SEC LETTER

We are transmitting herewith the responses of Green Mountain Power Corporation (“GMP” or the “Company”) to the comments of the Staff of Division of Corporation Finance (the “Staff”) contained in your letter dated April 25, 2005.

GMP has previously responded to all of your questions (#1-3) related to the Company’s Preliminary Proxy Statement on Schedule 14A filed March 30, 2005, in a letter dated April 25, 2005. Those questions and answers are not repeated in this response to the Staff’s Form 10-K comments. For your convenience and reference, each Staff comment on Form 10-K contained in Mr. Owings’ letter is reprinted below in italics, numbered to correspond with the paragraph number assigned in the April 25, 2005 comment letter, and is followed by the corresponding response of the Company.

4. It does not appear that you have included disclosure required by Item 9B of Form 10-K. Please confirm to us that there is no other information required to be disclosed, or amend your Form 10-K to disclose the required information. Also, in future periodic reports, if no disclosure is required by an Item, then disclose “none” or “not similar” or something similar, rather than omitting the Item.

Our Form 10-K did not include the disclosure required by Item 9B. In future periodic reports, we will include an Item 9B with appropriate discussion, including the communication “none” when no required disclosures exist. We confirm that as of December 31, 2004, there

Green Mountain Power Corporation 163 Acorn Lane Colchester Vermont 05446-6611 P(802)655-8410 F(802)655-8406 www.greenmountainpower.biz

were no items to be disclosed by the Company under Item 9B, and that Item 9B should have been included with the communication “none”.

5. We note you disclose that there have been no significant changes to your internal control over financial reporting. Please be aware that Item 308(c) of Regulation S-K requires disclosure of any change that has materially affected, or is reasonably likely to material affect, your internal control over financial reporting. Please confirm to us that there have been no changes within the scope of Item 308(c), or amend to provide the necessary disclosure. Also, in future periodic reports, please ensure your disclosure reflects the precise Item 308(c) standard.

Our Form 10-K should have communicated that there were no changes that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting. In future periodic reports, we will use wording consistent with Item 308(c) of Regulation S-K.

6. Where a comment below requests additional disclosures or other revisions to be made, please show us in your supplemental response what the revisions will look like. These revisions should be included in your future filings.

Please see our responses below. Where appropriate, we have provided additional disclosures or other revisions based on your comments. We will incorporate these additional disclosures and revisions in future filings.

7. You indicate that your ownership in VYNPC increased in 2004, from 19 percent to 33.6 percent as a result of the investee’s purchase of certain minority shareholders’ interests. Note B indicates a 33.6% ownership interest as of December 31. 2003. Please explain or reconcile the disparity between the two sections of your Form 10-K.

Please also tell us how you view the investee’s purchase of certain minority shareholders interests. Furthermore, provide to us the accounting entries which were recorded by the investee, as well as the entries you recorded with respect to this transaction. If you changed the basis in the investee as a result of the investee’s treasury stock repurchase, please contrast this to a situation where your percentage in an investee was increased as a result of your direct purchase of investee shares from other shareholders. Also, please advise if the repurchase was consummated at book value, premium, or discount.

Finally, please tell us how you accounted for the change in the equity of VYNPC at the investor level. In this regard, we note that your net equity in the assets of VYNPC did not materially change from 2004 as compared with 2003. Please reconcile the change in net assets of VYNPC from 2003 to 2004.

The Company owns 33.6 percent of VYNPC. During 2003, the Company’s interest in VYNPC increased from 19 percent to 33.6 percent as a result of VYNPC’s purchase of the interests of certain minority shareholders. The ownership listed in the business section of the Form 10-K was incorrect. We will ensure appropriate disclosure in future filings. A reconciliation of 2003 ending balance for VYNPC to 2004 ending balance for VYNPC follows:

VYNPC paid book value to purchase minority shareholder interests. The purchase of minority shareholders’ interests by VYNPC was recorded by VYNPC at book value resulting in a reduction to its cash and equity accounts, and therefore there was no change in the Company’s basis in VYNPC as a result of the transaction. As a result, there were no entries on our books relating to the transaction and no change in investment value. The Company’s carrying value of its VYNPC investment is equal to its 33.6 percent share of the book value of VYNPC’s equity.

