Edgar Filing: EQT Corp

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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, 2012

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

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-3551

EQT CORPORATION

(Exact name of registrant as specified in its charter)

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

625 Liberty Avenue, 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, 2012, 149,613,335 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, 2012 and 2011	3

	Statements of Consolidated Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011	4

	Statements of Condensed Consolidated Cash Flows for the Nine Months Ended September 30, 2012 and 2011	5

	Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	6 – 7

	Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, 2012 and 2011	8

	Notes to Condensed Consolidated Financial Statements	9 – 20

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21 – 33

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34 – 36

Item 4.	Controls and Procedures	37

Part II. Other Information:

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 6.	Exhibits	40

Signature		41

Index to Exhibits		42

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EQT CORPORATION AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
	(Thousands, except per share amounts)

Operating revenues	$	364,057		$	362,644	$	1,151,821	$	1,203,130

Operating expenses:
Purchased gas costs	34,394			34,121		158,127		189,609
Operation and maintenance	36,259			35,872		105,464		91,513
Production	23,201			24,908		72,796		60,784
Exploration	1,163			814		4,878		3,387
Selling, general and administrative	51,481			44,745		136,201		124,572
Depreciation, depletion and amortization	131,611			87,343		354,817		247,627
Total operating expenses	278,109			227,803		832,283		717,492
(Loss) gain on dispositions	(187		)	180,143		923		202,928
Operating income	85,761			314,984		320,461		688,566
Other income	2,988			3,098		12,918		27,948
Interest expense	40,460			32,503		122,341		98,642

Income before income taxes	48,289			285,579		211,038		617,872
Income taxes	11,585			106,665		70,853		228,949
Net income	36,704			178,914		140,185		388,923
Less: Net income attributable to noncontrolling interests	4,831			—		4,831		—
Net income attributable to EQT Corporation	$	31,873		$	178,914	$	135,354	$	388,923

Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common shares outstanding	149,604			149,441		149,555		149,373
Net income	$	0.21		$	1.20	$	0.91	$	2.60
Diluted:
Weighted average common shares outstanding	150,388			150,301		150,270		150,144
Net income	$	0.21		$	1.19	$	0.90	$	2.59
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 Consolidated Comprehensive Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(Thousands)

Net income attributable to EQT Corporation	$	31,873		$	178,914		$	135,354		$	388,923

Other comprehensive (loss) income, net of tax:
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of ($62,383), $29,591, ($65,488) and $36,042 (see Note D)	(96,680		)	53,949			(101,394		)	64,579
Interest rate, net of tax (benefit) of ($1,322), ($3,249), ($4,487) and ($3,249) (see Note D)	(1,734		)	(4,645		)	(5,902		)	(4,587		)
Unrealized loss on available-for-sale securities, net of tax of $2,636	—			—			—			(4,896		)
Pension and other post-retirement benefits liability adjustment, net of tax of $369, $282, $583 and $845	455			412			1,891			1,236
Other comprehensive (loss) income	(97,959		)	49,716			(105,405		)	56,332
Comprehensive (loss) income	(66,086		)	228,630			29,949			445,255
Less: Comprehensive (loss) income attributable to noncontrolling interests	—			—			—			—
Comprehensive (loss) income attributable to EQT Corporation	$	(66,086	)	$	228,630		$	29,949		$	445,255

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,
	2012			2011
	(Thousands)
Cash flows from operating activities:
Net income	$	140,185		$	388,923
Adjustments to reconcile net income to cash provided by operating activities:
Recovery for losses on accounts receivable	(3,187		)	(176		)
Depreciation, depletion and amortization	354,817			247,627
Unrealized losses (gains) on derivatives and inventory	2,897			(3,905		)
Other income	(12,918		)	(27,948		)
Gain on dispositions	(923		)	(202,928		)
Equity award expense	28,752			15,118
Deferred income taxes	45,473			190,330
Noncash financial instrument put premiums	8,227			—

Changes in other assets and liabilities:
Dividend from Nora Gathering LLC	7,750			23,500
Inventory	35,981			467
Accounts receivable and unbilled revenues	50,870			66,952
Accounts payable	(10,001		)	37,535
Other assets and liabilities	22,047			1,340
Net cash provided by operating activities	669,970			736,835

Cash flows from investing activities:
Capital expenditures	(1,023,503		)	(892,557		)
Proceeds from sale of available-for-sale investments	—			29,947
Proceeds from sale of assets	4,842			619,999
Net cash used in investing activities	(1,018,661		)	(242,611		)

Cash flows from financing activities:
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs	276,780			—
Dividends paid	(98,840		)	(98,709		)
Decrease in short-term loans	—			(53,650		)
Repayments and retirements of long-term debt	(19,315		)	(9,457		)
Proceeds and tax benefits from exercises under employee compensation plans	1,831			2,504
Revolving credit facility origination fees	(4,022		)	—
Net cash provided by (used in) financing activities	156,434			(159,312		)

Net (decrease) increase in cash and cash equivalents	(192,257		)	334,912
Cash and cash equivalents at beginning of period	831,251			—
Cash and cash equivalents at end of period	$	638,994		$	334,912

Cash paid during the period for:
Interest, net of amount capitalized	$	93,872		$	76,934
Income taxes, net	$	17,193		$	35,628

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,		December 31,
	2012		2011
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	638,994	$	831,251
Accounts receivable (less accumulated provision for doubtful accounts September 30, 2012 and December 31, 2011: $10,684 and $16,371)	126,022		153,321
Unbilled revenues	9,874		30,257
Inventory	88,171		123,960
Derivative instruments, at fair value	319,203		512,161
Prepaid expenses and other	45,663		39,184
Total current assets	1,227,927		1,690,134

Equity in nonconsolidated investments	133,861		136,972

Property, plant and equipment	9,781,025		8,768,713
Less: accumulated depreciation and depletion	2,288,586		1,962,404
Net property, plant and equipment	7,492,439		6,806,309

Regulatory assets	102,774		94,095
Other assets	40,699		45,209
Total assets	$	8,997,700	$	8,772,719

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,			December 31,
	2012			2011
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	223,204		$	219,315
Accounts payable	246,756			256,757
Derivative instruments, at fair value	125,452			123,306
Other current liabilities	223,526			205,532
Total current liabilities	818,938			804,910

Long-term debt	2,503,333			2,527,627
Deferred income taxes and investment tax credits	1,599,097			1,618,944
Other credits	228,561			227,408
Total liabilities	5,149,929			5,178,889

Equity:
Stockholders’ equity
Common stock, no par value, authorized 320,000 shares; shares issued September 30, 2012 and December 31, 2011: 175,684 and 175,684	1,773,570			1,734,994
Treasury stock, shares at cost: September 30, 2012 and December 31, 2011: 26,071 and 26,207	(470,732		)	(473,215		)
Retained earnings	2,180,424			2,143,910
Accumulated other comprehensive income	82,736			188,141
Total common stockholders’ equity	3,565,998			3,593,830
Noncontrolling interests in consolidated subsidiaries	281,773			—
Total equity	3,847,771			3,593,830
Total liabilities and equity	$	8,997,700		$	8,772,719

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

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EQT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Equity (Unaudited)

	Common Stock						Accumulated Other			Noncontrolling Interests in		Total Common
	Shares Outstanding	No Par Value		Retained Earnings			Comprehensive Income (Loss)			Consolidated Subsidiaries		Stockholders’ Equity
	(Thousands)
Balance, January 1, 2011	149,153	$	1,244,826	$	1,795,766		$	38,104		$	—	$	3,078,696
Net income				388,923								388,923
Other comprehensive income							56,332					56,332
Dividends on common stock				(98,709		)						(98,709		)
Stock-based compensation plans, net	285	12,495										12,495
Balance, September 30, 2011	149,438	$	1,257,321	$	2,085,980		$	94,436		$	—	$	3,437,737

Balance, January 1, 2012	149,477	$	1,261,779	$	2,143,910		$	188,141		$	—	$	3,593,830
Net income				135,354						4,831		140,185
Other comprehensive (loss)							(105,405		)			(105,405		)
Dividends on common stock				(98,840		)						(98,840		)
Stock-based compensation plans, net	136	35,688								162		35,850
Issuance of common units of EQT Midstream Partners, LP										276,780		276,780
Deferred taxes related to IPO of EQT Midstream Partners, LP		5,371										5,371
Balance, September 30, 2012	149,613	$	1,302,838	$	2,180,424		$	82,736		$	281,773	$	3,847,771

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

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A. Financial Statements

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of September 30, 2012 and December 31, 2011, the results of its operations for the three and nine month periods ended September 30, 2012 and 2011 and its cash flows for the nine month periods ended September 30, 2012 and 2011. 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, 2011 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, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

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, 2011 as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 21 of this document.

