP (1/1/01)

• I/C Agreement between International Paper Company and CMP (3/1/00)

• I/C Agreement between J & L Electric and CMP (6/23/03)

• I/C Agreement between Ledgemere Hydro LLC and CMP (12/23/03)

• I/C Agreement between Moosehead Energy, Inc. and CMP (3/1/00)

• I/C Agreement between Kennebec Water District and CMP (3/1/00)

• I/C Agreement between Kezar Falls Hydro and CMP (12/23/03)

• I/C Agreement between Marsh Power L.P. and CMP (3/1/00)

• I/C Agreement between Messalonskee Stream Hydro and CMP (12/23/00)

• I/C Agreement between Regional Waste System Inc. and CMP (1/1/01)

• I/C Agreement between Robbins Lumber, Inc. and CMP (2/15/01)

• I/C Agreement between Rocky Gorge Corporation and CMP (1/1/01)

• I/C Agreement between Rumford Power Associates L.P. and CMP (10/21/98)

• I/C Agreement between S. D. Warren Company and CMP (3/1/00)

• I/C Agreement between Sparhawk Mill Company and CMP (3/1/00)

• I/C Agreement between Stony Brook Hydro and CMP (2/1/02)

• I/C Agreement between Wight Brook Hydro and CMP (2/1/02)

Schedule 3.11(c)

FLORIDA POWER & LIGHT COMPANY-NEW ENGLAND DIVISION

List of Grandfathered Interconnection Agreements

• Interconnection and Operating Agreement by and between Florida Power & Light Company and FPL Energy Seabrook, LLC (6/25/03)

Schedule 3.11(c)

NEW ENGLAND POWER COMPANY

Grandfathered Interconnection Agreements

• Direct Assignment Facilities Charge/MAHY and Multiple (dated 6/1/85)

• Direct Assignment Facilities Charge/NECO and ANP Blackstone Energy Company, LLC (dated 5/5/99)

• Direct Assignment Facilities Charge/NECO and Pawtucket Power Associates (dated 12/15/01)

• Direct Assignment Facilities Charge/NEET and Multiple (dated 10/1/86)

• Direct Assignment Facilities Charge/NEP and AES Londonderry, LLC (dated 6/22/01)

• Direct Assignment Facilities Charge/NEP and ANP Bellingham Energy Company, LLC (dated 2/23/99)

• Direct Assignment Facilities Charge/NEP and ANP Blackstone Energy Company, LLC (dated 4/30/99)

• Direct Assignment Facilities Charge/NEP and Ashburnham Municipal Light Plant (dated 12/18/96)

• Direct Assignment Facilities Charge/NEP and Boott Mills Hydropower (dated 6/22/86)

• Direct Assignment Facilities Charge/NEP and Boston Edison Company (dated 12/15/85)

• Direct Assignment Facilities Charge/NEP and Boston Edison Company (dated 6/1/76)

• Direct Assignment Facilities Charge/NEP and Boston Edison Company (dated 1/18/73)

• Direct Assignment Facilities Charge/NEP and Boston Edison Company (dated 5/25/88)

• Direct Assignment Facilities Charge/NEP and Boston Edison Company (dated 10/10/86)

• Direct Assignment Facilities Charge/NEP and Centennial Island Hydroelectric Company (12/29/89)

• Direct Assignment Facilities Charge/NEP and Central Vermont Public Service (dated 9/7/66)

• I/A between NEP/Montaup & Dighton Power Associates, LP (dated 4/10/97)

• Direct Assignment Facilities Charge/NEP and Fitchburg (dated 3/1/02)

• Direct Assignment Facilities Charge/NEP and FPLE Rhode Island State Energy Partners (dated 12/22/00)

• Direct Assignment Facilities Charge/NEP and Gas Recovery Systems (BFI) Randolph (dated 11/23/98)

• Direct Assignment Facilities Charge/NEP and Georgetown Municipal Electric Department (dated 12/6/90)

• Direct Assignment Facilities Charge/NEP and Hingham Municipal Light Plant (dated 7/1/96)

• Direct Assignment Facilities Charge/NEP and HQ AC-Multiple (dated 6/16/87)

• I/A between NEP and Hudson Tap Transmission (dated 6/22/86)

• Direct Assignment Facilities Charge/NEP and Hull Municipal Lighting Plant (dated 7/9/96)

• Direct Assignment Facilities Charge/NEP and Indeck Energy Services of Turner Falls, Inc. (dated 7/7/88)

• Related Facilities Agreement between NEP/Blackstone Valley Electric Company and Lake Road Generating, LLP (dated 8/31/990)

• Direct Assignment Facilities Charge/NEP and Littleton Electric Light Department (MA) (dated 10/31/92)

• Direct Assignment Facilities Charge/NEP and Littleville Power Company (dated 9/27/95)

• Direct Assignment Facilities Charge/NEP and Marblehead Municipal Light Department (dated 12/7/94)

• Direct Assignment Facilities Charge/NEP and Massachusetts Water Resource Authority (dated 9/21/95)

• Direct Assignment Facilities Charge/NEP and MBTA (dated 11/1/96)

• Direct Assignment Facilities Charge/NEP and MBTA (dated 10/1/97)

• Direct Assignment Facilities Charge/NEP and Middleton Municipal Electric Department (dated 12/1/92)

• Direct Assignment Facilities Charge/NEP and Milford Power (dated 3/20/92)

• Direct Assignment Facilities Charge/NEP and Millennium Power Partners (dated 12/29/97)

• Direct Assignment Facilities Charge/NEP and Nantucket (dated 5/5/03)

• Direct Assignment Facilities Charge/NEP and Narragansett Electric Company (dated 4/6/72)

• Direct Assignment Facilities Charge/NECO Boston Edison and New Bedford Gas Edison Light Company (dated 8/31/71)

• Network Integrated Transmission Service between NEP and North Attleborough Electric (dated 7/9/96)

• Direct Assignment Facilities Charge/NEP and NRG Energy, Inc. (Somerset Power, LLC) (First Amendment of I/C Agreement dated 10/13/98) dated 4/26/99

• Direct Assignment Facilities Charge/NEP and Paxton Municipal Light Department (dated 2/27/02)

• Direct Assignment Facilities Charge/NEP and Peabody Municipal Light Department (dated 11/16/90)

• Direct Assignment Facilities Charge/NEP and Pioneer Hydro Inc. (dated 10/18/83)

• Direct Assignment Facilities Charge/NEP and Public Service Company of New Hampshire (dated 2/16/37)

• Direct Assignment Facilities Charge/NEP and Refuse Energy System’s Company (dated 6/12/80)

• Direct Assignment Facilities Charge/NEP and River Mill Hydro (10/12/89)

• Direct Assignment Facilities Charge/NEP and Rowley Municipal Lighting Plant (dated 4/10/90)

• Support Agreement /NEP and Seabrook Transmission-Multiple (dated 12/15/87)

• Direct Assignment Facilities Charge/NEP and Sithe Fore River Development (dated 5/25/01)

• Direct Assignment Facilities Charge/NEP and Sterling Municipal Light Department (dated 1/11/86)

• Direct Assignment Facilities Charge/NEP and Taunton Municipal Lighting Plant (dated 9/1/95)

• Direct Assignment Facilities Charge/NEP and Templeton Municipal Light Plant (dated 10/30/81)

• Interconnection Related Facilities Agreement /NEP and Tiverton Power Associates (dated 8/19/98)

• I/A between NEP and Tiverton Power Associates (dated 6/1/92)

• Direct Assignment Facilities Charge/NEP and UAE Lowell Cogen (dated 5/25/88)

• Direct Assignment Facilities Charge/NEP and UAE Lowell Power (dated 5/9/90)

• Direct Assignment Facilities Charge/NEP and US Gen New England Inc. (PG&E National Energy Group) (dated 9/1/98)

• Support Agreement/NEP and Vermont Electric Power Company, Inc. Bellows Falls (dated 8/1/98)

• Support Agreement/NEP and Vermont Electric Power Company, Inc. W-149 Reconductoring (dated 3/1/95)

• Support Agreement/NEP and Vermont Electric Power Company, Inc. (dated 4/5/74)

• Direct Assignment Facilities Charge/NEP and Wakefield Municipal Light Department (dated 6/16/87)

• Direct Assignment Facilities Charge/NEP and Wheelabrator North Andover, Inc. (dated 1/1/02)

• Direct Assignment Facilities Charge/NHHY and Multiple (dated 6/16/87)

• I/A between MECO and Gas Recovery Systems (BFI) East Bridgewater (dated 5/31/95)

• I/A between MECO and Gas Recovery Systems (BFI) Fall River (dated 5/5/99)

• I/A between MECO and Gas Recovery Systems (BFI) Halifax (dated 5/31/95)

• I/A between MECO and Littleville Power (dated 7/24/79)

• I/A between MECO and Methuen Hydro (dated 12/1/87)

• I/A between MECO and Mini Watt Electric Company (O’Connell Energy) (dated 3/24/82)

• I/A between MECO and Mini Watt Electric Company (O’Connell Energy) (dated 10/9/91)

• I/A between MECO and Rowley Municipal Lighting Plant (dated 4/10/90)

• I/A between MECO and South Barre Hydroelectric Company (dated 11/13/89)

• I/A between MECO and South Barre Hydroelectric Company (dated 6/1/92)

• I/A between MECO and South Barre Landfill (Zapco) (dated 2/10/87)

• I/A between MECO and Swift River Company (Collins Dam) (dated 8/30/84)

• I/A between MECO and Webster Hydro (dated 7/22/81)

• I/A between MECO and West Dudley Hydroelectric Company (dated 8/1/83)

• I/A between NECO and Northeast Energy Associates (dated 6/20/92)

• I/A between NECO and Ocean State Power (dated 8/16/89)

• I/A between NECO and ANP Milford Power (dated 1/1/02)

• I/A between NEP and Black Hills Energy Capital (dated 1/1/02)

• I/A between NEP and Danvers Electric Department (dated 12/29/92)

• I/A between NEP and Green Mountain Power (dated 8/16/96)

• I/A between NEP and Hingham Municipal Light Plant (dated 10/7/87)

• I/A between NEP and Indeck Pepperell Power Associates, Inc. (dated 1/31/89)

• I/A between NEP and Indeck Pepperell Power Associates, Inc. (dated 5/24/89)

• I/A between NEP and Indeck Pepperell Power Associates, Inc. (dated 10/20/95)

• I/A between NEP and Lowell Cogen (dated 1/1/02)

• Integrated Facilities Agreements/NEP and Massachusetts Electric Company, Granite State Electric, Narragansett Electric Company (dated 1967)

