Edgar Filing: EQT Corp

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011

or

o	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 1-3551

EQT CORPORATION

(Exact name of registrant as specified in its charter)

PENNSYLVANIA		25-0464690
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania		15222
(Address of principal executive offices)		(Zip code)

(412) 553-5700

(Registrant’s telephone number, including area code:)

(Former name, former address and former fiscal year, if changed since last report)

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. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer x Accelerated Filer o

Non-Accelerated Filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of June 30, 2011, 149,458,779 shares of common stock, no par value, of the registrant were outstanding.

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EQT CORPORATION AND SUBSIDIARIES

Index

		Page No.


Part I. Financial Information:

Item 1.	Financial Statements (Unaudited):

	Statements of Consolidated Income for the Three and Six Months Ended June 30, 2011 and 2010	3

	Statements of Condensed Consolidated Cash Flows for the Six Months Ended June 30, 2011 and 2010	4

	Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010	5 – 6

	Notes to Condensed Consolidated Financial Statements	7 – 17

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18 – 29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30 – 31

Item 4.	Controls and Procedures	32

Part II. Other Information:

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 6.	Exhibits	33

Signature		34

Index to Exhibits		35

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EQT CORPORATION AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(Thousands, except per share amounts)
Operating revenues	$	349,000	$	257,515	$	804,671	$	694,155

Operating expenses:
Purchased gas costs	21,459		15,969		119,673		129,931
Operation and maintenance	30,586		35,774		55,641		70,292
Production	19,765		16,532		35,876		33,153
Exploration	1,198		1,078		2,573		2,413
Selling, general and administrative	40,936		44,416		79,827		83,628
Depreciation, depletion and amortization	81,886		65,217		160,284		127,096
Total operating expenses	195,830		178,986		453,874		446,513

Operating income	153,170		78,529		350,797		247,642
Gain on disposition	–		–		22,785		–
Other income	18,046		2,573		24,850		5,627
Interest expense	33,287		34,080		66,139		68,214

Income before income taxes	137,929		47,022		332,293		185,055
Income taxes	50,175		17,022		122,284		66,990
Net income	$	87,754	$	30,000	$	210,009	$	118,065

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	149,444		147,575		149,347		140,440
Net income	$	0.59	$	0.20	$	1.41	$	0.84
Diluted:
Weighted average common shares outstanding	150,111		148,289		150,034		141,270
Net income	$	0.58	$	0.20	$	1.40	$	0.84
Dividends declared per common share	$	0.22	$	0.22	$	0.44	$	0.44

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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EQT CORPORATION AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Six Months Ended June 30,
	2011		2010
	(Thousands)
Cash flows from operating activities:
Net income	$	210,009	$	118,065
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	160,284		127,096
Deferred income taxes	103,938		66,431
Gain on disposition	(22,785)		–
Other income	(24,850)		(5,627)
Equity award expense	10,868		6,752
Provision for losses on accounts receivable	1,704		4,061
Unrealized (gains) losses on derivative financial instruments	(1,454)		822
Changes in operating assets and liabilities:
Inventory	28,358		38,918
Accounts receivable and unbilled revenues	59,144		70,680
Accounts payable	(27,076)		(53,527)
Derivative instruments at fair value, net	9,126		5,135
Federal income tax carryback refund	–		121,463
Other assets and liabilities	(44,682)		(23,690)
Net cash provided by operating activities	462,584		476,579

Cash flows from investing activities:
Additions to property, plant and equipment	(544,911)		(522,860)
Dividend from Nora Gathering, LLC	18,500		–
Proceeds from sale of available-for-sale securities	29,947		–
Proceeds from disposition	230,525		–
Investment in available-for-sale-securities	–		(750)
Net cash used in investing activities	(265,939)		(523,610)

Cash flows from financing activities:
Dividends paid	(65,795)		(61,589)
Proceeds from issuance of common stock	–		537,239
Decrease in short-term loans	(53,650)		(5,000)
Proceeds from exercises under employee compensation plans	2,025		1,982
Net cash (used in) provided by financing activities	(117,420)		472,632

Net increase in cash and cash equivalents	79,225		425,601
Cash and cash equivalents at beginning of period	–		–
Cash and cash equivalents at end of period	$	79,225	$	425,601

Cash paid (received) during the period for:
Interest, net of amount capitalized	$	64,703	$	68,214
Income taxes	$	2,505	$	(124,266)

See discussion of non cash transactions in Notes B and K.
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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EQT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	June 30, 2011		December 31, 2010
	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	79,225	$	–
Accounts receivable (less accumulated provision for doubtful accounts June 30, 2011 and December 31, 2010: $18,180 and $18,335)	131,567		156,709
Unbilled revenues	7,061		38,361
Inventory	110,382		137,853
Derivative instruments, at fair value	211,986		225,339
Assets held for sale	201,852		207,678
Prepaid expenses and other	57,312		62,000
Total current assets	799,385		827,940

Equity in nonconsolidated investments	139,234		191,265

Property, plant and equipment	8,071,330		7,689,025
Less: accumulated depreciation and depletion	1,849,063		1,778,934
Net property, plant and equipment	6,222,267		5,910,091

Investments, available-for-sale	–		28,968
Regulatory assets	98,962		100,949
Other assets	33,241		39,225
Total assets	$	7,293,089	$	7,098,438

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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EQT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	June 30, 2011		December 31, 2010
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	24,988	$	6,000
Short-term loans	–		53,650
Accounts payable	187,419		212,134
Derivative instruments, at fair value	97,531		106,721
Other current liabilities	162,097		218,479
Total current liabilities	472,035		596,984

Long-term debt	1,988,380		1,943,200
Deferred income taxes and investment tax credits	1,387,673		1,274,888
Unrecognized tax benefits	36,748		41,451
Pension and other post-retirement benefits	40,271		44,135
Other credits	131,427		119,084
Total liabilities	4,056,534		4,019,742

Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares;
(shares issued June 30, 2011 and December 31, 2010: 175,685 and 175,684)	1,725,398		1,723,898
Treasury stock, at cost: (shares at June 30, 2011 and December 31, 2010: 26,226 and 26,531)	(473,543)		(479,072)
Retained earnings	1,939,980		1,795,766
Accumulated other comprehensive income	44,720		38,104
Total common stockholders’ equity	3,236,555		3,078,696
Total liabilities and stockholders’ equity	$	7,293,089	$	7,098,438

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A. Financial Statements

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of June 30, 2011, and the results of its operations and cash flows for the three and six month periods ended June 30, 2011 and 2010. Certain previously reported amounts have been reclassified to conform to the current year presentation. In this Form 10-Q, references to “we,” “us,” “our,” “EQT,” “EQT Corporation” and the “Company” refer collectively to EQT Corporation and its consolidated subsidiaries.

The balance sheet at December 31, 2010 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and storage businesses and the volatility of commodity prices, the interim statements for the three and six month periods ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

For further information, refer to the consolidated financial statements and footnotes thereto included in EQT Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 18 of this document.

B. Segment Information

Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.

The Company reports its operations in three segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids (NGLs) and a limited amount of crude oil in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, transportation, storage and marketing activities of the Company. Distribution’s operations are primarily composed of the state-regulated natural gas distribution activities of the Company.

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Actual headquarters’ expenses in excess of budget, which are primarily related to incentive compensation and administrative costs, are not allocated to the operating segments.

Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues from external customers:				(Thousands)
EQT Production	$	196,810		$	119,028		$	369,852		$	263,391
EQT Midstream	131,201			136,995			272,863			291,591
Distribution	69,100			63,349			264,191			285,604
Less: intersegment revenues (a)	(48,111		)	(61,857		)	(102,235		)	(146,431		)
Total	$	349,000		$	257,515		$	804,671		$	694,155
Operating income:
EQT Production	$	99,759		$	41,029		$	182,088		$	114,146
EQT Midstream	52,243			41,714			118,876			94,405
Distribution	8,928			4,290			62,295			51,709
Unallocated expenses (b)	(7,760		)	(8,504		)	(12,462		)	(12,618		)
Total	$	153,170		$	78,529		$	350,797		$	247,642

Reconciliation of operating income to net income:

Gain on disposition	$	–	$	–	$	22,785	$	–
Other income	18,046		2,573		24,850		5,627
Interest expense	33,287		34,080		66,139		68,214
Income taxes	50,175		17,022		122,284		66,990
Net income	$	87,754	$	30,000	$	210,009	$	118,065

	June 30,		December 31,
	2011		2010
	(Thousands)
Segment Assets:
EQT Production	$	4,520,399	$	3,979,676
EQT Midstream	1,854,299		2,076,485
Distribution	788,061		848,419
Total operating segments	7,162,759		6,904,580
Headquarters assets, including cash and short-term investments	130,330		193,858
Total assets	$	7,293,089	$	7,098,438

(a) Intersegment revenues primarily represent natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and both EQT Production and Distribution.

(b) Unallocated expenses primarily consist of certain incentive compensation and administrative costs in excess of budget that are not allocated to the operating segments.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010

	(Thousands)
Depreciation, depletion and amortization:
EQT Production	$	61,899		$	43,468	$	119,733		$	84,378
EQT Midstream	14,296			15,611		29,004			30,535
Distribution	5,923			6,016		11,880			12,010
Other	(232		)	122		(333		)	173
Total	$	81,886		$	65,217	$	160,284		$	127,096

Capital expenditures:
EQT Production (a)	$	317,906		$	483,656	$	544,878		$	662,071
EQT Midstream	46,500			44,293		75,605			78,980
Distribution	8,811			7,750		15,030			11,725
Other	881			321		2,013			771
Total	$	374,098		$	536,020	$	637,526		$	753,547

(a) Capital expenditures in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction discussed in Note K and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010.

C. Derivative Instruments

Natural Gas Hedging Instruments

The Company’s primary market risk exposure is the volatility of future prices for natural gas and natural gas liquids, which can affect the operating results of the Company primarily through EQT Production and storage, marketing and other activities at EQT Midstream. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Put option contracts provide protection from dropping prices and require the counterparty to pay the Company if the index price falls below the contract price. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on short or long-term debt.

The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income, net of tax, and is subsequently reclassified into operating revenues in the same period or periods during which the forecasted transaction affects earnings. For a derivative instrument that has been designated and qualifies as a fair value hedge, the change in the fair value for the instrument is recognized as a portion of operating revenues in the Statements of Consolidated Income each period. In addition, the change in the fair value of the hedged item (natural gas inventory) is recognized as a portion of operating revenues in the Statements of Consolidated Income. The Company has elected to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges. Any hedging ineffectiveness and any change in fair value of derivative instruments that have not been designated as hedges, are recognized as a portion of operating revenues in the Statements of Consolidated Income each period.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Exchange-traded instruments are generally settled with offsetting positions. Over the counter (OTC) arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Condensed Consolidated Cash Flows.

A portion of the derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. A portion of the derivative commodity instruments used by the Company to hedge its exposure to adverse changes in the market price of natural gas stored in the ground have been designated and qualify as fair value hedges. The current hedge position extends through 2015. See “Commodity Risk Management” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for further details of the Company’s hedged position.

In addition, the Company enters into a limited amount of energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Company also has a limited amount of other derivative instruments not designated as hedges. In 2008, the Company effectively settled certain derivative commodity swaps scheduled to mature during the period 2010 through 2013 by de-designating the swaps and entering into directly counteractive swaps. These transactions resulted in offsetting positions which are the majority of the derivative asset and liability balances not designated as hedging instruments.

Substantially all derivatives recognized in the balance sheet and used in hedging relationships are commodity contracts. All derivative instrument assets and liabilities are reported in the Condensed Consolidated Balance Sheets as derivative instruments, at fair value. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can effectively net settle its derivative instruments at any time.

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010

	(Thousands)
Derivatives designated as cash flow hedges
Amount of gain (loss) recognized in other comprehensive income (OCI) (effective portion), net of tax	$	33,253	$	(16,293	)	$	37,452		$	61,226
Amount of gain reclassified from accumulated OCI into income (effective portion), net of tax (a)	$	9,918	$	14,111		$	26,823		$	28,218
Amount of gain (loss) recognized in income (ineffective portion) (b)	$	364	$	(2,414	)	$	(261	)	$	(613	)

Derivatives designated as fair value hedges (c)
Amount of gain (loss) recognized in income for fair value commodity contracts	$	1,363	$	–		$	(533	)	$	–
Fair value gain recognized in income for inventory designated as hedged item	$	60	$	–		$	1,693		$	–

Derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in income	$	856	$	212		$	(823	)	$	89

(a) Includes $0 and $2.6 million for the three and six month periods ended June 30, 2010 of unrealized hedge gains reclassified into earnings to offset lower of cost or market adjustments on hedged items. The Company also had an immaterial amount of OCI reclassified to interest expense related to an interest rate swap on long-term debt.

(b) No amounts have been excluded from effectiveness testing of cash flow hedges.

(c) For the three months ended June 30, 2011, the net impact on operating revenues consisted of a $2.1 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.7 million loss due to changes in basis. For six months ended June 30, 2011, the net impact on operating revenues consisted of a $1.5 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.3 million loss due to changes in basis.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	June 30, 2011		December 31, 2010
	(Thousands)
Asset derivatives
Derivatives designated as hedging instruments	$	138,004	$	141,834
Derivatives not designated as hedging instruments	73,982		83,505
Total asset derivatives	$	211,986	$	225,339

Liability derivatives
Derivatives designated as hedging instruments	$	3,104	$	12,097
Derivatives not designated as hedging instruments	94,427		94,624
Total liability derivatives	$	97,531	$	106,721

The net fair value of derivative instruments decreased during the first six months of 2011 primarily as a result of settlements, partially offset by the positive net fair value of derivatives executed in the first six months of 2011 and a decrease in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 240 Bcf and 181 Bcf as of June 30, 2011 and December 31, 2010, respectively, and are primarily related to natural gas swaps and collars. The open positions at June 30, 2011 had maturities extending through December 2015. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as fair value hedges totaled 6 Bcf as of June 30, 2011. No derivative commodity instruments were designated as fair value hedges as of December 31, 2010.

The Company had net deferred gains of $75.9 million and $65.2 million in accumulated other comprehensive income, net of tax, as of June 30, 2011 and December 31, 2010, respectively, associated with the effective portion of the change in fair value of its derivative instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $34.8 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income, net of tax, as of June 30, 2011 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions.

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that New York Mercantile Exchange (NYMEX) traded future contracts have minimal credit risk because the Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.

The Company utilizes various processes and analyses to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.

When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposit in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010, respectively.

When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. The Company records such deposits as current assets. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

contract and are subject to change at the exchanges’ discretion. The Company recorded a current asset of $1.6 million as of June 30, 2011 and a current liability of $0.5 million as of December 31, 2010 for such deposits in its Condensed Consolidated Balance Sheets.

Certain of the Company’s derivative instrument contracts provide that if one or more of the Company’s credit ratings are lowered below investment grade, additional collateral must be deposited with the counterparty. The additional collateral can be up to 100% of the derivative liability. As of June 30, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $4.6 million, for which the Company had no collateral posted on June 30, 2011. If the Company’s credit rating had been downgraded below investment grade on June 30, 2011, the Company would have been required to post additional collateral of $4.6 million in respect of the liability position. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s unsecured medium-term debt was rated BBB by Standard & Poor’s Rating Services (S&P), Baa1 by Moody’s Investor Services (Moody’s) and BBB by Fitch Ratings Service (Fitch) at June 30, 2011. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Fitch and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade.

D. Investments, Available-For-Sale

As of December 31, 2010 the investments classified by the Company as available-for-sale consisted of $29.0 million of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures.

During the six month period ended June 30, 2011, the Company sold all of the available-for-sale securities for proceeds of $29.9 million which resulted in gross realized gains of $8.5 million, $4.9 million of which was reclassified from accumulated other comprehensive income. The Company uses the average cost method to determine the cost of securities sold.

During the six month period ended June 30, 2010, the Company purchased additional securities with a cost basis totaling $0.8 million.