8. You reference purchases of 197,241 MWh of power, representing 9.50 percent of the Company’s 2004 net power supply. You also indicate that you have arrangements with power marketers participating in the New England/York market. In general, New York market transactions typically settle financially. Please explain if you consider any of these arrangements non-trading derivatives and if not, your rationale. If so, tell us whether you apply the normal purchase and sale election of SFAS no. 133 and how you meet the “normal” criteria. Lastly, explain what percentage of these contracts physically settle. We may have further comment.

Nearly all ISO-NE and short-term purchases are settled physically. Our loads vary based on weather and seasonality and we buy and sell power to match our contract resources with the load that exists each hour. The 197,241 MWh relates primarily to these hourly physical settlements through ISO-NE to meet customer demands. For financial reporting purposes, sales of power to ISO-New England are netted hourly against any purchases from ISO-NE. There are no outstanding positions at the end of a quarter on these transactions since these transactions represent hourly load balancing.

Our transactions in New York are also physically settled. We utilize the New York market infrequently and only when transmission equipment is constrained in Vermont and we can’t otherwise receive energy from our contracts directly in Vermont. In these situations, we will have the contract energy physically delivered to New York.

We have, on rare occasions, had several minor transactions that were settled financially. These transactions were for immaterial amounts and settled before a quarter-end so that there were no derivative valuation requirements at quarter-end. Our trader uses these transactions to cover several days up to a week of severe weather or outages where we believe our resources are not quite adequate to meet our customer demand. These types of transactions are rare and have never been done on a longer-term basis for our Company. These transactions are not left open at the end of a reporting period so that there are no derivative valuation requirements.

We also occasionally purchase power from power marketers when we anticipate that demand will exceed our power supply resources. These energy purchases are typically physically settled and the energy is sold to our customers. We account for these purchases as normal purchase and sales. These are bilateral transactions that are short-term in duration, physically delivered, and which provide energy in quantities expected to meet our immediate customer load demands in the normal course of business.

9. We note the ISO-NE implemented their SMD plan on March 1, 2003, and currently the State of Vermont constitutes a single zone under the plan. Please explain how nodal pricing will impact your power supply and transmission costs; an example would be helpful to the staff’s understanding. You indicate that nodal pricing could result in a material adverse impact. In this regard, please explain whether there are any steps you could take to reduce such impact.

Nodal pricing relates to the price at the point that power comes onto the transmission system. The price at every node is a function of availability of generation and transmission. Where load exceeds available transmission capacity, higher priced generation must be used to balance the system. We have attached an ISO-NE paper that provides a general explanation of nodal pricing.

Prior to December 4, 2004, FERC was supportive of moving to nodal pricing. The FERC reaffirmation of zonal pricing (See 2004 MD&A – Transmission Expenses) on December 4, 2004, mitigates the immediate risk of moving towards nodal pricing. At this point in time, we don’t know when, if ever, nodal pricing will be implemented. We will deemphasize this particular risk in future filings, unless views at FERC or ISO-NE reverse course. Our Form 10-Q for the quarter ended March 31, 2005 revises the disclosure as follows:

Currently, the State of Vermont constitutes a single zone under the plan, although it is possible pricing could eventually be determined on a more localized (“nodal”) basis. FERC’s affirmation of zonal pricing in December 2004 substantially reduced the likelihood that nodal pricing would replace zonal pricing. There are no current initiatives to impose nodal pricing or to change Vermont’s use of zonal pricing to allocate congestion costs. We believe that nodal pricing, if it were ever adopted, could result in a material adverse impact on our power supply and/or transmission costs. Transmission projects, such as the recently approved Northwest Reliability Project (“NRP”), will reduce congestion and potential nodal pricing differences

within Vermont, when they are completed. The NRP is not expected to be completed prior to 2007.