B. EQT Midstream Partners, LP

On July 2, 2012, EQT Midstream Partners, LP (the Partnership), a subsidiary of the Company, completed an underwritten initial public offering (IPO) of 14,375,000 common units representing limited partner interests in the Partnership, which represented 40.6% of the Partnership’s outstanding equity. The Company retained a 59.4% equity interest in the Partnership, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest. Prior to the IPO, the Company contributed to the Partnership 100% of Equitrans, LP, (Equitrans, the Company’s Federal Energy Regulatory Commission (FERC) regulated transmission, storage and gathering subsidiary). A wholly-owned subsidiary of EQT serves as the general partner of the Partnership, and the Company continues to operate the Equitrans business pursuant to the contractual arrangements set forth below. The Company continues to consolidate the results of the Partnership but records an income tax provision only as to its ownership percentage. EQT records the noncontrolling interest of the public limited partners in EQT’s financial statements.

Also, in connection with the closing of the IPO:

· The Partnership, its general partner and EQT entered into an Omnibus Agreement (Omnibus Agreement), pursuant to which, among other things, EQT agreed to provide the Partnership with general and administrative services and a license to use the name “EQT” and related marks in connection with the Partnership’s business. The Omnibus Agreement also provides for certain indemnification and reimbursement obligations between EQT and the Partnership.

· EQT’s subsidiary EQT Gathering, LLC (EQT Gathering) and the Partnership entered into an operation and management services agreement (Services Agreement), pursuant to which EQT Gathering will provide the Partnership’s pipelines and storage facilities with certain operational and management services. The Services Agreement also provides for certain indemnification and reimbursement obligations between the Partnership and EQT Gathering.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

· The Partnership entered into a $350 million revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders, which will mature on July 2, 2017. The credit facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes. The Company is not a guarantor of the Partnership’s obligations under the credit facility.

· As a result of the IPO, the Company reversed $5.4 million of net deferred tax liability related to temporary differences between book and tax basis that will no longer impact the Company.

· The Company and the Partnership granted certain EQT employees, including executive officers of both entities, performance awards representing 146,490 common units. The Company accounted for these awards as equity awards using the grant date fair value. Additionally, the Partnership granted 4,780 share-based phantom units to each of the independent directors of its general partner, which units vested upon grant. The value of the phantom units will be paid in common units on the earlier of the director’s death or retirement from the general partner’s Board of Directors. The Company accounts for these awards as equity awards and as such, recorded compensation expense for the fair value of the awards at the grant date fair value.

The Partnership received cash proceeds, net of issuance costs, of approximately $277 million upon closing of the IPO which increased the noncontrolling interest component of total equity. Approximately $231 million of the proceeds were distributed to EQT, $12 million was retained by the Partnership to replenish amounts distributed by Equitrans to EQT prior to the IPO, $32 million was retained by the Partnership to pre-fund certain maintenance capital expenditures and $2 million was used by the Partnership to pay revolving credit facility origination fees associated with the revolving credit agreement entered into by the Partnership at the closing of the IPO.

C. Segment Information

Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and which 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, including ownership and operation of the Partnership. Distribution’s operations primarily comprise 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. Other income, interest 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. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments. As part of the 2012 budgeting process, the Company allocated additional corporate overhead charges to the operating segments. Current period corporate overhead costs have stayed relatively consistent with budgeted amounts; thus, unallocated expenses presented in the segment tables below have decreased for the three and nine month periods ended September 30, 2012.

The Company’s management reviews and reports the EQT Production segment results with third party transportation costs reflected as a deduction from operating revenues. During 2011, because of increased materiality of these costs, the Company determined that consolidated results are required to be reported on a gross basis with third-party transportation costs recorded as a portion of purchased gas costs. The consolidated operating revenues, purchased gas costs and total operating expenses for all periods presented have been adjusted to reflect this gross presentation. This adjustment had no impact on consolidated net income, consolidated operating income or on the segment results for any period presented. Management believes this adjustment is not material to the overall financial statement presentation.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(Thousands)
Revenues from external customers:
EQT Production	$	195,289		$	207,500		$	549,334		$	577,352
EQT Midstream	120,484			122,614			362,630			395,477
Distribution	35,649			49,175			219,343			313,366
Other (a)	12,635			(16,645		)	20,514			(83,065		)
Total	$	364,057		$	362,644		$	1,151,821		$	1,203,130
Operating income:
EQT Production (b)	$	38,341		$	98,936		$	116,193		$	281,024
EQT Midstream (b)	51,021			221,816			166,907			363,477
Distribution	685			2,463			43,831			64,758
Unallocated expenses	(4,286		)	(8,231		)	(6,470		)	(20,693		)
Total	$	85,761		$	314,984		$	320,461		$	688,566

Reconciliation of operating income to net income:

Other income	$	2,988		$	3,098		$	12,918		$	27,948
Interest expense	40,460			32,503			122,341			98,642
Income taxes	11,585			106,665			70,853			228,949
Total	$	36,704		$	178,914		$	140,185		$	388,923

	September 30,		December 31,
	2012		2011
	(Thousands)
Segment Assets:
EQT Production	$	5,458,646	$	5,256,645
EQT Midstream	1,990,056		1,785,089
Distribution	818,790		850,414
Total operating segments	8,267,492		7,892,148
Headquarters assets, including cash and short-term investments	730,208		880,571
Total assets	$	8,997,700	$	8,772,719

(a) Includes entries to eliminate intercompany natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and both EQT Production and Distribution. In addition, this amount reflects the reclassification of third party transportation costs from operating revenues to purchased gas costs at the consolidated level. Reduced activity between segments, lower prices and increased third-party transportation costs caused the change for the three and nine month periods presented.

(b) Losses on dispositions of $0.2 million and gains on dispositions of $0.9 million are included in EQT Production operating income for the three and nine month periods ended September 30, 2012 and gains on dispositions of $180.1 million and $202.9 million are included in EQT Midstream operating income for the three and nine month periods ended September 30, 2011. See Note K.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012		2011
	(Thousands)
Depreciation, depletion and amortization:
EQT Production	$	108,204		$	66,947		$	289,176	$	186,680
EQT Midstream	17,172			14,093			46,864		43,097
Distribution	6,237			6,534			18,767		18,414
Other	(2		)	(231		)	10		(564		)
Total	$	131,611		$	87,343		$	354,817	$	247,627

Expenditures for segment assets:
EQT Production (c)	$	255,223		$	255,151		$	703,834	$	800,029
EQT Midstream	97,135			81,227			296,698		156,832
Distribution	8,164			10,149			21,066		25,179
Other	661			1,118			1,905		3,131
Total	$	361,183		$	347,645		$	1,023,503	$	985,171

(c) Capital expenditures at EQT Production for the nine month period ended 2011 include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction discussed in Note J.

D. Derivative Instruments

Natural Gas Hedging Instruments

The Company uses derivative commodity instruments that are purchased from or placed with major financial institutions whose creditworthiness is regularly 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 a 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. 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 the Statements of Consolidated Income 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 of 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 for 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 in the Statements of Consolidated Income each period.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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

Some 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. Some 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.

In addition, the Company enters into a limited number of energy trading contracts to leverage its assets and limit its exposure to shifts in market prices and has a limited number of other derivative instruments not designated as hedges. In 2008 and 2011, the Company effectively settled certain derivative commodity swaps scheduled to mature during the period 2010 through 2013 by de-designating the instruments and entering into directly counteractive instruments. These transactions result in offsetting positions which are the majority of the derivative asset and liability balances not designated as hedging instruments.