E. Fair Value Measurements

The Company records its financial instruments, principally derivative commodity instruments, at fair value in its Condensed Consolidated Balance Sheets. The Company has an established process for determining fair value which is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk free instrument. The Company also considers credit default swaps rates where applicable.

The Company has categorized its assets and liabilities recorded at fair value into a three-level hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities included in Level 1 include the Company’s futures contracts. Assets and liabilities in Level 2 include the majority of the Company’s swap agreements and assets in Level 3 include the Company’s collar and option agreements and an insignificant portion of the Company’s swap agreements. Since the adoption of fair value accounting, the Company has not made any changes to its classification of assets and liabilities in each category.

The fair value of assets and liabilities included in Level 2 is based on industry models that use significant observable inputs, including NYMEX forward curves and LIBOR-based discount rates. Swaps included in Level 3 are valued using internal models that use significant unobservable inputs; these internal models are validated each period with non-binding broker price quotes. The Company has not experienced significant differences between internally calculated values and broker price quotes. Collars and options included in Level 3 are valued using internal models calculated with market derived volatilities. The Company uses NYMEX forward curves to value futures, NYMEX swaps, collars and options. The NYMEX forward curves are validated to external sources at least monthly.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The following assets and liabilities were measured at fair value on a recurring basis during the period:

			Fair value measurements at reporting date using
Description	June 30, 2011		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(Thousands)
Assets
Derivative instruments, at fair value	$	211,986	$	2,698	$	107,316	$	101,972
Total assets	$	211,986	$	2,698	$	107,316	$	101,972

Liabilities
Derivative instruments, at fair value	$	97,531	$	3,339	$	94,192	$	–
Total liabilities	$	97,531	$	3,339	$	94,192	$	–

	Fair value measurements using significant unobservable inputs (Level 3)

	Derivative instruments, at fair value, net
	(Thousands)
Balance at January 1, 2011	$	116,672
Total gains or losses:
Included in earnings	14
Included in other comprehensive income	11,020
Settlements	(25,734)
Transfers in and/or out of Level 3	–
Balance at June 30, 2011	$	101,972

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held as of June 30, 2011	$	–

The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments.

The estimated fair value of long-term debt on the Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was approximately $2 billion. The fair value was estimated using the Company’s established fair value methodology based on quoted rates reflective of the remaining maturity and risk.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

F. Comprehensive Income (Loss)

Total comprehensive income (loss), net of tax, was as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Thousands)
Net income	$	87,754		$	30,000		$	210,009		$	118,065
Other comprehensive (loss) income:
Net change in cash flow hedges	23,363			(30,374		)	10,688			33,069
Unrealized (loss) gain on investments, available-for-sale	(2,925		)	(2,354		)	(4,896		)	(1,499		)
Pension and other post-retirement benefit plans	413			403			824			806
Total comprehensive income (loss)	$	108,605		$	(2,325	)	$	216,625		$	150,441

The components of accumulated other comprehensive income, net of tax, are as follows:

	June 30,			December 31,
	2011			2010
	(Thousands)
Net unrealized gain from hedging transactions	$	75,702		$	65,014
Unrealized gain on available-for-sale securities	–			4,896
Pension and other post-retirement benefits adjustment	(30,982		)	(31,806		)
Accumulated other comprehensive income	$	44,720		$	38,104

G. Income Taxes

The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations and any other separately reported net income items, such as discontinued operations.

The Company’s effective income tax rate for the six months ending June 30, 2011 was 36.8%. The Company currently estimates the 2011 annual effective income tax rate to be approximately 36.8%. The estimated annual effective income tax rate as of June 30, 2010 was 36.2%. The increase in the expected annual effective tax rate from 2010 is primarily the result of increased state income taxes partially offset by a decrease in the reserves for uncertain tax positions.

There were no material changes to the Company’s methodology or for unrecognized tax benefits during the six months ended June 30, 2011.

During the second quarter of 2011, the Company finalized a settlement with the Internal Revenue Service (IRS) relating to its research and experimentation tax credits claimed from 2001 through 2005. Except for claims related to tax losses carried back to those years, the consolidated federal income tax liability of the Company has been settled with the IRS through 2005. During the second quarter of 2010 the IRS began its audit and review of the Company’s income tax filings for the 2006 through 2009 years. The Company also is the subject of various state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions.

The Worker, Homeownership and Business Assistance Act of 2009 extended the applicability of the tax net operating loss carryback provision from 2 years to 5 years for either the 2008 or 2009 tax year. The Company elected to carryback its 2009 tax operating loss under this new law and received a refund of $121.5 million from the IRS during the second quarter of 2010. The net operating losses were primarily generated from intangible drilling costs (IDC) for the Company’s drilling program that are deducted currently for tax purposes and from accelerated tax depreciation for expansion of the Company’s midstream business.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

H. Short-Term Loans

As of June 30, 2011, the Company had no loans or letters of credit outstanding under its revolving credit facility. As of December 31, 2010, the Company had outstanding under the revolving credit facility loans of $53.7 million and an irrevocable standby letter of credit of $23.5 million. Commitment fees averaging approximately 5.0 basis points in the second quarter of 2011 and 2.0 basis points in the second quarter of 2010 were paid to maintain credit availability under the revolving credit facility.

The maximum amount of outstanding short-term loans at any time during the six months ended June 30, 2011 and 2010 was $104.0 million and $139.7 million, respectively. The average daily balance of short-term loans outstanding during the six months ended June 30, 2011 and 2010 was approximately $11.1 million and $26.6 million, respectively, at weighted average annual interest rates of 1.81% and 0.86%, respectively.

I. Long-Term Debt

	June 30, 2011		December 31, 2010
	(Thousands)
7.76% notes, due 2011 thru 2016	$	64,168	$	–
5.15% notes, due November 15, 2012	200,000		200,000
5.00% notes, due October 1, 2015	150,000		150,000
5.15% notes, due March 1, 2018	200,000		200,000
6.50% notes, due April 1, 2018	500,000		500,000
8.13% notes, due June 1, 2019	700,000		700,000
7.75% debentures, due July 15, 2026	115,000		115,000
Medium-term notes:
8.5% to 9.0% Series A, due 2011 thru 2021	46,200		46,200
7.3% to 7.6% Series B, due 2013 thru 2023	30,000		30,000
7.6% Series C, due 2018	8,000		8,000
	2,013,368		1,949,200
Less debt payable within one year	24,988		6,000
Total long-term debt	$	1,988,380	$	1,943,200

During the second quarter of 2011 the Company assumed 7.76% Guaranteed Senior Notes due August 31, 2011 through February 28, 2016 in the aggregate principal amount of $57.1 million in a non-cash transaction. See Note K.

The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s long-term indebtedness.

Aggregate maturities of long-term debt are $15.5 million in 2011, $219.3 million in 2012, $23.2 million in 2013, $11.2 million in 2014 and $166.0 million in 2015.

J. Recently Issued Accounting Standards

Presentation of Comprehensive Income

In June 2011, the Financial Accounting Standards Board (FASB) issued a standard update to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the impact this standard will have on its disclosures.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Disclosures about Fair Value Measurements

In May 2011, the FASB issued an amendment intended to enhance the fair value disclosure requirements to result in common fair value measurement in U.S. generally accepted accounting principles (GAAP) and International Financial Reporting Standards (IFRS). The amendments are to be applied prospectively, and are effective during interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the impact this standard will have on its financial statements.

K. Acquisitions

In December 2000, the Company sold a net profits interest (NPI) in certain producing properties located in the Appalachian Basin to a trust in exchange for approximately $298 million. The NPI entitled the trust to receive 100% of the net profits received from the sale of natural gas and oil from the producing properties until cumulative production from such properties reached a specified amount. The Company owned the Class B interest in the trust, entitling it to specified percentages of any available cash from the trust over time. An outside party, Appalachian NPI, LLC (ANPI), owned the Class A interest in the trust.

Effective May 4, 2011, the Company, through EQT Production Company, acquired the Class A interest in the trust thereby acquiring 100% of the NPI associated with the producing properties (the ANPI transaction). As part of the consideration for the acquired assets, the Company entered into a discounted natural gas sales agreement with ANPI and assumed a swap held by ANPI on the trust’s sales of natural gas.

