Edgar Filing: EQT Corp

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013

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

(412) 553-5700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý 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 ý 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 ý	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 ý

As of June 30, 2013, 150,594,277 shares of common stock, no par value, of the registrant were outstanding.

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EQT CORPORATION AND SUBSIDIARIES

Index

		Page No.

Part I. Financial Information:

Item 1.	Financial Statements (Unaudited):

	Statements of Consolidated Income for the Three and Six Months Ended June 30, 2013 and 2012	3

	Statements of Consolidated Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012	4

	Statements of Condensed Consolidated Cash Flows for the Six Months Ended June 30, 2013 and 2012	5

	Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	6 – 7

	Statements of Condensed Consolidated Equity for the Six Months Ended June 30, 2013 and 2012	8

	Notes to Condensed Consolidated Financial Statements	9 – 21

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22 – 35

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36 – 38

Item 4.	Controls and Procedures	38

Part II. Other Information:

Item 1.	Legal Proceedings	39

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				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(Thousands, except per share amounts)
Operating revenues	$	520,092	$	337,804	$	1,078,752	$	787,764

Operating expenses:
Purchased gas costs	50,365		39,667		150,934		123,733
Operation and maintenance	35,040		34,815		68,263		69,205
Production	27,747		22,572		52,636		49,595
Exploration	6,138		1,887		9,868		3,715
Selling, general and administrative	60,930		41,778		109,428		84,720
Depreciation, depletion and amortization	168,577		115,681		317,693		223,206
Total operating expenses	348,797		256,400		708,822		554,174

Operating income	171,295		81,404		369,930		233,590
Other income	2,111		5,249		4,441		11,040
Interest expense	37,384		40,629		75,136		81,881
Income before income taxes	136,022		46,024		299,235		162,749
Income taxes	41,904		14,578		95,836		59,268
Net income	94,118		31,446		203,399		103,481
Less: Net income attributable to noncontrolling interests	7,262		–		16,288		–
Net income attributable to EQT Corporation	$	86,856	$	31,446	$	187,111	$	103,481

Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common shares outstanding	150,525		149,582		150,425		149,532
Net income	$	0.58	$	0.21	$	1.24	$	0.69
Diluted:
Weighted average common shares outstanding	151,393		150,149		151,191		150,200
Net income	$	0.57	$	0.21	$	1.24	$	0.69
Dividends declared per common share	$	0.03	$	0.22	$	0.06	$	0.44

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

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EQT CORPORATION AND SUBSIDIARIES

Statements of Consolidated Comprehensive Income (Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013			2012
	(Thousands)
Net income	$	94,118	$	31,446		$	203,399		$	103,481

Other comprehensive income (loss), net of tax:
Net change in cash flow hedges:
Natural gas, net of tax expense (benefit) of $41,436, $(41,598), $(10,147) and $(3,105)	62,939		(64,216		)	(15,495		)	(4,714		)
Interest rate, net of tax expense (benefit) of $25, ($4,966), $50 and ($3,165)	36		(6,606		)	72			(4,168		)
Pension and other post-retirement benefits liability adjustment, net of tax expense of $306, $92, $613 and $214	436		489			869			1,436
Other comprehensive income (loss)	63,411		(70,333		)	(14,554		)	(7,446		)
Comprehensive income (loss)	157,529		(38,887		)	188,845			96,035
Less: Comprehensive income attributable to noncontrolling interests	7,262		–			16,288			–
Comprehensive income (loss) attributable to EQT Corporation	$	150,267	$	(38,887	)	$	172,557		$	96,035

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

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EQT CORPORATION AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Six Months Ended
	June 30,
	2013			2012
	(Thousands)
Cash flows from operating activities:
Net income	$	203,399		$	103,481
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes	63,252			53,057
Depreciation, depletion, and amortization	317,693			223,206
Provision for losses on accounts receivable	2,246			(2,638		)
Other income	(4,441		)	(11,040		)
Stock-based compensation expense	27,480			17,235
Unrealized losses (gains) on derivatives and inventory	4,756			1,118
Lease impairment	8,133			1,095
Noncash financial instrument put premiums	–			8,227
Changes in other assets and liabilities:
Dividend from Nora Gathering, LLC	4,500			7,750
Accounts receivable and unbilled revenues	(11,093		)	72,790
Inventory	23,952			51,004
Accounts payable	(18,005		)	(54,274		)
Other items, net	(13,046		)	(52,572		)
Net cash provided by operating activities	608,826			418,439

Cash flows from investing activities:
Capital expenditures	(805,019		)	(662,320		)
Proceeds from sale of assets	–			3,746
Net cash used in investing activities	(805,019		)	(658,574		)

Cash flows from financing activities:
Increase in short-term loans	55,000			–
Dividends paid	(9,038		)	(65,887		)
Distributions to noncontrolling interests	(10,350		)	–
Repayments and retirements of long-term debt	(20,161		)	(9,532		)
Proceeds and tax benefits from exercises under employee compensation plans	15,387			1,499
Revolving credit facility origination fees	–			(2,158		)
Net cash provided by (used in) financing activities	30,838			(76,078		)

Net change in cash and cash equivalents	(165,355		)	(316,213		)
Cash and cash equivalents at beginning of period	182,055			831,251
Cash and cash equivalents at end of period	$	16,700		$	515,038

Cash paid during the period for:
Interest, net of amount capitalized	$	75,281		$	81,529
Income taxes, net	$	25,061		$	13,193

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

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EQT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	June 30,		December 31,
	2013		2012
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	16,700	$	182,055
Accounts receivable (less accumulated provision for doubtful accounts of $13,189 at June 30, 2013 and $12,586 at December 31, 2012)	237,372		205,479
Unbilled revenues	4,653		27,699
Inventory	55,034		76,787
Derivative instruments, at fair value	230,139		304,237
Prepaid expenses and other	33,510		56,588
Total current assets	577,408		852,845

Equity in nonconsolidated investments	129,695		130,368

Property, plant and equipment	10,929,867		10,139,903
Less: accumulated depreciation and depletion	2,729,035		2,424,605
Net property, plant and equipment	8,200,832		7,715,298

Regulatory assets	110,123		111,915
Other assets	36,217		39,436
Total assets	$	9,054,275	$	8,849,862

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

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EQT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
	2013			2012
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	6,212		$	23,204
Short-term loans	55,000			–
Accounts payable	271,027			289,032
Derivative instruments, at fair value	36,471			75,562
Other current liabilities	126,694			182,667
Total current liabilities	495,404			570,465

Long-term debt	2,499,074			2,502,969
Deferred income taxes and investment tax credits	1,719,918			1,666,029
Other credits	237,654			221,597
Total liabilities	4,952,050			4,961,060

Equity:
Stockholders’ equity:
Common stock, no par value, authorized 320,000 shares, shares issued: 175,684 at June 30, 2013 and December 31, 2012	1,805,500			1,770,545
Treasury stock, shares at cost: 25,090 at June 30, 2013 and 25,575 at December 31, 2012	(452,992		)	(461,774		)
Retained earnings	2,373,575			2,195,502
Accumulated other comprehensive income	84,993			99,547
Total common stockholders’ equity	3,811,076			3,603,820
Noncontrolling interests in consolidated subsidiaries	291,149			284,982
Total equity	4,102,225			3,888,802
Total liabilities and equity	$	9,054,275		$	8,849,862

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 Equity (Unaudited)

	Common Stock					Accumulated Other		Noncontrolling Interests in
	Shares Outstanding	No Par Value		Retained Earnings		Comprehensive Income		Consolidated Subsidiaries		Total Equity
	(Thousands)
Balance, January 1, 2012	149,477	$	1,261,779	$	2,143,910	$	188,141	$	–	$	3,593,830
Net income				103,481						103,481
Other comprehensive loss						(7,446)				(7,446		)
Dividends on common stock ($0.44 per share)				(65,887)						(65,887		)
Stock-based compensation plans, net	118	22,030								22,030
Balance, June 30, 2012	149,595	$	1,283,809	$	2,181,504	$	180,695	$	–	$	3,646,008

Balance, January 1, 2013	150,109	$	1,308,771	$	2,195,502	$	99,547	$	284,982	$	3,888,802
Net income				187,111				16,288		203,399
Other comprehensive loss						(14,554)				(14,554		)
Dividends on common stock ($0.06 per share)				(9,038)						(9,038		)
Stock-based compensation plans, net	485	43,737						229		43,966
Distributions to noncontrolling interests ($0.72 per common unit)								(10,350)		(10,350		)
Balance, June 30, 2013	150,594	$	1,352,508	$	2,373,575	$	84,993	$	291,149	$	4,102,225

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 (GAAP) 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 GAAP for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of June 30, 2013 and December 31, 2012, the results of its operations for the three and six month periods ended June 30, 2013 and 2012 and its cash flows for the six month periods ended June 30, 2013 and 2012. 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, 2012 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 GAAP 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 financial statements for the three and six month periods ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

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, 2012 as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 22 of this Form 10-Q.

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, L.P. (Equitrans, the Company’s Federal Energy Regulatory Commission regulated transmission, storage and gathering subsidiary). An indirect wholly-owned subsidiary of EQT serves as the general partner of the Partnership, and the Company continues to operate the Equitrans business pursuant to contractual arrangements entered into in connection with the closing of the IPO. The Company continues to consolidate the results of the Partnership but records an income tax provision only as to the Company’s ownership percentage. EQT records the noncontrolling interest of the public limited partners in EQT’s financial statements.

The Partnership paid distributions of $5.3 million to noncontrolling interests at $0.37 per common unit and $10.4 million to noncontrolling interests at $0.72 per common unit during the three and six month periods ended June 30, 2013, respectively.

