May 27, 2009

Mr. H. Christopher Owings
Assistant Director
Securities and Exchange Commission

CF/AD2 Mail Stop 3561

100 F Street, NE
Washington, D.C. 20549-3561

Re:	EQT Corporation
	Form 10-K for Fiscal Year Ended December 31, 2008
	Filed February 20, 2009
	Proxy Statement on Schedule 14A
	Filed March 5, 2009
	Form 10-Q for Fiscal Quarter Ended March 31, 2009
	Filed April 30, 2009
	File No. 1-3551

Dear Mr. Owings:

This letter is in response to your letter dated May 12, 2009 to EQT Corporation (EQT, the Company).  Your letter included seven comments to which the Company responded below.  For your convenience, we have set forth each comment and provided our responses immediately after each comment.

Form 10-K for the Fiscal Year Ended December 31, 2008

Statements of Consolidated Income, page 58

1.SEC COMMENT: We note your response to comment seven from our comment letter dated April 13, 2009 and appreciate the additional information you provided.  Based on your response, we do not object to your presentation of Purchased Gas Costs and the subtotal titled Net Operating Revenues when discussing your Distribution or Midstream segment.  However, it remains unclear to us why these measures are meaningful or appropriate when presenting your consolidated results on the face of your statements of consolidated income.  In this regard, it is unclear to us that subtracting a cost that only applies to certain portions of your business from consolidated revenues and calculating the resulting subtotal is meaningful to your investors.  Please advise.  As part of your response, please tell us

EQT Corporation   I  225 North Shore Drive  I  Pittsburgh, PA   15212-5860

T 412.553.5700   I  F 412.553.5757   I  www.eqt.com

May 27, 2009

Page 2

how you considered prevailing practice for the presentation of Purchased Gas Costs and subtotals similar to Net Operating Revenues by others in your industry.

COMPANY RESPONSE:  The Company notes your comment regarding the presentation of purchased gas cost and the subtotal titled Net Operating Revenue and agrees that the Company should and will continue to present this information in the Distribution and Midstream segment discussions in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the segment footnote, in substantially the same form as presented in the Form 10-K for the year ended December 31, 2008. With regard to the presentation of purchased gas cost on the face of the statement of consolidated income, the Company has reviewed a cross-section of industry peers and finds that the more prevalent practice among this group is to not subtotal net operating revenue but to include purchased gas cost as an operating expense. In future filings, the Company will include the cost of purchased gas in a suitably titled separate line item within operating expenses and will not subtotal net operating revenues on the face of the statement of consolidated income.

Notes to Consolidated Financial Statements

Note 7.  Income Taxes, page 78

2.SEC COMMENT: We see from your response to comment 14 in our letter dated April 13, 2009 that you intend to add disclosures from other parts of your Form 10-K to your tax footnote.  While we think that it will be helpful to investors to provide all of the relevant disclosures in one location within your filing, we remain unclear as to why this taxable loss occurred in 2008, but not in prior years. Please explain to us what occurred in 2008 to cause the intangible drilling costs and accelerated tax depreciation to increase enough to cause so significant a taxable loss, and how this differed from previous years. Please disclose this additional information in future filings as we believe a more detailed explanation would be useful to your readers.

COMPANY RESPONSE:  As disclosed on pages 42-43 of the Capital Resources and Liquidity portion of Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s Form 10-K for the year ended December 31, 2008, the Company’s capital expenditures for drilling and development totaled $701 million, $328 million and $205 million during 2008, 2007 and 2006, respectively.  As a result of this increase in drilling and development expenditures, the intangible drilling cost tax deduction increased to

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approximately $430 million in 2008 compared to $195 million and $145 million in 2007 and 2006, respectively.

Bonus depreciation was authorized by the Economic Stimulus Act of 2008, resulting in an estimated tax deduction in 2008 of approximately $180 million which was not available to the Company in 2007 or 2006.

The combined effect of the increase in the intangible drilling cost deduction and the bonus depreciation deduction resulted in a taxable loss for 2008.  The Company will include similar additional information in future filings.