In addition, the Company assumed 7.76% Guaranteed Senior Notes due August 31, 2011 through February 28, 2016 in the aggregate principal amount of $57.1 million. The notes had a fair value of $64.2 million.

Under U.S. GAAP, the ANPI transaction was a business combination achieved in stages because EQT owned an equity interest in the trust prior to the transaction. As required by the relevant accounting standard, the Company revalued its existing equity investment in the trust at fair value on the date of the acquisition and recorded a gain of $10.1 million included in other income on the Statements of Consolidated Income. The fair value was determined using an internal model; significant inputs to the calculation included publicly available forward price curves, expected production volumes and operating costs, as well as Company-determined risk adjusted discount rates which were based on publicly available debt and equity risk premiums.

As a result of this transaction, the Company recorded an increase in oil and gas properties of $140.6 million resulting from the removal of the post-revaluation $48.0 million equity investment in the trust from its books and a net $92.6 million of increased liabilities consisting of: $64.2 million of long term debt, a $16.4 million discounted sales agreement and a $12.7 million swap liability offset by various working capital balances.

This transaction also resulted in the elimination of certain previously disclosed relationships including the Company’s noncontrolling interest in the trust, the Company’s liquidity reserve guarantee to ANPI, the Company’s agreement with the trust to provide gathering and operating services to deliver its gas to market and the marketing fee the Company received for the sale of the trust’s gas based on the net revenue for gas delivered.

L. Dispositions

On May 11, 2011, the Company announced the sale of the Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million. The transaction closed on July 1, 2011. Big Sandy is a natural gas pipeline regulated by the Federal Energy Regulatory Commission with a current capacity of 171,000 Dth per day. Big Sandy transports natural gas from the Langley natural gas processing complex to interconnects with unaffiliated pipelines leading to the mid-Atlantic and Northeast markets. EQT classified the Big Sandy properties as assets held for sale in the accompanying Condensed Consolidated Balance Sheets.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

On February 1, 2011, the Company sold its natural gas processing complex in Langley, Kentucky and associated natural gas liquids pipeline for $230.5 million. In conjunction with this transaction, the Company realized a pre-tax gain of $22.8 million.

M. Earnings Per Share

The difference between weighted average common shares outstanding in the basic and diluted earnings per share calculations relates to potentially dilutive options and restricted stock awards. Options to purchase common stock which were anti-dilutive and thus excluded from these shares totaled 6,480 and 1,237,425 for the three months ended June 30, 2011 and June 30, 2010, respectively, and 884,497 and 1,237,425 for the six months ended June 30, 2011 and June 30, 2010, respectively.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY STATEMENTS

Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “will,” “may,” “forecast,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling and infrastructure programs (including the expected costs of drilling and fracturing services and availability of drilling and completion services) and technology, the Company’s expected use of proceeds from and book gain on the sale of the Big Sandy Pipeline, the expected incremental Marcellus gathering capacity to be added by year end 2011, production and sales volumes, revenue projections, reserves, capital expenditures, hedging strategy and tax position. These statements involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2010.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

In reviewing any agreements incorporated by reference in this Form 10-Q, please remember they are included to provide you with information regarding the terms of such agreement and are not intended to provide any other factual or disclosure information about the Company. The agreements may contain representations and warranties by the Company, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.

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CORPORATE OVERVIEW

The Company completed several transactions in the first half of 2011 that had a positive impact on results for the periods ending June 30, 2011, including:

· The February 2011 sale of the Langley natural gas processing complex and the associated NGL pipeline for $230.5 million, which resulted in a pre-tax gain of $22.8 million.

· The May 2011 purchase of all outstanding net profits interest (NPI) from ANPI (the ANPI transaction), which resulted in an increase in oil and gas properties of $140.6 million as well as a pre-tax gain of $10.1 million, recorded in other income, on the revaluation of the previously existing equity investment in the NPI to fair value.

· Sales of available-for-sale securities for proceeds of $29.9 million resulting in pre-tax gains of $4.5 million and $8.5 million for the three and six month periods ended June 30, 2011, respectively. These gains were also recorded in other income.

In addition, on May 11, 2011, the Company announced the sale of the Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million. The transaction closed on July 1, 2011 and is expected to result in a pre-tax gain of $170 million to $180 million in the third quarter 2011. Big Sandy is a natural gas pipeline regulated by the Federal Energy Regulatory Commission with a current capacity of 171,000 Dth per day. Big Sandy transports natural gas from the Langley natural gas processing complex to interconnects with unaffiliated pipelines leading to the mid-Atlantic and Northeast markets.

The Company also commissioned its natural gas vehicle fueling station in Pittsburgh, Pennsylvania, in June 2011 and continues to investigate additional methods of promoting natural gas as a transportation fuel, including providing advice to third parties interested in fleet conversion.

Three Months Ended June 30, 2011 vs. Three Months Ended June 30, 2010

EQT Corporation’s consolidated net income increased $57.8 million, to $0.58 per diluted share from $0.20 per diluted share, for the three months ended June 30, 2011 compared to the same period in 2010. Operationally, the Company was favorably impacted by a 47% increase in production sales volumes, higher average wellhead sales prices and increased gathering and transmission revenues, partially offset by increased depreciation, depletion and amortization as a result of the increase in production and lower storage, marketing and other revenues. In addition, the Company was favorably impacted by gains associated with the ANPI transaction and on the sale of available-for-sale securities during the quarter.

The average wellhead sales price to EQT Corporation was $5.60 per Mcfe during the second quarter 2011 compared to $5.33 per Mcfe in the same period of the prior year. Hedging activities resulted in an increase in the average natural gas price of $0.41 per Mcf in 2011 compared to $0.61 per Mcf in 2010 as a result of higher NYMEX prices for the quarter.

Six Months Ended June 30, 2011 vs. Six Months Ended June 30, 2010

EQT Corporation’s consolidated net income increased $91.9 million, to $1.40 per diluted share from $0.84 per diluted share, in the six months ended June 30, 2011 compared to 2010. This increase was driven by a 45.5% increase in production sales volumes and higher gathering and transmission revenues combined with the gain on the sale of the Langley natural gas processing complex, reductions in certain non income tax reserves and gains on the ANPI transaction and sales of available-for-sale securities. These favorable variances were partially offset by increased depreciation, depletion and amortization as a result of higher volumes, lower net revenues from storage, marketing and other activities and a lower average wellhead sales price.

The average wellhead sales price to EQT Corporation was $5.52 per Mcfe in 2011 compared to $5.87 per Mcfe in 2010. Hedging activities resulted in an increase in the average natural gas sales price of $0.44 per Mcf in 2011 compared to $0.42 per Mcf in 2010 as a result of lower NYMEX prices which had a greater impact than a lower average floor price on collars in the current year.

See Investing Activities in Capital resources and Liquidity for a discussion of capital expenditures.

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EQT CORPORATION

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010		%	2011		2010		%
OPERATIONAL DATA
Average wellhead sales price to EQT Corporation:
Natural gas excluding hedges ($/Mcf)	$	4.58	$	4.09	12.0	$	4.47	$	4.84	(7.6)
Hedge impact ($/Mcf of natural gas) (a)	$	0.41	$	0.61	(32.8)	$	0.44	$	0.42	4.8
Natural gas including hedges ($/Mcf)	$	4.99	$	4.70	6.2	$	4.91	$	5.26	(6.7)
NGLs ($/Bbl)	$	51.71	$	46.60	11.0	$	51.86	$	48.21	7.6
Crude oil ($/Bbl)	$	89.08	$	76.24	16.8	$	84.95	$	76.12	11.6
Total ($/Mcfe)	$	5.60	$	5.33	5.1	$	5.52	$	5.87	(6.0)

Less revenues to EQT Midstream ($/Mcfe)	$	1.44	$	1.67	(13.8)	$	1.45	$	1.69	(14.2)
Average wellhead sales price to EQT Production ($/Mcfe)	$	4.16	$	3.66	13.7	$	4.07	$	4.18	(2.6)

NYMEX natural gas ($/Mcf)	$	4.31	$	4.09	5.4	$	4.21	$	4.70	(10.4)

Natural gas sales volumes (MMcf)	43,830		29,167		50.3	83,965		56,658		48.2
NGL sales volumes (Mbbls)	774		667		16.0	1,500		1,285		16.7
Crude oil sales volumes (Mbbls)	49		29		69.0	80		50		60.0
Total production sales volumes (MMcfe) (b)	47,030		31,915		47.4	90,077		61,915		45.5

Capital expenditures (thousands) (c)	$	374,098	$	536,020	(30.2)	$	637,526	$	753,547	(15.4)

(a)		All hedges are related to natural gas.
(b)		NGLs were converted to Mcfe at the rate of 3.75 Mcfe per barrel and 3.86 Mcfe per barrel based on the liquids content for the three and six months ended June 30, 2011 and 2010, respectively, and crude oil was converted to Mcfe at the rate of six Mcfe per barrel for all periods.
(c)		Capital expenditures in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010.