We have not quantified the impacts of nodal pricing on the Company, if it were to be adopted. Any estimate would be highly dependent upon the timing of when nodal pricing was implemented. We know that nodal prices would be higher in northwestern Vermont where most of the Company’s load resides, than in the remainder of the state. We also know from studies submitted to the Vermont Public Service Board (“VPSB”) by VELCO for construction of transmission to relieve constraints in northwestern Vermont, that significant congestion costs were foreseen to be allocated to northwestern Vermont from ISO-NE absent construction of the additional transmission capacity that VELCO was seeking to build. Based on the studies submitted by VELCO, and the location of most of our load in constrained areas in northwestern Vermont, we have concluded that if nodal pricing were implemented, it could have a material adverse effect on the Company. In general, nodal price differences may be mitigated by building additional generation or transmission capacity. VELCO’s construction of the Northwest Reliability Project, which will bring additional transmission capacity to northwestern Vermont, is expected to reduce nodal price differences substantially within the Vermont zone.

Quantitative and Qualitative Disclosures about Market Risk, and Other Risk Factors

10. Please explain to us how you determined the risk free rate used to value the Morgan Stanley and the 9701 Arrangement. Specifically address the disparity in risk free interest rate and the extent to which the disparity is maturity-related. Lastly, explain why you are using two different option models to value these contracts.

We utilized a 3-month treasury bill rate for the Morgan Stanley Contract and a 10 year treasury bond rate for the 9701 Agreement. The Morgan Stanley Contract ends December 31, 2006 and the 9701 Agreement ends in 2015. Therefore, most of the disparity in rates is due to varying contract maturities. While we could have used a two-year rate for the Morgan Stanley Contract instead of the 3-month rate, it would not have had a significant effect on the valuation. The two-year rate at December 31, 2004, was 3.09 percent, compared with the 2 percent rate we used. The effect of using the two-year rate instead of the three-month rate on the derivative valuation would have reduced the fair value from $10,736,478 to $10,593,062 or by approximately 1.3 percent. In future periodic reports, we will utilize a risk free rate matching the duration equivalent to the remaining outstanding life of the contract being fair valued.

The Morgan Stanley Contract has two remaining years at December 31, 2004. Current energy prices are well above the contract price. Most of the fair value of the derivative relates to this differential, as opposed to the discount rate. The deterministic model used to evaluate the Morgan Stanley Contract incorporates market price forwards that are currently available (used for actual market transactions) for the remaining duration of the contract (electricity futures market typically extends out a couple of years. The deterministic model calculates the difference between quoted forward energy price and the contract price for the quantity purchased under the contract and discounts the result using the 3-month treasury rate. Given the short-term nature of

the Morgan Stanley Contract and the simplicity of the contract, we believe the deterministic model is appropriate for use as a valuation tool. We have concluded that valuation of the Morgan Stanley Contract using the deterministic model provides a superior valuation to other methods such as Black-Scholes, because the deterministic approach uses readily available forward prices as opposed to using past pricing volatility to generate estimated future prices.

The 9701 Agreement ends in 2015. Therefore, energy futures are not available for most of the contract duration. Use of the Black Scholes model, commonly used for derivative valuations, provides better valuation in our opinion based upon the absence of reliable future market prices for electricity through 2015.

Based on a VPSB approved accounting order dated April 11, 2001, we record the change in fair value of derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain. Because the Company applies this regulatory accounting treatment to such transactions, we do not make a determination as to whether the derivatives qualify as cash flow hedges.

11. We assume the Morgan Stanley contract is not an energy trading derivative but is a derivative. If our assumption is correct please provide to us your EITF 03-11 analysis with respect to income statement classification of the contract. Finally, tell us whether the contract is physically or net settled. Please be detailed in your response explaining how the contract operates including explanation of the index or specified prices.

The Morgan Stanley Contract is a non-trading derivative and activity under this contract is reported gross. Sales to Morgan Stanley are recorded under “Wholesale revenues” in the Company’s Consolidated Statements of Income. Purchases of energy from Morgan Stanley are recorded as “Power Supply – Purchases from others” under “Operating Expenses” in the Company’s Consolidated Statements of Income.