Note 24.  Natural Gas Producing Activities (Unaudited), page 100

3.SEC COMMENT: We read in your response to comment 17 in our letter dated April 13, 2009 that you currently hold a 1% limited interest in Appalachian Natural Gas Trust, which owns a net profit interest in certain oil and gas properties. We further note from your response that once certain contractual provisions that you call “payout” are met, which you expect to occur in October 2013, you will receive a 99% interest in the Trust.  We have the following additional comments:

·Please describe to us in more detail the terms of the Restated Trust Agreement as it relates to your rights and obligations prior to and after payout. Explain to us the terms of any cash you may receive under this payout. Also explain to us the purpose of structuring the agreement such that you initially hold a small ownership interest but receive a payout, and once certain contractual provisions are met, you no longer receive a payout but own the vast majority of the Trust.

·With reference to your response to the above bullet point, please tell us how you considered the applicability of FIN 46R to your investment in the Trust, and how you concluded that equity method accounting currently is appropriate.

·Given that you do not currently consolidate the Trust and that you currently own only 1% of the Trust, please explain to us why you feel it is appropriate to include the reserves that are expected to be produced from these properties after payout in your reserve disclosures, rather than only including 1% of the Trust’s reserves consistent with your current 1% limited interest.

May 27, 2009

Page 4

COMPANY RESPONSE:  Appalachian NPI, LLC (ANPI) was formed in 2000 for the purpose investing in the Appalachian Natural Gas Trust (the Trust or ANGT).  ANPI raised cash to make its investment in the Trust by selling debt securities.  ANPI is 100% owned by Barclays Bank, PLC and is not consolidated or otherwise reflected in the financial statements of EQT.

ANGT was formed by ANPI and EQT which collectively contributed cash of $297 million as equity in ANGT.  These funds were used by the Trust to purchase a 100% net profit interest in 219.68 Bcfe of production from specific previously drilled wells owned by EQT.  The subject wells and reserves in excess of the 219.68 Bcfe were not transferred to the Trust and continue to be owned by EQT.

ANPI entered into a natural gas commodity swap which hedges forecasted production attributable to ANPI’s share of the net profits interest in the properties owned by ANGT.  The swap began January 1, 2001 and ends February 15, 2013.  ANPI’s share of the net profits of ANGT, net of commodity swap payments, are required to be used to repay the debt issued by ANPI to invest in the Trust.

Currently, the profits and losses of ANGT are allocated 1% to EQT and 99% to ANPI.  Under the Restated Trust Agreement of ANGT, “payout” is the contractual reference for the point of time at which the following will have occurred:

·the swap agreement has matured, been terminated or offset with another swap;

·ANPI has repaid its debt or has received sufficient funds to repay the debt; and

·ANPI has achieved a 20% internal rate of return.

Upon occurrence of “payout,” the allocations of profits and losses of ANGT will flip so that EQT has a 99% interest (rather than a 1% interest) and ANPI has a 1% interest (rather than a 99% interest).  “Payout” does not involve any special or one-time cash payments to EQT or ANPI.

The Company reviewed the provisions of paragraph 5 of FIN 46R and determined that ANGT did not qualify as a variable interest entity (VIE).  At inception, the Trust’s ratio of equity to assets was approximately 100% as there was no debt in the structure.  ANGT continues to have no debt and minimal liabilities, demonstrating the Trust’s ability to finance activities without financial support.  The investors in the Trust retain the direct ability to make decisions about the Trust’s activities as all decisions regarding these activities either

May 27, 2009

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require investor approval or are carried out by a Trustee which can be removed at any time by the investors.  Finally, the investors as a group have both the obligation to absorb the expected losses and the right to receive the expected residual returns of the Trust.  The voting interests in the Trust are proportional with the economic interest of the holders both before and after payout (i.e. the voting interests flip when the economic interests flip).  The Company also determined that even if ANGT was a VIE the Company is not the primary beneficiary and would not be required to consolidate the Trust.

ANGT entered into an agreement with EQT to administer the business and affairs of the Trust.  Thus, despite the fact that the investors in the Trust retain the ability to make decisions about the Trust’s activities, the Company effectively runs the day to day operations of ANGT.  The Company determined that the equity method of accounting was consistent with the provisions of APB 18 because of the Company’s ability to exert significant influence over the operating and financial decisions of ANGT.