• Network/NECO and Pascoag Utility District (dated 10/24/97)

• Network/NEP and ANP Bellingham Energy Company, LLC (dated 5/30/01)

• Network/NEP and Ashburnham Municipal Light Plant (dated 7/9/96)

• Network/NEP and Boston Edison Company (dated 7/24/98)

• Network/NEP and Boylston Municipal Light (dated 7/9/96)

• Network/NEP and Central Vermont Public Service (dated 10/30/96)

• Network/NEP and Danvers Electric Department (dated 5/31/01)

• Network/NEP and Fitchburg Gas & Electric (dated 3/1/02)

• Network/NEP and Georgetown Municipal Light Department (dated 7/9/96)

• Network/NEP and Granite State Electric Company (dated 10/3/01)

• Network/NEP and Groton Electric Light Department (dated 7/9/96)

• Network/NEP and Groveland Electric Department (dated 6/29/98)

• Network/NEP and Holden Municipal Light Department (dated 7/9/96)

• Network/NEP and Hudson Light & Power Department (dated 7/9/96)

• Network/NEP and Ipswich Utilities Department (dated 7/9/96)

• Network/NEP and Littleton Electric Department (dated 7/9/96)

• Network/NEP and Littleton, NH Water and Light Department (dated 1/1/98)

• Network/NEP and MA Development Devens (dated 11/1/96)

• Network/NEP and Mansfield Municipal Lighting Plant (dated 7/9/96)

• Network/NEP and Marblehead Municipal Light Department (dated 7/9/96)

• Network/NEP and Massachusetts Electric Company (dated 5/27/97)

• Network/NEP and MBTA (dated 8/13/98)

• Network/NEP and Merrimac Municipal Light Department (dated 7/1/98)

• Network/NEP and Middleborough Gas and Electric (dated 3/1/02)

• Network/NEP and Middleton Municipal Electric Department (dated 7/9/96)

• Network/NEP and Millennium Power Partners (dated 2/1/02)

• Network/NEP and New Hampshire Electric Co-Op (dated 10/23/01)

• Network/NEP and Pascoag Utility District (dated 1/1/98)

• Network/NEP and Paxton Municipal Light Department (dated 7/9/96)

• Network/NEP and Peabody Municipal Light Department (dated 7/9/01)

• Network/NEP and PG&E National Energy Group (US GEN) (dated 9/1/98)

• Network/NEP and Princeton Municipal Light Department (dated 7/9/96)

• Network/NEP and Public Service Company of New Hampshire (dated 11/1/01)

• Network/NEP and Reading Municipal Light Department (dated 12/1/99)

• Network/NEP and Rowley Municipal Lighting Plant (dated 7/9/96)

• Network/NEP and Shrewsbury Electric Light Department (dated 7/9/96)

• Network/NEP and Sterling Municipal Light Department (dated 7/9/96)

• Network/NEP and Taunton Municipal Lighting Plant (dated 4/25/03)

• Network/NEP and The Narragansett Electric Company (dated 2/1/02)

• Network/NEP and West Boylston Municipal Lighting Department (dated 7/9/96)

• Network/NEP and Western Mass. Electric Company (dated 4/1/99)

• Other/MECO and MBTA (dated 8/18/97)

• Other/MECO and Milford Power (dated 6/6/91)

• Other/NECO and Blackstone Valley Electric Company/Montaup Electric Company (dated 5/1/00)

• Other/NECO and Boston Edison Company Commonwealth Electric Company (dated 8/31/71)

• Other/NECO and Montaup Electric Company (dated 5/1/00)

• Other/NECO and Montaup Electric Company (dated 5/1/00)

• Other/NECO and The Narragansett Electric Company (dated 12/1/01)

• Other/NECO and The Narragansett Electric Company (dated 5/1/00)

• Other/NEP and Boston Edison Company/Middleborough Gas & Electric Department (dated 1/1/02)

• Other/NEP and MBTA (dated 3/20/98)

• Other/NEP and REMVEC-Multiple (dated 7/1/94)

• Transmission Owners Agreement/MECO and Ashburnham Municipal Light Plant (dated 12/18/96)

• Transmission Owners Agreement/MECO and MBTA (dated 4/18/94)

• I/A between NEP and American Paper Mills of Vermont, Inc. (dated 11/30/00)

• Transmission Owners Agreement/NEP and Gas Recovery Services (formerly Browning Ferris Gas Services-East Bridgewater & Halifax) (dated 5/1/97)

• Transmission Owners Agreement/NEP and Indeck Pepperell Power Associates, Inc. (dated 10/20/95)

• Transmission Owners Agreement/NEP and Pawtucket Power Associates, LP (dated 11/2/01)

• Transmission Owners Agreement/NEP and Templeton Municipal Light Plant (dated 8/4/87)

• Network/NEP and Wakefield Municipal Light Department (dated 7/9/01)

• Agreement for Reinforcement and Improvements of NEP’s Transmission System (dated 4/1/83)

• Upper Development-Lower Development Transmission Line Support Agreement: NEET and NEPCo. (dated 1982)

• Service Agreement for Firm Local Generation Delivery Service under NEP’s Open Access Transmission Tarriff (dated 9/21/01)

• Network Integration Transmission Service NEP/ Hull Municipal Lighting Plant (dated 7/9/96)

• Network Integration Transmission Service NEP/Templeton Municipal Lighting Plant (dated 7/9/96)

• Network Integration Transmission Service NEP/North Attleborough Templeton & Wakefield (dated 7/9/96)

• Amendment No. 1 Support Improvement Agreement NEP/Boston Edison

• I/A between Eastern Edison/MBTA

• I/A between NEP/MECO Shrewsbury St. (dated 10/23/96)

• Transmission Facilities Support Agreement/NEP /Boston Edison/Mystic Golden Hills (5/25/88)

• Transmission Support Agreement/Boston Edison/Woburn Sandy Pond Tewksbury (dated 7/18/73)

• Support Agreement NEP Seabrook/Tewksbury (12/15/87)

• Support Agreement NEP Seabrook/Tewksbury/Woburn M-139 Line (dated 11/12/85)

• Support Agreement NEP Seabrook/Tewksbury/Woburn M-140 Line (dated 11/12/85)

• I/A Montaup Electric/Somerset Power dated 10/13/98

• Service Agreement NEP/Granite State (dated 10/3/01)

• Ispwich Network Operating Agreement (dated 7/7/97)

• Restated Distribution Agreement MECO/MBTA-Amtrak 2^nd Amendment (4/18/94)

• Service Agreement Boston Edison/NEP/Blackstone Valley Electric

• VELCO Letter Agreement/Support reconductoring of W-149 Line (dated 3/11/85)

• Support Agreement Public Service Co. of New Hampshire and Seabrook (dated 5/1/73)

• Support Agreement Public Service Co. of NH and NEP/Seabrook/Tewksbury (dated 12/15/87)

• Facilities Support Agreement NEP and VELCO (dated 4/5/74)

• Amendment to Service Agreement for Firm Local Generation Delivery Service/ANP Bellingham (dated 11/6/00)

• I/A between Eastern Edison Company/Browning Ferris Gas Services, Inc./Bridgewater (dated 4/30/99)

• I/A between MECO/NEP/Granite State/Narragansett-Boott Mills Hydro (dated 12/3/92)

• Agreement for Installation of Surge Arrestors between NEP and ANP Blackstone Energy Company (dated 3/30/00)

• First Amendment to the I/A between NEP/Pepperell Power Associates (dated 5/24/89)

• Service Agreement for Firm Local Generation Delivery Service NEP/ANP Bellingham Energy Company (dated 6/1/01)

Schedule 3.11(c)

NORTHEAST UTILITIES ON BEHALF OF ITS OPERATING COMPANIES

List of Grandfathered Interconnection Agreements

• Interconnection and Operations Agreement between Public Service of New Hampshire and AES Londonderry, LLC (dated 2/26/03)

• I/A between The Connecticut Light and Power Company and AES Thames (dated 7/19/99)

• Interconnection, Operations and Maintenance Agreement between Western Massachusetts Electric Company and Altresco Pittsfield, L.P. (dated 7/19/90)

• I/A between The Connecticut Light and Power Company and Capitol District Energy Center Cogeneration Associates (dated 9/15/01)

• Interconnection and Operations Agreement between Western Massachusetts Electric Company and Berkshire Power Company, LLC (dated 12/03)

• Millstone Transmission Support Agreement between The Connecticut Light and Power Company and Central Vermont Public Service Corp. (8/9/74)

• I/A between The Connecticut Light and Power Company and CRRA (12/20/00)

• Interconnection and Operations Agreement between Western Massachusetts Electric Company and Consolidated Edison Energy Massachusetts, Inc. (dated 12/10/01)

• I/A between The Connecticut Light and Power Company and Dominion Nuclear Connecticut, Inc. (dated 3/31/01)

• I/A between Errol Hydroelectric Limited Partnership and Public Service of New Hampshire (dated 4/7/86)

• I/A between The Connecticut and Power Company and Exeter Energy, LP (dated 3/24/03)

• I/A between Public Service of New Hampshire and FPL Energy Seabrook, LLP (dated 11/1/02)

• Seabrook Transmission Support Agreement between PSNH, New England Power Company and FPL Energy Seabrook (dated 6/1/88)

• I/A between The Connecticut Light and Power Company and Hartford Steam Company (dated 8/29/03)

• I/A between Public Service of New Hampshire and Hawkeye Funding, L.P. (Newington Energy) (dated 9/30/02)

• Seabrook Transmission Support Agreement between Public Service of New Hampshire, New England Power Company and Hudson Light & Power (dated 6/1/88)

• I/A between The Connecticut Light and Power Company and Lake Road Trust (dated 12/31/03)

• Interconnection, Operation and Maintenance Agreement between The Western Massachusetts Electric Company and Littleville Power Company, Inc. (dated 12/31/92)

• Millstone 3 Transmission Support Agreement between The Connecticut Light and Power Company and Mass. Municipal Wholesale Electric Company (dated 1/17/74)

• Seabrook Transmission Agreement between The Public Service Company of New Hampshire, New England Power Company and Mass. Municipal Wholesale Electric Company (dated 6/1/88)

• Stony Brook-Ludlow Agreement between Western Massachusetts Electric Company and Mass. Municipal Wholesale Electric Company (dated 8/1/79) (O&M agreement)

• Interconnection, Operation and Maintenance Agreement between Western Massachusetts Electric Company and MASSPOWER (dated 7/1/93)

• I/A between The Connecticut Light and Power Company and Milford Power Company, LLC (dated 7/21/03)