The Company has reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. EQT’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of EQT’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and certain compensation expenses. In addition, management uses these measures for budget planning purposes.

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EQT PRODUCTION

RESULTS OF OPERATIONS

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010		%	2011		2010		%
OPERATIONAL DATA

Natural gas, NGL and crude oil production (MMcfe) (a)	48,039		32,789		46.5	92,565		64,186		44.2
Company usage, line loss (MMcfe)	(1,009)		(874)		15.4	(2,488)		(2,271)		9.6
Total production sales volumes (MMcfe)	47,030		31,915		47.4	90,077		61,915		45.5

Average daily sales volumes (MMcfe/d)	517		351		47.3	498		342		45.6

Sales volume detail (MMcfe):
Horizontal Marcellus Play	18,505		4,997		270.3	34,495		8,762		293.7
Horizontal Huron Play	10,017		9,345		7.2	20,360		18,122		12.3
CBM Play	3,396		3,310		2.6	6,775		6,494		4.3
Other (vertical non-CBM)	15,112		14,263		6.0	28,447		28,537		(0.3)
Total production sales volumes	47,030		31,915		47.4	90,077		61,915		45.5

Average wellhead sales price ($/Mcfe)	$	4.16	$	3.66	13.7	$	4.07	$	4.18	(2.6)

Lease operating expenses, excluding production taxes (LOE) ($/Mcfe)	$	0.22	$	0.26	(15.4)	$	0.20	$	0.25	(20.0)
Production taxes ($/Mcfe)	$	0.20	$	0.25	(20.0)	$	0.19	$	0.26	(26.9)
Production depletion ($/Mcfe)	$	1.24	$	1.27	(2.4)	$	1.25	$	1.25	–

Depreciation, depletion and amortization (DD&A) (thousands):
Production depletion	$	59,709	$	41,527	43.8	$	115,321	$	80,504	43.2
Other DD&A	2,190		1,941		12.8	4,412		3,874		13.9
Total DD&A	$	61,899	$	43,468	42.4	$	119,733	$	84,378	41.9

Capital expenditures (thousands) (b)	$	317,906	$	483,656	(34.3)	$	544,878	$	662,071	(17.7)

FINANCIAL DATA (Thousands)

Total operating revenues	$	196,810	$	119,028	65.3	$	369,852	$	263,391	40.4

Operating expenses:
LOE	10,348		8,396		23.2	18,148		16,199		12.0
Production taxes (c)	9,417		8,136		15.7	17,728		16,954		4.6
Exploration expense	1,198		1,078		11.1	2,573		2,413		6.6
Selling, general and administrative (SG&A)	14,189		16,921		(16.1)	29,582		29,301		1.0
DD&A	61,899		43,468		42.4	119,733		84,378		41.9
Total operating expenses	97,051		77,999		24.4	187,764		149,245		25.8
Operating income	$	99,759	$	41,029	143.1	$	182,088	$	114,146	59.5

(a) Natural gas, NGL and oil production represents the Company’s interest in natural gas, NGL and oil production measured at the wellhead. It is equal to the sum of total sales volumes and Company usage and line loss.

(b) Capital expenditures in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010.

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Three Months Ended June 30, 2011 vs. Three Months Ended June 30, 2010

EQT Production’s operating income totaled $99.8 million for the three months ended June 30, 2011 compared to $41.0 million for the three months ended June 30, 2010. The increase in operating income was primarily due to a 47% increase in production sales volumes and a higher average wellhead sales price partially offset by an increase in DD&A.

Total operating revenues were $196.8 million for the three months ended June 30, 2011 compared to $119.0 million for the three months ended June 30, 2010. The increase in total operating revenues was primarily due to an increase in production sales volumes and higher average wellhead sales prices. The 47% increase in production sales volumes was the result of increased production from the 2009 and 2010 drilling programs, primarily in the Marcellus and Huron plays, as well as the acquisition of producing properties associated with the ANPI transaction in May 2011 which added 1,390 MMcfe of sales volumes in the second quarter. The increase in produced natural gas sales volumes from new drilling was partially offset by the normal production decline in the Company’s wells. The $0.50 per Mcfe increase in the average wellhead sales price was primarily due to a 5% increase in the average NYMEX price, lower gathering rates and a higher sales price for NGLs in the current year partially offset by lower hedging gains compared to the second quarter of 2010.

Operating expenses totaled $97.1 million for the three months ended June 30, 2011 compared to $78.0 million for the three months ended June 30, 2010. The increase in operating expenses was primarily the result of increases in production depletion, LOE and production taxes partially offset by a decrease in SG&A. The depletion expense reflects an increase in volumes ($19.3 million) offset by a decrease in the unit rate ($1.1 million). The increase in LOE was primarily the result of increased activity in the Marcellus play in the current year as well as the elimination of certain pre-acquisition arrangements associated with the ANPI transaction, pursuant to which the Company was reimbursed for certain operating services. Production taxes increased due to the higher revenues in jurisdictions that impose such taxes in the current year. The decrease in SG&A was due to a charge in the prior year related to the buy-out of excess contractual capacity for the processing and disposal of salt water, partially offset by slightly higher overhead costs associated with the growth of the Company.

Six Months Ended June 30, 2011 vs. Six Months Ended June 30, 2010

EQT Production’s operating income totaled $182.1 million for the six months ended June 30, 2011 compared to $114.1 million for the six months ended June 30, 2010. The increase in operating income was primarily due to increased production sales volumes, partially offset by an increase in DD&A and a lower average wellhead sales price.

Total operating revenues were $369.9 million for the six months ended June 30, 2011 compared to $263.4 million for the six months ended June 30, 2010. The increase in total operating revenues was due to an increase in production sales volumes which more than offset lower average wellhead sales prices. The 45.5% increase in production sales volumes was the result of increased production from the 2009 and 2010 drilling programs, primarily in the Marcellus and Huron plays, as well as the acquisition of producing properties associated with the ANPI transaction in May 2011, which added 1,390 MMcfe of sales volumes in the current year. These increases were partially offset by the normal production decline in the Company’s wells. The $0.11 per Mcfe decrease in the average wellhead sales price was primarily due to a 10% decrease in the average NYMEX price partially offset by lower gathering rates, higher sales price for NGLs, and higher hedging gains compared to the first six months of 2010.

Operating expenses totaled $187.8 million for the six months ended June 30, 2011 compared to $149.2 million for the six months ended June 30, 2010. The increase in operating expenses was primarily the result of increases in DD&A and LOE. The depletion expense increased as a result of increased volumes. The increase in LOE was primarily the result of increased activity in the Marcellus play in the current year as well as the elimination of the previous mentioned pre-ANPI transaction reimbursement arrangements. SG&A increased slightly due to higher overhead costs associated with the growth of the Company offset by a charge in the prior year related to the buy-out of excess contractual capacity for the processing and disposal of salt water.