The contract with Morgan Stanley has two facets. First, it is a contract to purchase energy in specified amounts during specified times at specified prices through 2006. We pay a specified fixed contractual price per MWh to Morgan Stanley that changes January 1 each year. We utilize this portion of the contract to fix our power supply costs and reduce our exposure to New England wholesale market price volatility; wholesale prices in the New England market are typically based on fossil fuel prices. We purchased approximately 321,000 MWh during 2004 from Morgan Stanley under this facet of the contract. Purchases and sales under the Morgan Stanley Contract are required to be physically settled.

Second, the contract also gives Morgan Stanley the right to call the energy producing output capability from the Company’s ownership share of two fossil fuel plants, Wyman and Stonybrook using pricing based on an index. The Wyman index price is equal to the daily spot price for No. 6 Sulfur oil per barrel. Stonybrook is a duel fuel plant, and index price for gas is

the daily spot price for NUMEX Henry Hub Gas, while the index price for oil is the daily spot price for NYH #2 oil. In 2004, we sold Morgan Stanley approximately 125,000 MWh under this option.

Since EITF 03-11 did not address the issue of whether gains and losses (realized and unrealized) should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives under FAS 133, we used the guidance set forth in EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. At least two of the indicators in EITF 99-19 lead us to determine that we act as a principal in these transactions; 1) the Company is the primary obligor in the arrangement- the contract is settled physically, all of the energy is delivered from specific facilities; and 2) the risks and rewards of ownership exist; both Morgan Stanley and the Company act as principals, take title to delivered energy and bear inventory and counterparty credit risk. The consensus reached in EITF 03-11 was that gross versus net presentation of physically settled derivative contracts “not held for trading purposes” is a matter of judgment that depends on the relevant facts and circumstances in the context of various activities of the entity rather than based solely on the terms of the individual contracts. Based on the above accounting guidance, we account for these forward sale and purchase contracts on a gross basis.

12. Please reconcile the number of shares granted under your compensation programs to the number of shares issued on your consolidated statements of stockholders’ equity.

A reconciliation of the number of shares issued under Company compensation programs to the number of common shares identified as issued under compensation programs in our 2004 Consolidated Statements of Shareholders’ Equity follows:

In our 2004 10-K, the number of options exercised was incorrectly disclosed in Note C as 84,150; the disclosure should have indicated 89,650 shares. We will correct this disclosure in future filings and disclose the number of shares granted under each compensation program. Our future disclosure of “Common Stock Equity and Stock Award Plans” will include a similar sentence to the 2004 example below:

Common stock issuance from compensation programs during 2004 amounted to 107,264 shares. Of this amount, 89,650 shares were issued for exercised options, 9,914 shares were issued for employee stock grants and 7,700 shares were issued for grants to the Company’s Board of Directors.

13. You indicate that you fund an employee savings and investment plan. Please tell us whether your financial statements reflect any expense associated with this plan. If not, please explain the reasons. A description of the plan may be helpful to our understanding. If so, please disclose the expense as discussed in paragraph 11 of SFAS No. 132 (R). Lastly, please tell us if you are matching employee contributions in either cash or stock.

In our 2004 10-K, we failed to disclose contributions made to the Company sponsored 401(k) plan. Under our employee savings and investment plan, we match employee contributions up to the first four percent of annual base salary (and make an additional contribution of a ½ percent of base salary on a non-matching basis). Matching contributions are made in cash. Contributions for the last three years follow:

In future periodic reports, we will include the above amounts in the notes to the financial statements under “Pension and Retirement Plans”.

The Company maintains a 401(k) Savings Plan for substantially all employees. This savings plan provides for employee contributions up to specified limits. The Company matches employee pre-tax contributions up to 4 percent, [and contributes an additional ½ percent each year made on a non-matching basis, of eligible compensation]. The additional half percent contribution was added effective January 2004. The Company match is immediately vested. The Company’s matching contributions for 2005, 2004 and 2003 amounted to $xxx, 000, $487,000 and $398,000, respectively.