On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units, which included the full exercise of the underwriters’ over-allotment option, representing limited partner interests in the Partnership. Net proceeds from the offering were used to finance the cash consideration paid by the Partnership to EQT in connection with the merger of Sunrise Pipeline, LLC (Sunrise) into Equitrans. Following the offering and Sunrise merger, EQT retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and a 2% general partner interest. For further information regarding the offering and Sunrise merger, refer to Note M below.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 on a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarter expenses are not allocated to the operating segments.

As described in Note I, the Company and its direct wholly-owned subsidiary, Distribution Holdco, LLC (Holdco), executed a definitive agreement (the Master Purchase Agreement) with PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC (Peoples), pursuant to which EQT and Holdco will transfer 100% of their ownership interests of Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Homeworks and Equitable Gas are direct wholly-owned subsidiaries of Holdco and comprise substantially all of the Distribution segment. The transaction is subject to approval by a number of federal and state regulatory agencies. Once the Company makes satisfactory progress in the regulatory process, the Distribution operating segment is expected to be classified as held for sale in the Company’s financial statements.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(Thousands)
Revenues from external customers:
EQT Production	$	306,132	$	158,649	$	556,643	$	354,045
EQT Midstream	150,366		120,098		297,054		242,146
Distribution	56,345		48,273		210,163		183,694
Third-party transportation costs (a)	34,827		30,470		70,568		57,677
Less intersegment revenues, net (b)	(27,578)		(19,686)		(55,676)		(49,798		)
Total	$	520,092	$	337,804	$	1,078,752	$	787,764

Operating income:
EQT Production	$	105,056	$	17,704	$	179,153	$	76,742
EQT Midstream	72,246		59,750		146,460		115,886
Distribution	6,170		6,376		58,446		43,146
Unallocated expenses (c)	(12,177)		(2,426)		(14,129)		(2,184		)
Total operating income	$	171,295	$	81,404	$	369,930	$	233,590

Reconciliation of operating income to net income:
Other income	$	2,111	$	5,249	$	4,441	$	11,040
Interest expense	37,384		40,629		75,136		81,881
Income taxes	41,904		14,578		95,836		59,268
Net income	$	94,118	$	31,446	$	203,399	$	103,481

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	As of June 30,		As of December 31,
	2013		2012
	(Thousands)
Segment assets:
EQT Production	$	6,011,973	$	5,675,534
EQT Midstream	2,119,342		2,046,558
Distribution	834,577		860,029
Total operating segments	8,965,892		8,582,121
Headquarters assets, including cash and short-term investments	88,383		267,741
Total assets	$	9,054,275	$	8,849,862

(a) EQT Production’s segment results are reported with third-party transportation costs reflected as a deduction from operating revenues. Third-party transportation costs are reported as a component of purchased gas costs in the consolidated results. This amount reflects the reclassification of third-party transportation costs from operating revenues to purchased gas costs at the consolidation level.

(b) 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.

(c) Unallocated expenses consist primarily of incentive compensation expenses, general and administrative costs and expenses related to the pending sale of Equitable Gas and Homeworks for the three and six months ended June 30, 2013.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(Thousands)
Depreciation, depletion and amortization:
EQT Production	$	144,073	$	94,405	$	268,982	$	180,972
EQT Midstream	18,452		14,984		36,671		29,692
Distribution	6,072		6,287		12,120		12,530
Other	(20)		5		(80)		12
Total	$	168,577	$	115,681	$	317,693	$	223,206

Expenditures for segment assets:
EQT Production (d)	$	398,078	$	264,926	$	645,024	$	448,611
EQT Midstream	91,254		119,925		142,612		199,563
Distribution	9,558		7,439		15,163		12,902
Other	1,872		443		2,220		1,244
Total	$	500,762	$	392,733	$	805,019	$	662,320

(d) Expenditures for segment assets in the EQT Production segment include $128.9 million and $56.5 million for property acquisitions during the three months ended June 30, 2013 and 2012, respectively, and $141.6 million and $74.6 million for property acquisitions during the six months ended June 30, 2013 and 2012, respectively.

D. Derivative Instruments

The Company uses derivative commodity instruments that are 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

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

payments to or receipts from counterparties based on the differential between two prices 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 potential debt issuances.

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 (OCI), 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.

Most 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.

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.

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.

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, 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 resulted 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				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(Thousands)
Commodity derivatives designated as cash flow hedges
Amount of gain (loss) recognized in OCI (effective portion), net of tax	$	73,429	$	(8,930)	$	20,828	$	98,558
Amount of gain reclassified from accumulated OCI into operating revenues (effective portion), net of tax	$	10,490	$	55,286	$	36,323	$	103,272
Amount of loss recognized in operating revenues (ineffective portion) (a)	$	(7,473)	$	(212)	$	(7,954)	$	(243)

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Interest rate derivatives designated as cash flow hedges
Amount of loss recognized in OCI (effective portion), net of tax	$	–		$	(6,670	)	$	–		$	(4,297	)
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	$	(36	)	$	(64	)	$	(72	)	$	(129	)

Commodity derivatives designated as fair value hedges (b)
Amount of gain (loss) recognized in operating revenues for fair value commodity contracts	$	2,700		$	(2,378	)	$	(839	)	$	4,694
Fair value (loss) gain recognized in operating revenues for inventory designated as hedged item	$	(4,075	)	$	8,388		$	462		$	(1,543	)

Derivatives not designated as hedging instruments
Amount of gain (loss) recognized in operating revenues	$	1,512		$	(790	)	$	1,250		$	1,673

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

(b) For the three months ended June 30, 2013, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $0.8 million gain which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $2.2 million loss due to changes in basis. For the three months ended June 30, 2012, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $6.0 million gain which resulted from the Company’s election to the exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges. For the six months ended June 30, 2013, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $2.1 million gain which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $2.5 million loss due to changes in basis. For the six months ended June 30, 2012, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $2.8 million gain which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $0.4 million loss due to changes in basis.

	As of June 30,		As of December 31,
	2013		2012
	(Thousands)
Asset derivatives
Commodity derivatives designated as hedging instruments	$	206,776	$	259,459
Commodity derivatives not designated as hedging instruments	23,363		44,778
Total asset derivatives	$	230,139	$	304,237

Liability derivatives
Commodity derivatives designated as hedging instruments	$	12,301	$	27,946
Commodity derivatives not designated as hedging instruments	24,170		47,616
Total liability derivatives	$	36,471	$	75,562

The net fair value of commodity derivative instruments changed during the first half of 2013 primarily as a result of settlements. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 414 Bcf and 365 Bcf as of June 30, 2013 and December 31, 2012, respectively, and are primarily related to natural gas swaps and collars. The open positions at June 30, 2013 and December 31, 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 5 Bcf and 8 Bcf as of June 30, 2013 and December 31, 2012, respectively. The open positions at June 30, 2013 had maturities extending through April 2014, and the open positions at December 31, 2012 had maturities extending through January 2014.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The Company deferred net gains of $122.7 million and $138.2 million in accumulated OCI, net of tax, as of June 30, 2013 and December 31, 2012, 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 $71.7 million of net unrealized gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of June 30, 2013 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions. During the second quarter of 2012, the Company identified an error related to the accounting for a derivative instrument put premium which should have been recognized over the period January 2010 through December 2011 in conjunction with the settlements of the related financial positions. The Company evaluated materiality in accordance with SEC Staff Accounting Bulletins Topics 1.M and 1.N and considered relevant qualitative and quantitative factors. Based on this analysis, the Company corrected the error in the second quarter of 2012 through a reduction of EQT Production segment operating revenue by $8.2 million, an increase of accumulated OCI by $5.1 million and a decrease of deferred tax expense by $3.1 million. The Company concluded that this error was not material to any prior periods, the then expected annual results of 2012 or the trend in earnings over the affected periods. The error had no effect on cash flows or debt covenant compliance.

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 limited 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 analyses to monitor and evaluate its credit risk exposures. These include closely monitoring current market conditions, counterparty credit fundamentals and credit default swap rates. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.

When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Condensed Consolidated Balance Sheets as of June 30, 2013 or December 31, 2012.

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. The Company 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. The margin requirements are subject to change at the exchanges’ discretion. The Company recorded a current asset of $0.7 million as of June 30, 2013 and December 31, 2012 for such deposits in its Condensed Consolidated Balance Sheets.

The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. Margin deposits remitted to financial counterparties or received from financial counterparties related to OTC natural gas swap agreements and options and any funds remitted to or deposits received from the Company’s brokers related to exchange-traded natural gas contracts are also recorded on a gross basis. The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

gross commodity derivative liabilities. The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of June 30, 2013 and December 31, 2012.

As of June 30, 2013	Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross		Derivative instruments subject to master netting agreements		Margin deposits remitted to counterparties		Derivative instruments, net
	(Thousands)
Asset derivatives:
Derivative instruments, at fair value	$	230,139	$	(35,437)	$	–	$	194,702

Liability derivatives:
Derivative instruments, at fair value	$	36,471	$	(35,437)	$	(656)	$	378

As of December 31, 2012	Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross		Derivative instruments subject to master netting agreements		Margin deposits remitted to counterparties		Derivative instruments, net
	(Thousands)
Asset derivatives:
Derivative instruments, at fair value	$	304,237	$	(73,753)	$	–	$	230,484

Liability derivatives:
Derivative instruments, at fair value	$	75,562	$	(73,753)	$	(736)	$	1,073

Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by Standard & Poor’s Rating Services (S&P) or Moody’s Investor Services (Moody’s) are lowered below investment grade, additional collateral must be deposited with the counterparty. The additional collateral can be up to 100% of the derivative liability. As of June 30, 2013, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $0.9 million, for which the Company had no collateral posted on June 30, 2013. If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on June 30, 2013, the Company would have been required to post additional collateral of $0.7 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 senior unsecured debt was rated BBB by S&P and Baa3 by Moody’s at June 30, 2013. 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 non-investment grade.