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						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(Thousands)
Commodity derivatives designated as cash flow hedges
Amount of (loss) gain recognized in other comprehensive income (OCI) (effective portion), net of tax	$	(51,397	)	$	69,204		$	47,159		$	106,657
Amount of (loss) gain reclassified from accumulated OCI into operating revenues (effective portion), net of tax	$	45,283		$	15,255		$	148,553		$	42,078
Amount of gain (loss) recognized in operating revenues (ineffective portion) (a)	$	166		$	(352	)	$	(76	)	$	(613	)

Interest rate derivatives designated as cash flow hedges
Amount of (loss) recognized in OCI (effective portion), net of tax	$	(1,800	)	$	(4,674	)	$	(6,097	)	$	(4,674	)
Amount of (loss) reclassified from accumulated OCI into interest expense (effective portion), net of tax	$	(66	)	$	(29	)	$	(195	)	$	(87	)

Commodity derivatives designated as fair value hedges (b)
Amount of (loss) gain recognized in operating revenues for fair value commodity contracts	$	(3,051	)	$	4,261		$	1,644		$	3,728
Fair value gain (loss) recognized in operating revenues for inventory designated as hedged item	$	1,491		$	(3,781	)	$	(52	)	$	(2,088	)

Derivatives not designated as hedging instruments
Amount of (loss) gain recognized in operating revenues	$	(632	)	$	2,663		$	1,041		$	1,840

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

(b) For the three months ended September 30, 2012, the net impact on operating revenues consisted of a $1.1 million loss related to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.5 million loss due to changes in basis. For the three months ended September 30, 2011, the net impact on operating revenues consisted of a $0.8 million gain related 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 the nine months ended September 30, 2012, the net impact on operating revenues consisted of a $1.6 million

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.1 million gain due to changes in basis. For the nine months ended September 30, 2011, the net impact on operating revenues consisted of a $2.3 million gain related to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.7 million loss due to changes in basis.

	September 30,		December 31,
	2012		2011
	(Thousands)
Asset derivatives
Commodity derivatives designated as hedging instruments	$	263,141	$	412,626
Commodity derivatives not designated as hedging instruments	56,062		99,535
Total asset derivatives	$	319,203	$	512,161

Liability derivatives
Commodity derivatives designated as hedging instruments	$	42,043	$	3,681
Interest rate derivatives designated as hedging instruments	21,520		10,861
Commodity derivatives not designated as hedging instruments	61,889		108,764
Total liability derivatives	$	125,452	$	123,306

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 deferred losses of $13.5 million and $7.6 million in accumulated other comprehensive income, net of tax, as of September 30, 2012 and December 31, 2011, respectively, associated with the change in fair value of interest rate swaps.

The net fair value of commodity derivative instruments decreased during the first nine months of 2012 as a result of settlements and increased commodity prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 361 Bcf and 349 Bcf as of September 30, 2012 and December 31, 2011, respectively, and are primarily related to natural gas swaps and collars. The open positions at September 30, 2012 had maturities extending through December 2017. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as fair value hedges totaled 9 Bcf as of September 30, 2012 and December 31, 2011.

The Company deferred net gains of $130.7 million and $232.1 million in accumulated other comprehensive income, net of tax, as of September 30, 2012 and December 31, 2011, 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 $91 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income, net of tax, as of September 30, 2012 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, which may change as market prices change. The Company believes that New York Mercantile Exchange (NYMEX) traded futures contracts have reduced credit risk because 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 OTC swap and collar 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. These include closely monitoring current market conditions 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. As of September 30, 2012, all derivative contracts outstanding were with counterparties having a Standard & Poor’s Rating Services (S&P) rating of A- or higher and a Moody’s Investor Services (Moody’s) rating of Baa2 or higher.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 the 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, 2012 and December 31, 2011.

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 these deposits as a current asset in the Condensed Consolidated Balance Sheets. 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 the price, 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 $0.6 million and $0.1 million as of September 30, 2012 and December 31, 2011, respectively, 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 S&P or Moody’s are lowered below investment grade, additional collateral must be deposited with the counterparty. This additional collateral can be up to 100% of the derivative liability. As of September 30, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position was $8.7 million, for which the Company had no collateral posted. If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on September 30, 2012, the Company would have been required to post additional collateral of $1.5 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 long-term debt was rated BBB by S&P and Baa2 by Moody’s at September 30, 2012. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered to be non-investment grade.

E. Investments, Available-For-Sale

During the three and nine month periods ended September 30, 2012 and 2011, the Company did not purchase any investment securities.

During the nine month period ended September 30, 2011, the Company sold all of its available-for-sale securities for proceeds of $29.9 million which resulted in gross realized gains recorded as other income in the accompanying statements of consolidated income 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.

F. Fair Value Measurements

The Company records its financial instruments, principally derivative 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, 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.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value 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 and liabilities in Level 3 include the Company’s collars and a limited number of the Company’s swap agreements. Since the adoption of fair value accounting, the Company has not made any changes to its classification of assets and liabilities in each category.

The fair value of assets and liabilities included in Level 2 is based on standard industry income approach models that use significant observable inputs, including NYMEX and LIBOR forward curves and LIBOR-based discount rates. Collars included in Level 3 are valued using standard industry income approach models. The primary significant unobservable input to the valuation of assets and liabilities in Level 3 is the volatility assumption to the option pricing model used to value commodity collars. The Corporate Risk Control Group (CRCG), which reports to the Chief Financial Officer, is responsible for calculating the volatilities. The CRCG considers current market information about option trading and historical averages. The Company prepares an analytical review of all derivative instruments for reasonableness on at least a quarterly basis. At September 30, 2012, the range of Company derived market volatilities used to value Level 3 assets and liabilities was 25-54%. The fair value of the collar agreements is sensitive to changes in the volatility assumption. Significant changes in this assumption might result in significantly higher or lower fair values for these assets and liabilities. As of September 30, 2012, an increase in the volatility assumption would increase the value of the derivative asset and a decrease in the volatility assumption would decrease the value of the derivative asset. The Company uses NYMEX forward curves to value futures, commodity swaps and collars. The Company uses LIBOR forward curves to value interest rate swaps. The NYMEX and LIBOR 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, 2012		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	$	319,203	$	2,153	$	209,506	$	107,544
Total assets	$	319,203	$	2,153	$	209,506	$	107,544

Liabilities
Derivative instruments, at fair value	$	125,452	$	2,529	$	112,350	$	10,573
Total liabilities	$	125,452	$	2,529	$	112,350	$	10,573

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

			Fair value measurements at reporting date using
Description	December 31, 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	$	512,161	$	3,612	$	365,238	$	143,311
Total assets	$	512,161	$	3,612	$	365,238	$	143,311

Liabilities
Derivative instruments, at fair value	$	123,306	$	2,727	$	120,528	$	51
Total liabilities	$	123,306	$	2,727	$	120,528	$	51

	Fair value measurements using significant unobservable inputs (Level 3)
	Derivative instruments, at fair value, net three months ended September 30,						Derivative instruments, at fair value, net nine months ended September 30,
	2012			2011			2012			2011
	(Thousands)
Beginning of period	$	129,436		$	101,972		$	143,260		$	116,672
Total gains or losses:
Included in earnings	(90		)	—			(90		)	14
Included in other comprehensive income	(13,839		)	24,101			13,554			35,121
Purchases	22			—			(994		)	—
Settlements	(18,558		)	(12,989		)	(58,759		)	(38,723		)
Transfers in and/or out of Level 3	—			—			—			—
End of period	$	96,971		$	113,084		$	96,971		$	113,084

There are no material gains or losses included in earnings for the periods in the table above attributable to the change in unrealized gains or losses relating to assets and liabilities still held as of September 30, 2012 and 2011.

The carrying value of cash equivalents approximates fair value due to the short-term maturity of the instruments; these are considered Level 1 fair values.

The Company estimates the fair value of its debt using its established fair value methodology. Because not all of the Company’s debt is actively traded, the fair value of the debt is a Level 2 fair value. Fair value for non-traded debt obligations is estimated using a standard industry income approach model which utilizes a discount rate based on market rates for debt with similar remaining time to maturity and credit risk. The estimated fair value of long-term debt on the Condensed Consolidated Balance Sheets at September 30, 2012 and December 31, 2011 was approximately $3.1 billion and $3 billion, respectively.

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.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

The Company’s effective income tax rate for the nine months ending September 30, 2012 was 33.6%. The effective income tax rate for the nine months ended September 30, 2011 was 37.1%. The decrease in the effective tax rate from 2011 was attributable to a decrease in state taxes primarily as a result of lower pre-tax income on state tax paying entities in 2012, higher taxes on the sale of Big Sandy in 2011 and the impact of the Partnership IPO. As a result of the IPO, the Company records an income tax provision on its unit ownership percentage, which is currently 59.4% of the pre-tax income for the Partnership reported during each period.

As a result of the IPO, the Company reversed $5.4 million of net deferred tax liability because those temporary differences between book and tax basis that will no longer impact the Company.