14. It is not clear whether you have any deferred income taxes associated with accelerated tax depreciation on public utility property. Please advise how you depreciate plant for rate making versus tax purposes and how this complies with the normalization requirements contained in the USTC. To the extent you have taken the investment tax credit in the past, please help us understand which election you made under the Revenue Act of 1971 and how such election is reflected in your financial statements based on your rate making treatment of the credit. As part of your explanation, ensure you tell us whether the flow through items contained in the determination of deferred income tax expense or benefit, includes any of the above mentioned items. In short, explain why it appears you have no deferred tax items related to plant and whether you have any regulatory deferrals related to ITC.

We have described the deferred income tax liabilities associated with accelerated tax depreciation on public utility property as “property-related” under Note G “Income Taxes”. Prospectively, we will clarify this disclosure by referring to this line item as “accelerated tax depreciation on property.” Under our rate-making, book depreciation is calculated based on depreciation studies. For tax purposes, we use accelerated MACRS depreciation for the appropriate tax lives for the underlying property. Our rate-making treatment complies with the normalization requirements of the USTC because deferred income tax liabilities that result from temporary timing differences are subtracted from rate base as part of the rate-making process, thereby reducing rates.

Under the Revenue Act of 1971, we elected IRC Section 46(f)(2), option 2. We have regulatory deferrals related to the ITC. These differences are amortized over the remaining lives of the property giving rise to the ITC. Benefits are provided to customers as an adjustment to rates since our effective tax rate is reduced by these amounts.

15. Please explain to us how you calculate the market related value of plan assets as that term is defined in SFAS 87. Since there are alternative ways to calculate the market value of plan assets and it has a direct impact on your pension expense, we believe you should disclose how you determine this amount in future filings.

We calculate the market-related value of plan assets based on the fair value of the assets at the measurement date, 12/31/2004, as allowed by paragraph 30 of SFAS no. 87. We do not use a calculated value that recognizes changes in fair value in a systematic manner to determine the market related value of plan assets. Our future disclosure will include the following sentences:

The Company records annual expense and accounts for its pension plan in accordance with Statement of Financial Accounting Standards No. 87 (SFAS 87), Employers’ Accounting for Pensions. The Company calculates the market related value of plan assets under SFAS87 based on the fair value of the assets at the measurement date, 12/31/xx.

16. Please tell us your achieved rate or return for the years covered by the statements statements, then we believe disclosure of the achieved return in percentage and absolute dollars would be useful of income. If the achieved rate of return is not readily calculable from your financial information. Such information may be disclosed outside the financial statements.

The consolidated rate of return is addressed in Management’s Discussion and Analysis in the first table under Item 7. Our achieved rates of return for 2002, 2003, and 2004 were 11.06 percent, 10.76 percent and 11.03 percent respectively. The process to submit our results for regulatory review is extensive and mirrors a rate filing, and includes a submission of all costs to

regulators for review after year-end but not before the Form 10-K is filed. The regulators have never required us to adjust our rate of return based on their review. As such, the Company would prefer not to disclose an estimate of return on equity of utility operations in the Form 10-K prospectively and prior to review by the regulators, which would not be completed within the timeframes allowed under present reporting requirements. Additionally, since our Company has very few unregulated investments, we expect minimal differences between allowed rate of return as ultimately determined by our regulators and expected consolidated rate of return for the Company.

17. Tell us how you view the VJO Contract under SFAS no. 133. If you treat as a normal purchase contract, please show us your analysis. We assume from your previous disclosure of the fair market value of “the 9701 agreement” that contract represents a mark-to-market derivative. If our assumption is incorrect, please clarify. Please also tell us how you accounted for the $8 million payment associated with writing the calls that constitute “the 9701 agreement”.