E. 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.

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

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

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. 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 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 Company’s 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 June 30, 2013, derived market volatilities used to value Level 3 assets and liabilities ranged from 20% to 32%. 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 June 30, 2013, 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 NYMEX forward curves and LIBOR-based discount rates are validated to external sources at least monthly.

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

			Fair value measurements at reporting date using
Description	June 30, 2013		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	$	230,139	$	907	$	153,342	$	75,890

Liabilities
Derivative instruments, at fair value	$	36,471	$	1,180	$	34,089	$	1,202

			Fair value measurements at reporting date using
Description	December 31, 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	$	304,237	$	1,228	$	204,592	$	98,417

Liabilities
Derivative instruments, at fair value	$	75,562	$	1,609	$	66,250	$	7,703

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

	Fair value measurements using significant unobservable inputs (Level 3)

	Derivative instruments, at fair value, net Three Months Ended June 30,				Derivative instruments, at fair value, net Six Months Ended June 30,
	2013		2012		2013		2012
	(Thousands)
Beginning of period	$	69,865	$	156,066	$	90,714	$	143,260
Total gains or losses:
Included in earnings	(1,178)		–		(755)		–
Included in OCI	13,125		(4,203)		1,392		27,393
Purchases	–		(1,016)		72		(1,016		)
Settlements	(7,124)		(21,411)		(16,735)		(40,201		)
Transfers in and/or out of Level 3	–		–		–		–
End of period	$	74,688	$	129,436	$	74,688	$	129,436

Losses of $1.2 million are included in earnings in the table above for the three and six months ended June 30, 2013, respectively, attributable to the change in unrealized gains or losses relating to assets held as of June 30, 2013. There were no gains or losses included in earnings in the table above for the three and six months ended June 30, 2012 attributable to the change in unrealized gains or losses relating to assets and liabilities held as of June 30, 2012.

The carrying value of cash equivalents approximates fair value due to the short 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 measurement. 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 June 30, 2013 and December 31, 2012 was approximately $2.8 billion and $2.9 billion, respectively.

F. 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. However, while all of the Partnership’s earnings are included in the Company’s net income, the Company does not record an income tax provision with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners, which reduces the Company’s effective tax rate for periods following the IPO. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period.

The Company’s effective income tax rate for the six months ended June 30, 2013 was 32.0%, compared to 36.4% for the six months ended June 30, 2012. The decrease in the first half of 2013 is primarily attributable to unfavorable state net operating loss adjustments recorded in 2012, a reduction in a valuation allowance related to bonus depreciation for state tax purposes in 2013 and the impact of the Partnership’s ownership structure, partially offset by increased state tax expense in 2013 due to higher natural gas prices and production sales volumes.

There were no material changes to the Company’s methodology for determining unrecognized tax benefits during the three months ended June 30, 2013. The Company’s consolidated federal income tax liability has been settled with the Internal Revenue Service (IRS) through 2009. During the second quarter of 2013, the IRS began its examination of the Company’s 2010 and 2011 tax years. The Company believes that it is appropriately reserved for any federal and state uncertain tax positions.

On July 9, 2013, Pennsylvania House Bill 465 was signed into law by the Governor of the Commonwealth of Pennsylvania (the Commonwealth). This legislation adopts multiple changes to the Commonwealth’s tax code,

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

including an intangible expense addback provision effective in 2015, an increase of the cap on the net operating loss deduction in 2014 and 2015 and an extension of the franchise tax through 2015. The Company is evaluating the legislation but does not anticipate that it will have a material impact on its financial statements.

G. Revolving Credit Facilities

The Company had loans of $55.0 million and no letters of credit outstanding under its $1.5 billion revolving credit facility as of June 30, 2013. There were no loans or letters of credit outstanding under the revolving credit facility as of December 31, 2012. Commitment fees averaging approximately 6 basis points and 11 basis points in the three and six months ended June 30, 2013, respectively, and 6 basis points and 14 basis points in the three and six months ended June 30, 2012, respectively, were paid to maintain credit availability under the Company’s revolving credit facility.

The maximum amount of the Company’s outstanding short-term loans at any time was $178.5 million during the three and six months ended June 30, 2013, respectively. The average daily balance of short-term loans outstanding was approximately $26.7 million and $13.4 million during the three and six months ended June 30, 2013, respectively, at weighted average interest rates of 0.38% and 0.19%, respectively.

As of June 30, 2013 and December 31, 2012, the Partnership had no loans or letters of credit outstanding under its $350 million revolving credit facility. The Partnership incurred commitment fees averaging approximately 6 basis points and 13 basis points in the three and six months ended June 30, 2013, respectively, to maintain credit availability under its revolving credit facility. The Partnership did not have any short-term loans outstanding at any time during the three and six months ended June 30, 2013 and 2012.

H. Long-Term Debt

	June 30,		December 31,
	2013		2012
	(Thousands)
7.76% notes, due 2013 thru 2016	$	22,086	$	32,973
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:
7.3% to 7.6% Series B, due 2013 thru 2023	20,000		30,000
8.7% to 9.0% Series A, due 2014 thru 2021	40,200		40,200
7.6% Series C, due 2018	8,000		8,000
	2,505,286		2,526,173
Less debt payable within one year	6,212		23,204
Total long-term debt	$	2,499,074	$	2,502,969

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

Aggregate maturities of long-term debt are $3.0 million for the second half of 2013, $11.2 million in 2014, $166.0 million in 2015, $3.0 million in 2016 and zero in 2017.

I. Proposed Sale of Properties

On December 19, 2012, the Company and its direct wholly-owned subsidiary, Holdco, executed the Master Purchase Agreement with PNG Companies, the parent company of Peoples, pursuant to which EQT and Holdco will

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

transfer 100% of their ownership interests of Equitable Gas and Homeworks to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Homeworks and Equitable Gas are direct wholly-owned subsidiaries of Holdco. Peoples is a portfolio company of SteelRiver Infrastructure Fund North America LP.

The Company has submitted filings with the Pennsylvania Public Utility Commission (PA PUC), the West Virginia Public Service Commission (WV PSC), the Kentucky Public Service Commission (KY PSC) and the Federal Energy Regulatory Commission (FERC) – each must approve the transaction as part of the regulatory process. The Company expects to receive all necessary approvals by the end of 2013. The transaction was also subject to review by the Federal Trade Commission (FTC) under the Hart-Scott Rodino Antitrust Improvements Act (HSR Act). The waiting period under the HSR Act expired on April 22, 2013, without a request for additional information. This expiration indicates that the FTC has not objected to the transaction and that, from an HSR Act perspective, the parties may complete the transaction. As the transaction is still subject to approval by the PA PUC, the WV PSC, the KY PSC and the FERC, the Company has not classified Equitable Gas and Homeworks as held for sale in its financial statements as of June 30, 2013 and will not do so until the Company makes satisfactory progress in the regulatory process.

The Company incurred $0.8 million and $2.9 million in expenses during the three and six months ended June 30, 2013, respectively, related to the proposed sale of Equitable Gas and Homeworks, which expenses are reported in selling, general and administrative expenses in the Statements of Consolidated Income.

J. 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 867,373 and 560,244 for the three months ended June 30, 2013 and 2012, respectively, and 766,054 and 667,224 for the six months ended June 30, 2013 and 2012, respectively. There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the three and six months ended June 30, 2013. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 1,149,523 and 243,398 for the three and six months ended June 30, 2012, respectively.

The Partnership’s dilutive units did not have a material impact on the Company’s earnings per share calculation for the three and six month periods ended June 30, 2013.

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

K. Changes in Accumulated Other Comprehensive Income by Component

The following tables explain the changes in accumulated OCI by component for the three and six months ended June 30, 2013:

	Three Months Ended June 30, 2013
	Natural gas cash flow hedges, net of tax			Interest rate cash flow hedges, net of tax			Pension and other post- retirement benefits liability adjustment, net of tax			Accumulated OCI (loss), net of tax
	(Thousands)
Accumulated OCI (loss), net of tax, as of April 1, 2013	$	59,754		$	(1,240)		$	(36,932)		$	21,582
Gains recognized in accumulated OCI, net of tax	73,429		(a)	–			–			73,429
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	(10,490)		(a)	36		(a)	436		(b)	(10,018)
Change in accumulated OCI, net of tax	62,939			36			436			63,411
Accumulated OCI (loss), net of tax, as of June 30, 2013	$	122,693		$	(1,204)		$	(36,496)		$	84,993

	Six Months Ended June 30, 2013
	Natural gas cash flow hedges, net of tax			Interest rate cash flow hedges, net of tax			Pension and other post- retirement benefits liability adjustment, net of tax			Accumulated OCI (loss), net of tax
	(Thousands)
Accumulated OCI (loss), net of tax, as of January 1, 2013	$	138,188		$	(1,276)		$	(37,365)		$	99,547
Gains recognized in accumulated OCI, net of tax	20,828		(a)	–			–			20,828
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	(36,323)		(a)	72		(a)	869		(b)	(35,382)
Change in accumulated other comprehensive (loss) income, net of tax	(15,495)			72			869			(14,554)
Accumulated OCI (loss), net of tax, as of June 30, 2013	$	122,693		$	(1,204)		$	(36,496)		$	84,993

(a)		See Note D for additional information.