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EQT MIDSTREAM

RESULTS OF OPERATIONS

	Three Months Ended June 30,					Six Months Ended June 30,

	2011		2010		%	2011		2010		%
OPERATIONAL DATA

Gathered volumes (BBtu)	62,566		47,461		31.8	121,188		92,084		31.6
Average gathering fee ($/MMBtu)	$	0.98	$	1.08	(9.3)	$	0.99	$	1.10	(10.0)
Gathering expense ($/MMBtu)	$	0.27	$	0.39	(30.8)	$	0.22	$	0.38	(42.1)
Transmission pipeline throughput (BBtu)	43,439		24,065		80.5	79,001		49,058		61.0

Net operating revenues (thousands):
Gathering	$	61,257	$	51,029	20.0	$	120,238	$	99,763	20.5
Transmission	24,566		18,007		36.4	50,955		39,560		28.8
Storage, marketing and other	12,015		24,260		(50.5)	33,167		55,448		(40.2)
Total net operating revenues	$	97,838	$	93,296	4.9	$	204,360	$	194,771	4.9

Unrealized gains (losses) on derivatives and inventory (thousands) (a)	$	1,310	$	(232)	(664.7)	$	158	$	(822)	(119.2)

Capital expenditures (thousands)	$	46,500	$	44,293	5.0	$	75,605	$	78,980	(4.3)

FINANCIAL DATA (Thousands)

Total operating revenues	$	131,201	$	136,995	(4.2)	$	272,863	$	291,591	(6.4)
Purchased gas costs	33,363		43,699		(23.7)	68,503		96,820		(29.2)
Total net operating revenues	97,838		93,296		4.9	204,360		194,771		4.9

Operating expenses:
Operating and maintenance (O&M)	20,033		24,756		(19.1)	34,360		47,984		(28.4)
SG&A	11,266		11,215		0.5	22,120		21,847		1.2
DD&A	14,296		15,611		(8.4)	29,004		30,535		(5.0)
Total operating expenses	45,595		51,582		(11.6)	85,484		100,366		(14.8)
Operating income	$	52,243	$	41,714	25.2	$	118,876	$	94,405	25.9

(a) Included within storage, marketing and other net operating revenues.

Three Months Ended June 30, 2011 vs. Three Months Ended June 30, 2010

EQT Midstream’s operating income increased $10.5 million to $52.2 million for the three months ended June 30, 2011 compared to 2010 primarily as a result of increased gathering and transmission revenues combined with lower operating expenses. These favorable variances were partially offset by decreased storage, marketing and other net operating revenues and a lower average gathering fee.

Total net operating revenues increased $4.5 million for the three months ended June 30, 2011 compared to 2010. Gathering net operating revenues increased $10.2 million as a result of a 32% increase in gathered volumes, primarily related to EQT Production’s increased produced natural gas in the Marcellus play, partially offset by a 9% decrease in the average gathering fee resulting from lower gathering rates in that play. Transmission net revenues increased primarily as a result of the increased sale of capacity associated with the initial phase of the Equitrans Marcellus expansion project which came on-line in the fourth quarter 2010. These increases were partially offset by a $12.2 million decrease in storage, marketing and other net revenues as a result of decreased asset optimization activities because of lower price volatility. These net revenues also declined because of lower natural gas marketing volumes and lower net revenues from natural gas liquids as a result of the loss of processing fees due to the sale of the Langley natural

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gas processing complex. Higher NGL prices were substantially offset by lower liquids volumes marketed for non-affiliated producers.

Decreased commercial activity resulted in decreases in both total operating revenues and purchase gas costs. This decline in commercial revenue was partially offset by the increase in gathering and transmission revenues.

Operating expenses decreased $6.0 million for the three months ended June 30, 2011 compared to 2010 as a result of a $4.7 million decrease in O&M and a $1.3 million decrease in DD&A. The decrease in O&M was primarily due to the absence of operating expenses associated with the recently sold Langley natural gas processing complex as well as adjustments for certain non-income taxes. The decrease in DD&A is primarily due to the sale of assets associated with the Langley natural gas processing complex.

Six Months Ended June 30, 2011 vs. Six Months Ended June 30, 2010

EQT Midstream’s operating income increased $24.5 million for the six months ended June 30, 2011 compared to 2010 primarily as a result of increased gathering and transmission net revenues combined with lower operating expenses. These favorable variances were partially offset by a decrease in storage, marketing and other net revenues.

Total net operating revenues increased $9.6 million for the six months ended June 30, 2011 compared to the prior year. Gathering net operating revenues increased $20.5 million as a result of a 32% increase in gathered volumes partially offset by a 10% decrease in the average gathering fee. The volume increase was driven primarily by higher Marcellus volumes gathered for EQT Production. Transmission net operating revenues increased $11.4 million primarily as a result of higher firm transportation activity resulting from increased Marcellus volumes from affiliated shippers and the increased capacity from Phase 1 of the Equitrans Marcellus expansion. Storage, marketing and other net revenues decreased $22.3 million primarily as a result of lower margins due to reduced commodity price volatility and lower seasonal price spreads as well as lower net revenues from natural gas liquids marketed for non-affiliated producers and a decrease in natural gas volumes marketed for third parties utilizing pipeline capacity.

Total operating revenues and purchased gas costs decreased as a result of decreased commercial activity and lower sales prices. These revenue reductions were partially mitigated by increases in gathering and transmission revenues.

Operating expenses for the first six months of 2011 decreased compared to the prior year primarily as a result of decreases of $13.6 million in O&M and $1.5 million in DD&A. The decrease in O&M primarily resulted from the reduction of certain non-income tax reserves as a result of property tax settlements as well as the absence of operating expenses associated with the recently sold Langley natural gas processing complex. The decrease in DD&A is primarily a result of the sale of assets associated with the Langley natural gas processing complex.

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DISTRIBUTION

RESULTS OF OPERATIONS

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010		%	2011		2010		%

OPERATIONAL DATA

Heating degree days (30 year average: Qtr - 665; YTD – 3,535) (a)	487		417		16.8	3,423		3,277		4.5

Residential sales and transportation volumes (MMcf)	2,694		2,238		20.4	14,718		14,103		4.4
Commercial and industrial volumes (MMcf)	5,611		5,394		4.0	16,742		16,830		(0.5)
Total throughput (MMcf) – Distribution	8,305		7,632		8.8	31,460		30,933		1.7

Net operating revenues (thousands):
Residential	$	19,146	$	17,333	10.5	$	70,096	$	66,963	4.7
Commercial & industrial	8,237		7,665		7.5	29,416		27,488		7.0
Off-system and energy services	5,506		4,222		30.4	11,270		11,610		(2.9)
Total net operating revenues	$	32,889	$	29,220	12.6	$	110,782	$	106,061	4.5

Capital expenditures (thousands)	$	8,811	$	7,750	13.7	$	15,030	$	11,725	28.2

FINANCIAL DATA (thousands)

Total operating revenues	$	69,100	$	63,349	9.1	$	264,191	$	285,604	(7.5)
Purchased gas costs	36,211		34,129		6.1	153,409		179,543		(14.6)
Net operating revenues	32,889		29,220		12.6	110,782		106,061		4.5

Operating expenses:
O&M	10,731		10,980		(2.3)	21,052		21,580		(2.4)
SG&A	7,307		7,934		(7.9)	15,555		20,762		(25.1)
DD&A	5,923		6,016		(1.5)	11,880		12,010		(1.1)
Total operating expenses	23,961		24,930		(3.9)	48,487		54,352		(10.8)
Operating income	$	8,928	$	4,290	108.1	$	62,295	$	51,709	20.5

(a) The 30-year heating degree days figures are derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures. NOAA released updated heating degree days figures for the period 1981 to 2010 and accordingly, the 30-year heating degree days decreased from 705 and 3,635 for the three and six months ended June 30, 2010 to 665 and 3,535 for the three and six months ended June 30, 2011.

Three Months Ended June 30, 2011 vs. Three Months Ended June 30, 2010

Distribution’s operating income totaled $8.9 million for the second quarter of 2011 compared to $4.3 million for the second quarter of 2010. The increase in operating income was primarily due to colder weather and a decrease in bad debt expense.