We describe the VJO Contract in Note K of our 2004 Form 10-K. The contract is a full requirements contracts for use in the normal course of business. In determining the appropriate accounting for the power supply contract with Hydro-Quebec we determined whether the contract met the definition of a derivative under FASB Statement No. 133, including amendments to that statement (collectively referred to as FAS 133). We assessed whether the contract possessed all three of the characteristics required by FAS 133, which include:

Based on our assessment of the three characteristics outlined above, we determined that the VJO Contract does not meet the definition of a derivative under FAS 133 because there is no notional amount. We are obligated to pay for capacity under the terms of the contract, and only for the amount of energy delivered, which is subject to the Vermont Joint Owner aggregate load factor.

The default percentage requires that if the Vermont Joint Owners notify Hydro-Quebec that a delinquent party will cease to have any rights under the contract such rights will be assumed by the remaining Vermont Joint Owners in proportion to their pro-rata share of the delinquent party’s obligation. In this case, we would be obligated to pay our pro-rata share of the delinquent party’s obligation under the contract, and our obligation under the contract would increase to reflect our pro-rata share of the delinquent party’s obligation. The Vermont Joint Owners includes Vermont utilities with varying obligation percentages under the contract. In considering the guidance under DIG Issue A6, although the pro-rata share of output would increase, this does not allow us the ability to quantify the notional amount of the contract.

The 9701 Agreement is a derivative. Based on a VPSB approved accounting order dated April 11, 2001, we record the change in fair value of derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain. Because the Company applies this regulatory accounting treatment to such transactions, we do not make a determination as to whether the derivatives qualify as cash flow hedges.

Hydro-Quebec obtained options to purchase certain amounts of energy at VJO Contract energy prices through 2015 in return for an $8 million payment made to GMP by Hydro-Quebec as we disclosed in Note K of Form 10-K. The VPSB issued an accounting order dated December 31, 1996,requiring the Company to reflect the $8 million payment from Hydro-Quebec as revenue during 1997. In accordance with such VPSB Order and SFAS 71, we recorded the $8 million of revenue during 1997.

18. The report does not appear to have been signed by your Controller or principal accounting officer. If this officer is one of the current signatories, then he should also be identified as a signatory in this capacity. See General Instruction D to Form 10-K

The Company’s Chief Financial Officer is also its principal accounting officer. Future filings will incorporate both title references.

In connection with responding to these SEC comments, the Company acknowledges that:

If you have questions or require additional information, please contact me (802) 655-8452.

Very truly yours,

/s/ Robert J. Griffin

Robert J. Griffin

Vice President, CFO, Treasurer and

Principal Accounting Officer

Locational marginal pricing (LMP) is a market-pricing approach used to manage the efficient use of the transmission system when congestion occurs on the bulk power grid.

Congestion arises when one or more restrictions on the transmission system prevent the economic, or least expensive, supply of energy from serving the demand. For example, transmission lines may not have enough capacity to carry all the electricity to meet the demand in a certain location. This is called a “transmission constraint.” LMP includes the cost of supplying the more expensive electricity in those locations, thus providing a precise, market-based method for pricing energy that includes the “cost of congestion.”

LMP provides market participants a clear and accurate signal of the price of electricity at every location on the grid. These prices, in turn, reveal the value of locating new generation, upgrading transmission, or reducing electricity consumption—elements needed in a well-functioning market to alleviate constraints, increase competition and improve the system’s ability to meet power demand.

Unlike the original market in New England, in which there is only one energy clearing price, under SMD, prices are calculated at three types of locations: the node, the load zone and the hub. Offers and bids are submitted, markets settle, and LMPs are calculated at these locations.

Under SMD, prices are first calculated at more than 900 locations, called nodes, throughout New England. Nodes represent places on the system where generators inject power into the system or where demand, or load, withdraws from the system. Each pricing node is related to one or more electrical buses on the power grid. A bus is a specific component of the power system at which generators, loads or the transmission system are connected.

These location-specific prices are made up of three components: energy, congestion and losses. The energy component (or marginal cost) is defined as the cost to serve the next increment of demand at the specific location, or node, that can be produced from the least expensive generating unit in the system that still has available capacity.