(b)		This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note

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EQT Corporation and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

14 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2012 for additional information.

L. Acquisitions

On May 3, 2013, the Company entered into a definitive agreement for the purchase of approximately 99,000 net acres in southwestern Pennsylvania and ten horizontal Marcellus wells, located in Washington County, Pennsylvania, from Chesapeake Energy Corporation and its partners (Chesapeake) for approximately $112.5 million. The transaction closed on June 3, 2013. The acreage includes 67,000 Marcellus acres, of which 42,000 acres are unlikely to be developed due to near-term lease expirations or a scattered footprint, and 32,000 Utica acres. Of the total purchase price, $54.6 million was preliminarily allocated to the undeveloped acreage and $57.9 million was preliminarily allocated to the acquired Marcellus wells. The Marcellus wells are expected to add approximately 1.0 Bcfe of production sales volumes in 2013 and represent approximately 54.0 Bcfe of proved developed reserves.

As the transaction qualifies as a business combination under US GAAP, the fair value of the acquired assets was determined using a discounted cash flow model under the income approach. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and NYMEX forward pricing, which classify the acquired assets as a Level 3 measurement.

The Company intends to qualify the acquisition as replacement property in a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code. The Company has entered into a qualified exchange accommodation agreement whereby the Company assigned the right to acquire the Chesapeake properties and loaned the purchase price to an exchange accommodation titleholder, which formed the legal entity that owns title to the properties. The Company operates the acquired properties pursuant to lease and management agreements. The Company has identified potential properties to be relinquished to complete the reverse like-kind exchange, which must be effectuated by November 30, 2013 or otherwise lapse. In either event, the exchange accommodation titleholder will transfer title to the acquired properties to the Company. As the lease and management agreements provide that the Company is the primary beneficiary of the acquired properties, the legal entity that owns title to the acquired properties is a variable interest entity that is consolidated within the Condensed Consolidated Balance Sheets as of June 30, 2013. All revenues and expenses incurred since the closing date related to the acquired properties are included in the Company’s Statements of Consolidated Income for the three and six months ended June 30, 2013.

M. Subsequent Event

On July 15, 2013, the Company and Sunrise entered into an Agreement and Plan of Merger (Merger Agreement) with the Partnership and Equitrans. Effective July 22, 2013, Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. The Company received total consideration of $540 million consisting of a $507.5 million cash payment, 479,184 Partnership common units and 267,942 Partnership general partner units, which common and general partner units were valued at $32.5 million. Prior to the merger, Sunrise entered into a precedent agreement with a third party for firm transportation service over a twenty-year term. If a transportation agreement pursuant to this precedent agreement becomes effective on its current terms by December 31, 2014, the Partnership will make an additional payment of $110 million to EQT. The transportation agreement is subject to review by regulatory authorities, which is expected to be completed by year-end 2013. The Partnership will also pay EQT additional consideration in the event certain other transportation agreements on the Sunrise system become effective prior to December 31, 2014.

On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units, which included the full exercise of the underwriters’ over-allotment option, representing limited partner interests in the Partnership. Net proceeds from the offering were used to finance the cash consideration paid to the Company in connection with the Merger. Following the offering and the closing of the Merger, the Company retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and a 2% general partner interest. The Partnership received net proceeds of $529 million from the offering, after deducting the underwriters’ discount and estimated offering expenses of approximately $21 million, which it used to fund the $507.5 million cash payment to EQT. As the Company controls the Partnership through its general partner interest, the Partnership continues to be consolidated in the Company’s consolidated financial statements.

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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,” “forecast,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report on Form 10-Q 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, feet of pay and location of wells to be drilled and the availability of capital to complete these plans and programs); production and sales volumes and growth rates (including liquids sales volumes and the projected additional production sales volumes attributable to the Marcellus wells acquired in the second quarter of 2013); gathering and transmission growth and volumes; infrastructure programs (including the timing, cost and capacity of the transmission and gathering expansion projects); technology (including drilling techniques); monetization transactions, including midstream asset sales (dropdowns) to EQT Midstream Partners, LP, the Company’s publicly-traded master limited partnership formed in 2012 (the Partnership), and other asset sales, and joint ventures or other transactions involving the Company’s assets (including the timing of receipt, if at all, of any additional consideration from the Partnership for new transportation agreements entered into by the Partnership in connection with the Company’s sale of its Sunrise Pipeline); the proposed transfer of Equitable Gas Company, LLC (Equitable Gas) to PNG Companies LLC; the timing of receipt of required approvals for the proposed Equitable Gas transaction; natural gas prices; reserves; projected capital expenditures; liquidity and financing requirements, including funding sources and availability; hedging strategy; the effects of government regulation and litigation; and tax position (including the Company’s ability to complete like-kind exchanges). 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. With respect to the proposed Equitable Gas transaction, these risks and uncertainties include, among others, the ability to obtain regulatory approvals for the transaction on the proposed terms and schedule; disruption to the Company’s business, including customer, employee and supplier relationships resulting from the transaction; and risks that the conditions to closing may not be satisfied. 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, 2012.

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 statement, whether as a result of new information, future events or otherwise.

In reviewing any agreements incorporated by reference in or filed with this Quarterly Report on 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.

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EQT Corporation and Subsidiaries

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

CORPORATE OVERVIEW

Three Months Ended June 30, 2013 vs. Three Months Ended June 30, 2012

Net income attributable to EQT Corporation for the three months ended June 30, 2013 was $86.9 million, $0.57 per diluted share, compared with $31.4 million, $0.21 per diluted share, for the three months ended June 30, 2012. The $55.5 million increase in net income attributable to EQT Corporation between periods resulted primarily from a 55% increase in natural gas volumes sold, a 14% increase in the average effective sales prices for natural gas and natural gas liquids (NGLs) and increases in transmission pipeline throughput and gathered volumes. These increases were partially offset by higher depreciation, depletion and amortization (DD&A) expense, higher income tax expense and higher selling, general and administrative (SG&A) expenses due to higher incentive compensation expenses.

The average effective sales price to EQT Corporation for production sales volumes was $4.37 per Mcfe during the three months ended June 30, 2013 compared to $3.83 per Mcfe in the same period of 2012. The Company’s average New York Mercantile Exchange (NYMEX) natural gas sales price increased to $4.09 per Mcf for the three months ended June 30, 2013 compared to $2.22 per Mcf for the three months ended June 30, 2012. Hedging activities resulted in an increase in the effective sales price of $0.11 per Mcf in the second quarter of 2013 compared to an increase of $1.52 per Mcf in the second quarter of 2012. The $1.41 per Mcf decrease in the impact of hedging activities from 2012 to 2013 was the result of the differential in the NYMEX natural gas sales prices between periods and the lower average hedge prices in 2013.

Other income decreased $3.1 million during the three months ended June 30, 2013 compared to the three months ended June 30, 2012. The decrease was primarily attributable to a decrease in the allowance for funds used during construction, as a result of the Sunrise Pipeline being placed into service during the third quarter of 2012.

Interest expense was $3.2 million lower during the three months ended June 30, 2013 compared to the three months ended June 30, 2012, primarily as a result of the Company’s repayment of $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $20.2 million of debentures that matured in the first quarter of 2013.

Income tax expense increased $27.3 million during the three months ended June 30, 2013 compared to the three months ended June 30, 2012 primarily as a result of higher pre-tax income in the second quarter of 2013.

Net income attributable to noncontrolling interests of the Partnership, which completed its initial public offering (IPO) in the third quarter of 2012, was $7.3 million for the three months ended June 30, 2013.

Six Months Ended June 30, 2013 vs. Six Months Ended June 30, 2012

Net income attributable to EQT Corporation for the six months ended June 30, 2013 was $187.1 million, $1.24 per diluted share, compared with $103.5 million, $0.69 per diluted share, for the six months ended June 30, 2012. The $83.6 million increase in net income attributable to EQT Corporation between periods was primarily attributable to a 51% increase in natural gas volumes sold, increases in transmission pipeline throughput and gathered volumes and colder weather. The increases were partially offset by higher DD&A expense, higher income tax expense and higher SG&A expenses due to higher incentive compensation expenses.

The average effective sales price to EQT Corporation for production sales volumes was $4.32 per Mcfe during the six months ended June 30, 2013 compared to $4.31 per Mcfe in the same period of 2012. The Company’s average NYMEX natural gas sales price increased to $3.71 per Mcf for the six months ended June 30, 2013 from $2.48 per Mcf for the six months ended June 30, 2012. Hedging activities resulted in an increase in the effective sales price of $0.33 per Mcf in the first half of 2013 compared to an increase of $1.51 per Mcf in the first half of 2012. The $1.18 per Mcf decrease in the impact of hedging activities from 2012 to 2013 was the result of the differential in the NYMEX natural gas sales prices between periods and the lower average hedge prices in 2013.

Other income was $4.4 million for the six months ended June 30, 2013 compared to $11.0 million for the six months ended June 30, 2012. The $6.6 million decrease is primarily attributable to a decrease in the allowance for funds used during construction, as a result of the Sunrise Pipeline being placed into service during the third quarter of 2012, and a gain recognized on the sale of leases in the first half of 2012.

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EQT Corporation and Subsidiaries

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

Interest expense was $6.7 million lower in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 primarily as a result of the Company’s repayment of the $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $20.2 million of debentures that matured in the first quarter of 2013.