Net operating revenues were $32.9 million for the second quarter of 2011, a $3.7 million increase from 2010. This increase was the result of several factors. Net operating revenues from residential customers increased $1.8 million primarily as a result of weather which was 17% colder than the second quarter of 2010. Off-system and energy services net operating revenues increased $1.3 million primarily due to higher revenues from asset optimization opportunities realized in the second quarter of 2011. Commercial and industrial net operating revenues increased approximately $0.6 million primarily due to the colder weather. The increase in volumes due to colder weather resulted in an increase in both total operating revenues and purchased gas costs.

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Operating expenses totaled $24.0 million for the second quarter of 2011 compared to $24.9 million for the second quarter of 2010. The decrease in operating expenses was primarily the result of a $1.3 million decrease in bad debt expense partially offset by an increase in other SG&A. The decrease in bad debt expense was primarily the result of a decrease in the commodity component of residential tariff rates and the Company’s favorable collections experience.

Six Months Ended June 30, 2011 vs. Six Months Ended June 30, 2010

Distribution’s operating income totaled $62.3 million for the six months ended June 30, 2011 compared to $51.7 million for six months ended June 30, 2010. The increase in operating income was primarily the result of colder weather, an increase in the Company’s West Virginia base rates and a decrease in operating expenses.

Net operating revenues were $110.8 million for the six months ended June 30, 2011, an increase of $4.7 million from 2010. The increase was primarily a result of increased net operating revenues from residential and commercial and industrial customers partially offset by a decrease in off system and energy services net operating revenues. Net operating revenues from residential customers increased $3.1 million as a result of colder weather and the approval of the Company’s West Virginia base rate increase in August 2010. The weather in Distribution’s service territory in the first six months of 2011 was 4.5% colder than the first six months of 2010. Commercial and industrial net revenues increased $1.9 million due to colder weather, an increase in the West Virginia base rate and an increase in performance-based revenues. Off system and energy services net operating revenues decreased $0.3 million due to less optimization opportunities realized in 2011 partially offset by higher revenues from gathering activities resulting from increased rates. A decrease in the commodity component of residential tariff rates resulted in a decrease in both total operating revenues and purchased gas costs.

Operating expenses totaled $48.5 million for the six months ended June 30, 2011 compared to $54.4 million for the six months ended June 30, 2010. This decrease was primarily due to the reduction of certain non-income tax reserves as a result of settlements with tax authorities and lower bad debt expense. The decrease in bad debt expense was primarily the result of a decrease in the commodity component of residential tariff rates and the Company’s favorable collections experience.

OUTLOOK

A substantial portion of the Company’s drilling efforts in 2011 are focused on drilling horizontal wells in shale formations in Pennsylvania, West Virginia and Kentucky. Natural gas producers compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and the securing of labor and equipment required to conduct operations. Increased drilling activity in the Appalachian basin, especially the Marcellus play, is expected to result in higher competition for drilling and completion services and higher costs for drilling and fracturing services.

The Company continues to be committed to profitably expanding its production and developing its reserves through environmentally responsible, cost-effective, technologically-advanced horizontal drilling in its existing plays. The Company currently expects natural gas sales volumes of 190 Bcfe to 195 Bcfe for the full year 2011, approximately 43% higher than 2010.

To support the drilling growth, the Company plans to add approximately 300 MMcfe per day of incremental Marcellus gathering capacity by the end of 2011. The Company will also strive to optimize its contractual capacity and storage assets.

On July 1, 2011, the Company completed the sale of the Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million. The Company plans to invest the majority of the proceeds to develop its approximately 520,000 Marcellus acres, including associated midstream gathering, and to develop its extensive Huron reserves. As a result of the transaction, the Company expects to recognize pre-tax gain on the sale of approximately $170 million to $180 million after customary post closing adjustments.

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CAPITAL RESOURCES AND LIQUIDITY

Overview

The Company’s primary sources of cash for the first six months of 2011 were proceeds from operating activities and proceeds from the sale of the Langley natural gas processing complex. The Company used the cash primarily to fund its capital program and operations.

Operating Activities

Cash flows provided by operating activities during the six months ended June 30, 2011 were $462.6 million compared to $476.6 million for the same period of 2010. The decrease in cash flows provided by operating activities was primarily attributable to a $121.5 million federal income tax carryback refund received in 2010, partially offset by higher operating receipts as a result of increased production sales volumes and average wellhead sales prices.

Investing Activities

Net cash flows used in investing activities totaled $265.9 million for the first six months of 2011 and $523.6 million for the first six months of 2010. The decrease in cash flows used in investing activities was primarily attributed to 2011 proceeds from the sales of the Langley natural gas processing complex and available-for-sale securities as well as a dividend received from Nora Gathering, LLC. Capital expenditures totaled $544.9 million for the first six months of 2011 and $522.9 million for the first six months of 2010.

The Company commenced drilling on (drilled) 113 gross wells during the first six months of 2011. Of these wells, 112 were horizontal wells; 61 targeting the Huron play and 51 targeting the Marcellus play. The Company drilled 272 gross wells, including 205 horizontal wells during the first six months of 2010; 143 targeting the Huron play and 62 targeting the Marcellus play. Capital expenditures for drilling and development were $20.9 million higher in 2011 than 2010 despite the decline in the number of wells on which drilling commenced in the current year. This increase was primarily due to the completion of more Marcellus wells in 2011 that were drilled in 2010 compared to ones that were completed in 2010 but drilled in 2009, higher costs for drilling and fracturing services and longer average lateral lengths for both horizontal Marcellus and Huron wells in the current year.

The Company also increased oil and gas properties by $140.6 million in a non-cash transaction in the second quarter 2011. See Note K of the Condensed Consolidated Financial Statements of this Form 10-Q for a discussion of the ANPI transaction. During the second quarter 2010, the Company acquired $230.7 million in undeveloped oil and gas property in exchange for EQT common stock.

Capital expenditures for the midstream operations totaled $75.6 million and $79.0 million during the first six months of 2011 and 2010, respectively. Expenditures for both years were primarily for gathering pipeline and compression projects. The decrease in capital expenditures is attributable to 2010 upgrades to the Langley natural gas processing complex which was sold earlier this year.

Capital expenditures at Distribution totaled $15.0 million for the first six months of 2011 compared to $11.7 million for the first six months of 2010. The increase in capital expenditures was primarily due to the construction of the Company’s natural gas fueling station in Pittsburgh, Pennsylvania.

The Company is currently forecasting capital expenditures for 2011, excluding the ANPI transaction, of approximately $1.35 billion including approximately $80 million for lease acquisitions.

Financing Activities

Cash flows used in financing activities totaled $117.4 million for the first six months of 2011 compared to $472.6 million provided by financing activities for the first six months of 2010. In the first half of 2010, the Company received $537.2 million from a common stock offering. The Company used the net proceeds from the offering to accelerate development of its Marcellus and Huron plays. In 2011, the Company repaid $53.7 million of short-term loans with proceeds from the sale of the Langley natural gas processing complex.

During the second quarter of 2011 the Company assumed notes in a non-cash transaction for oil and gas properties. See Note K of the Condensed Consolidated Financial Statements of this Form 10-Q for a discussion of the ANPI transaction. As noted above, during the second quarter 2010, the Company issued EQT common stock in exchange for undeveloped oil and gas properties.

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Security Ratings

The table below reflects the credit ratings for the outstanding debt instruments of the Company at June 30, 2011. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

Rating Service	Senior Notes	Short-Term Rating
Moody’s Investors Service	Baa1	P-2
Standard & Poor’s Ratings Services	BBB	A-3
Fitch Ratings	BBB	F2

On April 14, 2011, S&P affirmed its ratings on EQT. The outlook is negative.

On March 23, 2011, Fitch downgraded its rating on EQT to BBB from BBB+. The outlook is stable. Fitch stated that “the key factor for the downgrade is increased business risk from EQT’s growing focus on upstream operations.”

On September 30, 2010, Moody’s reaffirmed its ratings on EQT. The outlook is negative. Moody’s stated that the “ratings reflect the diversification and vertical integration among its three business segments as well as the Baa stand-alone quality of both its E&P and LDC operations.”