• I/A between The Connecticut Light and Power Company and National Railroad Passenger Corporation (Amtrak) (dated 7/2/99)

• I/A between The Connecticut Light and Power Company and Northeast Generation Company as Amended (dated 3/00)

• I/A between Western Massachusetts Electric Company and Northeast Generation Company as Amended (dated 7/2/99)

• I/A between The Connecticut Light and Power Company and NRG Energy, Inc. (dated 11/15/99)

• I/A between The Public Service Company of New Hampshire and Pontook Hydro, LP (dated 7/25/85)

• I/A between The Public Service Company of New Hampshire and Pinetree Power-Tamworth, Inc. (dated 12/11/87)

• Interconnection Agreement attached to Electricity Purchase Agreement between The Connecticut Light and Power Company and Riley Energy Systems of Lisbon Corporation for The Lisbon Resources Recovery Project (dated 6/3/91)

• Electrical Interconnection, Licensing and Construction of Transmission Facilities Agreement between The Connecticut Light and Power Company and Southern Connecticut Regional Resource Recovery Authority (SCRRA) (dated 1/30/90)

• Seabrook Transmission Support Agreement with PSNH, New England Power Company and Tauton Municipal Light Department (dated 6/1/88)

• I/A with Respect to The Connecticut Light and Power Company and the United Illuminating Company (dated 6/15/74)

• I/A between The Public Service Company of New Hampshire and Vermont Electric Power Company, Inc. (dated 7/13/72)

• Interconnection Authorization Agreement Letter between The Connecticut Light and Power Company and Wallingford Resource Recovery Plant (dated 4/10/87)

• I/A between The Connecticut Light and Power Company and Waterside Power, LLC (dated 5/20/03)

• I/A between The Connecticut Light and Power Company and Waterside Power, LLC (dated 1/15/04)

• I/A between The Public Service Company of New Hampshire and Town of Wolfeboro (dated 9/26/03)

• Letter Agreement between Public Service of New Hampshire and Central Maine Power Company (Section 214 & Saco Valley Substation) (dated 11/18/86)

• Amended and Restated Electricity Purchase Agreement between The Connecticut Light and Power Company and The Dexter Corporation (Windsor Locks Cogeneration Facility) (dated 12/1/87)

• Long Island Power Authority 10/31/67 Agreement between The Connecticut Light and Power Company and (formally Long Island Lighting Company) Long Island Lighting Company, as amended or superseded.

Schedule 3.11(c)

NSTAR ELECTRIC & GAS CORP.

ON BEHALF OF ITS OPERATING AFFILIATES

List of Grand fathered Interconnection Agreements

• Related Facilities Agreement between Entergy Nuclear Generation Company and BECo (1/21/03)

• Phase II Boston Edison with “New England Utilities” AC Facilities Support Agreement (6/1/85)

• Concord Municipal Light Plant and Boston Edison I/C Agreement (4/13/93)

• BECo and AES Londonderry, L.L.C. Related Facilities Agreement (RFA) (11/20/01)

• RFA between BECo and ANP Bellingham Energy Company

• I/C Agreement between Boston Edison and ANP Blackstone Energy Company (3/19/99)

• Mirant Kendall and BECo RFA (3/26/02)

• I/C Agreement between Mirant Kendall LLC and Cambridge Electric Light Company (12/24/01)

• Related Facilities Agreement between BECo and PG&E (2002)

• Related Facilities Agreement between Tiverton Power Associates Limited Partnership and Commonwealth Electric Company (9/21/98)

• Radial Line Service Agreement between Town of Reading and BECo (11/10/79)

• Related Facilities Agreement between Canal Electric Company (Unit 2) and the planned Pilgrim Unit 2 of BECo (9/21/72)

• Joint Ownership Agreement between BECo and New Bedford Gas and Light Company (Card St. Line) (1/2/68)

• Ownership Agreement among BECo, New Bedford Gas and Blackstone Valley Electric Company (8/31/71)

• Related Facilities Agreement between Entergy Nuclear Generation Company and Commonwealth Electric Company (8/11/03)

• Facilities Support Agreement between NSTAR and Entergy Nuclear (no date)

• I/C Agreement between Commonwealth Electric Company (NSTAR) and MBTA-dated 2/99 (actual date is 5/1/99)

• I/C Agreement between BECo and Northeast Energy Associates (9/23/93)

• I/C Agreement between Commonwealth Electric Company (NSTAR) and Southern Energy New England, LLC (concerning the “Oak Bluffs Diesels”) (5/15/98)

• Support Agreement for Lines 255-2337 and 255-2338 between NEP and BECo (2/22/80)

• Support Agreement for 115kv Line 201-502 between NEP and BECo (5/11/79)

• Support Agreement for a “stabilizing” line (342) between Pilgrim and Canal stations-the agreement is between Commonwealth Electric Company (NSTAR-formerly New Bedford Gas and Edison Light Company) and NEP (two letters dated 3/29/68 and 11/4/74)

• I/C Agreement between BECo (NSTAR) and Sithe Fore River Development LLC (12/31/2000)

• I/C Agreement between Sithe Mystic Development LLC and BECo (3/6/2001)

• I/C Agreement for West Tisbury Diesels between Commonwealth Electric Company (NSTAR) and Southern Energy New England, LLC (5/15/1998)

• Facilities Support Agreement between BECo and Montaup Electric Company regarding 345 kv Tap Line (Whitman Tap) (April 1975)

• Canal Pilgrim Transmission Agreement for construction and support of Line #342

• Agreement for the Purchase and Sale of High Voltage Electric Service By and Between Boston Edison Company and the National Railroad Passenger Corporation (AMTRAK) (7/8/2002)

• Interconnection Agreement between Town of Norwood Municipal Light Department and Boston Edison Company (5/27/2002)

• Interconnection Agreement between Commonwealth Electric Company and Nantucket Electric Company (6/3/1996)

• Interconnection and Operation Agreement between Boston Edison Company and Sithe Energies, Inc. (12/10/1997)

• I/C Agreement for Canal Units between Commonwealth Electric Company and Southern Energy New England, LLC (5/15/1998)

Schedule 3.11(c)

UNITED ILLUMINATING COMPANY

List of Grandfathered Interconnection Agreements

• Exhibit B only to Service Agreement between United Illuminating and Bridgeport Energy LLC (6/9/98)

• I/C Agreement between United Illuminating and Cross Sound Cable (7/9/02)

• I/C Agreement between United Illuminating and McCallum Enterprises (10/19/87)

• I/C Agreement between United Illuminating and Quinnipiac Energy LLC (8/8/00)

• I/C Agreement between United Illuminating and Wisvest-Connecticut LLC (4/16/99)

• Appendix D only to Power Purchase Agreement between United Illuminating and Connecticut Resources Recovery Authority (12/1/85)

Schedule 3.11(c)

UNITIL ENERGY SYSTEMS, INC. AND

FITCHBURG GAS AND ELECTRIC LIGHT COMPANY

List of Grandfathered Interconnection Agreements

• The attached Interconnection Agreement of Wheeling Agreement between Unitil Energy Systems and Briar Hydro Associates (Effective Date – December 2, 2002)

• The attached Interconnection Agreement of Wheeling Agreement between Unitil Energy Systems and Concord Steam Corporation (Effective Date – June 1, 1994)

• The attached Interconnection Agreement of Wheeling Agreement between Unitil Energy Systems and New Hampshire Hydro Associates (Effective Date – July 2, 1983)

• The attached Interconnection Agreement of Wheeling Agreement between Unitil Energy Systems and Penacook Hydro Associates (Effective Date – April 15, 1985)

• I/C Agreement between Fitchburg Gas & Elec. And KES Fitchburg (Interconnector) (1/29/91)

• Service Agreement for Network Integration Transmission Service dated April 17, 2000 between Fitchburg Gas and Electric Light Company and Massachusetts Bay Transportation Authority

• Service Agreement for Network Integration Transmission Service dated March 1, 1997 between New England Power Company and Fitchburg Gas and Electric Light Company

• Service Agreement for Network Integration Transmission Service dated March 1, 2002 between New England Power Company and Fitchburg Gas and Electric Light Company

• Service Agreement No. 1 dated March 1, 1994 under Unitil Energy Systems, Inc. Tariff for Firm Transmission Service and Related Interconnection between Concord Electric Company and SES Concord Company, LP

Schedule 3.11(c)

VERMONT ELECTRIC POWER COMPANY

List of Grandfathered Interconnection Agreements

• I/A between Vermont Electric Power and Entergy Nuclear Vermont Yankee (dated 7/27/02)

• I/A for Hydro-Quebec Derby Line Tie (1/88)

• I/A between United Illuminating Company and McCallum Enterprised I Limited Partnership (dated 10/19/87)

Schedule 4.01(d)

New England Power Company

Facilities Not Subject to this Agreement

Circuit #	Voltage (kV)
3512	345
3521	345

Schedule 11.02

Superseded Agreements

The Interim Independent System Operator Agreement

Schedule 11.04

PTO Administrative Committee

1. The PTO AC established pursuant to Section 11.04 shall function as described in this Schedule 11.04.

2. Representatives. Each PTO shall appoint a representative and an alternate representative to serve as a member of the PTO AC with authority to act for that PTO with respect to actions taken or decisions made by the PTO AC.

a. Initial Representatives. Within thirty (30) days of the Operations Date, each PTO shall appoint its representative and alternate and provide written notice thereof to the other PTOs and to the ISO. Subsequent to the Operations Date, an entity that becomes a PTO pursuant to Section 11.05 of this Agreement shall appoint its representative and alternate and provide written notice to the other PTOs within thirty (30) days after becoming a PTO.

b. Change of or Substitution for a Representative or Alternate. A PTO may at any time, upon providing written notice to the other PTOs and to the ISO, designate a replacement representative or alternate. Any designated member of the PTO AC, by providing written notice to the Chair of the PTO AC, may also designate a substitute to act for him or her with respect to any matter specified in such written notice.

3. Officers. At the initial meeting of the PTO AC, a Chair and Vice Chair from different companies shall be elected among the PTOs’ representatives on the PTO AC. The term of office for the Chair and Vice Chair shall be one year, or until succession to each office occurs as provided herein. Except as provided in Section 4, at each annual meeting, the Vice Chair shall succeed to the office of the Chair, and a new Vice Chair from a different company as the new and outgoing Chairs shall be elected.