Income tax expense increased $36.6 million during the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily as a result of higher pre-tax income. The Company’s effective income tax rate decreased to 32.0% from 36.4%. This decrease in the first half of 2013 was primarily attributable to unfavorable state net operating loss adjustments recorded in 2012, a reduction in a valuation allowance related to bonus depreciation for state tax purposes in 2013 and the impact of the Partnership’s ownership structure, partially offset by increased state tax expense in 2013 due to higher production sales volumes and natural gas prices.

Net income attributable to noncontrolling interests of the Partnership, which completed its IPO in the third quarter of 2012, was $16.3 million for the six months ended June 30, 2013.

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

Consolidated Operational Data

Revenues earned by the Company at the wellhead from the sale of natural gas are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average effective sales price. The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist the understanding of the Company’s consolidated operations.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012		%	2013		2012		%
in thousands (unless noted)
LIQUIDS
*NGLs:*
Sales Volume (MMcfe) (a)	4,863		3,206		51.7	9,233		6,176		49.5
Sales Volume (Mbbls)	1,234		850		45.2	2,428		1,637		48.3
Gross Price ($/Mbbls)	$	39.93	$	41.56	(3.9)	$	41.47	$	48.42	(14.4	)
Gross NGL Revenue	$	49,260	$	35,323	39.5	$	100,683	$	79,263	27.0
*BTU Premium (Ethane sold as natural gas):*
Sales Volume (MMbtu)	6,962		5,068		37.4	13,329		9,717		37.2
Price ($/MMbtu)	$	4.09	$	2.22	84.2	$	3.74	$	2.46	52.0
BTU Premium Revenue	$	28,488	$	11,245	153.3	$	49,894	$	23,952	108.3
*Oil:*
Sales Volume (MMcfe) (a)	327		437		(25.2)	695		764		(9.0	)
Sales Volume (Mbbls)	54		73		(26.0)	116		127		(8.7	)
Net Price ($/Mbbls)	$	83.95	$	85.99	(2.4)	$	82.55	$	85.49	(3.4	)
Net Oil Revenue	$	4,575	$	6,277	(27.1)	$	9,561	$	10,884	(12.2	)

Total Liquids Revenue	$	82,323	$	52,845	55.8	$	160,138	$	114,099	40.4

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

GAS
Sales Volume (MMcf)	87,226		56,353		54.8	161,880		107,127		51.1
NYMEX Price ($/Mcf) (b)	$	4.09	$	2.22	84.2	$	3.74	$	2.46	52.0
Gas Revenue	$	356,929	$	125,029	185.5	$	605,949	$	263,945	129.6
Basis	(939)		366		(356.6)	(1,132)		248		(556.5	)
Gross Gas Revenue (unhedged)	$	355,990	$	125,395	183.9	$	604,817	$	264,193	128.9

Total Gross Gas & Liquids Revenue (unhedged)	$	438,313	$	178,240	145.9	$	764,955	$	378,292	102.2
Hedge impact	9,728		85,397		(88.6)	53,226		162,144		(67.2	)
Total Gross Gas & Liquids Revenue	$	448,041	$	263,637	69.9	$	818,181	$	540,436	51.4
Total Sales Volume (MMcfe)	92,416		59,997		54.0	171,808		114,067		50.6
Average hedge adjusted price ($/Mcfe)	$	4.85	$	4.39	10.5	$	4.76	$	4.74	0.4

Midstream Revenue Deductions ($ / Mcfe)
Gathering to EQT Midstream	$	(0.83)	$	(1.05)	(21.0)	$	(0.86)	$	(1.06)	(18.9	)
Transmission to EQT Midstream	(0.24)		(0.16)		50.0	(0.24)		(0.17)		41.2
Third-party gathering and transmission (c)	(0.37)		(0.46)		(19.6)	(0.33)		(0.33)		0.0
Third-party processing	(0.11)		(0.10)		10.0	(0.11)		(0.10)		10.0
Total midstream revenue deductions	(1.55)		(1.77)		(12.4)	(1.54)		(1.66)		(7.2	)
Average effective sales price to EQT Production	$	3.30	$	2.62	26.0	$	3.22	$	3.08	4.5

EQT Revenue ($ / Mcfe)
Revenues to EQT Midstream	$	1.07	$	1.21	(11.6)	$	1.10	$	1.23	(10.6	)
Revenues to EQT Production	3.30		2.62		26.0	3.22		3.08		4.5
Average effective sales price to EQT Corporation	$	4.37	$	3.83	14.1	$	4.32	$	4.31	0.2

	(a)	NGLs were converted to Mcfe at the rates of 3.94 Mcfe per barrel and 3.77 Mcfe per barrel based on the liquids content for the three months ended June 30, 2013 and 2012, respectively, and 3.80 Mcfe per barrel and 3.77 Mcfe per barrel based on the liquids content for the six months ended June 30, 2013 and 2012, respectively. Crude oil was converted to Mcfe at the rate of six Mcfe per barrel for all periods.

	(b)	The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/Mcf) was $4.09 and $2.22 for the three months ended June 30, 2013 and 2012, respectively, and $3.71 and $2.48 for the six months ended June 30, 2013 and 2012, respectively).

	(c)	Due to the sale of unused capacity on the El Paso 300 line that was not under long-term resale agreements at prices below the capacity charge, third-party gathering and transmission rates increased by $0.09 per Mcfe and $0.07 per Mcfe for the three and six months ended June 30, 2013, respectively. The unused capacity on the El Paso 300 line not under long-term resale agreements was sold at prices below the capacity charge, increasing third-party gathering and transmission rates by $0.12 per Mcfe for the three months ended June 30, 2012. The sale of unused capacity on the El Paso 300 line that was not under long-term resale agreements had no impact on third-party gathering and transmission rates for the six months ended June 30, 2012.

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 business 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 with third-party transportation costs reflected as a deduction from operating revenues, as management believes this presentation provides a more useful view of net effective 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 of this Quarterly Report on Form 10-Q.

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.

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EQT Corporation and Subsidiaries

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

Differences between budget and actual headquarter expenses totaling $12.2 million and $14.1 million were not allocated to the operating segments for the three and six months ended June 30, 2013, respectively. The unallocated expenses for both periods consist primarily of incentive compensation expenses, general and administrative costs and expenses related to the pending sale of Equitable Gas and Equitable Homeworks, LLC (Homeworks).

EQT PRODUCTION

RESULTS OF OPERATIONS

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

	2013		2012		%	2013		2012		%
OPERATIONAL DATA
Sales volume detail (MMcfe):
Horizontal Marcellus Play (a)	68,057		32,223		111.2	122,572		59,065		107.5
Horizontal Huron Play	7,500		9,852		(23.9)	15,531		19,518		(20.4	)
CBM Play	3,116		3,288		(5.2)	6,232		6,586		(5.4	)
Other (vertical non-CBM)	13,743		14,634		(6.1)	27,473		28,898		(4.9	)
Total production sales volumes	92,416		59,997		54.0	171,808		114,067		50.6

Average daily sales volumes (MMcfe/d)	1,016		659		54.2	949		627		51.4

Average effective sales price to EQT Production ($/Mcfe)	$	3.30	$	2.62	26.0	$	3.22	$	3.08	4.5

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.16	$	0.20	(20.0)	$	0.16	$	0.20	(20.0	)
Production taxes ($/Mcfe) (b)	$	0.14	$	0.17	(17.6)	$	0.15	$	0.18	(16.7	)
Production depletion ($/Mcfe)	$	1.53	$	1.54	(0.6)	$	1.54	$	1.55	(0.6	)

DD&A (thousands):
Production depletion	$	141,661	$	92,430	53.3	$	264,152	$	176,956	49.3
Other DD&A	2,412		1,975		22.1	4,830		4,016		20.3
Total DD&A (thousands)	$	144,073	$	94,405	52.6	$	268,982	$	180,972	48.6

Capital expenditures (thousands) (c)	$	398,078	$	264,926	50.3	$	645,024	$	448,611	43.8

FINANCIAL DATA (thousands)

Total net operating revenues	$	306,132	$	158,649	93.0	$	556,643	$	354,045	57.2

Operating expenses:
LOE, excluding production taxes	14,612		11,798		23.9	27,651		22,734		21.6
Production taxes (b)	13,134		10,774		21.9	24,985		26,861		(7.0	)
Exploration expense	6,138		1,887		225.3	9,868		3,715		165.6
SG&A	23,119		22,081		4.7	46,004		43,021		6.9
DD&A	144,073		94,405		52.6	268,982		180,972		48.6
Total operating expenses	201,076		140,945		42.7	377,490		277,303		36.1
Operating income	$	105,056	$	17,704	493.4	$	179,153	$	76,742	133.4

(a)	Includes Upper Devonian wells.

(b)	Production taxes include severance and production-related ad valorem and other property taxes and the Pennsylvania impact fee. The Pennsylvania impact fee for the three and six months ended June 30, 2013 totaled $2.7 million and $5.6 million, respectively. The Pennsylvania impact fee for the three and six months ended June 30, 2012 totaled $3.1 million and $11.3 million, respectively, of which $0.5 million

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

and $6.7 million represented the retroactive fee for pre-2012 Marcellus wells. The production taxes unit rate for the three and six months ended June 30, 2012 excludes the impact of the accrual for pre-2012 Marcellus wells.

(c) Includes $112.5 million of capital expenditures for the purchase of acreage and Marcellus wells from Chesapeake Energy Corporation and its partners (Chesapeake) during the three and six months ended June 30, 2013.