During the second quarter of 2012 and 2011, the Company finalized settlements with the Internal Revenue Service (IRS) relating to its research and experimentation tax credits claimed from 2006 through 2009 and from 2001 through 2005, respectively. Except for refund claims from 2004 and 2005 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. The Company is currently under audit for the 2006 through 2009 periods. The examination of these periods began in the second quarter of 2010. The Company is also subject to 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, 2012 and December 31, 2011, neither the Company nor the Partnership had loans or letters of credit outstanding under their respective revolving credit facilities. Commitment fees averaging approximately 5 basis points in the third quarter of 2012 and 7.5 basis points in the third quarter of 2011 were incurred to maintain credit availability under the Company’s revolving credit facility. The Partnership incurred commitment fees averaging approximately 25 basis points in the third quarter of 2012 to maintain credit availability under its revolving credit facility.

Neither the Company nor the Partnership had any short-term loans outstanding at any time during the nine months ended September 30, 2012. The maximum amount of outstanding short-term loans at any time for the Company during the nine months ended September 30, 2011 was $104.0 million. The average daily balance of short-term loans outstanding for the Company during the nine months ended September 30, 2011 was approximately $7.3 million at a weighted average annual interest rate of 1.81%.

I. Long-Term Debt

	September 30,		December 31,
	2012		2011
	(Thousands)
7.76% notes, due 2012 thru 2016	$	33,337	$	53,742
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
4.88% notes, due November 15, 2021	750,000		750,000
7.75% debentures, due July 15, 2026	115,000		115,000
Medium-term notes:
8.7% to 9.0% Series A, due 2014 thru 2021	40,200		40,200
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
	2,726,537		2,746,942
Less debt payable within one year	223,204		219,315
Total long-term debt	$	2,503,333	$	2,527,627

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

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a ratings 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 long-term indebtedness.

Aggregate maturities of long-term debt are $200.0 million in 2012, $23.2 million in 2013, $11.2 million in 2014, $166.0 million in 2015 and $3.0 million in 2016.

J. 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 unrelated 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. At the time of the transaction, the notes had a fair value of $64.2 million.

Under U.S. generally accepted accounting principles (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 pre-tax gain of $10.1 million which was included in other income in the second quarter of 2011 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.

K. 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 FERC. Big Sandy transports natural gas from the natural gas processing complex in Langley, Kentucky to interconnections 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 in the third quarter of 2011.

On February 1, 2011, the Company sold its natural gas processing complex in Langley, Kentucky and the associated natural gas liquids pipeline for $230 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)

L. Recently Issued Accounting Standards

Disclosure about Offsetting Assets and Liabilities

In December 2011, the FASB issued a standards update intended to enhance disclosures by requiring additional information about financial instruments and derivative instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement. The update is to be applied prospectively and is effective for annual reporting periods beginning on or after January 1, 2013. The Company is currently evaluating the impact this standard will have on its financial statement disclosures.

M. Earnings Per Share

Potentially dilutive securities, consisting of options and restricted stock awards, which were included in the calculation of diluted earnings per share totaled 784,079 and 860,759 for the three months ended September 30, 2012 and 2011, respectively, and 715,512 and 771,035 for the nine months ended September 30, 2012 and 2011, respectively. Options to purchase common stock which were not included in potentially dilutive securities because they were anti-dilutive totaled 3,228 and 0 for the three months ended September 30, 2012 and 2011, respectively, and 281,528 and 6,480 for the nine months ended September 30, 2012 and 2011, respectively. The impact of the Partnership’s diluted units did not have a material impact to the Company’s earnings per share calculations for any of the periods presented.

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EQT Corporation and Subsidiaries

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

CAUTIONARY STATEMENTS

Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecasts,” “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 strategy to develop its Marcellus and other reserves; drilling plans and programs (including the number, type, and location of wells to be drilled and the availability of capital to complete these plans and programs); production and sales volumes; gathering and transmission growth and volumes; infrastructure programs (including the transmission and gathering expansion projects); technology (including drilling techniques); monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets; natural gas prices; reserves; capital expenditures, including funding sources and availability; financing requirements and availability; hedging strategy; the effects of government regulation and tax position. The forward-looking statements in this Quarterly Report on Form 10-Q 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” in the Company’s Form 10-K for the year ended December 31, 2011.

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 or filed in this Form 10-Q, please remember such agreements are included to provide information regarding the terms of such agreements 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.

CORPORATE OVERVIEW

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

Net income attributable to EQT Corporation for the three months ended September 30, 2012 was $31.9 million, $0.21 per diluted share, compared with $178.9 million, $1.19 per diluted share, for the period ended September 30, 2011. The $147.0 million decrease in net income was primarily attributable to the $180.1 million pre-tax gain realized in 2011 on the sale of the Big Sandy Pipeline, lower gas prices, higher depreciation, depletion and amortization and higher interest expense, partially offset by higher production and gathering volumes and lower income tax expense.

The average realized sales price to EQT Corporation for production sales volumes was $4.04 per Mcfe during the third quarter of 2012 compared to $5.25 per Mcfe in the same period of the prior year. The average NYMEX natural gas price decreased to $2.81 in 2012 from $4.19 in 2011. Hedging activities resulted in an increase in the price of production sales volumes of $1.16 per Mcf in 2012 compared to $0.47 per Mcf in 2011 as a result of higher volumes being hedged and decreases in NYMEX natural gas prices in the current year.

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Interest expense was $40.5 million for the three months ended September 30, 2012, an increase of $8.0 million from $32.5 million for the three months ended September 30, 2011. This increase was primarily a result of the Company’s November 2011 issuance of $750 million 4.875% notes due in 2021, partially offset by the maturity of medium-term notes during the fourth quarter of 2011 and higher capitalized interest on increased Marcellus well development in 2012. The Company continues to use the net proceeds of the recently issued notes to invest in drilling and midstream infrastructure to develop the Marcellus play.

Income tax expense was $95.1 million lower in 2012 compared to 2011, primarily as a result of lower pre-tax income in 2012 coupled with an overall lower effective tax rate as a result of less income on state tax paying entities in 2012, higher taxes on the Big Sandy sale in 2011 and the impact of the Partnership IPO. Taken together, these factors resulted in a third quarter effective tax rate of 24.0%.

As a result of the Partnership’s IPO, net income attributable to noncontrolling interests was $4.8 million for the three months ended September 30, 2012.

Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

Net income attributable to EQT Corporation for the nine months ended September 30, 2012 was $135.4 million, $0.90 per diluted share, compared with $388.9 million, $2.59 per diluted share, for the period ended September 30, 2011. The $253.5 million decrease in net income was primarily attributable to the $202.9 million pre-tax gain realized by the Company in 2011 on the sales of the Big Sandy Pipeline and the Langley natural gas processing complex, a decrease in production revenues due to lower realized sales prices, higher depreciation, depletion and amortization expenses, warmer weather during the current period and higher interest expense, partially offset by increased production and gathering volumes and lower income tax expense.

The average realized sales price to EQT Corporation for production sales volumes was $4.21 per Mcfe during the nine months ended September 30, 2012 compared to $5.42 per Mcfe in the same period of the prior year. The average NYMEX natural gas price decreased to $2.59 in 2012 from $4.21 in 2011. Hedging activities resulted in an increase in the price of production sales volumes of $1.38 per Mcf in 2012 compared to $0.46 per Mcf in 2011 as a result of higher volumes being hedged and lower NYMEX natural gas prices in the current year.

Other income was $12.9 million for the first nine months of 2012 compared to $27.9 million in the same period in 2011. This $15.0 million decrease was a result of sales of available-for-sale securities in 2011 yielding a gain of $8.5 million, as well as a $10.1 million gain recognized on the ANPI transaction in 2011.

Interest expense increased by $23.7 million from the nine months ended September 30, 2011 compared to the nine months ended September 30, 2012, as a result of the Company’s November 2011 issuance of $750 million 4.875% notes due in 2021. This increase was partially offset by the maturity of medium-term notes during the fourth quarter of 2011 and higher capitalized interest on increased Marcellus well development in 2012.

Income tax expense was $158.1 million lower in 2012 compared to 2011, primarily as a result of lower pre-tax income.

As a result of the Partnership’s IPO, net income attributable to noncontrolling interests was $4.8 million for the nine months ended September 30, 2012.

See Investing Activities under the caption Capital Resources and Liquidity for a discussion of capital expenditures.

