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 SEPTEMBER 30, 2011

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:)

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 September 30, 2011, 149,437,433 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 Nine Months ended September 30, 2011 and 2010	3

			Statements of Condensed Consolidated Cash Flows for the Nine Months ended September 30, 2011 and 2010	4

			Condensed Consolidated Balance Sheets as of September 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 – 30

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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(Thousands, except per share amounts)
Operating revenues	$	336,720	$	257,335	$	1,141,391	$	951,490

Operating expenses:
Purchased gas costs	8,197		8,838		127,870		138,769
Operation and maintenance	35,872		40,483		91,513		110,775
Production	24,908		16,010		60,784		49,163
Exploration	814		941		3,387		3,354
Selling, general and administrative	44,745		34,333		124,572		117,961
Depreciation, depletion and amortization	87,343		68,548		247,627		195,644
Total operating expenses	201,879		169,153		655,753		615,666

Operating income	134,841		88,182		485,638		335,824
Gain on dispositions	180,143		–		202,928		–
Other income	3,098		2,924		27,948		8,551
Interest expense	32,503		33,861		98,642		102,075

Income before income taxes	285,579		57,245		617,872		242,300
Income taxes	106,665		20,723		228,949		87,713
Net income	$	178,914	$	36,522	$	388,923	$	154,587

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	149,441		149,133		149,373		143,048
Net income	$	1.20	$	0.24	$	2.60	$	1.08
Diluted:
Weighted average common shares outstanding	150,301		149,775		150,144		143,806
Net income	$	1.19	$	0.24	$	2.59	$	1.07
Dividends declared per common share	$	0.22	$	0.22	$	0.66	$	0.66

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)

	Nine Months Ended September 30,
	2011			2010
	(Thousands)
Cash flows from operating activities:
Net income	$	388,923		$	154,587
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	247,627			195,644
Deferred income taxes	190,330			99,205
Gain on dispositions	(202,928		)	–
Equity award expense	15,118			10,290
Other income	(27,948		)	(8,551		)
Provision for losses on accounts receivable	(176		)	2,917
Unrealized (gains) losses on derivative financial instruments	(3,905)			(4,702		)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues	66,952			90,183
Inventory	467			15,589
Accounts payable	37,535			(57,402		)
Derivative instruments at fair value, net	3,884			(9,294		)
Federal income tax carryback refund	–			121,463
Other assets and liabilities	(2,544		)	11,118
Net cash provided by operating activities	713,335			621,047

Cash flows from investing activities:
Additions to property, plant and equipment	(892,557		)	(863,011		)
Dividend from Nora Gathering, LLC	23,500			–
Proceeds from sale of available-for-sale securities	29,947			–
Proceeds from dispositions	619,999			–
Investment in available-for-sale-securities	–			(750		)
Net cash used in investing activities	(219,111		)	(863,761		)

Cash flows from financing activities:
Dividends paid	(98,709		)	(94,438		)
Proceeds from issuance of common stock	–			537,239
Decrease in short-term loans	(53,650		)	(5,000		)
Repayments of long-term debt	(9,457		)	–
Proceeds from exercises under employee compensation plans	2,504			2,280
Net cash (used in) provided by financing activities	(159,312		)	440,081

Net increase in cash and cash equivalents	334,912			197,367
Cash and cash equivalents at beginning of period	–			–
Cash and cash equivalents at end of period	$	334,912		$	197,367

Cash paid (received) during the period for:
Interest, net of amount capitalized	$	76,934		$	80,703
Income taxes, net of refunds	$	35,628		$	(124,124	)

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)

	September 30, 2011		December 31, 2010
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	334,912	$	–
Accounts receivable (less accumulated provision for doubtful accounts at September 30, 2011 and December 31, 2010: $14,913 and $18,335)	124,542		156,709
Unbilled revenues	8,158		38,361
Inventory	138,012		137,853
Derivative instruments, at fair value	313,537		225,339
Assets held for sale	–		207,678
Prepaid expenses and other	49,732		62,000
Total current assets	968,893		827,940

Equity in nonconsolidated investments	136,148		191,265

Property, plant and equipment	8,393,467		7,689,025
Less: accumulated depreciation and depletion	1,907,848		1,778,934
Net property, plant and equipment	6,485,619		5,910,091

Investments, available-for-sale	–		28,968
Regulatory assets	98,388		100,949
Other assets	31,146		39,225
Total assets	$	7,720,194	$	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)

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

Current liabilities:
Current portion of long-term debt	$	25,315		$	6,000
Short-term loans	–			53,650
Accounts payable	252,030			212,134
Derivative instruments, at fair value	108,926			106,721
Other current liabilities	206,369			218,479
Total current liabilities	592,640			596,984

Long-term debt	1,978,596			1,943,200
Deferred income taxes and investment tax credits	1,502,625			1,274,888
Unrecognized tax benefits	36,991			41,451
Pension and other post-retirement benefits	38,845			44,135
Other credits	132,760			119,084
Total liabilities	4,282,457			4,019,742

Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares (shares issued September 30, 2011 and December 31, 2010: 175,685 and 175,684)	1,731,246			1,723,898
Treasury stock, at cost (shares at September 30, 2011 and December 31, 2010: 26,247 and 26,531)	(473,925		)	(479,072		)
Retained earnings	2,085,980			1,795,766
Accumulated other comprehensive income	94,436			38,104
Total common stockholders’ equity	3,437,737			3,078,696
Total liabilities and stockholders’ equity	$	7,720,194		$	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 its subsidiaries as of September 30, 2011, and the results of its operations and cash flows for the three and nine month periods ended September 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 nine month periods ended September 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 certain 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues from external customers:
EQT Production	$	207,500		$	131,791		$	577,352		$	395,182
EQT Midstream	122,614			144,634			395,477			436,225
Distribution	49,175			53,208			313,366			338,812
Less: intersegment revenues (a)	(42,569		)	(72,298		)	(144,804		)	(218,729		)
Total	$	336,720		$	257,335		$	1,141,391		$	951,490
Operating income:
EQT Production	$	98,936		$	55,651		$	281,024		$	169,797
EQT Midstream	41,673			35,858			160,549			130,263
Distribution	2,463			644			64,758			52,353
Unallocated expenses (b)	(8,231		)	(3,971		)	(20,693		)	(16,589		)
Total	$	134,841		$	88,182		$	485,638		$	335,824

Reconciliation of operating income to net income:

Gain on dispositions	$	180,143		$	–		$	202,928		$	–
Other income	3,098			2,924			27,948			8,551
Interest expense	32,503			33,861			98,642			102,075
Income taxes	106,665			20,723			228,949			87,713
Net income	$	178,914		$	36,522		$	388,923		$	154,587


	September 30,		December 31,
	2011		2010
	(Thousands)
Segment Assets:
EQT Production	$	4,797,066	$	3,979,676
EQT Midstream	1,729,988		2,076,485
Distribution	812,652		848,419
Total operating segments	7,339,706		6,904,580
Headquarters assets, including cash and short-term investments	380,488		193,858
Total assets	$	7,720,194	$	7,098,438

(a)	Intersegment revenues primarily represent natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream 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 September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010

	(Thousands)
Depreciation, depletion and amortization:
EQT Production	$	66,947		$	46,658	$	186,680		$	131,036
EQT Midstream	14,093			15,705		43,097			46,240
Distribution	6,534			6,057		18,414			18,067
Other	(231		)	128		(564		)	301
Total	$	87,343		$	68,548	$	247,627		$	195,644

Capital expenditures:
EQT Production (a)	$	255,151		$	267,154	$	800,029		$	929,225
EQT Midstream	81,227			59,499		156,832			138,479
Distribution	10,149			9,382		25,179			21,107
Other	1,118			4,116		3,131			4,887
Total	$	347,645		$	340,151	$	985,171		$	1,093,698

(a)

Expenditures for segment assets in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction (defined below) 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.

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.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 net settle its derivative instruments at any time.

	Three Months Ended September 30,						Nine Months Ended September 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	$	64,530		$	59,120		$	101,982		$	120,346
Amount of gain reclassified from accumulated OCI into income (effective portion), net of tax (a)	15,255			17,331			42,078			45,549
Amount of gain (loss) recognized in income (ineffective portion) (b)	(352		)	2,980			(613		)	2,367

Derivatives designated as fair value hedges (c)
Amount of gain (loss) recognized in income for fair value commodity contracts	$	4,261		$		–	$	3,728		$		–
Fair value gain (loss) recognized in income for inventory designated as hedged item	$	(3,781	)	$		–	$	(2,088	)	$		–

Derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in income	$	2,663		$	(1,323	)	$	1,840		$	(1,234	)

(a) Includes $2.1 million for the three and nine month periods ended September 30, 2011, of unrealized hedge gains reclassified into earnings to offset lower of cost or market adjustments on hedged items. Includes $7.9 million and $10.5 million for the three and nine month periods ended September 30, 2010, respectively, 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 September 30, 2011, the net impact on operating revenues consisted of a $0.8 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. For nine months ended September 30, 2011, the net impact on operating revenues consisted of a $2.3 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.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	September 30, 2011		December 31, 2010
	(Thousands)
Asset derivatives
Derivatives designated as hedging instruments	$	231,946	$	141,834
Derivatives not designated as hedging instruments	81,591		83,505
Total asset derivatives	$	313,537	$	225,339

Liability derivatives
Derivatives designated as hedging instruments	$	11,933	$	12,097
Derivatives not designated as hedging instruments	96,993		94,624
Total liability derivatives	$	108,926	$	106,721

In August 2011, the Company entered into a forward-starting interest rate swap to mitigate the risk of rising interest rates. The forward-starting interest rate swap was designated as a cash flow hedge of forecasted future interest payments. The Company recorded a deferred loss of $4.7 million in accumulated other comprehensive income, net of tax, as of September 30, 2011, associated with the change in fair value of the forward-starting interest rate swap. Additionally, the forward-starting interest rate swap is included in the liability derivatives designated as hedging instruments in the table above.

The net fair value of derivative instruments changed during the first nine months of 2011 primarily as a result of the positive net fair value of derivatives executed in 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 221 Bcf and 181 Bcf as of September 30, 2011 and December 31, 2010, respectively, and are primarily related to natural gas swaps and collars. The open positions at September 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 September 30, 2011. No derivative commodity instruments were designated as fair value hedges as of December 31, 2010.