Three Months Ended June 30, 2013 vs. Three Months Ended June 30, 2012

EQT Production’s operating income totaled $105.1 million for the three months ended June 30, 2013 compared to $17.7 million for the three months ended June 30, 2012. The $87.4 million increase in operating income was primarily due to an increase in sales of produced natural gas and a higher average effective sales price partially offset by an increase in operating expenses.

Total net operating revenues were $306.1 million for the three months ended June 30, 2013 compared to $158.6 million for the three months ended June 30, 2012. The $147.5 million increase in net operating revenues was primarily due to a 54% increase in production sales volumes and a 26% increase in the average effective sales price to EQT Production. The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.

The $0.68 per Mcfe increase in the average effective sales price to EQT Production was primarily due to an 84% increase in the average NYMEX natural gas price and lower midstream charges partially offset by a smaller hedge gain and lower NGL prices compared to the same period of 2012. During the second quarter of 2013, hedging gains included a loss for ineffectiveness of $7.6 million. The second quarter of 2012 included an unfavorable adjustment of $8.2 million to recognize financial instrument put premiums that should have been recorded ratably over 2010 and 2011.

Operating expenses totaled $201.1 million for the three months ended June 30, 2013 compared to $140.9 million for the three months ended June 30, 2012. The increase in operating expenses was the result of increases in DD&A, LOE, SG&A, exploration expense and production taxes. DD&A expense increased as a result of higher production sales volumes in the current year. The increase in SG&A expense was primarily a result of higher personnel costs including incentive compensation expenses. The increase in LOE was mainly due to increased Marcellus activity. The increase in exploration expense was due to increased impairments of unproved lease acreage resulting from lease expirations during the second quarter of 2013.

In February 2012, the Commonwealth of Pennsylvania passed legislation imposing a natural gas impact fee. The legislation, which covers a significant portion of EQT’s Marcellus 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. During the second quarter of 2013, the Pennsylvania impact fee was $2.7 million compared to $3.1 million in the second quarter of 2012, of which $0.5 million represented a retroactive fee for pre-2012 Marcellus wells. Production taxes increased in the second quarter of 2013 compared to the second quarter of 2012 primarily due to a $3.5 million increase in severance taxes as the result of higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes. The increase in severance tax was partially offset by the $0.4 million decrease in the Pennsylvania impact fee as well as a $0.8 million decrease in property taxes.

Six Months Ended June 30, 2013 vs. Six Months Ended June 30, 2012

EQT Production’s operating income totaled $179.2 million for the six months ended June 30, 2013 compared to $76.7 million for the six months ended June 30, 2012. The $102.5 million increase in operating income was primarily due to an increase in sales of produced natural gas and a higher average effective sales price partially offset by an increase in operating expenses.

Total net operating revenues were $556.6 million for the six months ended June 30, 2013 compared to $354.0 million for the six months ended June 30, 2012. The $202.6 million increase in net operating revenues was

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EQT Corporation and Subsidiaries

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

primarily due to a 51% increase in production sales volumes and a 5% increase in the average effective sales price to EQT Production. The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.

The $0.14 per Mcfe increase in the average effective sales price to EQT Production was primarily due to a 52% increase in the actual average NYMEX natural gas price and lower midstream charges partially offset by a smaller hedge gain and lower NGL prices compared to the same period of 2012. During the first half of 2013, hedging gains included a loss for ineffectiveness of $8.1 million. The first half of 2012 included an unfavorable adjustment of $8.2 million to recognize financial instrument put premiums that should have been recorded ratably over 2010 and 2011.

Operating expenses totaled $377.5 million for the six months ended June 30, 2013 compared to $277.3 million for the six months ended June 30, 2012. The increase in operating expenses was the result of increases in DD&A, LOE, SG&A and exploration expense partially offset by a decrease in production taxes. DD&A expense increased as a result of higher production sales volumes in the current year partially offset by a slightly lower overall depletion rate. The increase in SG&A expense was primarily a result of higher environmental reserves for remediation and higher personnel costs, including incentive compensation expenses. The increase in LOE was mainly due to increased Marcellus activity. The increase in exploration expense was due to increased impairments of unproved lease acreage resulting from lease expirations during the first half of 2013 partially offset by a reduction in geophysical activity compared to the prior year.

Production taxes decreased in the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily due to a $5.7 million decrease in the Pennsylvania impact fee and a $2.2 million decrease in property taxes due to lower assessments received during 2013. During the first half of 2013, the Pennsylvania impact fee was $5.6 million compared to $11.3 million in the first half of 2012, of which $6.7 million represented a retroactive fee for pre-2012 Marcellus wells. The decreases in the impact fee and property taxes were partially offset by a $6.0 million increase in severance taxes due to higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes.

EQT MIDSTREAM

RESULTS OF OPERATIONS

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2013			2012		%		2013		2012			%
OPERATIONAL DATA

Gathered volumes (BBtu)	116,132			77,393		50.1		217,363		148,559			46.3
Average gathering fee ($/MMBtu)	$		0.75	$	0.93	(19.4	)	$	0.78	$	0.95		(17.9	)
Gathering and compression expense ($/MMBtu)	$		0.17	$	0.27	(37.0	)	$	0.18	$	0.27		(33.3	)
Transmission pipeline throughput (BBtu)	104,846			47,049		122.8		185,817		89,124			108.5

Net operating revenues (thousands):
Gathering	$		86,992	$	72,124	20.6		$	168,806	$	141,377		19.4
Transmission	38,836			21,514		80.5		76,143		44,455			71.3
Storage, marketing and other	5,502			14,671		(62.5	)	15,261		29,594			(48.4	)
Total net operating revenues	$	131,330		$	108,309	21.3		$	260,210	$	215,426		20.8

Unrealized gains (losses) on derivatives and inventory (thousands) (a)	$		1,288	$	3,519	(63.4	)	$	2,962	$	(1,928	)	(253.6	)

Capital expenditures (thousands)	$		91,254	$	119,925	(23.9	)	$	142,612	$	199,563		(28.5	)

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

FINANCIAL DATA (thousands)

Total operating revenues	$	150,366	$	120,098	25.2	$	297,054	$	242,146	22.7
Purchased gas costs	19,036		11,789		61.5	36,844		26,720		37.9
Total net operating revenues	131,330		108,309		21.3	260,210		215,426		20.8

Operating expenses:
Operating and maintenance (O&M)	23,936		23,700		1.0	46,609		47,804		(2.5	)
SG&A	16,696		9,875		69.1	30,470		22,044		38.2
DD&A	18,452		14,984		23.1	36,671		29,692		23.5
Total operating expenses	59,084		48,559		21.7	113,750		99,540		14.3
Operating income	$	72,246	$	59,750	20.9	$	146,460	$	115,886	26.4

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

Three Months Ended June 30, 2013 vs. Three Months Ended June 30, 2012

EQT Midstream’s operating income totaled $72.2 million for the three months ended June 30, 2013 compared to $59.8 million for the three months ended June 30, 2012. The increase in operating income was primarily the result of increased transmission and gathering net operating revenues partially offset by a decrease in storage, marketing and other net operating revenues and increased operating expenses.

Total net operating revenues were $131.3 million for the three months ended June 30, 2013 compared to $108.3 million for the three months ended June 30, 2012. Transmission net operating revenues increased $17.3 million primarily as a result of an additional $11.9 million of capacity reservation revenues and usage charges, of which $9.1 million was related to the Sunrise Pipeline (which was placed into service in the third quarter of 2012), and an additional $5.2 million of fees associated with transported volumes in excess of firm capacity.

The $14.9 million increase in gathering net operating revenues was due to a 50% increase in gathered volumes partially offset by a 19% decrease in the average gathering fee. The increase in gathered volumes was driven primarily by higher volumes gathered for EQT Production in the Marcellus play. The average gathering fee decreased primarily from lower gathered volumes in the Huron play and increased gathered volumes in the Marcellus play, as the Marcellus gathering rate is lower than the rate in the Huron and other areas. In addition, during the three months ended June 30, 2013, the Marcellus gathering charge to affiliates decreased by $0.10 per unit as compared to the same period in 2012 due to greater economies of scale achieved in recent periods.

Storage, marketing and other net operating revenues decreased due to lower realized margins and reduced activity, a decrease in unrealized gains on derivatives and inventory and $1.6 million of lower liquids pricing on NGLs marketed for non-affiliated producers primarily due to lower pricing.

Total operating revenues increased $30.3 million primarily as a result of increased transmission revenues and increased gathered volumes, which were partially offset by reduced total operating revenues for storage, marketing and other. Purchased gas costs increased $7.2 million primarily as a result of an increase in commodity prices.

Operating expenses totaled $59.1 million for the three months ended June 30, 2013 compared to $48.6 million for the three months ended June 30, 2012. The increase in operating expenses was primarily due to increased personnel costs including incentive compensation expenses and increased DD&A expense as a result of additional assets placed in-service. Additionally, operating expenses increased as a result of a recovery of $0.5 million from Lehman Brothers in 2013 compared to a recovery of $2.5 million in 2012.

Six Months Ended June 30, 2013 vs. Six Months Ended June 30, 2012

EQT Midstream’s operating income totaled $146.5 million for the six months ended June 30, 2013 compared to $115.9 million for the six months ended June 30, 2012. The increase in operating income was primarily the result of increased transmission and gathering net operating revenues partially offset by a decrease in storage, marketing and other net operating revenues and increased operating expenses.

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EQT Corporation and Subsidiaries

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

Total net operating revenues were $260.2 million for the six months ended June 30, 2013 compared to $215.4 million for the six months ended June 30, 2012.