The Trust’s net profits interest entitles it to receive 100% of the net profits received from the sale of natural gas and oil from the wells subject to the Trust for the period beginning on January 1, 2001 and ending when the cumulative production from the wells equals 219.68 Bcfe.  The subject wells have estimated reserves in excess of the 219.68 Bcfe which were effectively pre-sold to the Trust.  The Company includes only the reserves beyond this 219.68 Bcfe in its reserve report.  ANGT has no rights in or to these excess reserves; accordingly, the Company determined that it is appropriate to include the excess reserves in the Company’s reserve report.  No portion of the 219.68 Bcfe subject to the Trust is included in the Company’s reserve disclosures because Company determined its 1% interest in ANGT’s net profits interest is immaterial.

Definitive Proxy Statement on Schedule 14A

Compensation Discussion and Analysis, page 25

Components of the Company Compensation Program, page 34

Annual Incentives, page 35

Operational Component, page 36

4.SEC COMMENT:  We note your response to comment 28 from our letter dated April 13, 2009.  Please discuss the pre-set measurable criteria and the level of performance actually achieved as it relates to the calculation of the performance multiple.

May 27, 2009

Page 6

COMPANY RESPONSE:  Exhibit A hereto identifies the pre-set measurable criteria and the level of performance actually achieved for each of the twenty-five business unit value drivers constituting the 2008 operational component of the incentive pool size calculation.  The operational component is one of three elements used to calculate the size of the annual incentive pool for headquarters employees.  As described on page 38 of the Company’s 2009 proxy statement, the size of the annual incentive pool is one of a number of factors considered by the Compensation Committee in exercising its downward discretion after determining the annual incentives authorized for the executive officers under the Executive STIP. While the operational component may be directionally indicative of executive officer annual incentives, it is not determinative.  Both quantitatively and in light of Committee discretion, the individual business unit value drivers constituting the operational component are not material.

Form 10-Q for the Quarter Ended March 31, 2009

Notes to Consolidated Financial Statements

Note C.  Derivative Instruments, page 9

5.SEC COMMENT: Please explain to us why all of your asset derivatives and liability derivatives are classified as current assets and current liabilities in your Condensed Consolidated Balance Sheets given your statements at the bottom of page 10 that your current hedge position extends through 2015.

COMPANY RESPONSE:  As SFAS No. 133 does not provide guidance on the statement of financial position location for derivative assets and liabilities, the Company considered the nature of the derivative portfolio in determining the proper financial statement presentation.  Based on the Company’s ability to net settle the derivatives at any time, the Company determined that a current classification was appropriate.  The Company has periodically net settled derivatives for various operational reasons; for example, as disclosed on page 10 of the Company’s Form 10-Q for the quarter ended March 31, 2009, the Company terminated certain collar agreements scheduled to mature during the period 2010 through 2012 during the first quarter of 2009.

Historically, the Company’s derivative portfolio has been in a net liability position which rendered current classification conservative.  As a result of a decline in commodity prices, the Company’s derivative portfolio was in a net asset position at March 31, 2009 and at December 31, 2008.  The Company considered this change in position and determined the current presentation was still appropriate in light of the ability to net settle discussed above and the fact that approximately 65% of the derivative asset reported in the Consolidated Balance Sheet as of

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March 31, 2009 is related to derivative agreements scheduled to mature within the next 12 months.  The Company will continue to assess the balance sheet classification of its derivative assets and liabilities in connection with future filings and will continue to provide adequate disclosure about the duration of the derivative portfolio.

Item 2.  Management’s Discussion and Analysis of Financial Condition and. . . page 19

EQT Production, page 21

Results of Operations, page 21

6.SEC COMMENT: Please explain to us where or how you discussed the changes in your results from interest expense and income tax expense, as we note that your interest expense increased significantly from the prior year period and your effective tax rate increased approximately 3% from the prior year period. In future filings please ensure that you analyze changes to all components of consolidated net income, including those items that are not included in your segmental measure of profit or loss.