4. Vacancies. If the office of the Chair becomes vacant for any reason, the Vice Chair shall succeed to the office of the Chair and a new Vice Chair from a different company shall be elected at the next regular or special meeting to serve the remainder of the term; provided that if the remaining term is less than six months, the new Chair and Vice Chair shall serve for the remaining term plus an additional term of one year. If the office of the Vice Chair becomes vacant for any reason, a new Vice Chair from a different company as the Chair shall be elected at the next regular or special meeting and shall serve out the term of the Vice Chair whose office became vacant.

5. Duties of the Officers. The Chair shall (1) call and preside at meetings of the PTO AC; (2) cause minutes of each meeting to be taken and maintained; (3) cause notices and agendas of all meetings and minutes of the prior meeting to be distributed as set forth below; and (4) carry out such other responsibilities as the PTO AC shall assign or as may be specified in this

Agreement. The Vice Chair shall preside at meetings of the PTO AC if the Chair is absent for any reason, and shall otherwise act for the Chair at the Chair’s request.

6. Meetings. The PTO AC shall hold meetings no less frequently than once each calendar quarter as scheduled by the Chair. At the initial meeting, one of such regular meetings shall be designated as the annual meeting, at which officers shall be elected. The matters to be addressed at all meeting shall be specified in a written agenda provided in the notice distributed pursuant to Section 7 hereof.

7. Notice of Meetings. Written notice and agendas for a meeting shall be distributed by the Chair by facsimile or email to the PTOs’ representatives and any designated alternates and to the ISO not later than ten (10) days prior to the meeting; provided, however, that meetings may be called on shorter notice as the Chair deems necessary to deal with an emergency or to meet a deadline for action; provided further that no vote shall be taken on any matter at any meeting or special meeting without at least three days prior written notice to the PTOs’ representatives of the matter to be voted upon unless the representatives of the PTOs agree unanimously to waive this minimum notice requirement. The Chair shall include in the agenda for the meeting any matters that one or more PTOs request to be included.

8. Special Meetings. A special meeting of the PTO AC may be called at any time by two or more unaffiliated PTOs having combined Individual Votes exceeding twenty five percent of the aggregate Individual Votes of the PTOs at the time of the proposed special meeting; provided that the Chair shall schedule such special meeting at a time and location convenient to the representatives (but no more than ten days after the request for the meeting) and shall issue an agenda setting forth the issue or issues to be considered at the behest of the PTOs requesting the special meeting no less than five days before the scheduled date thereof.

9. Attendance. Regular or special meetings may be conducted in person or by telephone as authorized by the Chair or pursuant to rules adopted by the PTO AC in according with the voting procedures set forth in Section 12 below. Each PTO shall be represented at a meeting by its representative or alternate, or a duly-designated substitute representative. A PTO shall also have the right to designate another PTO to vote on such PTO’s behalf at a meeting by proxy provided to the Chair in advance of the meeting. Any PTO choosing not to participate in a meeting pursuant to one of the methods described in this section 9 shall be deemed to have given its proxy to the Chair to vote on the non-participating PTO’s behalf.

10. Open Meetings. All meetings of the PTO AC shall be open to all PTOs that are signatories to this Agreement and each such PTO shall receive timely written notice of a meeting.

11. Cost of Meetings. Each PTO shall be solely responsible for all costs incurred for its representative or alternate to attend any meeting. The PTOs shall share the costs incurred by the host of any meeting of the PTO AC in proportion to their Individual Votes.

12. Manner of Acting. Actions taken by the PTO AC with respect to amendments to this Agreement shall require the support of the number of votes specified in Section 11.04(a)(iii)(B), (C), or (D) of the Agreement as applicable.

13. Individual Votes. For all purposes under Section 11.04(a)(iii) and this Schedule 11.04, the “Individual Votes” of Non-Affiliated PTOs shall mean the number of votes accorded to each PTO at the time of the applicable meeting pursuant to the following formula: Each Individual Vote shall be equal to the average of the net book value and the gross book value, as determined in accordance with generally accepted accounting principles for electric utilities, of the Transmission Facilities comprising the New England Transmission System of each PTO: (expressed in dollars and divided by one million (1,000,000)), as determined on April 1 of each year on the basis of the book values of the Transmission Facilities as of the prior December 31, provided that the book value of the following facilities shall not be included in the calculation of such PTO’s Individual Votes:

a. The Merchant Facilities of a PTO or a PTO’s affiliate; and

b. The transmission facilities comprising Phase I and Phase II of the Hydro-Quebec interconnection, the Highgate interconnection, and the MEPCO interconnection until such time as a PTO includes the capital investment for its ownership of these transmission facilities in the ISO OATT in a manner such that the allowed return on equity for the PTO’s ownership in these facilities is treated the same as the return on equity of the PTO’s Transmission Facilities.

For those PTOs that are public utilities under the Federal Power Act, the values used to calculate Individual Votes shall be those used in such PTO’s Form 1 filing with the FERC. For any PTOs that are not required to make FERC Form 1 filings, the values used shall be consistent with generally accepted accounting practices for public utilities with the objective that the Individual Votes of such non-FERC jurisdictional PTOs shall be calculated on a consistent basis with those of the FERC-jurisdictional PTOs.

14. Text of Amendments. The text of any amendment to be voted upon at a meeting of the PTO AC shall be distributed to the representatives no less than fourteen (14) days the meeting at which the amendment is to be considered; provided that the representatives may agree to make changes to such amendment at such meeting.

15. Record of Voting. The Chair shall cause each PTO that is a signatory to this Agreement to be provided with a written record of all votes (with the exception of straw votes or other informal votes) undertaken at a meeting of the PTO AC, including votes with respect to amendments to this Agreement pursuant to Section 11.04(a) of this Agreement and votes with respect to joint PTO Section 205 filings pursuant to the Disbursement Agreement.

Schedule 11.19(c)

Additional Conditions Precedent

EX-10.2.1.3

Exhibit 10.2.1.3

MARKET PARTICIPANT SERVICE AGREEMENT

This MARKET PARTICIPANT SERVICE AGREEMENT is dated this 1^st day of February, 2005 and is entered into by and between:

[Name of Market Participant]            having its registered and principal place of business located at                     [Address]                     (the “Market Participant”);

and

ISO New England Inc., a Delaware corporation having its principal place of business located at One Sullivan Road, Holyoke, MA 01040-2841, and acting as the Regional Transmission Organization for New England (“ISO”).

The Market Participant and the ISO are sometimes hereinafter referred to individually as a “Party” and collectively as the “Parties.”

BACKGROUND

A. The ISO operates the New England Transmission System pursuant to a certain Transmission Operating Agreement dated February 1, 2005, and other agreements entered into with merchant and other transmission owners. The ISO’s operation of the New England Transmission System is intended to insure the reliability of the New England Transmission System. Subject to the requirements of bulk power supply reliability, the ISO provides non-discriminatory, open access to the New England Transmission System pursuant to the ISO’s Transmission, Markets and Services Tariff on file with the Federal Energy Regulatory Commission (the “Commission”) (as amended from time to time, the “Tariff”).

B. The ISO operates competitive markets for the purchase and sale of energy, capacity, certain demand response services, certain Ancillary Services and certain related products and services pursuant to the Tariff. Accordingly, the ISO seeks to create and sustain open, non-discriminatory, competitive, unbundled markets for energy, capacity, and ancillary services (including Operating Reserves) that operate efficiently consistent with proper standards of reliability and the long-term sustainability of competitive markets.

C. The ISO operates purchase programs for certain Ancillary Services that are not procured through competitive markets. The ISO seeks to operate purchase programs for such services at rates that are intended to compensate sellers at not less than the incremental cost of providing such services and to attract and sustain adequate supplies of such services.

D. The ISO seeks to provide transparency with respect to the operation of and the pricing in markets and purchase programs to allow informed participation and encourage ongoing market improvements.

E. The ISO seeks to provide access to competitive markets within the New England Control Area and to neighboring regions.

Page No. 1

F. The Market Participant made an application to the ISO to be eligible to participate in the markets and purchase programs for energy, capacity ancillary services and related products and services administered by the ISO.

G. The ISO has accepted the Market Participant’s application.

H. The Market Participant and the ISO wish to set forth the terms and conditions upon which the ISO will provide services and the Market Participant may participate in the markets and programs administered by the ISO.

AGREEMENTS

In consideration of the mutual covenants set forth herein, the Parties, intending to be legally bound, agree as follows:

ARTICLE 1

DEFINITIONS, INTERPRETATIONS AND OBJECTIVES

1.1 Definitions. Capitalized terms not defined herein shall have the meanings given them in the Tariff

1.2 Interpretation. In this Agreement, unless otherwise indicated or otherwise required by the context, the following rules of interpretation shall apply:

(a) Reference to and the definition of any document or specific section thereof (including this Agreement and the ISO New England Operating Documents) shall be deemed a reference to such document as it may be amended, supplemented, revised or modified from time to time and any document that is a successor thereto. Nothing herein shall limit the ISO’s right to modify the ISO New England Operating Documents as expressly provided in the Tariff and the laws and regulations governing the adoption and amendment of the ISO New England Operating Documents.

(b) The article and section headings and other captions in this Agreement are for the purpose of reference only and do not limit or affect its meaning.

(c) Defined terms in the singular shall include the plural and vice versa, and the masculine, feminine or neuter gender shall include all genders.

(d) The term “including” when used herein shall be by the way of example only and shall not be considered in any way a limitation.

(e) Unless the context otherwise requires, any reference to a Party includes a reference to its permitted successors and assigns.

1.3 Objectives. The objectives of the ISO are (through means including but not limited to planning, central dispatching, coordinated maintenance of electric supply and demand-side resources and transmission facilities, obtaining emergency power for Market Participants from other Control Areas, system restoration (when required), the development of market rules, the

Page No. 2

provision of an open access regional transmission tariff and the provision of a means for effective coordination with other control areas and utilities situated in the United States and Canada):

(a) to assure the bulk power supply within the New England Control Area conforms to proper standards of reliability;

(b) to create and sustain open, non-discriminatory, competitive, unbundled markets for energy, capacity, and ancillary services (including Operating Reserves) that are (i) economically efficient and balanced between buyers and sellers, and (ii) provide an opportunity for a participant to receive compensation through the market for a service it provides, in a manner operate efficiently in a manner consistent with proper standards of reliability and the long-term sustainability of competitive markets;

(c) to provide market rules that (i) promote a market based on voluntary participation, (ii) allow market participants to manage the risks involved in offering and purchasing services, and (iii) compensate at fair value (considering both benefits and risks) any required service, subject to FERC’s jurisdiction and review;

(d) to allow informed participation and encourage ongoing market improvements;

(e) to provide transparency with respect to the operation of and the pricing in markets and purchase programs;

(f) to provide access to competitive markets within the New England Control Area and to neighboring regions; and.