Transmission net operating revenues increased $31.7 million primarily as a result of $19.8 million of additional capacity reservation revenues and usage charges, of which $16.6 million were related to the Sunrise Pipeline (which was placed into service in the third quarter of 2012), $10.0 million of fees associated with transported volumes in excess of firm capacity and increased pipeline safety revenues.

Gathering net operating revenues increased due to a 46% increase in gathered volumes partially offset by an 18% decrease in the average gathering fee. The increase in gathered volumes was driven primarily by higher volumes gathered for EQT Production in the Marcellus play. The average gathering fee decreased primarily from lower gathered volumes in the Huron play and increased gathered volumes in the Marcellus play, as the Marcellus gathering volumes are charged a lower gathering rate than in the rate charged in the Huron and other areas. In addition, during the six months ended June 30, 2013, the Marcellus gathering charge to affiliates decreased by $0.08 per unit as compared to the same period in 2012 due to greater economies of scale achieved in recent periods.

Storage, marketing and other net operating revenues decreased by $15.3 million primarily as a result of lower realized margins and reduced activity due to lower price spreads. Revenues related to NGLs marketed for non-affiliated producers decreased by $3.2 million primarily as a result of lower liquids pricing. These decreases were partially offset by a $4.9 million favorable change in unrealized gains (losses) on derivatives and inventory.

Total operating revenues increased $54.9 million primarily as a result of increased transmission revenues and increased gathered volumes, which were partially offset by reduced total operating revenues for storage, marketing and other. Purchased gas costs increased $10.1 million primarily as a result of an increase in commodity prices.

Operating expenses totaled $113.8 million for the six months ended June 30, 2013 compared to $99.5 million for the six months ended June 30, 2012. The increase in operating expenses was primarily due to increased DD&A expense as a result of additional assets placed in-service, increased personnel costs of $5.8 million including incentive compensation expenses, increased property taxes and increased allocated expenses from affiliates in 2013, partially offset by decreases in compressor operating expenses in 2013. Additionally, operating expenses increased as a result of a recovery of $0.5 million from Lehman Brothers in 2013 compared to a recovery of $2.5 million in 2012.

DISTRIBUTION

RESULTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013		2012		%		2013		2012		%
OPERATIONAL DATA

Heating degree days (30 year average: QTD – 665; YTD – 3,535)	505		489		3.3		3,409		2,721		25.3

Residential sales and transportation volumes (MMcf)	2,892		2,405		20.2		14,544		11,460		26.9
Commercial and industrial volumes (MMcf)	5,190		5,753		(9.8	)	15,231		15,112		0.8
Total throughput (MMcf)	8,082		8,158		(0.9	)	29,775		26,572		12.1

Net operating revenues (thousands):
Residential	$	19,860	$	17,974	10.5		$	73,927	$	58,634	26.1
Commercial and industrial	7,938		8,660		(8.3	)	27,644		25,683		7.6
Off-system and energy services	4,474		4,554		(1.8	)	9,412		10,262		(8.3	)
Total net operating revenues	$	32,272	$	31,188	3.5		$	110,983	$	94,579	17.3

Capital expenditures (thousands)	$	9,558	$	7,439	28.5		$	15,163	$	12,902	17.5

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EQT Corporation and Subsidiaries

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

FINANCIAL DATA (thousands)

Total operating revenues	$	56,345	$	48,273	16.7		$	210,163	$	183,694	14.4
Purchased gas costs	24,073		17,085		40.9		99,180		89,115		11.3
Net operating revenues	32,272		31,188		3.5		110,983		94,579		17.3

Operating expenses:
O&M	11,018		10,248		7.5		21,053		20,461		2.9
SG&A	9,012		8,277		8.9		19,364		18,442		5.0
DD&A	6,072		6,287		(3.4	)	12,120		12,530		(3.3	)
Total operating expenses	26,102		24,812		5.2		52,537		51,433		2.1
Operating income	$	6,170	$	6,376	(3.2	)	$	58,446	$	43,146	35.5

Three Months Ended June 30, 2013 vs. Three Months Ended June 30, 2012

Distribution’s operating income totaled $6.2 million for the three months ended June 30, 2013 compared to $6.4 million for the three months ended June 30, 2012. The decrease in operating income was primarily due to higher operating expenses partially offset by colder weather during the second quarter of 2013.

Net operating revenues were $32.3 million for the three months ended June 30, 2013 compared to $31.2 million for the three months ended June 30, 2012. Net operating revenues from residential customers increased $1.9 million as a result of favorable weather and related customer usage patterns. Commercial and industrial net operating revenues decreased $0.7 million as a result of a $0.9 million decrease in revenue from a contract that terminated in 2012 partially offset by favorable weather and related customer usage patterns in the second quarter of 2013. Commercial and industrial volumes decreased primarily due to decreased usage by one industrial customer. These high volume industrial sales have low margins and did not significantly impact total net operating revenues. The increases in both total operating revenues and purchased gas costs were primarily due to higher customer throughput as a result of slightly colder weather during the second quarter of 2013 and an increase in the commodity component of tariff rates.

Operating expenses totaled $26.1 million for the three months ended June 30, 2013 compared to $24.8 million for the three months ended June 30, 2012. The increase in operating expenses was primarily due to higher bad debt expense of $0.9 million and higher O&M labor costs partially offset by lower DD&A expense. Bad debt expense increased as a result of increased gas sales due to significantly colder weather in the 2013 winter as compared to 2012. The Company continues to closely monitor its collection rates and adjusts its reserve for uncollectible accounts as necessary.

Six Months Ended June 30, 2013 vs. Six Months Ended June 30, 2012

Distribution’s operating income totaled $58.4 million for the six months ended June 30, 2013 compared to $43.1 million for the six months ended June 30, 2012. The increase in 2013 operating income was primarily due to colder winter weather and a favorable change in estimated recoverable costs due to the completion of the Company’s regulatory gas cost audit.

Net operating revenues were $111.0 million for the six months ended June 30, 2013 compared to $94.6 million for the six months ended June 30, 2012. The increase in net operating revenues was the result of several factors. Net operating revenues from residential customers increased $10.3 million as a result of favorable winter weather that was 25% colder than 2012 and related customer usage patterns. Residential net operating revenues also increased $5.0 million as a result of the completion of the Company’s regulatory gas cost audit which resulted in a favorable change to estimated recoverable costs. Commercial and industrial net operating revenues increased $3.5 million due to favorable weather and related customer usage, partially offset by lower revenues associated with a contract that terminated and competitive contract renewals in 2012. Commercial and industrial volumes increased due to favorable weather in the first half of 2013 but were partially offset by decreased usage by one industrial customer. These high volume industrial sales have low margins and did not significantly impact total net operating revenues. Off-system and energy services net operating revenues decreased primarily as a result of lower gathered volumes in the first half of 2013 as compared to the same period in 2012 partially offset by favorable asset optimization opportunities.

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EQT Corporation and Subsidiaries

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

The increases in both total operating revenues and purchased gas costs were primarily due to higher customer throughput as a result of colder weather during the six months ended June 30, 2013 partially offset by a decrease in the commodity component of tariff rates and a decrease in asset optimization off-system and energy services transactions. The increase in purchased gas costs was also partially offset by the favorable change in estimated recoverable costs due to the completion of the Company’s regulatory gas cost audit.

Operating expenses totaled $52.5 million for the six months ended June 30, 2013 compared to $51.4 million for the six months ended June 30, 2012. The increase in operating expenses was primarily due to higher bad debt expense of $2.6 million as a result of increased gas sales partially offset by the reversal of a $1.0 million operating reserve resulting from the completion of the Company’s regulatory gas cost audit. The Company continues to closely monitor its collection rates and adjusts its reserve for uncollectible accounts as necessary.

OUTLOOK

The Company is committed to profitably developing its Marcellus reserves through environmentally responsible, cost-effective and technologically advanced horizontal drilling. The market price for natural gas can be volatile and these fluctuations can impact the Company’s revenues, earnings and liquidity. The Company is unable to predict 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 its strategy and operations appropriately.

Total capital investment, excluding acquisitions, is expected to be approximately $1.6 billion in 2013. Capital spending for well development (primarily drilling and completion) in 2013 is expected to be approximately $1.1 billion to support the drilling of approximately 176 gross wells, including 146 Marcellus wells, 22 Upper Devonian wells and eight wells in the Utica Shale of Ohio. The Company plans to drill seven fewer Marcellus wells and 11 more Upper Devonian wells than originally planned to take advantage of operational efficiencies of drilling more total wells per pad. All of the Upper Devonian wells are being drilled on Marcellus multi-well pads. Estimated sales volumes for 2013 have been increased to between 360 and 365 Bcfe, approximately 40% higher than in 2012, while NGL volumes are expected to be between 4,800 and 5,000 Mbbls. In addition, the Company plans to invest approximately $400 million on midstream infrastructure in 2013 which includes capital expenditures for the Partnership of $80 million primarily to support its production growth and expects gathering and transmission volumes to increase as a result of this expansion. EQT Midstream expects to add approximately 400 MMcf per day of incremental gathering capacity and approximately 450 MMcf per day of transmission capacity in 2013. The 2013 capital spending plan is expected to be funded by cash on hand, cash flow generated from operations and proceeds from midstream dropdowns to the Partnership.

On December 19, 2012, the Company and its direct wholly-owned subsidiary, Distribution Holdco, LLC (Holdco), executed a definitive agreement with PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC (Peoples), pursuant to which EQT and Holdco will transfer 100% of their ownership interests of Equitable Gas and Homeworks to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Homeworks and Equitable Gas are direct wholly-owned subsidiaries of Holdco. Peoples is a portfolio company of SteelRiver Infrastructure Fund North America LP.