The Company had net deferred gains of $129.8 million and $65.2 million in accumulated other comprehensive income, net of tax, as of September 30, 2011 and December 31, 2010, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $78.6 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income, net of tax, as of September 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 futures 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 September 30, 2011 or December 31, 2010, respectively.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 contract and are subject to change at the exchanges’ discretion. The Company recorded a current asset of $1.8 million as of September 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 the Company’s credit ratings by Standard & Poor’s Rating Services (S&P) or Moody’s Investor Services (Moody’s) 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 September 30, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $2.3 million, for which the Company had no collateral posted on September 30, 2011. If the Company’s credit rating had been downgraded by S&P or Moody’s below investment grade on September 30, 2011, the Company would have been required to post additional collateral of $2.3 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 S&P, Baa2 by Moody’s and BBB by Fitch Ratings Service (Fitch) at September 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 nine month period ended September 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.

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 fair 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, including the forward-starting interest rate swap, 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.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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.

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	September 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	$	313,537	$	7,014	$	193,439	$	113,084
Total assets	$	313,537	$	7,014	$	193,439	$	113,084

Liabilities
Derivative instruments, at fair value	$	108,926	$	8,271	$	100,655	$	–
Total liabilities	$	108,926	$	8,271	$	100,655	$	–

	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	35,121
Settlements	(38,723		)
Transfers in and/or out of Level 3	–
Balance at September 30, 2011	$	113,084

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 September 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 September 30, 2011 and December 31, 2010 was approximately $2 billion. The fair value was estimated using the Company’s established fair value methodology primarily 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, net of tax, was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2011	2010	2011		2010
	(Thousands)
Net income	$178,914	$ 36,522	$ 388,923		$ 154,587
Other comprehensive (loss) income:
Net change in cash flow hedges	49,304	41,816	59,992		74,885
Unrealized (loss) gain on investments, available- for-sale	–	2,252	(4,896	)	753
Pension and other post-retirement benefit plans	412	405	1,236		1,211
Total comprehensive income (loss)	$228,630	$ 80,995	$ 445,255		$ 231,436

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

	September 30,			December 31,
	2011			2010
	(Thousands)
Net unrealized gain from hedging transactions	$	125,006		$	65,014
Unrealized gain on available-for-sale securities	–			4,896
Pension and other post-retirement benefits adjustment	(30,570		)	(31,806		)
Accumulated other comprehensive income	$	94,436		$	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 nine months ending September 30, 2011 was 37.1%, including a 38.2% discrete tax rate for the Big Sandy Pipeline gain. The Company currently estimates the 2011 annual effective income tax rate to be approximately 36.9%. The estimated annual effective income tax rate as of September 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 nine months ended September 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.

H. Short-Term Loans

As of September 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 7.5 basis points in the third quarter of 2011 and 2.0 basis points in the third quarter of 2010 were paid to maintain credit availability under the revolving credit facility.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The maximum amount of outstanding short-term loans at any time during the nine months ended September 30, 2011 and 2010 was $104.0 million and $139.7 million, respectively. The average daily balance of short-term loans outstanding during the nine months ended September 30, 2011 and 2010 was approximately $7.3 million and $17.7 million, respectively, at weighted average annual interest rates of 1.81% and 0.86%, respectively.

I. Long-Term Debt

	September 30,		December 31,
	2011		2010
	(Thousands)
7.76% notes, due 2012 thru 2016	$	54,711	$	–
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
	2,003,911		1,949,200
Less debt payable within one year	25,315		6,000
Total long-term debt	$	1,978,596	$	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 the Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.

Aggregate maturities of long-term debt are $6.0 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.

Disclosures about Fair Value Measurements

In May 2011, the FASB issued a standard update intended to enhance the fair value disclosure requirements to result in common fair value measurement in United States generally accepted accounting principles (GAAP) and International Financial Reporting Standards (IFRS). The amendments are to be applied prospectively, and are

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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. Acquisition

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 which is 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 increase in 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 non-controlling 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 July 1, 2011, the Company sold the Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million. Big Sandy is a natural gas pipeline regulated by the Federal Energy Regulatory Commission. 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. In conjunction with this transaction, the Company realized a pre-tax gain of $180.1 million.

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.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 1,327,494 for the three months ended September 30, 2010, and 6,480 and 1,249,037 for the nine months ended September 30, 2011 and September 30, 2010 respectively. There were no anti-dilutive shares for the three months ended September 30, 2011.

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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,” “could,” “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 section 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 Equitrans Marcellus Expansion Project) and technology, the Company’s expected use of proceeds from the sale of the Big Sandy Pipeline and the Langley natural gas processing complex, the expected incremental Marcellus gathering capacity to be added throughout 2011, midstream structural alternatives, 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.

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.

CORPORATE OVERVIEW

The Company completed several transactions in the first nine months of 2011 that had a positive impact on results for the period ending September 30, 2011, including:

·	The July 2011 sale of the Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million, which resulted in a pre-tax gain of $180.1 million. This transaction resulted in tax expense of $68.8 million.
·	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 interests (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.

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·	Sales of available-for-sale securities for proceeds of $29.9 million, which resulted in pre-tax gains of $8.5 million.

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

In July 2011 the Company commissioned its 150 MMcfe per day Callisto Compressor Station in Greene County, Pennsylvania in support of the increased drilling activity in the Marcellus play.