(g) to provide for an equitable allocation of costs, benefits and responsibilities among market participants.

The Parties agree that the preceding Objectives are consistent with the Federal Power Act and do not in and of themselves create independent causes of action.

ARTICLE 2

TERM AND TERMINATION

2.1 Effective Date. This Agreement shall be effective as of the later of: (i) the effective date specified in the Commission order accepting the Agreement for filing, and (ii) the date on which the Market Participant is in compliance with the credit review procedures set forth in the ISO New England Operating Documents. In no event, however, shall the effective date be sooner than the Operations Date. This Agreement shall remain in full force and effect until terminated pursuant to Section 2.2 or 2.3 of this Agreement.

2.2 Termination by the ISO. The ISO may terminate this Agreement, upon the Market Participant committing any material default under this Agreement as provided in the ISO New England Operating Documents. With respect to any termination pursuant to this Section, the

Page No. 3

ISO must file a notice of termination with the Commission. This Agreement shall terminate upon acceptance by the Commission of such notice of termination.

2.3 Termination by Market Participant. In the event that the Market Participant no longer wishes to participate in the New England Markets or provide or receive services through the New England Transmission System with respect to any Asset then subject to this Agreement it may terminate this Agreement by complying with applicable provisions of the ISO New England Operating Documents, including Sections 3.9 and 3.10 of Section I of the Tariff, as well as all other legal or regulatory requirements applicable to the Market Participant.

2.4 Other Remedies. Nothing in Section 2.2 shall limit the remedies of the ISO under applicable law or the ISO New England Operating Documents, including the right, as applicable, to suspend the rights of one or more Assets to submit Bids, Schedules, Supply Offers or supply offers for Ancillary Services in the New England Markets or otherwise provide or receive services through the New England Transmission System.

2.5 Survival of Obligations. Notwithstanding any termination of this Agreement, any accrued obligations under this Agreement or the ISO New England Operating Documents, including obligations for the payment of money or obligations to provide information regarding operations or activities conducted prior to termination, shall survive the termination of this Agreement.

ARTICLE 3

GENERAL TERMS AND CONDITIONS

3.1 ISO Services.

(a) The ISO agrees to operate the New England Control Area, provide transmission service through the New England Transmission System, and administer the New England Markets all in accordance with the ISO New England Operating Documents.

(b) The ISO will monitor the New England Markets in accordance with the ISO New England Operating Documents.

(c) The ISO will maintain procedures for interconnection of Assets with the New England Transmission System in accordance with the New England Operating Documents.

(d) The ISO does not provide Local Service. Local Service is acquired through a separate transmission service agreement with the applicable PTO.

3.2 Service Under the Tariff. The Market Participant accepts service under the Tariff as a participant in the New England Markets. Market Participant agrees to be bound by the terms of the ISO New England Operating Documents and to make timely payment of all amounts due under the ISO New England Operating Documents.

Page No. 4

3.3 Registration of Assets.

(a) The Market Participant must register each Asset of which it is the Owner that seeks eligibility to sell or purchase services in the New England Markets by complying with the requirements of the ISO New England Operating Documents including, as applicable, registration information required by Section 12.2 of ISO New England Manual 28, approval of an interconnection application required by Section I, Section 3.9 of the Tariff, compliance with the metering requirements of ISO New England Operating Procedure No. 18, and providing the electrical operating information required by ISO New England Operating Procedure No. 14. Market Participant must also register its contractual interest in any Load Asset which it has transferred to a new Owner without a corresponding transfer of legal title to the Load Asset (whether or not the Market Participant is the holder of the legal title).

(b) The ISO shall be entitled to inspect and verify all registration information, including technical specifications, provided pursuant to Section 3.3.

(c) The Market Participant shall provide written notice to the ISO of any proposed changes to the registration information as required by the ISO New England Operating Documents.

(d) The Market Participant may withdraw Assets from the provision of particular services in accordance with the procedures set forth in the ISO New England Operating Documents.

3.4 Market Participant Operating Responsibilities. The Market Participant shall direct, physically operate, repair and maintain all metering and interconnection equipment under its control and all Assets providing services through the New England Transmission System (a) consistent with New England Transmission System reliability; (b) in accordance with (i) this Agreement, (ii) all applicable provisions of the ISO New England Operating Documents and (iii) all applicable reliability guidelines, policies, standards, rules, regulations, orders, license requirements and all other requirements of NERC, NPCC, other applicable reliability organizations’ reliability rules and all applicable requirements of federal or state laws or regulatory authorities; and (c) in such a manner as to maintain safe operations, including the enforcement of rules and procedures to ensure the safety of personnel.

3.5 Reserved Rights.

(a) Except for obligations and limitations specifically imposed by the ISO New England Operating Documents, the Market Participant retains all rights that it otherwise has incident to its ownership of and legal and equitable title to, its Assets, including all land and land rights and the right to build, acquire, sell, lease, merge, dispose of, retire, use as security, or otherwise transfer or convey all or any part of its Assets.

(b) The Market Participant has the right to adopt and implement procedures, consistent with Good Utility Practice, and to take such actions as it deems necessary to protect its facilities from physical damage or to prevent injury or damage to persons or property.

Page No. 5

(c) Nothing contained in this agreement is intended to alter or waive any rights that the ISO or the Market Participant may have to make filings with the Commission under the Federal Power Act.

3.6 Participants Agreement. By entering into this Agreement, the Market Participant agrees to be bound by the Participants Agreement, through NEPOOL or individually, as the case may be, and to pay the fees and charges specified therein. The Participants Agreement provides processes for stakeholder input, individually and collectively, into revisions of certain provisions of ISO New England Operating Documents and the planning process for the New England Transmission System.

ARTICLE 4

PROVISIONS RELATING TO SELLERS

4.1 Appointment of the ISO as Agent. Market Participant appoints the ISO as its agent to apportion, bill and collect on its behalf for Energy, capacity, Ancillary Services, demand response services or other related products or services sold through the New England Markets in accordance with the ISO New England Operating Documents.

4.2 Collection. The ISO agrees to apportion, bill and collect for Market Participant’s services and to remit to Market Participant amounts due to it under the Market Rules, as and when collected. The ISO will use commercially reasonable efforts to collect amounts due to Market Participant, including exercising its rights under the ISO New England Financial Assurance Policy and ISO New England Billing Policy. Allocation of revenues received will be made, and all disputes regarding amounts collected and remitted will be handled in accordance with the ISO New England Operating Documents.

4.3 Participation in Markets and Programs. In connection with submitting schedules, bids, and supply offers or otherwise offering to provide or providing services through the New England Markets, the Market Participant agrees at all times to comply with the ISO New England Operating Documents. The Market Participant hereby warrants to the ISO that, unless the ISO New England Operating Documents specifically permit supply offers unrelated to physical parameters, whenever it submits a Supply Offer for Energy or supply offer for Ancillary Services or a demand response service, it has the capability and the intention to provide that service in accordance with the ISO New England Operating Documents and it will comply with ISO dispatch instructions for the provisions of service in accordance with the ISO New England Operating Documents.

4.4 Rate Authority. Market Participant warrants that, at any time it has registered one or more Assets, it either (a) has on file with the Commission for each such Asset market-based rate authority or other Commission-approved basis for setting prices for services offered by means of the New England Transmission System by such Asset or (b) is exempt from the requirement to have rates for services on file with the Commission.

Page No. 6

4.5 Central Dispatch. The Market Participant shall, to the extent scheduled or otherwise obligated under the ISO New England Operating Documents, either individually or through the Second Restated NEPOOL Agreement, as provided therein, subject each of the Assets it owns or operates to central dispatch by the ISO, provided, however, that each Market Participant shall at all times be the sole judge as to whether or not and to what extent safety requires that at any time any of such Assets will be operated at less than their full capacity or not at all.

ARTICLE 5

PROVISIONS RELATING TO BUYERS

5.1 Appointment of the ISO as Agent. The Market Participant appoints the ISO as its agent to purchase on its behalf Energy, capacity, Ancillary Services, demand response services or other related products or services through the New England Markets in accordance with the ISO New England Operating Documents.

5.2 Purchase of Services. In connection with submitting schedules, demand bids or withdrawing Energy from the system in Real-Time or otherwise offering to buy or receive services through the New England Markets, the Market Participant agrees at all times to comply with the ISO New England Operating Documents. Except as emergency circumstances may result in the ISO requiring load curtailments by Market Participants, and subject to the availability of transmission capacity, each Market Participant will be entitled to buy from other Market Participants, and shall be required to remit payment to those Market Participants therefor in accordance with the ISO New England Operating Documents, such amounts, if any, of Energy, capacity, Ancillary Services, demand response services or other related products or services as it requires.

5.3 Disputes. All disputes regarding amounts payable for services purchased will be handled in accordance with the ISO New England Operating Documents.

ARTICLE 6

FORCE MAJEURE; INDEMNIFICATION AND LIABILITIES

6.1 Force Majeure Event. An event of Force Majeure shall be as set forth in the Tariff.

6.2 Reasonable Efforts to Perform and Notice. When the performance of either Party under this Agreement is hindered by an event of Force Majeure, that Party shall make all reasonable efforts to perform its obligations under this Agreement, and shall promptly notify the other Party and any affected Transmission Customers, if appropriate, of the commencement and end of each event of Force Majeure in accordance with the ISO New England Operating Documents.

6.3 Indemnification and Liabilities. The indemnification responsibilities of the Parties, to the extent permitted by law, shall be as set forth in the Tariff.

Page No. 7

ARTICLE 7

MISCELLANEOUS PROVISIONS

7.1 Commission Filing. The ISO shall file this Agreement with, or electronically report this Agreement to, as applicable, the Commission.

7.2 Notices. Unless otherwise expressly specified or permitted by the terms hereof, all communications and notices provided for herein shall be in writing and any such communication or notice shall become effective (a) upon personal delivery thereof, including by overnight mail or courier service, (b) in the case of notice by United States mail, certified or registered, postage prepaid, return receipt requested, upon receipt thereof, or (c) in the case of notice by facsimile, upon receipt thereof; provided that such transmission is promptly confirmed by either of the methods set forth in clauses (a) or (b) above, in each case addressed to each Party hereto at its address(es) set forth below or, at such other address(es) as such Party may from time to time designate by written notice to the other Party hereto; further provided that a notice given in connection with this Section 7.2 but received on a day other than a business day, or after business hours in the situs of receipt, will be deemed to be received on the next business day:

MARKET PARTICIPANT:	ISO New England Inc.:
[Name of Market Participant]	ISO New England Inc.
[Market Participant Representative Address]	One Sullivan Road
[Market Participant Representative Address]	Holyoke, MA 01040
[Name of Market Participant Representative]	Attn: General Counsel
Tel: [Tel]	Tel: (413) 540-4000
Fax: [Fax]	Fax: (413) 535-4379
[E-mail]

7.3 Other Agreements. In the event of a conflict between this Agreement and other agreements with respect to subjects addressed in this Agreement, this Agreement shall govern, subject to Section 13 of the Settlement Agreement.