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EQT CORPORATION

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012		2011		%		2012		2011		%
OPERATIONAL DATA

Average wellhead sales price to EQT Corporation:
Natural gas excluding hedges ($/Mcf)	$	2.61	$	4.21	(38.0	)	$	2.44	$	4.37	(44.2	)
Hedge impact ($/Mcf of natural gas) (a)	$	1.16	$	0.47	146.8		$	1.38	$	0.46	200.0
Natural gas including hedges ($/Mcf)	$	3.77	$	4.68	(19.4	)	$	3.82	$	4.83	(20.9	)

NGLs ($/Bbl)	$	31.67	$	52.56	(39.7	)	$	37.97	$	52.12	(27.1	)
Crude oil ($/Bbl)	$	80.25	$	81.66	(1.7	)	$	83.44	$	83.52	(0.1	)
Total ($/Mcfe)	$	4.04	$	5.25	(23.0	)	$	4.21	$	5.42	(22.3	)

Less revenues to EQT Midstream ($/Mcfe)	$	1.19	$	1.23	(3.3	)	$	1.22	$	1.37	(10.9	)
Average wellhead sales price to EQT Production ($/Mcfe)	$	2.85	$	4.02	(29.1	)	$	2.99	$	4.05	(26.2	)

Average NYMEX natural gas ($/Mcf)	$	2.81	$	4.19	(32.9	)	$	2.59	$	4.21	(38.5	)

Natural gas sales volumes (MMcf)	64,637		48,070		34.5		171,763		132,035		30.1
NGL sales volumes (Mbbls)	853		759		12.4		2,490		2,259		10.2
Crude oil sales volumes (Mbbls)	64		61		4.9		192		141		36.2
Total produced sales volumes (MMcfe) (b)	68,213		51,298		33.0		182,280		141,375		28.9

Capital expenditures (thousands) (c)	$	361,183	$	347,645	3.9		$	1,023,503	$	985,171	3.9

(a) All hedges are related to natural gas.

(b) NGLs were converted to Mcfe at the rates of 3.74 Mcfe per barrel and 3.76 Mcfe per barrel based on the liquids content for the three months ended September 30, 2012 and 2011, respectively, and 3.76 Mcfe per barrel based on the liquids content for both the nine months ended September 30, 2012 and 2011. 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 for the nine month period ended 2011 include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction discussed in Note J.

Business Segment Results

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 other income. In addition, management uses these measures for budget planning purposes. The Company’s management reviews and reports the EQT Production segment results for operating revenues and purchased gas costs with transportation costs reflected as a deduction from operating revenues as management believes this presentation provides a more useful view of net wellhead price and is consistent with industry practices. Third party transportation costs are reported as a component of purchased gas costs in the consolidated results. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note C to the Condensed Consolidated Financial Statements. As part of the 2012 budgeting process, the Company allocated additional corporate overhead charges to the operating segments. As current period corporate overhead costs have stayed relatively consistent with budgeted amounts, unallocated expenses have decreased for the three and nine month periods ended September 30, 2012.

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EQT PRODUCTION

RESULTS OF OPERATIONS

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2012			2011			%		2012			2011			%
OPERATIONAL DATA

Natural gas, NGL and crude oil production (MMcfe) (a)	68,957			52,456			31.5		184,383			145,021			27.1
Company usage, line loss (MMcfe)	(744		)	(1,158		)	(35.8	)	(2,103		)	(3,646		)	(42.3	)
Total sales volumes (MMcfe)	68,213			51,298			33.0		182,280			141,375			28.9

Average daily sales volumes (MMcfe/d)	741			558			32.8		665			518			28.4

Sales volume detail (MMcfe):
Horizontal Marcellus Play	41,486			22,401			85.2		100,551			56,896			76.7
Horizontal Huron Play	8,934			9,815			(9.0	)	28,452			30,175			(5.7	)
CBM Play	3,282			3,479			(5.7	)	9,868			10,254			(3.8	)
Other (vertical non-CBM)	14,511			15,603			(7.0	)	43,409			44,050			(1.5	)
Total production sales volumes	68,213			51,298			33.0		182,280			141,375			28.9

Average wellhead sales price to EQT Production ($/Mcfe)	$	2.85		$	4.02		(29.1	)	$	2.99		$	4.05		(26.2	)

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.18		$	0.22		(18.2	)	$	0.19		$	0.21		(9.5	)
Production taxes ($/Mcfe) (b)	$	0.16		$	0.25		(36.0	)	$	0.17		$	0.21		(19.0	)
Production depletion ($/Mcfe)	$	1.54		$	1.23		25.2		$	1.54		$	1.24		24.2

Depreciation, depletion and amortization (DD&A) (thousands):
Production depletion	$	106,196		$	64,742		64.0		$	283,152		$	180,063		57.3
Other DD&A	2,008			2,205			(8.9	)	6,024			6,617			(9.0	)
Total DD&A (thousands)	$	108,204		$	66,947		61.6		$	289,176		$	186,680		54.9

Capital expenditures (thousands) (c)	$	255,223		$	255,151		0.0		$	703,834		$	800,029		(12.0	)

FINANCIAL DATA (Thousands)

Total net operating revenues	$	195,289		$	207,500		(5.9	)	$	549,334		$	577,352		(4.9	)

Operating expenses:
LOE, excluding production taxes	12,257			11,612			5.6		34,991			29,760			17.6
Production taxes (b)	10,944			13,296			(17.7	)	37,805			31,024			21.9
Exploration expense	1,163			814			42.9		4,878			3,387			44.0
Selling, general and administrative (SG&A)	24,193			15,895			52.2		67,214			45,477			47.8
DD&A	108,204			66,947			61.6		289,176			186,680			54.9
Total operating expenses	156,761			108,564			44.4		434,064			296,328			46.5
(Loss) gain on dispositions	(187		)	—			(100.0	)	923			—			100.0
Operating income	$	38,341		$	98,936		(61.2	)	$	116,193		$	281,024		(58.7	)

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(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, Company usage and line loss.

(b) Production taxes include severance and production-related ad valorem and other property taxes. In 2012, production taxes also include the Pennsylvania impact fee of $2.0 million and $13.2 million for the three and nine months, respectively. The production taxes unit rate for the nine months ending September 30, 2012 excludes the impact of $6.7 million for the accrual for pre-2012 Marcellus wells.

(c) Capital expenditures in EQT Production for the nine month period ended 2011 include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction discussed in Note J.

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

EQT Production’s operating income totaled $38.3 million for the three months ended September 30, 2012 compared to $98.9 million for the three months ended September 30, 2011. The $60.6 million decrease in operating income was primarily due to a lower average wellhead sales price and an increase in operating expenses partially offset by increased sales of produced natural gas.

Total operating revenues were $195.3 million for the three months ended September 30, 2012 compared to $207.5 million for the three months ended September 30, 2011. The $12.2 million decrease in operating revenues was primarily due to a 29% decrease in the average wellhead sales price to EQT Production which more than offset a 33% increase in production sales volumes. The $1.17 per Mcfe decrease in the average wellhead sales price to EQT Production was primarily due to a 33% decrease in the average NYMEX price as well as lower NGL and basis prices partially offset by higher hedging gains and lower gathering rates compared to the third quarter of 2011. The average wellhead sales price was also impacted unfavorably in 2012 by an increase in the cost of third party transmission capacity, net of excess capacity sales, primarily due to the new transmission capacity on the El Paso 300 line. The increase in production sales volumes was primarily the result of increased production from the 2011 and 2012 drilling programs in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s wells.

Operating expenses totaled $156.8 million for the three months ended September 30, 2012 compared to $108.6 million for the three months ended September 30, 2011. The increase in operating expenses was the result of increases in DD&A, SG&A and LOE partially offset by a decrease in production taxes. Depletion expense increased as a result of a higher overall depletion rate in 2012 as well as higher produced volumes in the current year. The increase in the depletion rate was primarily due to an increase in costs to complete wells, higher capitalized overhead and interest costs, the removal of proved reserves due to lower natural gas prices and the suspension of drilling activity in the Huron play. The increase in SG&A was primarily a result of higher corporate overhead and commercial services allocations, an increase in franchise taxes and increased labor and relocation expenses associated with increased Marcellus drilling. The increase in LOE was mainly due to increased Marcellus activity.

In February 2012, the Commonwealth of Pennsylvania passed a natural gas impact fee. The legislation, which covers a significant portion of EQT’s Marcellus Shale acreage, imposes an annual fee for a period of fifteen years on each well drilled in Pennsylvania. The impact fee adjusts annually based on three factors: age of the well, changes in the Consumer Price Index and the average monthly NYMEX natural gas price. The Pennsylvania impact fee increased production taxes in the third quarter of 2012 by $2.0 million, but the increase was more than offset by a decrease in both property and severance taxes. Property taxes decreased mainly as a result of the recognition of a special assessment in the third quarter of 2011 while severance taxes were lower due to the current year decrease in the average wellhead sales price.

Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

EQT Production’s operating income totaled $116.2 million for the nine months ended September 30, 2012 compared to $281.0 million for the nine months ended September 30, 2011. The $164.8 million decrease in operating income

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was primarily due to a lower average wellhead sales price and an increase in operating expenses partially offset by increased sales of produced natural gas and natural gas liquids.

Total operating revenues were $549.3 million for the nine months ended September 30, 2012 compared to $577.4 million for the nine months ended September 30, 2011. The $28.1 million decrease in operating revenues was primarily due to a 26% decrease in the average wellhead sales price to EQT Production which more than offset a 29% increase in production sales volumes. The $1.06 per Mcfe decrease in the average wellhead sales price to EQT Production was primarily due to a 39% decrease in the average NYMEX price as well as lower basis and NGL prices partially offset by higher hedging gains and lower gathering rates compared to 2011. The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs in the Marcellus, as well as the acquisition of producing properties associated with the ANPI transaction in May 2011 which added 2.6 Bcfe of sales volumes in the nine months ended September 30, 2012. This increase was partially offset by the normal production decline in the Company’s wells.

Operating expenses totaled $434.1 million for the nine months ended September 30, 2012 compared to $296.3 million for the nine months ended September 30, 2011. The increase in operating expenses was the result of increases in DD&A, SG&A, LOE and production taxes. Depletion expense increased as a result of a higher overall depletion rate in 2012 as well as higher produced volumes in the current year. The increase in the depletion rate was primarily due to an increase in costs to complete wells, higher capitalized overhead and interest costs, and the removal of proved reserves due to lower natural gas prices and the suspension of drilling activity in the Huron play. The increase in SG&A was primarily a result of higher corporate overhead and commercial services allocations, increased labor and relocation expenses associated with increased Marcellus drilling and an increase in franchise taxes. The increase in LOE was mainly due to increased Marcellus activity in 2012 as well as the elimination, as part of the ANPI transaction, of certain operating expense reimbursement agreements.

Production taxes increased primarily due to the Pennsylvania impact fee in the current year of $13.2 million, of which $6.7 million represents the retroactive fee for pre-2012 Marcellus wells, as well as an increase in property taxes partially offset by a decrease in severance taxes due to the current year decrease in average wellhead sales price.

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EQT MIDSTREAM

RESULTS OF OPERATIONS

	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2012			2011		%		2012			2011		%
OPERATIONAL DATA

Gathered volumes (BBtu)	87,318			67,304		29.7		235,877			188,492		25.1
Average gathering fee ($/MMBtu)	$	0.88		$	0.94	(6.4	)	$	0.93		$	0.97	(4.1	)
Gathering and compression expense ($/MMBtu) (a)	$	0.24		$	0.33	(27.3	)	$	0.26		$	0.30	(13.3	)
Transmission pipeline throughput (BBtu)	59,746			38,121		56.7		148,870			117,122		27.1

Net operating revenues (thousands):
Gathering	$	77,034		$	63,285	21.7		$	218,411		$	183,523	19.0
Transmission	26,563			18,339		44.8		71,018			69,294		2.5
Storage, marketing and other	5,362			12,380		(56.7	)	34,956			45,547		(23.3	)
Total net operating revenues	$	108,959		$	94,004	15.9		$	324,385		$	298,364	8.7

Unrealized (loss) gain on derivatives and inventory (thousands) (b)	$	(3,018	)	$	1,396	(316.2	)	$	(4,946	)	$	1,850	(367.4	)

Capital expenditures (thousands)	$	97,135		$	81,227	19.6		$	296,698		$	156,832	89.2

FINANCIAL DATA (Thousands)

Total operating revenues	$	120,484		$	122,614	(1.7	)	$	362,630		$	395,477	(8.3	)
Purchased gas costs	11,525			28,610		(59.7	)	38,245			97,113		(60.6	)
Total net operating revenues	108,959			94,004		15.9		324,385			298,364		8.7

Operating expenses:
Operating and maintenance (O&M)	25,441			25,348		0.4		73,245			59,708		22.7
SG&A	15,325			12,890		18.9		37,369			35,010		6.7
DD&A	17,172			14,093		21.8		46,864			43,097		8.7
Total operating expenses	57,938			52,331		10.7		157,478			137,815		14.3
Gain on dispositions	—			180,143		(100.0	)	—			202,928		(100.0	)
Operating income	$	51,021		$	221,816	(77.0	)	$	166,907		$	363,477	(54.1	)

(a) Gathering and compression expense per unit excludes $7.1 million of favorable adjustments during the nine months ended September 30, 2011 for certain non-income tax reserves.

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

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

EQT Midstream’s operating income totaled $51.0 million for the three months ended September 30, 2012 compared to $221.8 million for the three months ended September 30, 2011. The $170.8 million decrease in operating income was primarily the result of the $180.1 million pre-tax gain on the sale of Big Sandy in 2011 and increased operating expenses in 2012 partially offset by an increase in net operating revenues.

Total net operating revenues were $109.0 million for the three months ended September 30, 2012 compared to $94.0 million for the three months ended September 30, 2011. The increase in total net operating revenues was primarily due to a $13.7 million increase in gathering net operating revenues and an $8.2 million increase in transmission net operating revenues, partially offset by a $7.0 million decrease in storage, marketing and other net operating revenues.

Gathering net operating revenues increased due to a 30% increase in gathered volumes partially offset by a 6% decrease in the average gathering fee. The gathered volume increase was driven by higher volumes gathered for EQT

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Production in the Marcellus play. The average gathering fee decreased due to the mix of gathered volumes as Marcellus volumes increased while Huron and other volumes, which have a higher gathering fee, decreased.

Transmission net operating revenues in the three months ended September 30, 2012 increased from the prior year as a result of higher firm transportation activity from affiliated shippers due to increased Marcellus volumes and increased capacity reservation fee revenues from the Sunrise Pipeline project. The decrease in storage, marketing and other net revenues was due to unrealized losses on derivatives and natural gas inventory and lower prices on sales of natural gas liquids.

Total operating revenues decreased $2.1 million, primarily as a result of lower sales prices on decreased commercial activity partially offset by increases in gathered volumes and transmission capacity reservation fee revenues. Total purchased gas costs decreased 60% primarily as a result of lower gas costs on decreased commercial activity.

Operating expenses totaled $57.9 million for the three months ended September 30, 2012 compared to $52.3 million for the three months ended September 30, 2011. The increase in operating expenses was primarily due to increased depreciation expense from recent asset additions, higher labor and benefits and increased expenses associated with the cost of the Partnership being a public company.

Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

EQT Midstream’s operating income totaled $166.9 million for the nine months ended September 30, 2012 compared to $363.5 million for the nine months ended September 30, 2011. The $196.6 million decrease in operating income was primarily the result of the $202.9 million pre-tax gain on sales of the Langley natural gas processing complex and Big Sandy Pipeline in 2011 and increased operating expenses in 2012 partially offset by an increase in 2012 of net operating revenues.

Total net operating revenues were $324.4 million for the nine months ended September 30, 2012 compared to $298.4 million for the nine months ended September 30, 2011. The increase in total net operating revenues was primarily due to a $34.9 million increase in gathering net operating revenues and a $1.7 million increase in transmission net operating revenues partially offset by a $10.6 decrease in storage, marketing and other net operating revenues.

Gathering net operating revenues increased due to a 25% increase in gathered volumes partially offset by a 4% decrease in the average gathering fee. The gathered volume increase was driven by higher volumes gathered for EQT Production in the Marcellus play. The average gathering fee decreased due to the mix of gathered volumes as Marcellus volumes increased while Huron and other volumes, which have a higher gathering fee, decreased.

Transmission net operating revenues in the first nine months of 2012 increased from the prior year as a result of higher firm transportation activity from affiliated shippers due to increased Marcellus volumes and increased capacity resulting from the Equitrans 2010 Marcellus expansion project and the Sunrise Pipeline project partially offset by the absence of $16 million of revenues due to the July 2011 sale of the Big Sandy Pipeline. The decrease in storage, marketing and other revenues was attributable to unrealized losses on derivatives and natural gas inventory and lower prices on natural gas liquids sales during the period.

Total operating revenues decreased $32.8 million, or 8%, primarily as a result of lower sales prices on decreased commercial activity partially offset by an increase in gathered volumes. Total purchased gas costs decreased 61% primarily as a result of lower gas costs on decreased commercial activity.