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

EQT Corporation’s consolidated net income increased $142.4 million, to $1.19 per diluted share from $0.24 per diluted share, for the three months ended September 30, 2011 compared to the same period in 2010. Approximately $111.3 million of net income, or $0.74 per diluted share, resulted from the realized gain, net of tax, on the sale of the Big Sandy Pipeline. Operationally, the Company was favorably impacted by a 50.9% increase in production sales volumes and increased gathering revenues, partially offset by increased depreciation, depletion and amortization and operating expenses as a result of the increase in production and a lower average wellhead sales price.

The average wellhead sales price to EQT Corporation was $5.25 per Mcfe during the third quarter 2011 compared to $5.52 per Mcfe in the same period of the prior year. NYMEX price decreased $0.19 for the three months ended September 30, 2011 compared to the prior year. Hedging activities resulted in an increase in the average natural gas price of $0.47 per Mcf in 2011 compared to $0.58 per Mcf in 2010, with the difference mainly resulting from the non-cash benefit for ineffectiveness associated with certain cash flow hedges recognized in 2010.

Nine Months Ended September 30, 2011 vs. Nine Months Ended September 30, 2010

EQT Corporation’s consolidated net income increased $234.3 million, to $2.59 per diluted share from $1.07 per diluted share, in the nine months ended September 30, 2011 compared to 2010. Excluding $0.91 per diluted share from the gains described above, this increase was driven by a 47.4% increase in production sales volumes, higher gathering revenues, transmission revenues, and reductions in certain non-income tax reserves. 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 $5.42 per Mcfe in 2011 compared to $5.75 per Mcfe in 2010. NYMEX price decreased $0.38, while impact from hedging activities remained relatively flat from 2010 to 2011.

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

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EQT CORPORATION

	Three Months Ended September 30,			Nine Months Ended September 30,
	2011	2010	%	2011	2010	%
OPERATIONAL DATA
Average wellhead sales price to EQT Corporation:
Natural gas excluding hedges ($/Mcf)	$ 4.21	$ 4.40	(4.3)	$ 4.37	$ 4.68	(6.6)
Hedge impact ($/Mcf of natural gas) (a)	$ 0.47	$ 0.58	(19.0)	$ 0.46	$ 0.48	(4.2)
Natural gas including hedges ($/Mcf)	$ 4.68	$ 4.98	(6.0)	$ 4.83	$ 5.16	(6.4)

NGLs ($/Bbl)	$ 52.56	$ 43.89	19.8	$ 52.12	$ 46.69	11.6
Crude oil ($/Bbl)	$ 81.66	$ 62.39	30.9	$ 83.52	$ 70.37	18.7
Total ($/Mcfe)	$ 5.25	$ 5.52	(4.9)	$ 5.42	$ 5.75	(5.7)

Less revenues to EQT Midstream ($/Mcfe)	$ 1.23	$ 1.71	(28.1)	$ 1.37	$ 1.70	19.4
Average wellhead sales price to EQT Production ($/Mcfe)	$ 4.02	$ 3.81	5.5	$ 4.05	$ 4.05	_


NYMEX natural gas ($/Mcf)	$ 4.19	$ 4.38	(4.3)	$ 4.21	$ 4.59	(8.3)

Natural gas sales volumes (MMcf)	48,070	31,087	54.6	132,035	87,746	50.5
NGL sales volumes (Mbbls)	759	697	9.0	2,259	1,982	14.0
Crude oil sales volumes (Mbbls)	61	36	69.4	141	86	64.0
Total production sales volumes (MMcfe) (b)	51,298	33,988	50.9	141,375	95,903	47.4

Capital expenditures (thousands) (c)	$ 347,645	$ 340,151	2.2	$ 985,171	$1,093,698	(9.9)

(a)	All hedges are related to natural gas.
(b)	NGLs were converted to Mcfe at the rate of 3.76 Mcfe per barrel and 3.86 Mcfe per barrel based on the liquids content for the three and nine months ended September 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.

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EQT PRODUCTION

RESULTS OF OPERATIONS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010		%	2011		2010		%
OPERATIONAL DATA

Natural gas, NGL and crude oil production (MMcfe) (a)	52,456		35,334		48.5	145,021		99,520		45.7
Company usage, line loss (MMcfe)	(1,158)		(1,346)		(13.9)	(3,646)		(3,617)		0.8
Total production sales volumes (MMcfe)	51,298		33,988		50.9	141,375		95,903		47.4

Average daily sales volumes (MMcfe/d)	558		369		51.2	518		351		47.6

Sales volume detail (MMcfe):
Horizontal Marcellus Play	22,401		6,372		251.6	56,896		15,134		275.9
Horizontal Huron Play	9,815		9,953		(1.4)	30,175		28,075		7.5
CBM Play	3,479		3,513		(1.0)	10,254		10,007		2.5
Other (vertical non-CBM)	15,603		14,150		10.3	44,050		42,687		3.2
Total production sales volumes	51,298		33,988		50.9	141,375		95,903		47.4

Average wellhead sales price ($/Mcfe)	$	4.02	$	3.81	5.5	$	4.05	$	4.05	0.0

Lease operating expenses, excluding production taxes (LOE) ($/Mcfe)	$	0.22	$	0.22	0.0	$	0.21	$	0.24	(12.5)
Production taxes ($/Mcfe)	$	0.25	$	0.23	8.7	$	0.21	$	0.25	(16.0)
Production depletion ($/Mcfe)	$	1.23	$	1.26	(2.4)	$	1.24	$	1.26	(1.6)