7.4 Waiver. Any term or condition of this Agreement may be waived at any time by the Party that is entitled to the benefit thereof, but no such waiver shall be effective unless set forth in a written instrument duly executed by or on behalf of the Party waiving such term or condition. No waiver by any Party of any term or condition of this Agreement, in any one or more instances, shall be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. All remedies, either under this Agreement or by applicable law or otherwise afforded, shall be cumulative and not alternative.

7.5 Amendment. Except as otherwise specifically provided herein, this Agreement shall not be subject to modification or amendment unless agreed to in writing by both Parties hereto. Notwithstanding the foregoing, nothing in this Agreement shall restrict in any way the rights of either Party to submit an application under Section 206 of the Federal Power Act for revisions to this Agreement.

Page No. 8

The Parties acknowledge that this Agreement is entered into subject to the approval and continuing jurisdiction of the Commission. The ISO will notify the Market Participant of any changes to this Agreement required or approved by the Commission. Any such changes will take effect at the times and in the manner specified by the Commission in its order requiring or approving such changes. The Market Participant may, subject to the procedures referenced in Section 2.3, terminate this Agreement rather than accept any such changes.

7.6 No Third Party Beneficiaries. It is not the intention of this Agreement or of the Parties to confer a third party beneficiary status or rights of action upon any Person or entity whatsoever other than the Parties and nothing contained herein, either express or implied, shall be construed to confer upon any Person or entity other than the Parties any rights of action or remedies either under this Agreement or in any manner whatsoever.

7.7 No Assignment. Neither this Agreement nor any right, interest or obligation hereunder may be assigned by a Party (including by operation of law) without the prior written consent of each other Party in its sole discretion and any attempt at assignment in contravention of this Section 7.7 shall be void.

7.8 Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, including all matters of construction, validity and performance without regard to the conflicts-of-laws provisions thereof.

7.9 Consent to Service of Process. Each of the Parties hereby consents to service of process by registered mail, Federal Express or similar courier at the address to which notices to it are to be given, it being agreed that service in such manner shall constitute valid service upon such party or its respective successors or assigns in connection with any such action or proceeding; provided, however, that nothing in this Section 7.9 shall affect the right of any such Parties or their respective successors and permitted assigns to serve legal process in any other manner permitted by applicable law or affect the right of any such Parties or their respective successors and assigns to bring any action or proceeding against any other one of such Parties or its respective property in the courts of other jurisdictions.

7.10 Dispute Resolution. The Parties shall resolve their disputes relating to this Agreement utilizing the dispute resolution provisions of the Tariff.

7.11 Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future law, and if the rights or obligations of any Party under this Agreement shall not be materially and adversely affected thereby, (a) such provision shall be fully severable, (b) this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, (c) the remaining provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom, and (d) the court holding such provision to be illegal, invalid or unenforceable may in lieu of such provision add as a part of this Agreement a legal, valid and enforceable provision as similar in terms to such illegal, invalid or unenforceable provision as it deems appropriate.

Page No. 9

7.12 Relationship of the Parties. Nothing in this Agreement is intended to create a partnership, joint venture or other joint legal entity making either Party jointly or severally liable for the acts or omissions of the other Party.

7.13 Confidentiality. Confidential information acquired by either Party pursuant to this Agreement shall be governed by the ISO New England Operating Documents.

7.14 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all of which together shall constitute but one and the same instrument. The Parties hereto agree that any document or signature delivered by facsimile transmission shall be deemed an original executed document for all purposes hereof.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed on behalf of each by and through their authorized representatives as of the date hereinabove written.

Market Participant:	The ISO:
[Name of Market Participant]	ISO New England Inc.
By:	By:
Name:	Name:	Gordon van Welie
Title:	Title:	President and CEO
Date:	Date:	February 1, 2005
[for Munis: Town of                                     , acting by and through its Municipal Light Department as it is a member of NEPOOL]

Page No. 10

EX-10.2.1.4

Exhibit 10.2.1.4

ATTACHMENT 5

REVISED DISBURSEMENT AGREEMENT

RATE DESIGN AND FUNDS DISBURSEMENT AGREEMENT

This Rate Design and Funds Disbursement Agreement (this “Disbursement Agreement”), effective as of the Operations Date (the “Effective Date”) is made and entered into by and among [The names of the Initial PTOs will be submitted in a compliance filing prior to the Operations Date.] (herein collectively referred to as the “Initial Participating Transmission Owners”), along with any Additional Participating Transmission Owners or Independent Transmission Companies (as defined in that Transmission Operating Agreement (“TOA”) between the Initial Participating Transmission Owners and the ISO New England Inc. (“ISO”)). The Initial Participating Transmission Owners, the Additional Participating Transmission Owners, and the Independent Transmission Companies are collectively referred to herein as the “Transmission Companies” and individually each is referred to as a “Transmission Company”. All capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the TOA.

RECITALS

WHEREAS, each of the Transmission Companies owns and/or operates certain transmission facilities that are interconnected with the transmission facilities of certain other Transmission Companies within the transmission system operated by the ISO, or otherwise provides transmission service within the New England Transmission System;

WHEREAS, the ISO is a regional transmission organization (“RTO”) authorized by the Federal Energy Regulatory Commission (“FERC”) to exercise the functions required of RTOs pursuant to FERC’s Order No. 2000 and FERC’s RTO regulations;

WHEREAS, each of the PTOs has entered into the TOA with the ISO, and any ITC will enter into an ITC Agreement with the ISO, whereby the ISO will be the regional transmission provider under the ISO Open Access Transmission Tariff (“ISO OATT”) of transmission services over the Transmission Facilities of the Transmission Companies (“Transmission Service”);

WHEREAS, the ISO shall invoice transmission customers for regional Transmission Services and remit payments for Invoiced Amounts to the Transmission Companies in accordance with the TOA;

WHEREAS, the Transmission Companies wish to establish the procedures for disbursing to each Transmission Company its proper allotment of the Invoiced Amounts; and

WHEREAS, the Transmission Companies also wish to establish the procedure for reaching agreement on joint Transmission Company filings relating to rate design and other provisions of the ISO OATT under Section 205 of the Federal Power Act (“Section 205”).

NOW, THEREFORE, in consideration of the promises, and the mutual representations, warranties, covenants and agreements hereinafter set forth, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, each of the Transmission Companies agrees as follows:

Article I. JOINT TRANSMISSION COMPANY FILINGS UNDER SECTION 205

Section 1.01 Application Authority. As more fully set forth in Sections, 2.05(a), 3.03(d) and 3.04(b) of the TOA and as may be set forth in comparable provisions of one or more ITC Agreements, the Transmission Companies, acting jointly, shall have the authority to submit filings under Section 205 to amend pro forma interconnection agreements, to establish and amend pro forma Local Service Agreements, and to establish and to revise the design of the rates and charges for service provided by the Transmission Companies collectively pursuant to which the revenue requirements for all facilities of the Transmission Companies used for the provision of Transmission Service are recovered (“Regional Transmission Service”). The Transmission Companies may also elect, through the joint exercise of the individual filing rights set forth in Section 3.04(a) of the TOA and as may be set forth in comparable provisions of one or more ITC Agreements to submit joint filings under Section 205 to establish common terms and conditions applicable to Local Service provided by some or all of the Transmission Companies. Collectively, all of the joint Section 205 filings described in this Section 1.01 shall be referred to hereafter as “Joint Transmission Company Filings”.

Section 1.02 Agreement to Joint Transmission Company Filings.

(a) Those Transmission Companies supporting a proposed Joint Transmission Company Filing will be authorized to make a joint Section 205 filing upon a vote of the Transmission Companies approving such a filing that satisfies each of the following criteria:

(i) Transmission Companies shall have cast Individual Votes in favor of such a proposed Section 205 filing in a number equal to or greater than sixty-five (65) percent of the aggregate Individual Votes of all the Transmission Companies at the time of voting;

(ii) A number of Non-Affiliated Transmission Companies that have Supporting Votes that are equal to either (x) fifty percent (50%) of all Non-Affiliated Transmission Companies or (y) four (whichever is less) shall have cast votes in favor of such a proposed Joint Transmission Company Filing; and

(iii) The negative vote of a single PTO with Individual Votes equal to thirty-five (35) but not more than fifty (50) percent of the aggregate Individual Vote of the Transmission Companies shall not cause the filing to be disapproved by the Transmission Companies if the combined Individual Votes of the Transmission Companies voting in favor of the filing are equal to or greater than ninety-five (95) percent of the Individual Votes of all the remaining Transmission Companies. The negative vote of a single PTO with Individual Votes greater than fifty (50) percent of the aggregate Individual Votes of the Transmission Companies voting shall cause the filing to be disapproved by the Transmission Companies.

- 2 -

(b) “Non-Affiliated Transmission Companies” as used in this Disbursement Agreement shall mean two or more Transmission Companies that are not Affiliates, as defined in the TOA.

(c) During the Moratorium Period established in Section 3.04(h) of the TOA, the Transmission Companies shall not submit a filing under Section 205 of the Federal Power Act to modify provisions or schedules of the ISO OATT, including Schedules 9, 11, or 12 of the ISO OATT (or any successor schedules thereto), in a manner that would modify:

(i) the split between PTF and Non-PTF Transmission Facilities in effect prior to the Operations Date for purposes of allocating costs to Transmission Customers;

(ii) the methodology by which the costs of Transmission Upgrades related to generator interconnections are regionally allocated; or

(iii) the methodology by which the costs of New Transmission Facilities and Transmission Upgrades are regionally allocated under the ISO OATT.

(d) The PTO Administrative Committee shall, on the joint behalf of the Transmission Companies, give notice to the ISO of Transmission Company meetings and agendas related to rate design filings. For purposes of taking actions under this Disbursement Agreement, a Transmission Company that is an ITC shall have the right to participate in the PTO Administrative Committee under the same terms and conditions as a Participating Transmission Owner. Any meetings of the PTO Administrative Committee or votes taken by the Transmission Companies for purposes of taking actions under this Disbursement Agreement shall be subject to the scheduling, notice, quorum and other requirements set forth in Schedule 11.04 of the TOA.