COMPANY RESPONSE:  As disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 43 of the Company’s Form 10-K for the year ended December 31, 2008, and on page 16 of the Company’s Form 10Q for the quarter ended March 31, 2008, on March 13, 2008 the Company completed a public offering of $500 million in aggregate principal amount of 6.5% Senior Notes due April 1, 2018.  The increase in interest expense for the quarter ended March 31, 2009 compared to the quarter ended March 31, 2008 is primarily the result of a full quarter of interest expense incurred on these Senior Notes in 2009.

As disclosed on pages 14-15 of the Company’s Form 10-Q for the quarter ended March 31, 2008, during the first quarter of 2008 the Company recorded a tax benefit to reflect an overall decrease in the Company’s expected deferred tax liability as a result of a change in West Virginia’s corporate net income tax rates.  The Company’s effective income tax rate for the three months ending March 31, 2008 was 36.2% while the Company estimated the annual effective income tax rate for 2008 to be approximately 38.6% at March 31, 2008.  The increase in the Company’s effective tax rate for the quarter ended March 31, 2009 compared to the quarter ended March 31, 2008 is primarily the result of this discrete item in 2008.

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In future filings the Company will analyze significant changes to all components of consolidated net income; changes in line items not included in the segment disclosures will be discussed in the Corporate Overview portion of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Capital Resources and Liquidity, page 28

7.SEC COMMENT: Please explain to us what you mean in the second to last paragraph on page 28 where you say that capital expenditures increased primarily due to spending in the first quarter of 2009 on horizontal wells that were spud in the fourth quarter of 2008.  Specifically, we would like you to explain to us and clarify in future filings what spud means and why it would result in increased capital expenditures during the following quarter.

COMPANY RESPONSE:  When the Company discloses the number of wells drilled, the counts are based on commencement of drilling operations, which is referred to as the well being “spud.”  Based on the Company’s historical experience, there is a 35 and 65 day lag, respectively, between when a vertical well or a horizontal well is “spud” and when it is turned-in-line for production to begin.  During this 35-65 day period, the majority of a well’s total capital expenditures are incurred on drilling and completing the well and placing the well in production.  As the lag for the wells drilled in the fourth quarter spans between the fourth quarter of that year and the first quarter of the subsequent year and the horizontal well counts increased during the fourth quarter 2008 compared to the fourth quarter 2007, the capital expenditures for drilling and development increased during the first quarter of 2009 when compared to the first quarter 2008 despite the fact that approximately the same number of wells were spud during the two first quarter periods.  This comment was provided to clarify that the increase in capital spending period-over-period was not the result of an increase in the cost per well.

In future filings, where it has a significant impact on the level of capital expenditures, the Company will more clearly describe the expenditures related to wells for which drilling operations were started in one period and completed in a subsequent period.

Please feel free to contact Terri Bone, Vice President and Corporate Controller, at 412-553-5785 with questions regarding the Company’s financial statements and related matters, including Form 10-K and Form 10-Q.  You may contact Kim Sachse, Deputy General Counsel, at 412-553-5758 with questions regarding the Company’s Proxy statement and Kim Sachse or me at 412-553-5863 with any other questions.

May 27, 2009

Page 9

Sincerely,

/s/ Philip P. Conti

Philip P. Conti

Senior Vice President,

Chief Financial Officer

cc:       Lewis B. Gardner, Vice President and General Counsel

Exhibit A

Production Business
Value Driver	Actual Performance*	Final Pool Multiple
Financial
Earnings Before Interest, Taxes, Depreciation, Amortization and Exploration Expenses (EBITDAX) for production, midstream and commercial businesses at a fixed natural gas price of $8.00.	Exceeds	1.0
Production Volumes
Two components:
Component 1: Actual production volumes.	Component 1: Exceeds	.50
Component 2: December average production per day.	Component 2: Exceeds
Safety
Comply with the Production Safety Plan.	Successful plus	0.25
Drilling
Three components:
Component 1: Approval to drill designated number of well equivalents per board approved 2009 capital budget plan. Each vertical well counts as one well equivalent and each horizontal well counts as three well equivalents.	Component 1: Successful plus	.50
Component 2: Develop inventory back-up of permitted locations at year end.	Component 2: Stretch
Component 3: Reduce drilling costs per well.	Component 3: Stretch