Depreciation, depletion and amortization (DD&A) (thousands):
Production depletion	$	64,742	$	44,609	45.1	$	180,063	$	125,113	43.9
Other DD&A	2,205		2,049		7.6	6,617		5,923		11.7
Total DD&A	$	66,947	$	46,658	43.5	$	186,680	$	131,036	42.5

Capital expenditures (thousands) (b)	$	255,151	$	267,154	(4.5)	$	800,029	$	929,225	(13.9)


FINANCIAL DATA (Thousands)


Total operating revenues	$	207,500	$	131,791	57.4	$	577,352	$	395,182	46.1

Operating expenses:
LOE	11,612		7,857		47.8	29,760		24,056		23.7
Production taxes (c)	13,296		8,153		63.1	31,024		25,107		23.6
Exploration expense	814		941		(13.5)	3,387		3,354		1.0
Selling, general and administrative (SG&A)	15,895		12,531		26.8	45,477		41,832		8.7
DD&A	66,947		46,658		43.5	186,680		131,036		42.5
Total operating expenses	108,564		76,140		42.6	296,328		225,385		31.5
Operating income	$	98,936	$	55,651	77.8	$	281,024	$	169,797	65.5

(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 in 2011 and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010.
(c)	Production taxes include severance and production-related ad valorem and other property taxes.

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

EQT Production’s operating income totaled $98.9 million for the three months ended September 30, 2011 compared to $55.7 million for the three months ended September 30, 2010. The $43.3 million increase in operating income was primarily the result of increases in sales of produced natural gas and in the average well-head sales price, partially offset by higher operating expenses.

Total operating revenues were $207.5 million for the three months ended September 30, 2011 compared to $131.8 million for the three months ended September 30, 2010. The $75.7 million increase in total operating revenues was primarily due to a 50.9% increase in produced natural gas sales volumes as well as a 5.5% increase in the average well-head sales price. The increase in produced natural gas sales volumes was the result of increased production from the 2010 and 2011 drilling programs, primarily in the Marcellus Shale play, as well as the acquisition of producing properties associated with the ANPI transaction in May 2011, which added 2.0 Bcfe of sales volumes in the third 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 $0.21 per Mcfe increase in the average well-head sales price was primarily due to lower gathering rates and a higher sales price for NGLs and oil in the current year partially offset by a 4.3% decrease in the average NYMEX price and lower hedging gains compared to the third quarter of 2010.

Operating expenses totaled $108.6 million for the three months ended September 30, 2011 compared to $76.1 million for the three months ended September 30, 2010. The increase in operating expenses was the result of increases in production depletion, production taxes, LOE and SG&A. The increase in depletion expense reflects an increase in volumes ($21.6 million) offset by a decrease in the unit rate ($1.5 million). Production taxes increased due to higher revenues and increased assessments in certain jurisdictions that were incurred in the current year. The increase in LOE was primarily the result of increased activity 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. SG&A expenses increased primarily due to higher overhead costs associated with the growth of the Company as well as increased labor and related incentive compensation costs.

Nine months ended September 30, 2011 vs. Nine months ended September 30, 2010

EQT Production’s operating income totaled $281.0 million for the nine months ended September 30, 2011 compared to $169.8 million for the nine months ended September 30, 2010. The $111.2 million increase in operating income was primarily due to increased production sales volumes, partially offset by an increase in DD&A.

Total operating revenues were $577.4 million for the nine months ended September 30, 2011 compared to $395.2 million for the nine months ended September 30, 2010. The $182.2 million increase in total operating revenues was primarily due to a 47.4% increase in sales volumes of produced natural gas while the average well-head sales price was flat between periods. The increase in produced natural gas sales volumes was the result of increased production from the 2010 and 2011 drilling programs, primarily in the Marcellus Shale and Huron plays, as well as the acquisition of producing properties associated with the ANPI transaction in May 2011, which added 3.4 Bcfe of sales volumes in the current year. The average well-head sales price remained flat as an 8.3% decrease in the average NYMEX price for natural gas was offset by lower gathering rates and higher sales prices for NGLs and oil in the current year.

Operating expenses totaled $296.3 million for the nine months ended September 30, 2011 compared to $225.4 million for the nine months ended September 30, 2010. The increase in operating expenses was the result of increases in production depletion, production taxes, LOE and SG&A. The depletion expense increased as a result of higher volumes in the current year. Production taxes increased due to higher revenues and increased assessments in certain jurisdictions during the year. The increase in LOE was primarily the result of increased activity in the current year as well as the elimination, as part of the ANPI transaction, of certain operating expense reimbursement arrangements. SG&A increased due to higher overhead costs associated with the growth of the Company and higher incentive compensation costs partially offset by a charge in the prior year related to the buy-out of excess contractual capacity for water treatment.