The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, the Company’s access to the capital markets may be limited, borrowing costs and margin deposits would increase, counterparties may request additional assurances and the potential pool of investors and funding sources may decrease. The required margin on derivative instruments is also subject to significant change as a result of factors other than credit rating such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company.

The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to total debt-to-total capitalization ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The financial covenants contained in the Company’s current credit facility and note purchase agreement governing the terms and conditions of the notes associated with the ANPI transaction require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income. As of June 30, 2011, the Company is in compliance with all existing debt provisions and covenants.

Commodity Risk Management

The substantial majority of the Company’s commodity risk management program is related to hedging sales of the Company’s produced natural gas. The Company’s overall objective in this hedging program is to protect cash flow from undue exposure to the risk of changing commodity prices. The Company’s risk management program may include the use of exchange-traded natural gas futures contracts and options and over the counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices. The derivative commodity instruments currently utilized by the Company are primarily fixed prices swaps, collars and futures.

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As of July 27, 2011, the approximate volumes and prices of the Company’s total hedge position for 2011 through 2013 production are:

	2011**		2012		2013
Swaps
Total Volume (Bcf)	45		80		29
Average Price per Mcf (NYMEX)*	$	4.88	$	5.31	$	5.64


	2011**		2012		2013
Puts
Total Volume (Bcf)	1		–		–
Average Floor Price per Mcf (NYMEX)*	$	7.35	$	–	$	–


	2011**		2012		2013
Collars
Total Volume (Bcf)	11		21		15
Average Floor Price per Mcf (NYMEX)*	$	6.51	$	6.51	$	6.12
Average Cap Price per Mcf (NYMEX)*	$	11.83	$	11.83	$	11.80

* The above price is based on a conversion rate of 1.05 MMBtu/Mcf

**July through December

In 2008, the Company effectively settled certain derivative commodity swaps scheduled to mature during the period 2010 through 2013 by de-designating the swaps and entering into directly counteractive swaps. In 2009, the Company also terminated certain collars scheduled to mature during the period 2010 through 2012. As of the dates of these transactions, the Company had recorded a loss, net of tax, in accumulated other comprehensive income of approximately $12 million ($21 million pre-tax) for the swaps and a gain, net of tax, in accumulated other comprehensive income of approximately $5 million ($8 million pre-tax) for the collars. The net loss recorded in other comprehensive income from these transactions will be recognized in operating revenues in the Statements of Consolidated Income, and included in the average wellhead sales price, when the underlying physical transactions occur. As a result, the Company expects to recognize reduced operating revenues of approximately $2.8 million over the final six months of 2011, $0.6 million in 2012 and $2.5 million in 2013.

Commitments and Contingencies

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.

Dividend

On July 14, 2011, the Board of Directors declared a regular quarterly cash dividend of 22 cents per share, payable September 1, 2011, to shareholders of record on August 6, 2011.

Critical Accounting Policies

The Company’s critical accounting policies are described in the notes to the Company’s Consolidated Financial Statements for the year ended December 31, 2010 contained in the Company’s Annual Report on Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Condensed Consolidated Financial Statements for the period ended June 30, 2011. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

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EQT Corporation and Subsidiaries

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Commodity Instruments

The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily through EQT Production and storage, marketing and other activities at EQT Midstream. The Company’s use of derivatives to reduce the effect of this volatility is described in Note C to the Condensed Consolidated Financial Statements and under the caption “Commodity Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to optimize its assets and limit its exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.

Commodity Price Risk

For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels which are exposed to price risk. For the derivative commodity instruments used to hedge forecasted natural gas purchases and sales which are exposed to price risk and to hedge natural gas inventory which is exposed to changes in fair value, the Company sets limits related to acceptable exposure levels.

The financial instruments currently utilized by the Company are primarily futures contracts, swap agreements, collar agreements which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers other contractual agreements in determining its commodity hedging strategy.

Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to protect cash flow from undue exposure to the risk of changing commodity prices.

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of June 30, 2011, the Company hedged portions of expected equity production, portions of forecasted purchases and sales and portions of natural gas inventory by utilizing futures contracts, swap agreements, collar agreements and option contracts covering approximately 236 Bcf of natural gas. See the “Commodity Risk Management” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q for further discussion. A hypothetical decrease of 10% in the market price of natural gas from the June 30, 2011 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $104.7 million. A hypothetical increase of 10% in the market price of natural gas from the June 30, 2011 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $102.5 million.

The Company determined the change in the fair value of the derivative commodity instruments using a model similar to its normal determination of fair value as described in Note 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010. The Company assumed a 10% change in the price of natural gas from its levels at June 30, 2011. The price change was then applied to the non-trading derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheets resulting in the change in fair value.

The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company’s physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above should be

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offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the physical derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.

If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

Other Market Risks

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because the Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.

The Company utilizes various processes and analysis to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company enters transactions with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.

Approximately 69%, or $209.3 million, of OTC derivative contracts outstanding at June 30, 2011 have a positive fair value. All derivative contracts outstanding as of June 30, 2011 are with counterparties having an S&P rating of A or above at that date.

As of June 30, 2011, the Company is not in default under any derivative contracts and has no knowledge of default by any counterparty to derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheets.

The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas. A significant amount of revenues and related accounts receivable from EQT Production are generated from the sale of produced natural gas, NGLs and crude oil to certain marketers, including the Company’s wholly-owned marketing subsidiary EQT Energy, utility and industrial customers located mainly in the Appalachian area and a gas processor in Kentucky. Additionally, a significant amount of revenues and related accounts receivable from EQT Midstream are generated from the gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.

The Company has a $1.5 billion revolving credit facility that matures on December 8, 2014. The credit facility is underwritten by a syndicate of 20 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. As of June 30, 2011, the Company had no loans outstanding under the revolving credit facility.

No one lender of the 20 financial institutions in the syndicate holds more than 10% of the facility. The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure to problems or consolidation in the banking industry.

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EQT Corporation and Subsidiaries

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.

Item 1A. Risk Factors

Information regarding risk factors is discussed in Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2010. There have been no material changes from the risk factors previously disclosed in the Company’s Form 10-K.

Item 6. Exhibits

3.1	EQT Corporation Restated Articles of Incorporation (Amended through May 10, 2011)

3.2	EQT Corporation Amended and Restated By-Laws (Amended through May 10, 2011)

10.1	Executive Alternative Work Arrangement Employment Agreement, dated May 10, 2011, between the Company and Murry S. Gerber

10.2	EQT Corporation 2011 Executive Short-Term Incentive Plan

10.3	Amendment to Stock Option Award Agreements

31.1	Rule 13(a)-14(a) Certification of Principal Executive Officer

31.2	Rule 13(a)-14(a) Certification of Principal Financial Officer

32	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer

101	Interactive Data File

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Signature

Pursuant to the requirements 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.

		EQT CORPORATION
		(Registrant)


	By:	/s/ Philip P. Conti
		Philip P. Conti
		Senior Vice President and Chief Financial Officer

Date: July 28, 2011

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INDEX TO EXHIBITS

Exhibit No.	Document Description	Incorporated by Reference

3.1	EQT Corporation Restated Articles of Incorporation (Amended through May 10, 2011)	Filed as Exhibit 3.1 to Form 8-K filed on May 10, 2011

3.2	EQT Corporation Amended and Restated By-Laws (Amended through May 10, 2011)	Filed as Exhibit 3.2 to Form 8-K filed on May 10, 2011

10.1	Executive Alternative Work Arrangement Employment Agreement, dated May 10, 2011, between the Company and Murry S. Gerber	Filed as Exhibit 10.1 to Form 8-K filed on May 10, 2011

10.2	EQT Corporation 2011 Executive Short-Term Incentive Plan	Filed as Exhibit 10.2 to Form 8-K filed on May 10, 2011

10.3	Amendment to Stock Option Award Agreements	Filed herewith as Exhibit 10.3

31.1	Rule 13(a)-14(a) Certification of Principal Executive Officer	Filed herewith as Exhibit 31.1

31.2	Rule 13(a)-14(a) Certification of Principal Financial Officer	Filed herewith as Exhibit 31.2

32	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer	Filed herewith as Exhibit 32

101	Interactive Data File	Filed herewith as Exhibit 101