Operating expenses totaled $157.5 million for the nine months ended September 30, 2012 compared to $137.8 million for the nine months ended September 30, 2011. The increase in operating expenses was primarily due to a reduction in 2011 of certain non-income tax reserves as a result of property tax settlements, increases in 2012 in DD&A, labor and employee benefits, compressor related expenses and higher pipeline safety amortization partially offset by cost savings resulting from the 2011 sales of the Langley natural gas processing complex and the Big Sandy Pipeline and a 2012 $2.5 million recovery of amounts due from Lehman Brothers in connection with its bankruptcy proceeding.

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DISTRIBUTION

RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012		2011		%		2012		2011		%
OPERATIONAL DATA

Heating degree days (30 year average: QTD — 114; YTD — 3,649)	115		85		35.3		2,836		3,508		(19.2	)

Residential sales and transportation volumes (MMcf)	1,266		1,175		7.7		12,726		15,893		(19.9	)
Commercial and industrial volumes (MMcf)	4,939		4,398		12.3		20,051		21,140		(5.2	)
Total throughput (MMcf)	6,205		5,573		11.3		32,777		37,033		(11.5	)

Net operating revenues (thousands):
Residential	$	14,221	$	13,640	4.3		$	72,855	$	83,736	(13.0	)
Commercial & industrial	6,499		6,543		(0.7	)	32,182		35,959		(10.5	)
Off-system and energy services	4,706		6,837		(31.2	)	14,968		18,107		(17.3	)
Total net operating revenues	$	25,426	$	27,020	(5.9	)	$	120,005	$	137,802	(12.9	)

Capital expenditures (thousands)	$	8,164	$	10,149	(19.6	)	$	21,066	$	25,179	(16.3	)

FINANCIAL DATA (Thousands)

Total operating revenues	$	35,649	$	49,175	(27.5	)	$	219,343	$	313,366	(30.0	)
Purchased gas costs	10,223		22,155		(53.9	)	99,338		175,564		(43.4	)
Net operating revenues	25,426		27,020		(5.9	)	120,005		137,802		(12.9	)

Operating expenses:
O&M	10,549		10,414		1.3		31,010		31,466		(1.4	)
SG&A	7,955		7,609		4.5		26,397		23,164		14.0
DD&A	6,237		6,534		(4.5	)	18,767		18,414		1.9
Total operating expenses	24,741		24,557		0.7		76,174		73,044		4.3
Operating income	$	685	$	2,463	(72.2	)	$	43,831	$	64,758	(32.3	)

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

Distribution’s operating income totaled $0.7 million for the three months ended September 30, 2012 compared to $2.5 million for the same period in 2011. The decrease in operating income was primarily due to a favorable change in estimated recoverable costs in 2011 partially offset by colder weather during the third quarter of 2012 as compared to the same period in 2011.

Net operating revenues were $25.4 million for the three months ended September 30, 2012 compared to $27.0 million for the third quarter of 2011. The $1.6 million decrease in net operating revenues was due to several factors. Off-system and energy services net operating revenues decreased $2.1 million primarily due to a favorable change in estimated recoverable costs in 2011. Net operating revenues from residential customers increased $0.6 million primarily as a result of slightly colder weather during the third quarter of 2012 as compared to the same period in 2011. Commercial and industrial volumes increased 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 off-system and energy services transactions and lower natural gas prices, as well as a decrease in the commodity component of tariff rates, resulted in a decrease in both total operating revenues and purchased gas costs.

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Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

Distribution’s operating income totaled $43.8 million for the first nine months of 2012 compared to $64.8 million for the first nine months of 2011. The decrease in operating income was primarily due to record warm weather during the first half of 2012.

Net operating revenues were $120.0 million for the first nine months of 2012 compared to $137.8 million for the first nine months of 2011. Net operating revenues from residential customers decreased $10.9 million as a result of weather which was 19% warmer than the first nine months of 2011 (22% warmer than the 30-year National Oceanic and Atmospheric Administration (NOAA) average for the Company’s service territory). According to the NOAA, it was the warmest January through March time period on record in the Company’s service territory. Commercial and industrial net operating revenues also decreased approximately $3.8 million primarily due to warmer weather and a decrease in performance-based revenues. Off-system and energy services net operating revenues decreased $3.1 million primarily due to a favorable change in estimated recoverable costs in 2011 and fewer asset optimization opportunities realized during the first nine months of 2012 as compared to the same period in 2011. These decreases were partially offset by higher revenues from gathering activities resulting from increased rates. The decreases in total operating revenues and purchased gas costs were primarily due to lower customer throughput as a result of warmer weather during the first nine months of 2012, a decrease in the commodity component of tariff rates and a decrease in asset optimization transactions.

Operating expenses totaled $76.2 million for the first nine months of 2012 compared to $73.0 million for the first nine months of 2011. The $3.2 million increase in operating expenses was primarily due to the reduction of certain non-income tax reserves in 2011 as a result of settlements with tax authorities, higher corporate overhead allocations and increased DD&A in 2012. This was partially offset by lower bad debt expense in 2012 which was primarily the result of a lower commodity component of residential tariff rates and the Company’s favorable collections experience. The Company will continue to closely monitor its collection rates and adjust its reserve for uncollectible accounts as necessary.

OUTLOOK

The Company is committed to profitably developing its Marcellus reserves through environmentally responsible, cost-effective, technologically-advanced horizontal drilling. The market price for natural gas can be volatile as demonstrated by significant declines in late 2011 and early 2012. In response to these lower prices, the Company suspended drilling new Huron wells. Huron wells in progress at January 20, 2012 and those that are required to maintain lease rights have been completed and turned-in-line. Changes in the market price for natural gas impact the Company’s revenues, earnings and liquidity. The Company is unable to predict potential future movements in the market price for natural gas and thus cannot predict the ultimate impact of prices on its operations; however, the Company monitors the market for natural gas and adjusts strategy and operations as deemed appropriate.

The Company plans to spend approximately $1.3 billion in 2012 for well development (primarily drilling and completion), which will support the drilling of approximately 143 gross wells, including 132 gross Marcellus wells, 9 gross Huron wells and 2 gross Utica wells. Forecasted production sales volumes have been increased to 257 Bcfe for an anticipated production sales volume growth of approximately 32% in 2012, while preliminary 2013 production sales volume estimates have been increased to at least 335 Bcfe, approximately 30% higher than 2012 forecasted volumes. To support its 2012 production growth, EQT Midstream will add 445 MMcfe per day of incremental gathering capacity and 700 MMcfe per day of transmission capacity in 2012. This includes 300 MMcfe per day of transmission volumes from the Sunrise Pipeline project which was placed into service in the third quarter of 2012. The balance of the 2012 capital spending plan will be funded by cash flow generated from operations, the proceeds received from the Partnership’s IPO and cash on hand.

We continue to focus on achieving our objective of maximizing shareholder value via an overarching strategy of economically accelerating the monetization of our asset base and prudent pursuit of investment opportunities, while living within our means. While the tactics continue to evolve based upon market conditions, the Company is considering arrangements, including asset sales and partnering with third parties, to monetize the value of mature assets to redeploy into higher-growth Marcellus Shale development.

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CAPITAL RESOURCES AND LIQUIDITY

Overview

The Company’s primary sources of cash for the first nine months of 2012 were proceeds from operating activities and the initial public offering of the Partnership. The Company used the cash primarily to fund its capital program and operations.

Operating Activities

Cash flows provided by operating activities totaled $670.0 for the first nine months of 2012 compared to $736.8 million for the first nine months of 2011, a decrease of $66.8 million. This decrease was a result of lower natural gas sales prices, a decrease in dividends received from Nora Gathering LLC and increased cash payments for interest, partially offset by higher natural gas volumes sold and lower cash payments for income taxes.

Investing Activities

Net cash flows used in investing activities increased $776.1 million from $242.6 million for the first nine months of 2011 compared to $1,018.7 million for the first nine months of 2012. Capital expenditures increased $130.9 million, totaling $1,023.5 million for the first nine months of 2012 compared to $892.6 million for the first nine months of 2011. Increased net cash flows used in investing activities was primarily attributable to the proceeds received in the first nine months of 2011 from the sales of the Big Sandy Pipeline, the Langley natural gas processing complex and available for sale securities.

Capital expenditures for EQT Production totaled $703.8 million for the first nine months of 2012 compared to $707.4 million, which excludes $92.6 million of liabilities assumed in exchanges for producing properties as part of the ANPI transaction, for the first nine months of 2011. The Company commenced drilling on (drilled) 107 gross horizontal wells during the first nine months of 2012; 100 targeting the Marcellus play and 7 targeting the Huron play. The Company drilled 180 gross wells, including 178 gross horizontal wells during the first nine months of 2011; 87 targeting the Marcellus play and 91 targeting the Huron play.