However, if the transmission network is congested, the next increment of energy cannot be delivered from the least expensive unit on the system because it would cause overloading on the transmission system or violate transmission operating criteria, such as voltage requirements. The congestion component, or transmission congestion cost, is calculated at a node as the difference between the energy component of the price and the cost of providing the additional, more expensive, energy that can be delivered at that location. The congestion component can also be negative in export-constrained areas where there is more generation than demand.

All transmission systems experience electrical losses, which occur as electricity is sent over transmission lines and accounts for a small percentage of electricity from generators. Nodal prices are adjusted to account for the marginal cost of losses.

If the system was entirely unconstrained and there were no losses, all of the LMPs would be equal and would reflect only the energy price. The lowest possible cost generation could flow to all nodes over the transmission system.

Generators are paid nodal LMPs. SMD market rules assure that generators recover their as-offered, or bid-in costs, including start-up and no load costs for all energy generated. If a generator operates “in-merit,” most of its compensation will be from the energy market, unless the energy revenues are insufficient to cover its costs.

If higher priced generation is dispatched to relieve congestion, the higher cost for this generation is borne by the location in which it occurs through higher LMPs that those locations must pay. In the original market, these costs are absorbed by all load, or demand, across the New England system, regardless of their areas’ contribution to the transmission constraint.

Under SMD, demand, or load, will pay the price calculated for eight load zones, or aggregations of nodes. New England will be divided into the following zones: Maine, New Hampshire, Vermont, Rhode Island, Connecticut, Western/Central Massachusetts, Northeastern Massachusetts (which includes Boston) and Southeastern Massachusetts.

The eight load zones under SMD coincide with the eight reliability regions in New England. Reliability regions reflect the operating characteristics of and the major transmission constraints on the transmission system.

The prices calculated for load zones are a load-weighted average of the nodal prices located within each zone. They still reflect the cost of congestion and represent a true cost for delivering power by location. But because they are an aggregation of nodes, zonal prices are less volatile than nodal prices.

The New England market is likely to move to a nodal pricing system for load and generation. Load zones are being implemented as a temporary means to help market participants transition from the old market design to SMD. To move to a nodal system, more detailed metering of the 900-plus nodes is needed.

In addition to the nodes and zones, a hub has been defined as a single trading location in which the average price is not affected significantly by congestion. It provides a stable pricing location for energy transactions within New England, which serves to enhance transparency and liquidity in the marketplace.

The hub is calculated as an average of the prices at all of the nodes defined of the hub. These nodes are electrically connected and are located in an area that has little congestion within it and therefore has a price that reflects the overall energy price.

LMP is a market-based means of pricing the efficient use of the transmission system when constraints prevent economically priced power from flowing to where it is needed.

In the short-term, LMP improves the efficiency of the wholesale electricity market by ensuring that the cost of congestion is reflected in electricity prices and ensures that the least-cost supply of electricity is delivered while respecting the physical limitation of the transmission network.

In the long-term, LMP helps relieve congestion by promoting efficient investment decisions. Because LMP creates price signals that reflect the locational value of electricity, participants can readily determine areas of congestion and will see the value of investing in generation, transmission and demand response programs.

Appropriately located generation additions, transmission and demand response will increase the competitiveness of the New England market. Greater access to a larger number of competing suppliers helps to enforce market discipline without resorting to administratively applied market power remedies. Increased access to energy from lower-cost generators or imported power will ensure robust, competitive prices. And increased competition from strategically located lower-cost units and demand response will benefit much of New England, as the transmission grid is utilized more efficiently. Ultimately, increased competition should result in a more efficient wholesale energy market with lower costs.


		In $000’s
12/31/2003	Investment in VYNPC	$	1,605
	2004 Earnings		181
	Dividends Received		(174	)
12/31/2004	Ending Balance		1,612


(7,700.00)		Directors stock grants
(9,914.00)		Employee stock grants
(89,650.00)		Options exercised

(107,264.00)		Consolidated Statements of Shareholders’ Equity


2002	$	366,000
2003	$	398,000
2004	$	487,000