(e) Each Transmission Company, including each participating ITC, if any, reserves the right to protest or file a complaint concerning any Section 205 filing made pursuant to this Agreement.

Article II. FUNDS DISBURSEMENT

Section 2.01 Disbursement of Transmission Revenues. The Transmission Companies agree that payments made to the ISO for Invoiced Amounts shall be divided among the Transmission Companies in accordance with this Section 2.01. For the purposes of this Section 2.01, capitalized terms used herein and not otherwise defined herein or in the TOA shall have the meanings assigned to such terms in the ISO OATT as in effect as of the Effective Date, or as may be amended from time to time in Section 205 filings submitted by the Transmission Companies pursuant to Section 1.02(a) and approved or accepted by FERC.

(a) Regional Network Service. The revenues received by the ISO for Regional Network Service shall be distributed to the Transmission Companies owning or supporting PTF in

- 3 -

proportion to their respective Annual Transmission Revenue Requirements for PTF, as determined in accordance with the ISO OATT, provided that with respect to VELCO, the revenues distributed for Regional Network Service will not only include distribution for VELCO’s PTF in proportion to their respective PTF Annual Transmission Revenue Requirements, but will also include distribution for HTF in proportion to these respective HTF Annual Transmission Revenue Requirements, to the extent such revenue requirements are included in the RNS rate pursuant to the ISO Tariff, further provided that VELCO shall redistribute such HTF revenues to the transmission owners of the HTF in accordance with an agreement between VELCO and the transmission owners of the HTF.

(b) Through or Out Service Revenues. The revenues received by the ISO for Through or Out Service shall be distributed among the Transmission Companies owning PTF and HTF on the basis of allocated flows for the transaction determined in accordance with the methodology specified in Exhibit A to this Disbursement Agreement, provided that VELCO shall redistribute such Through or Out Service revenues to the transmission owners of the HTF in accordance with an agreement between VELCO and the transmission owners of the HTF.

(c) Scheduling, System Control and Dispatch Service Payments. The revenues received by the ISO pursuant to Schedule 1 of the ISO OATT as in effect from time to time or, if Schedule 1 ceases to exist, the successor to Schedule 1, to cover the expenses incurred by Transmission Companies for providing Scheduling, System Control and Dispatch Service for transmission service over the PTF shall be allocated each month among the Transmission Companies whose Local Control Center costs or other costs are reflected in the computation of the surcharge for the service in proportion to the costs for each which are reflected in the computation of the surcharge.

(d) Redirection of Erroneous Payments. To the extent that any Transmission Company receives payments due to another Transmission Company under the terms of this Section 2.01, such Transmission Company shall redirect such misdirected payments to the appropriate Transmission Company as soon after discovery of the misdirected payments as practicable, together with an amount equal to the interest accruing on such misdirected payment from the date of receipt of such payment to the date payment is redirected to the proper recipient at a rate equal to the Overnight Funds Rate for the applicable period; provided, however, that if a Transmission Company fails to redirect any such misdirected payment within thirty (30) days following the date of discovery by such Transmission Company of such misdirected payment, such Transmission Company shall pay to the proper recipient of the payment, in addition to the amount of such misdirected payment, an amount equal to the interest accruing on such misdirected payment from the date of receipt of such payment at a rate equal to the applicable Prime Rate plus three percent per annum. Such Transmission Company shall also provide the proper recipient with notification of the erroneous payments within five (5) business days of discovery of the

- 4 -

mispayment. For purposes of this Section 2.01(d), the “Overnight Funds Rate” shall mean the inter-bank overnight funds rate.

(e) In the event that the Transmission Companies are required by a Governmental Authority to issue a refund or refunds of such rates and charges, each Transmission Company shall remit it’s respective share of the refunds, as determined in accordance with the ISO Tariff and the order of the Governmental Authority, to the ISO.

(f) Application of this Section 2.01. Each Transmission Company shall direct any questions or requests for clarification concerning the application or interpretation of this Section 2.01 to the PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose) and the directions of the PTO Administrative Committee shall be binding on all parties to this Agreement. The PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose) shall also respond to any ISO questions or requests for clarification concerning the application or interpretation of this Section 2.01; provided further that the ISO shall be able to rely upon the decision of the PTO Administrative Committee unless and until it receives notification from the PTO Administrative Committee of reversal of such direction by any Governmental Authority with jurisdiction over this Agreement.

Article III. MISCELLANEOUS

Section 3.01 This Disbursement Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns, including any Independent Transmission Companies (“ITCs”) formed by a Participating Transmission Owner to the extent the Participating Transmission Owner elects to assign any of its rights and responsibilities hereunder to such an ITC, and no other Persons shall have any rights herein. No transferee, successor or assign of any Participating Transmission Owner shall have any rights hereunder until notice and evidence of such transfer, succession or assignment has been provided to the Trustee and to the other Transmission Companies.

Section 3.02 This Disbursement Agreement may be executed in one or more counterparts and each of such counterparts shall, for all purposes, be deemed to be an original, but all counterparts together shall constitute one and the same instrument. Signatures sent to the other parties by: (a) personal delivery thereof, including by a recognized next-day courier service; (b) certified United States mail, postage prepaid, return receipt requested; or (c) facsimile transmission shall be binding as evidence of acceptance of the terms hereof by such signatory party.

Section 3.03 Any notice, statement, or other communication which is required or permitted hereunder shall be in writing and shall be sufficient in all respects if delivered personally or by certified United States mail, postage prepaid, return receipt requested, or by facsimile or by a recognized next-day courier service, in each case addressed to each Transmission Company at its

- 5 -

address set forth in Exhibit B. The address of a Transmission Company may be changed from time to time by giving notice in the manner prescribed in this paragraph. All such notices or communications will be effective (i) upon mailing or transmission, if mailed or sent by facsimile, (ii) upon receipt, if personally delivered, and (iii) on the first Business Day following the date of dispatch, if delivered by a nationally recognized next-day courier service.

Section 3.04 This Disbursement Agreement shall be governed by and construed in accordance with the laws of the District of Columbia, including all matters of construction, validity and performance without regard to the conflicts-of-laws provisions thereof.

Section 3.05 If any one or more provisions in this Disbursement Agreement, for any reason, shall be determined to be invalid, illegal, or unenforceable in any respect, the validity, legality and enforceability of any such provision in any other respect and the remaining provisions of this Disbursement Agreement shall not be in any way impaired.

Section 3.06 No failure or delay on the part of any party in the exercise of any power or right hereunder shall operate as a waiver thereof. No single or partial exercise of any right or power hereunder shall operate as a waiver of such right or power or of any other right or power. The waiver by any party of a breach of any provision of this Disbursement Agreement shall not operate or be construed as a waiver of any other or subsequent breach hereunder. Except as otherwise expressly provided herein, all rights and remedies existing under this Disbursement Agreement are cumulative with, and not exclusive of, any rights or remedies otherwise available.

Section 3.07 This Disbursement Agreement shall only be subject to modification or amendment as follows; provided, however, that no amendment that would or could be expected to affect a Transmission Company in a manner which is more adverse than its effect on other Transmission Companies shall be effective with respect to the more adversely affected PTO without the prior written consent of such PTO, and further provided that no amendment to Section 2.01 of this Disbursement Agreement that would or could be expected to increase the risk of a PTO’s recovery of its revenue requirements shall be effective with respect to such PTO without the express consent of such PTO.

(a) Agreement to Amendment of Articles II and III of this Disbursement Agreement. The Transmission Companies will be deemed to have agreed to an amendment to Articles II and III of this Disbursement Agreement upon a vote of the Transmission Companies that satisfies each of the following criteria:

(i) Transmission Companies shall have cast Individual Votes in favor of such amendment in a number equal to or greater than sixty-five (65) percent of the aggregate Individual Votes of all the Transmission Companies at the time of voting;

(ii) A number of Non-Affiliated Transmission Companies that have Supporting Votes that are equal to either (x) fifty percent (50%) of all Non-Affiliated Transmission

- 6 -

Companies or (y) four (whichever is less) shall have cast votes in favor of such an amendment; and

(iii) The negative vote of a single Transmission Company with Individual Votes equal to thirty-five (35) but not more than fifty (50) percent of the aggregate Individual Vote of the Transmission Companies shall not cause the amendment to fail if the combined Individual Votes of the Transmission Companies voting in favor of the filing are equal to or greater than ninety-five percent (95) of the Individual Votes of all the remaining Transmission Companies. The negative vote of a single Transmission Company with Individual Votes greater than fifty (50) percent of the aggregate Individual Votes of the Transmission Companies voting shall cause the amendment to fail.

(b) Agreement to Amendment of Article I of this Disbursement Agreement. The Transmission Companies will be deemed to have agreed to an amendment to Article I of this Disbursement Agreement upon a vote of the Transmission Companies that satisfies each of the following criteria:

(i) Transmission Companies shall have cast Individual Votes in favor of such amendment in a number equal to or greater than ninety-five (95) percent of the aggregate Individual Votes of all the Transmission Companies at the time of voting; and

(ii) A number of Non-Affiliated Transmission Companies that have Supporting Votes that are equal to either (x) seventy percent (70%) of all Non-Affiliated Transmission Companies or (y) five (whichever is less) shall have cast votes in favor of such an amendment.

Section 3.08 This Disbursement Agreement contains the entire agreement among the Transmission Companies with respect to the transactions contemplated hereby and supersedes all prior arrangements or understandings with respect thereto, written or oral.

Section 3.09 The rights of the parties under this Disbursement Agreement are unique and each party hereto acknowledges that the failure of a party to perform its obligations hereunder would irreparably harm the other parties hereto. Accordingly, the parties shall, in addition to such other remedies as may be available at law or in equity, have the right to enforce their rights hereunder by actions for specific performance to the extent permitted by law.

Section 3.10 No Transmission Company shall be liable to another Transmission Company for any incidental, indirect, special, exemplary, punitive or consequential damages, including lost revenues or profits, arising from an alleged breach of this Agreement, even if such damages are foreseeable or the damaged Transmission Company has advised such Transmission Company of the possibility of such damages and regardless of whether any such damages are deemed to result from the failure or inadequacy of any exclusive or other remedy.

- 7 -

Section 3.11 This Disbursement Agreement is not intended to confer any rights or remedies upon any Person other than the parties hereto and their successors or permitted assigns.