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EQT MIDSTREAM

RESULTS OF OPERATIONS

	Three Months Ended September 30,					Nine Months Ended September 30,

	2011		2010		%	2011		2010		%
OPERATIONAL DATA


Gathered volumes (BBtu)	67,304		49,990		34.6	188,492		142,074		32.7
Average gathering fee ($/MMBtu)	$	0.94	$	1.08	(13.0)	$	0.97	$	1.10	(11.8	)
Gathering expense ($/MMBtu)	$	0.33	$	0.40	(17.5)	$	0.26	$	0.38	(31.6	)
Transmission pipeline throughput (BBtu)	38,121		27,138		40.5	117,122		76,196		53.7


Net operating revenues (thousands):
Gathering	$	63,285	$	54,014	17.2	$	183,523	$	153,777	19.3
Transmission	18,339		19,497		(5.9)	69,294		59,057		17.3
Storage, marketing and other	12,380		18,975		(34.8)	45,547		74,423		(38.8	)
Total net operating revenues	$	94,004	$	92,486	1.6	$	298,364	$	287,257	3.9


Unrealized gains (losses) on derivatives and inventory (thousands) (a)	$	1,396	$	28	–	$	1,850	$	(794)	–

Capital expenditures (thousands)	$	81,227	$	59,499	36.5	$	156,832	$	138,479	13.3


FINANCIAL DATA (Thousands)


Total operating revenues	$	122,614	$	144,634	(15.2)	$	395,477	$	436,225	(9.3	)
Purchased gas costs	28,610		52,148		(45.1)	97,113		148,968		(34.8	)
Total net operating revenues	94,004		92,486		1.6	298,364		287,257		3.9

Operating expenses:
Operating and maintenance (O&M)	25,348		29,391		(13.8)	59,708		77,375		(22.8	)
SG&A	12,890		11,532		11.8	35,010		33,379		4.9
DD&A	14,093		15,705		(10.3)	43,097		46,240		(6.8	)
Total operating expenses	52,331		56,628		(7.6)	137,815		156,994		(12.2	)
Operating income	$	41,673	$	35,858	16.2	$	160,549	$	130,263	23.2

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

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

EQT Midstream’s operating income totaled $41.7 million for the three months ended September 30, 2011 compared to $35.9 million for the three months ended September 30, 2010. The $5.8 million increase in operating income was primarily the result of increased gathered volumes combined with lower operating expenses. These favorable variances were partially offset by decreased storage, marketing, and other net operating revenue and a lower average gathering fee.

Total net operating revenues were $94.0 million for the three months ended September 30, 2011 compared to $92.5 million for the three months ended September 30, 2010. Gathering net operating revenues increased $9.3 million as a result of a 35% increase in gathered volumes, primarily related to EQT Production’s increased produced natural gas in the Marcellus play, partially offset by a 13% decrease in the average gathering fee resulting from lower gathering rates in that play. Transmission net revenues decreased 6% from the prior year primarily as a result of the sale of the Big Sandy Pipeline during the quarter, which was partially offset by the increased sale of capacity associated with the initial phase of the Equitrans Marcellus expansion project which came on-line in the fourth quarter of 2010.

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Storage, marketing and other net revenues 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 gas processing complex. Higher NGL prices were substantially offset by lower liquid volumes marketed for non-affiliated producers. Decreased commercial activity resulted in decreases in both total operating revenues and purchased gas costs.

Operating expenses totaled $52.3 million for the three months ended September 30, 2011 compared to $56.6 million for the three months ended September 30, 2010. The decrease in operating expenses was primarily due to decrease of $4.0 million in O&M and $1.6 million in DD&A partially offset by a $1.4 million increase in SG&A. The decrease in O&M is primarily due to the absence of operating expenses associated with the recently sold Langley natural gas processing complex and Big Sandy Pipeline, as well as a reduction in property tax expense partially offset by increased labor costs. The decrease in DD&A is primarily due to the sale of assets associated with the Langley natural gas processing complex and the Big Sandy Pipeline. The increase in SG&A is primarily the result of increased labor costs.

Nine months ended September 30, 2011 vs. Nine months ended September 30, 2010

EQT Midstream’s operating income totaled $160.5 million for the nine months ended September 30, 2011 compared to $130.3 million for the nine months ended September 30, 2010. The $30.3 million increase in operating income was primarily the 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 $11.1 million for the nine months ended September 30, 2011 compared to the prior year. Gathering net operating revenues increased $29.7 million as a result of a 32.7% increase in gathered volumes partially offset by a 11.8% 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 $10.2 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, partially offset by the absence of capacity associated with the sale of the Big Sandy Pipeline. Storage, marketing and other net operating revenues decreased $28.9 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. Higher NGL prices were more than offset by the loss of processing fees discussed above and lower liquid volumes marketed for non-affiliated producers.

Total operating revenues decreased $40.7 million as a result of lower sales prices on decreased commercial activity partially offset by an increase in gathered volumes and increased transmission revenues. Total purchased gas costs decreased 35% primarily as a result of lower gas costs on decreased commercial activity.

Operating expenses for the nine months ended September 30, 2011 decreased compared to the prior year primarily as a result of decreases of $17.7 million in O&M and $3.1 million in DD&A partially offset by a $1.6 million increase in SG&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 and Big Sandy Pipeline. The decrease in DD&A is primarily a result of the sale of assets associated with the Langley natural gas processing complex and the Big Sandy Pipeline. The increase in SG&A is primarily the result of increased labor costs.