Capital expenditures for the EQT Midstream operations totaled $296.7 million and $156.8 million during the first nine months of 2012 and 2011, respectively. The $139.9 million increase is attributable to expenditures for construction of the Sunrise Pipeline project (which went into service during the third quarter of 2012) and increased gathering and compression projects in the Marcellus region.

Capital expenditures at Distribution decreased to $21.1 million for the first nine months of 2012 from $25.2 million for the first nine months of 2011, mainly as a result of the construction of the Company’s Pittsburgh, Pennsylvania natural gas fueling station and the partial conversion of Distribution’s fleet vehicles to compressed natural gas (CNG) in 2011.

Financing Activities

Cash flows provided by financing activities totaled $156.4 million for the first nine months of 2012 compared to $159.3 million used in financing activities for the first nine months of 2011, an increase of $315.7 million in cash flows from financing activities between such periods. In July 2012, in conjunction with the closing of the IPO by EQT’s subsidiary, EQT received $276.8 million, net of issuance costs, from the issuance of limited partnership interests in the Partnership. The Company also repaid $19.3 million of long-term debt and spent $4.0 million in origination fees for its revolving credit facility, which was amended in May 2012 to, among other things, extend the maturity date, while in 2011, the Company repaid short-term loans of $53.7 million and long-term debt of $9.5 million.

At September 30, 2012, the Company’s current portion of long-term debt was $223.2 million. The Company continues to evaluate financing alternatives that could include additional bond issuances or bank debt to meet these maturities.

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In connection with its IPO, the Partnership entered into a $350 million revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders, which will mature on July 2, 2017. The credit facility is available to the Partnership to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes. The Company is not a guarantor of the Partnership’s obligations under the credit facility.

Security Ratings

The table below reflects the credit ratings for the outstanding debt instruments of the Company at September 30, 2012. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt (including interest rates and fees under its lines of credit), collateral requirements under derivative instruments and its access to the credit markets.

Rating Service	Senior Notes	Short-Term Rating	Outlook
Moody’s Investors Service (Moody’s)	Baa2	P-2	Negative
Standard & Poor’s Ratings Services (S&P)	BBB	A-2	Stable
Fitch Ratings (Fitch)	BBB	F2	Negative

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 on derivative contracts 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 significant default events include maintaining covenants with respect to maximum 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 Company’s current credit facility’s financial covenants 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, 2012, the Company was in compliance with all existing debt provisions and covenants.

The Partnership’s credit facility contains various covenants and restrictive provisions and also requires maintenance of a consolidated leverage ratio of not more than 5.00 to 1.00 (or, after the Partnership obtains an investment grade rating, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and, until the Partnership obtains an investment grade rating, a consolidated interest coverage ratio of not less than 3.00 to 1.00. As of September 30, 2012, the Partnership was 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 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 price swaps, collars and futures.

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As of October 24, 2012, the approximate volumes and prices of the Company’s total hedge position for 2012 through 2015 production are:

	2012**		2013		2014		2015
Swaps
Total Volume (Bcf)	32		108		62		51
Average Price per Mcf (NYMEX)*	$	4.71	$	4.75	$	4.61	$	4.70

	2012**		2013		2014		2015
Collars
Total Volume (Bcf)	5		25		24		23
Average Floor Price per Mcf (NYMEX)*	$	6.51	$	4.95	$	5.05	$	5.03
Average Cap Price per Mcf (NYMEX)*	$	11.83	$	9.09	$	8.85	$	8.97

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

**October through December

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 accrues legal or other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters 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 17, 2012, the Board of Directors declared a regular quarterly cash dividend of 22 cents per share, payable December 1, 2012, to shareholders of record on November 9, 2012.

On October 23, 2012, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.35 per unit. The cash distribution is payable on November 14, 2012 to unitholders of record at the close of business on November 5, 2012.

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, 2011 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 on this Form 10-Q for the period ended September 30, 2012. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

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EQT Corporation and Subsidiaries

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Commodity Instruments

The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily through EQT Production and the 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 D 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 purchased from or placed with major financial institutions whose creditworthiness is regularly monitored. The Company also enters into derivative instruments to hedge other forecasted natural gas purchases and sales, to hedge natural gas inventory and to hedge exposure to fluctuations in interest rates. The Company’s use of these 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 a variable price for the commodity. The Company also considers other contractual agreements in determining its commodity hedging strategy.

The Company monitors price and production levels on a continuous basis and makes 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, 2012, 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 and collar agreements covering approximately 362 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, 2012 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $136.3 million. A hypothetical increase of 10% in the market price of natural gas from the September 30, 2012 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $135.8 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 D to the Condensed Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at September 30, 2012. The price change was then applied to the derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheet, resulting in the change in fair value.

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

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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 termination or maturity date, whichever comes first.

Interest Rate Risk

Changes in interest rates affect the amount of interest the Company earns on cash, cash equivalents and short-term investments and the interest rate it pays on borrowings under the revolving credit facility. All of the Company’s long-term borrowings have a fixed interest rate and thus do not expose the Company to fluctuations in its results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of the Company’s fixed rate debt. See Notes H and I to the Condensed Consolidated Financial Statements for further discussion of the Company’s borrowings and Note F to the Condensed Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of long-term debt. In August 2011, the Company entered into a forward-starting interest rate swap to mitigate the risk of rising interest rates. See Note D to the Condensed Consolidated Financial Statements for further discussion of this swap.

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, which may change as market prices change. The Company believes that NYMEX-traded futures contracts have limited 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 and collar 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 monitoring 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 into transactions with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.

Approximately 72%, or $317.0 million, of the Company’s OTC derivative contracts outstanding at September 30, 2012 have a positive fair value.

As of September 30, 2012, the Company is not in default under any derivative contracts and has no knowledge of default by any counterparty to any 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 Sheet.

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, 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, 2016. The credit facility is underwritten by a syndicate of financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. As of September 30, 2012, the Company had no letters of credit and no loans outstanding under the revolving credit facility.

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No one lender of the large group of 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.

The Partnership has a $350 million revolving credit facility that matures on July 2, 2017. The credit facility is underwritten by a syndicate of financial institutions each of which is obligated to fund its pro-rata portion of any borrowing by the Partnership. As of September 30, 2012, the Partnership had no letters of credit and no loans outstanding under the revolving credit facility.

No one lender of the large group of financial institutions in the syndicate holds more than 10% of the facility. The Partnership’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Partnership’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 (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 2012 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 accrues legal or other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters, 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.

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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, 2011. There have been no material changes from the risk factors previously disclosed in the Company’s Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended, that have occurred in the three months ended September 30, 2012:

Period	Total number of shares (or units) purchased (a)	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs

July 2012 (July 1 – July 31)	1,079	$	54.15	—	—

August 2012 (August 1 – August 31)	1,020	$	56.41	—	—

September 2012 (September 1 – September 30)	—	—		—	—

Total	2,099	$	55.25

(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock and early payout of 2011 Volume & Efficiency Program awards due to involuntary terminations.

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Item 6. Exhibits

10.1		Revolving Credit Agreement, dated July 2, 2012, by and among EQT Midstream Partners, LP, Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders named therein

10.2		EQT Midstream Services, LLC 2012 Long-Term Incentive Plan, dated May 2, 2012

10.3		Form of TSR Performance Award Agreement

10.4		EQT Corporation 2006 Payroll Deduction and Contribution Program (as amended and restated October, 16, 2012)

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 25, 2012

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INDEX TO EXHIBITS

Exhibit No.	Document Description	Incorporated by Reference

10.1	Revolving Credit Agreement, dated July 2, 2012, by and among EQT Midstream Partners, LP, Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders named therein	Filed as Exhibit 10.4 to EQT Midstream Partners, LP Form 8-K dated July 2, 2012

10.2	EQT Midstream Services, LLC 2012 Long-Term Incentive Plan, dated May 2, 2012	Filed as Exhibit 10.5 to EQT Midstream Partners, LP Form 8-K dated July 2, 2012

10.3	Form of TSR Performance Award Agreement	Filed as Exhibit 10.7 to EQT Midstream Partners, LP Form S-1 Registration Statement (#333-179487) filed on February 13, 2012

10.4	EQT Corporation 2006 Payroll Deduction and Contribution Program (as amended and restated October 16, 2012)	Filed herewith as Exhibit 10.4

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