* Actual performance ratings include:

Below successful

Successful

Exceeds

Stretch

1

Production Business
Value Driver	Actual Performance	Final Pool Multiple
Development
Three components:
Component 1: Present multi-year corridor development plan, including a 5 year schedule.	Component 1: Successful	.40
Component 2: Lease additional acreage.	Component 2: Successful
Component 3: Present at least two joint venture/new business opportunities.	Component 3: Exceeds
Exploration
Three components:
Component 1: Exploratory drilling.	Component 1: Exceeds	.15
Component 2: Identification of prospect areas.	Component 2: Successful
Component 3: Begin seismic permitting.	Component 3: Stretch

2

Midstream Business
Value Driver	Actual Performance	Final Pool Multiple
Financial
Same as Production Business Segment Financial Value Driver.  See above.	Same as Production Business Segment Financial Value Driver. See above.	1.0
Production Volumes
Same as Production Business Segment Production Volumes Value Driver. See above.	Same as Production Business Segment Production Volumes Value Driver. See above.	.50
Safety
Comply with the Midstream Safety Plan.	Successful plus	0.25

3

Midstream Business Segment
Value Driver	Actual Performance	Final Pool Multiple
Infrastructure Asset Planning Execution
Present multi-year corridor development plan (excluding Mayking Corridor), including a five year schedule.	Exceeds plus	.40
Major Project Execution
Component 1: Mayking Corridor Phase I completed.	Component 1: Exceeds	.20
Component 2: Pipeline Project Land Phase II completed.	Component 2: Exceeds
Construction Projects
Implement compressor and pipeline projects per authorization for expenditure and turned-in-line schedule.	Exceeds plus	.15
Midstream Metrics
Component 1: Develop performance metrics for new departments.	Component 1: Stretch	.20
Component 2: Track all metrics.	Component 2: Stretch
Staffing
Component 1: Manager response to applicant lists with resumes provided by HR.	Component 1: Stretch	.10
Component 2: Making hiring decisions after interviews	Component 2: Stretch

4

Commercial Function
Value Driver	Actual Performance	Final Pool Multiple
Financial
Same as Production Business Segment Financial Value Driver. See above.	Same as Production Business Segment Financial Value Driver. See above.	1.0
Production Volumes
Same as Production Business Segment Production Volumes Value Driver. See above.	Same as Production Business Segment Production Volumes Value Driver. See above.	.50
Safety
Comply with the Corporate Safety Plan	Successful	.00
Commercial Metrics
Develop metrics for each area of commercial focus: asset management, equity sales, liquids, producer services and retail.	Stretch	.50
Liquids Business Strategy
Develop and present comprehensive liquids strategy to executive management and begin implementation of approved strategy.	Exceeds	.35
Commercial Organization
Continue to define commercial organization and present to executive management team; begin implementation of hiring for new organizational focus.	Successful	.00

5

Distribution Business
Value Driver	Actual Performance	Final Pool Multiple
Financial
Earnings Before Interest, Taxes, Depreciation, and Amortization (EBITDA) for Distribution business segment.	Successful	.99
Safety
Comply with the Production Safety Plan.	Successful plus	0.15
Operational Effectiveness
Component 1: Develop work management plan that includes scope, business requirements, and implementation schedule.	Component 1: Exceeds	.40
Component 2: Re-design leak survey and corrosion management processes.	Component 2: Exceeds
Customer Satisfaction
Improve customer service by completing customer initiatives including increasing web/portal functionality, developing/executing on Equitable Gas Company community involvement plan, and expanding customer satisfaction initiatives to field process.	Exceeds	.20
Rate Case
Develop rate case strategy providing rate design alternatives.  Make all appropriate filings.	Successful	.25

Multiple Calculation

Average of Production,		7.95	X .85 = 2.3	1.99 X .15 = .30
Midstream and Commercial		3
weighted at 85% and Distribution weighted at 15%
Multiple	2.3 + .30 = 2.60
Operational Multiple (weighting – 40%)	2.6 X .40 = 1.0

6