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DISTRIBUTION

RESULTS OF OPERATIONS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010		%	2011		2010		%

OPERATIONAL DATA

Heating degree days (30 year average: Qtr - 114; YTD – 3,649) (a)	85		73		16.4	3,508		3,350		4.7

Residential sales and transportation volumes (MMcf)	1,175		1,131		3.9	15,893		15,234		4.3
Commercial and industrial volumes (MMcf)	4,398		3,990		10.2	21,140		20,820		1.5
Total throughput (MMcf) – Distribution	5,573		5,121		8.8	37,033		36,054		2.7

Net operating revenues (thousands):
Residential	$	13,640	$	13,642	0.0	$	83,736	$	80,605	3.9
Commercial & industrial	6,543		6,374		2.7	35,959		33,862		6.2
Off-system and energy services	6,837		4,206		62.6	18,107		15,816		14.5
Total net operating revenues	$	27,020	$	24,222	11.6	$	137,802	$	130,283	5.8

Capital expenditures (thousands)	$	10,149	$	9,382	8.2	$	25,179	$	21,107	19.3


FINANCIAL DATA (thousands)


Total operating revenues	$	49,175	$	53,208	(7.6)	$	313,366	$	338,812	(7.5)
Purchased gas costs	22,155		28,986		(23.6)	175,564		208,529		(15.8)
Net operating revenues	27,020		24,222		11.6	137,802		130,283		5.8


Operating expenses:
O&M	10,414		11,027		(5.6)	31,466		32,607		(3.5)
SG&A	7,609		6,494		17.2	23,164		27,256		(15.0)
DD&A	6,534		6,057		7.9	18,414		18,067		1.9
Total operating expenses	24,557		23,578		4.2	73,044		77,930		(6.3)
Operating income	$	2,463	$	644	282.5	$	64,758	$	52,353	23.7

(a) The 30-year heating degree days figures are derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures. In the second quarter 2011, the NOAA released updated heating degree days figures for the period 1981 to 2010 and accordingly, the 30-year heating degree days decreased from 124 and 3,759 for the three and nine months ended September 30, 2010 to 114 and 3,649 for the three and nine months ended September 30, 2011.

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

Distribution’s operating income totaled $2.5 million for the three months ended September 30, 2011, a $1.8 million increase as compared to the same quarter in 2010. The increase in operating income was primarily due to a change in estimated recoverable costs in 2011 partially offset by higher operating expenses.

Net operating revenues were $27.0 million for the three months ended September 30, 2011 compared to $24.2 million for the same period in 2010. The $2.8 million increase in net operating revenues was primarily due to a change in estimated recoverable costs. Distribution’s residential net operating revenues were essentially unchanged in 2011 as compared to the same quarter in 2010, as is typical during the summer months. The increase in commercial and industrial volumes from 2010 to 2011 was primarily due to increased usage by one industrial customer. These high volume industrial sales have low margins and did not significantly impact total net operating revenues. A decrease in asset optimization transactions also resulted in a decrease in both total operating revenues and purchased gas costs, but did not significantly impact total net operating revenues.

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Operating expenses totaled $24.6 million for the three months ended September 30, 2011 compared to $23.6 million for the three month period in the prior year. The $1.0 million increase in operating expenses was primarily due to increased labor costs. The increase in DD&A was primarily due to additional assets placed in service during 2010.

Equitable Gas’ contract with the members of the local United Steelworkers union expired on September 25, 2011. Equitable Gas and the union have agreed to work under the terms of the expired contract while negotiating a new contract.

Nine months ended September 30, 2011 vs. Nine months ended September 30, 2010

Distribution’s operating income totaled $64.8 million for the nine months ended September 30, 2011 compared to $52.4 million for the nine months ended September 30, 2010. The $12.4 million increase in operating income was primarily the result of higher sales volumes due to colder weather, an increase in the Company’s West Virginia base rates, the reversal of operating reserves in 2011 and a decrease in operating expenses.

Net operating revenues were $137.8 million for the nine months ended September 30, 2011, an increase of $7.5 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 increase 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 during 2011 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 nine months of 2011 was 4.7% colder than first the nine months of 2010. Commercial and industrial net revenues increased $2.1 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 increased $2.3 million due to the reversal of operating reserves in 2011 and higher revenues from gathering activities resulting from increased rates. These increases were partially offset by fewer asset optimization opportunities realized in 2011. A decrease in the commodity component of residential tariff rates and fewer asset optimization transactions resulted in a decrease in both total operating revenues and purchased gas costs.

Operating expenses totaled $73.0 million for the nine months ended September 30, 2011 compared to $77.9 million for the nine months ended September 30, 2010. This $4.9 million 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 Marcellus shale formations in Pennsylvania and West Virginia. 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. Due to oil field inflation, we are increasing our cost per well estimate from $6 million per well to $6.7 million per well. The cost per well assumes 5,300 feet of lateral pay and a standard frac design.

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 expects sales of produced natural gas in 2011 to be 195 Bcfe; the high end of our previous guidance of between 190 and 195 Bcfe. The Company also reiterates the 2012 guidance of more than 250 Bcfe.

To support the drilling growth, the Company plans to add approximately 310 MMcfe per day of incremental Marcellus gathering capacity throughout 2011, of which 150 MMcfe has already been added through its Callisto Compressor Station. The Company will continue to add to its gathering capacity in support of EQT Production’s growth. The Company is evaluating a number of structural alternatives for its midstream business in order to finance anticipated capital investments.