Section 3.12 Neither this Disbursement Agreement nor any part hereof shall be assigned by any Transmission Company hereto except: (i) to an affiliated corporation of such Transmission Company, provided that such affiliated corporation shall assume the liabilities of such Transmission Company hereunder and that such transfer shall not operate to relieve such Transmission Company of its liabilities hereunder; (ii) to any Person to whom any or all of such Transmission Company’s interest in Transmission Facilities or right to operate such Transmission Facilities is transferred, including an ITC, provided that such transferee shall assume the liabilities of the Transmission Company hereunder; (iii) to any corporation which succeeds to substantially all of the assets of the Transmission Company by acquisition, merger or consolidation and which assumes all of the Transmission Company’s obligations and liabilities hereunder; or (iv) to any other Transmission Company, provided that such transferee Transmission Company shall assume the liabilities of the transferor Transmission Company hereunder. The Transmission Company’s successors and assigns shall agree to be bound by the terms of this Disbursement Agreement except that a Transmission Company’s successors and assigns shall not be required to be bound by any obligations hereunder to the extent that the Transmission Company has agreed to retain such obligations.

Section 3.13 Each of the parties hereto agrees to cooperate with the other parties hereto in effectuating this Disbursement Agreement and to execute and deliver such further documents or instruments and to take such further actions as shall be reasonably requested in connection therewith.

Section 3.14 Additional Participating Transmission Owners and any ITC that is a successor to the rights and responsibilities of a Transmission Company with respect to some or all of such Transmission Company’s Transmission Facilities may become parties to this Disbursement Agreement without any amendment to this Disbursement Agreement pursuant to Section 3.07 or any consent or approval of the other Transmission Companies.

Section 3.15 To the extent that this Disbursement Agreement imposes additional obligations or requirements on any Transmission Company relating to subject matters set forth in the TOA, the Transmission Companies agree to be bound by this Disbursement Agreement.

Section 3.16 In the event of any dispute among the Transmission Companies concerning the interpretation of this Disbursement Agreement, the Transmission Companies agree to engage in good faith negotiations to resolve such disputes; provided that nothing in this Disbursement Agreement shall limit the right of any Transmission Company to submit questions of interpretation of this Disbursement Agreement to FERC or a court or agency with jurisdiction over this Disbursement Agreement upon the conclusion of such negotiations.

- 8 -

Section 3.17 If a Transmission Company withdraws from or terminates the TOA, then such Transmission Company shall be deemed to have withdrawn from or terminated this Agreement at such time as its withdrawal from or termination of the TOA becomes effective.

Section 3.18 It is not the intention of this Agreement or of the Transmission Companies thereto to confer a third party beneficiary status or rights of action upon any Person or entity whatsoever other than the Transmission Companies and nothing contained herein, either express or implied, shall be construed to confer upon any Person or entity other than Transmission Companies any rights of actions or remedies either under this Agreement or in any manner whatsoever.

Section 3.19 The Transmission Companies do not intend by this Agreement to create, nor does this Agreement constitute, a joint venture, association, partnership, corporation or an entity taxable as a corporation or otherwise. No express or implied term, provision or condition of this Agreement shall be deemed to constitute the Transmission Companies as partners or joint venturers.

Section 3.20 Absent the agreement of the Transmission Companies to any amendment of this Disbursement Agreement pursuant to Section 3.07 hereof, the standard of review for changes to this Disbursement Agreement proposed by a Transmission Company, a non-party or the Federal Energy Regulatory Commission acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956)

- 9 -

IN WITNESS WHEREOF, the parties hereto have caused their respective hands and seals to be set hereto with the intention of being bound effective in all respects as of the date and year first herein above written.

[The names of the Initial PTOs will be submitted in a compliance filing prior to the Operations Date.]

- 10 -

EXHIBIT A

Methodology for Determination of Transmission Flows

All capitalized terms used in this Exhibit A and not otherwise defined in this Exhibit A shall have the meanings assigned to such terms in the TOA or, to the extent not defined in the TOA, the ISO OATT.

The methodology for determining parallel path transmission flows to be used in determining the distribution of revenues received for Through or Out Service is as follows, and shall be determined on the basis of the flows for the particular transaction (“Transaction Flows”) for the purpose of allocating revenues from the furnishing of Through or Out Service:

A. Responsibility for Calculations. The calculation of mega watt mile allocations in accordance with this methodology shall be performed under the direction of the PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose).

B. Periodic Review. Calculations of MW-Mile allocations shall be performed whenever significant changes to the transmission system load flows, as determined by the PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose), occur.

C. Facilities Included in the Analysis

1. Transmission Lines. A calculation of MW-miles shall be determined for all PTF and HTF lines.

2. Generators. The analysis shall include all generators with a Winter Capability equal to or greater than 10.0 MW. Multiple generators connected to a single bus with a total Winter Capability equal to or greater than 10.0 MW shall also be included.

3. Transformers. All transformers connecting PTF and HTF transmission lines shall be included in the analysis.

D. Determination of Rate Distribution

1. General. Modeling of the transmission system shall be performed using a system simulation program and associated cases as approved by the PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose).

2. Determination of Regional Flows. The change in real power flow (MW) over each transmission line and transformer shall be determined for each generator (or

- 11 -

group of generators on a single bus) by determining the absolute value of the difference between the flows on each facility with the generator(s) modeled off and while operating at its net Winter Capability. In addition, a generator shall be simulated at each transmission line tie to the New England Control Area and changes in flow determined for this generator off or while generating at a level of 100 MW. Loads throughout the New England Control Area shall be proportionally scaled to account for differences in generator output and electrical losses. The changes in flow shall be multiplied by the length of each respective line. Changes in flow through transformers shall be multiplied by a factor of five. Changes in flow through phase-shifting transformers shall be multiplied by a factor of ten. The resulting values represent the MW-miles associated with each facility.

3. Determination of Transaction Flows

a. Definition of Supply and Receipt Areas. For the purposes of these calculations, areas of supply and receipt shall be determined by the PTO Administrative Committee (or such subcommittee as the PTO Administrative Committee shall designate for such purpose). These areas shall be based on the system boundaries of each Local Network.

b. Calculation of MW-Miles. The change in real power flow (MW) over each transmission line and transformer shall be determined for each combination of supply and receipt areas by determining the absolute value of the difference between the flows on each facility following a scaled increase of the supplying areas generation by 100 MW. Loads in the area of receipt shall be scaled to account for changes in generation and electrical losses. In instances where the areas of supply and/or receipt are outside the New England Control Area, the changes in real power flow will be determined only for facilities within the New England Control Area. The changes in flow shall then be multiplied by the length of each respective line. Changes in flow through transformers shall be multiplied by a factor of five. Changes in flow through phase-shifting transformers shall be multiplied by a factor of ten. The resulting values represent the MW-miles associated with each facility.

4. Assignment of MW-Miles to Transmission Companies. Each Transmission Company shall have assigned to it the MW- miles associated with each PTF and HTF facility for which it has full ownership and for which there are no arrangements in effect by which other Transmission Companies support the facility. For facilities that are jointly owned and/or supported, each Transmission Company shall be assigned MW-miles in proportion to the percentage of its ownership of jointly-owned facilities and/or the percentage of its support for facilities that are jointly supported to the extent such support payments are included in the determination of Annual Transmission Revenue Requirements.

- 12 -

EXHIBIT B

Notice Addresses

EX-21.1

Exhibit 21.1

Subsidiaries of NSTAR

	State of Incorporation
Boston Edison Company	Massachusetts
Commonwealth Electric Company	Massachusetts
Cambridge Electric Light Company	Massachusetts
Canal Electric Company	Massachusetts
NSTAR Gas Company	Massachusetts
Hopkinton LNG Corp.	Massachusetts
Advanced Energy Systems, Inc.	Massachusetts
Harbor Electric Energy Company	Massachusetts
BEC Funding LLC	Delaware
BEC Funding II, LLC	Delaware
CEC Funding, LLC	Delaware
NSTAR Communications, Inc.	Massachusetts
MATEP, LLC	Delaware
NSTAR Electric & Gas Corporation	Massachusetts

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-78285, 333-85559 and 333-87272) and in the Registration Statement on Form S-3 (No. 333-78285), of NSTAR of our report dated February 17, 2006 relating to the financial statements, the financial statement schedules, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Boston, Massachusetts

February 17, 2006

EX-31.1

Exhibit 31.1

Sarbanes - Oxley Section 302 Certification

I, Thomas J. May, certify that:

1. I have reviewed this annual report on Form 10-K of NSTAR;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of NSTAR as of, and for, the periods presented in this annual report;

4. NSTAR’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for NSTAR and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to NSTAR, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of NSTAR’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and

d) disclosed in this annual report any change in NSTAR’s internal control over financial reporting that occurred during NSTAR’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSTAR’s internal control over financial reporting; and

5. NSTAR’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to NSTAR’s auditors and the audit committee of NSTAR’s board of trustees:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect NSTAR’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in NSTAR’s internal control over financial reporting.

Date: February 17, 2006	/s/    THOMAS J. MAY
	Thomas J. May
	Chairman, President and
	Chief Executive Officer

EX-31.2

Exhibit 31.2

Sarbanes - Oxley Section 302 Certification

I, James J. Judge, certify that:

1. I have reviewed this annual report on Form 10-K of NSTAR;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of NSTAR as of, and for, the periods presented in this annual report;

4. NSTAR’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for NSTAR and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to NSTAR, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of NSTAR’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and

d) disclosed in this annual report any change in NSTAR’s internal control over financial reporting that occurred during NSTAR’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSTAR’s internal control over financial reporting; and

5. NSTAR’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to NSTAR’s auditors and the audit committee of NSTAR’s board of trustees:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect NSTAR’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in NSTAR’s internal control over financial reporting.

Date: February 17, 2006	/s/    JAMES J. JUDGE
	James J. Judge
	Senior Vice President, Treasurer and
	Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 of the Sarbanes-Oxley Act of 2002

The undersigned hereby certifies, in my capacity as an officer of NSTAR, for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(i) the enclosed Annual Report of NSTAR on Form 10-K for the period ended December 31, 2005 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii) the information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operation of NSTAR.

Dated: February 17, 2006	/s/    THOMAS J. MAY
	Thomas J. May
	Chairman, President and
	Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 of the Sarbanes-Oxley Act of 2002

The undersigned hereby certifies, in my capacity as an officer of NSTAR, for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(i) the enclosed Annual Report of NSTAR on Form 10-K for the period ended December 31, 2005 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii) the information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operation of NSTAR.

Dated: February 17, 2006	/s/    JAMES J. JUDGE
	James J. Judge
	Senior Vice President, Treasurer
	and Chief Financial Officer