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SEC LETTER

 May 13, 2005

 VIA FACSIMILE

 Mr. H. Christopher Owings

 Mr. Albert Yarashus

 Mr. Robert Babula

 Securities and Exchange Commission

 Division of Corporation Finance

 Mail Stop 0308

 450 Fifth Street, N.W.

 Washington, DC 20549-0308

Fax:
202-772-9202

Re:
GREEN MOUNTAIN POWER CORPORATION

Form 10-K for the year ended December 31, 2004 filed March 29, 2005

File No. 1-8291

 Dear Messrs. Owings, Yarashus and Babula:

 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.

 Form 10-K

 General

 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.

 RESPONSE:

 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

 H. Christopher Owings

 Albert Yarashus

 Robert Babula

 May
13, 2005

 Page 2 of 12

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.

 RESPONSE:

 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.

 Financial Statements

 General

 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.

 RESPONSE:

 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.

 Business

 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.

 H. Christopher Owings

 Albert Yarashus

 Robert Babula

 May
13, 2005

 Page 3 of 12

 RESPONSE:

 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:

In $000’s

 12/31/2003

    Investment in VYNPC

$
1,605

    2004 Earnings

181

    Dividends Received

(174
)

 12/31/2004

    Ending Balance

1,612

 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.

 RESPONSE:

 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.

 H. Christopher Owings

 Albert Yarashus

 Robert Babula

 May
13, 2005

 Page 4 of 12

 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.

 Results of Operations – Transmission Expenses

 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.

 RESPONSE:

 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

 H. Christopher Owings

 Albert Yarashus

 Robert Babula

 May
13, 2005

 Page 5 of 12

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.

 RESPONSE:

 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

 H. Christopher Owings

 Albert Yarashus

 Robert Babula

 May
13, 2005

 Page 6 of 12

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 w