On September 8, 2011, the Company received approval from the Federal Energy Regulatory Commission to proceed with construction of Phase II of the Equitrans Marcellus expansion project. The Equitrans Marcellus expansion project will expand Equitrans’ existing mainline transmission system by adding 41.5 miles of 24-inch-diameter pipeline and 2.7 miles of 16-inch-diameter pipeline that runs from Wetzel County, West Virginia to Greene County, Pennsylvania along with a new compressor station in Greene County to provide transport capacity for volumes from the increased drilling activity in the Appalachian basin.

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CAPITAL RESOURCES AND LIQUIDITY

Overview

The Company’s primary sources of cash for the first nine months of 2011 were cash flows from operating activities and proceeds from the sales of the Big Sandy Pipeline and Langley natural gas processing complex. The Company is using the cash primarily to fund its capital program and operations.

Operating Activities

Cash flows provided by operating activities during the nine months ended September 30, 2011 were $713.3 million compared to $621.0 million for the same period of 2010. The increase in cash flows provided by operating activities was primarily attributable to higher operating receipts as a result of increased production partially offset by a $121.5 million federal income tax carryback refund received in 2010.

Investing Activities

Net cash flows used in investing activities totaled $219.1 million for the first nine months of 2011 and $863.8 million for the first nine months of 2010. The decrease in cash flows used in investing activities was primarily attributed to 2011 proceeds from the sales of the Big Sandy Pipeline, the Langley natural gas processing complex, available-for-sale securities and a dividend received from Nora Gathering, LLC. Capital expenditures totaled $892.6 million for the first nine months of 2011 and $863.0 million for the first nine months of 2010. The Company is currently forecasting capital expenditures for 2011, excluding the ANPI transaction, of approximately $1.41 billion including approximately $50 million for lease acquisitions.

The Company commenced drilling on (drilled) 180 gross wells during the first nine months of 2011. Of these wells, 178 were horizontal wells; 87 targeting the Marcellus play and 91 targeting the Huron play. The Company drilled 402 gross wells, including 270 horizontal wells, during the first nine months of 2010; 79 targeting the Marcellus play and 191 targeting the Huron play. Capital expenditures for drilling and development were $8.9 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 its 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 EQT Midstream totaled $156.8 million and $138.5 million during the first nine months of 2011 and 2010, respectively. Expenditures for both years were primarily for gathering pipeline and compression projects. The $18.3 million increase in capital expenditures for 2011 was primarily for pipeline and compression projects associated with the Equitrans Marcellus expansion project, partially offset by the absence of 2010 upgrades to the Langley natural gas processing complex which was sold earlier this year.

Capital expenditures at Distribution totaled $25.2 million for the first nine months of 2011 compared to $21.1 million for the first nine 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.

Financing Activities

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Cash flows used by financing activities totaled $159.3 million for the first nine months of 2011 compared to $440.1 million provided by financing activities for the first nine 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.

Security Ratings

The table below reflects the credit ratings for the outstanding debt instruments of the Company at September 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.

	Senior	Short-Term
Rating Service	Notes	Rating
Moody’s Investors Service	Baa2	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 August 24, 2011, Moody’s downgraded its ratings on EQT to Baa2 from Baa1. The outlook is stable. Moody’s stated that the “ratings reflect the company’s credit profile as compared to other independent E&P companies with some added lift provided by its ownership of a lower risk natural gas utility.”

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 September 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 October 26, 2011 the approximate volumes and prices of the Company’s total hedge position for 2011 through 2014 production are:

	2011**		2012		2013		2014
Swaps
Total Volume (Bcf)	23		80		29		–
Average Price per Mcf (NYMEX)*	$	4.88	$	5.31	$	5.64	–

	2011**		2012		2013		2014
Puts
Total Volume (Bcf)	1		–		–		–
Average Floor Price per Mcf (NYMEX)*	$	7.35	–		–		–

	2011**		2012		2013		2014
Collars
Total Volume (Bcf)	5		21		15		14
Average Floor Price per Mcf (NYMEX)*	$	6.51	$	6.51	$	6.12	$	6.37
Average Cap Price per Mcf (NYMEX)*	$	11.83	$	11.83	$	11.80	$	11.55

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

**October 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 $1.5 million over the final three 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 October 12, 2011, the Board of Directors declared a regular quarterly cash dividend of 22 cents per share, payable December 1, 2011, to shareholders of record on November 4, 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 September 30, 2011. The application of the Company’s critical accounting policies may require management

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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.

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 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 and 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 September 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 214 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 September 30, 2011 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $86.4 million. A hypothetical increase of 10% in the market price of natural gas from the September 30, 2011 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $84.8 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 of Notes to Consolidated Financial Statements contained in Item 8, Financial Statements and Supplementary Data of 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 September 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

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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 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 75%, or $306.5 million, of OTC derivative contracts outstanding at September 30, 2011 have a positive fair value. All derivative contracts outstanding as of September 30, 2011 are with counterparties having an S&P rating of A or above at that date.

As of September 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 September 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 third 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

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: October 27, 2011

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INDEX TO EXHIBITS

Exhibit No.	Document Description	Incorporated by Reference

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