The Company has submitted filings with the Pennsylvania Public Utility Commission, the West Virginia Public Service Commission, the Kentucky Public Service Commission and the Federal Energy Regulatory Commission – each must approve the transaction as part of the regulatory process. The Company expects to receive all necessary approvals by the end of 2013. The transaction was also subject to review by the Federal Trade Commission (FTC) under the Hart-Scott Rodino Antitrust Improvements Act (HSR Act). The waiting period under the HSR Act expired on April 22, 2013, without a request for additional information. This expiration indicates that the FTC has not objected to the transaction and that, from an HSR Act perspective, the parties may complete the transaction.

On July 22, 2013, the Company completed the merger of Sunrise Pipeline, LLC (Sunrise) into the Partnership for a $507.5 million cash payment and Partnership common and general partner units. Prior to the merger, Sunrise entered into a precedent agreement with a third party for firm transportation service over a twenty-year term. If a transportation agreement pursuant to this precedent agreement becomes effective on its current terms by December 31, 2014, the Partnership will make an additional payment of $110 million to EQT. The transportation agreement is subject to review by regulatory authorities, which is expected to be completed by year-end 2013. The Partnership will also pay EQT additional consideration in the event certain other transportation agreements on the Sunrise system become effective prior to December 31, 2014.

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EQT Corporation and Subsidiaries

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

The Company continues to focus on achieving its objective of maximizing shareholder value via a strategy of economically accelerating the monetization of its asset base and prudent pursuit of investment opportunities, all while maintaining a strong balance sheet with solid cash flow. While the tactics continue to evolve based on market conditions, the Company is considering arrangements, including asset sales and joint ventures, to monetize the value of mature assets for re-deployment into higher-value Marcellus Shale development.

CAPITAL RESOURCES AND LIQUIDITY

Overview

The Company’s primary source of cash for the six months ended June 30, 2013 was from operating activities, while the primary use of cash was for capital expenditures.

Operating Activities

Cash flows provided by operating activities totaled $608.8 million for the six months ended June 30, 2013 compared to $418.4 million for the six months ended June 30, 2012. The $190.4 million increase was primarily a result of a 51% increase in natural gas volumes sold, increases in transmission pipeline throughput and gathered volumes, colder weather, which increased cash flows from the Distribution segment, and lower interest payments due to the repayment of long-term debt that matured in 2012, partially offset by higher income tax payments.

Investing Activities

Net cash flows used in investing activities totaled $805.0 million for the first half of 2013 compared to $658.6 million for the first half of 2012. Capital expenditures totaled $805.0 million for the first half of 2013 compared to $662.3 million for the first half of 2012.

Capital expenditures for EQT Production totaled $645.0 million for the six months ended June 30, 2013 compared to $448.6 million for the six months ended June 30, 2012. The $196.4 million increase was primarily attributable to the acquisition of acreage and wells from Chesapeake for approximately $112.5 million in the first half of 2013, while the remaining increase was due to the increase in the number of completed frac stages primarily in the Marcellus play, with approximately 1,703 frac stages completed in the first half of 2013 compared to approximately 1,024 frac stages completed in the first half of 2012. The Company spud 90 gross horizontal wells during the first half of 2013; 74 targeting the Marcellus play, 14 targeting the Upper Devonian play and 2 targeting the Utica play. The Company spud 77 gross horizontal wells during the first six months of 2012; 69 targeting the Marcellus play, one targeting the Upper Devonian play and 7 targeting the Huron play.

Capital expenditures for EQT Midstream totaled $142.6 million for the first six months of 2013 compared to $199.6 million for the first six months of 2012. The $57.0 million decrease was primarily due to the completion of the Sunrise Pipeline, which was placed into service during the third quarter of 2012, and a decrease in gathering compression projects in the Marcellus region. This decrease was partially offset by increased expenditures for gathering pipeline projects in the Marcellus region.

Capital expenditures for Distribution totaled $15.2 million for the first half of 2013 compared to $12.9 million for the first half of 2012, primarily for pipeline replacement.

Financing Activities

Cash flows provided by financing activities totaled $30.8 million for the six months ended June 30, 2013 compared to cash flows used in financing activities of $76.1 million for the six months ended June 30, 2012, a difference of $106.9 million between periods. The Company paid dividends of $9.0 million in the first half of 2013 compared to $65.9 million in the first half of 2012. The Company also had net proceeds of $55.0 million from short-term loans during the first half of 2013 compared to no proceeds or repayments of short-term loans during the same period in 2012. The proceeds from short-term loans were used to fund capital expenditures in excess of cash flow from operating activities. The increase in cash flows provided by financing activities was partially offset by $10.4 million

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EQT Corporation and Subsidiaries

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

in distributions paid to noncontrolling interests and a $10.6 million increase in repayments of long-term debt during 2013 compared to 2012.

Security Ratings and Financing Triggers

The table below reflects the credit ratings for debt instruments of the Company at June 30, 2013. 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 access to the credit markets.

Rating Service	Senior Notes	Short-Term Rating	Outlook
Moody’s Investors Service	Baa3	P-3	Stable
Standard & Poor’s Ratings Services	BBB	A-2	Stable
Fitch Ratings	BBB-	F3	Stable

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 agreements and other financial obligations contain various provisions that, if not complied with, could result in termination of the agreements, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, 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 contains financial covenants that require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income. As of June 30, 2013, the Company was in compliance with all debt provisions and covenants.

The Partnership’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility relate to maintenance of permitted leverage coverage and interest coverage ratios, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Under the credit facility, the Partnership is required to maintain 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 June 30, 2013, the Partnership was in compliance with all credit facility provisions and covenants.

Commodity Risk Management

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

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EQT Corporation and Subsidiaries

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

As of July 24, 2013, the approximate volumes and prices of the Company’s total hedge position for July 2013 through 2015 production were:

	2013**		2014		2015
Fixed Price
Total Volume (Bcf)	102		138		69
Average Price per Mcf (NYMEX)*	$	4.55	$	4.47	$	4.59

	2013**		2014		2015
Collars
Total Volume (Bcf)	13		24		23
Average Floor Price per Mcf (NYMEX)*	$	4.95	$	5.05	$	5.03
Average Cap Price per Mcf (NYMEX)*	$	9.09	$	8.85	$	8.97

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

**July 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 July 10, 2013, the Board of Directors of the Company declared a regular quarterly cash dividend of three cents per share, payable September 1, 2013, to the Company’s shareholders of record at the close of business on August 16, 2013.

Effective July 15, 2013, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.40 per unit. The cash distribution is payable on August 14, 2013, to unitholders of record at the close of business on August 5, 2013.

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, 2012 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 contained in this Form 10-Q for the three and six month periods ended June 30, 2013. 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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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative 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 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 derivative instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and reviewed by the Audit Committee of the 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 fixed price futures contracts, swap agreements and collar agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company also considers other contractual agreements in implementing 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 flows from undue exposure to the risk of changing commodity prices.

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of June 30, 2013 and December 31, 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 402 Bcf and 356 Bcf of natural gas, respectively. See the “Commodity Risk Management” section in the “Capital Resources and Liquidity” section in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for further discussion.

A hypothetical decrease of 10% in the market price of natural gas from the June 30, 2013 and December 31, 2012 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $149.5 million and $131.0 million, respectively. A hypothetical increase of 10% in the market price of natural gas from the June 30, 2013 and December 31, 2012 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $148.9 million and $130.2 million, respectively.

The Company determined the change in the fair value of the derivative commodity instruments using a method 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 June 30, 2013 and December 31, 2012. The price change was then applied to the non-trading natural gas derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheets, resulting in the change in fair value.

The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company’s physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity

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instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.

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

Interest Rate Risk

Changes in interest rates affect the amount of interest the Company and the Partnership earn on cash, cash equivalents and short-term investments and the interest rates the Company and the Partnership pay on borrowings under their respective revolving credit facilities. All of the Company’s long-term borrowings are fixed 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 G and H to the Condensed Consolidated Financial Statements for further discussion of the Company’s borrowings and Note E to the Condensed Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of long-term debt.

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 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.

Approximately 87%, or $229.2 million, of the Company’s OTC derivative contracts outstanding at June 30, 2013 had a positive fair value. Approximately 80%, or $303.0 million, of the Company’s OTC derivative contracts at December 31, 2012 had a positive fair value.

As of June 30, 2013, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheets.

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

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The Company has a $1.5 billion revolving credit facility that expires 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. The Company had loans of $55.0 million and no letters of credit outstanding under the revolving credit facility as of June 30, 2013. 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 expires 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 June 30, 2013, the Partnership had no loans or letters of credit 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. The Company is not a guarantor of the Partnership’s revolving credit obligations under the credit facility.

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 Rule 13a-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 Rule 13a-15(f) under the Exchange Act) that occurred during the second quarter of 2013 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 and its subsidiaries. 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.

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, 2012. 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 Exchange Act that have occurred in the three months ended June 30, 2013:

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

April 2013 (April 1 – April 30)	48	$	69.26	–	–

May 2013 (May 1 – May 31)	2,079	$	79.04	–	–

June 2013 (June 1 – June 30)	–	–		–	–

Total	2,127	$	78.82	–	–

(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.

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Item 6. Exhibits

10.1	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Randall L. Crawford

10.2	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Lewis B. Gardner

10.3	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Steven T. Schlotterbeck

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

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

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

101	Interactive Data File

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Signature

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EQT CORPORATION
		(Registrant)





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

Date: July 25, 2013

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INDEX TO EXHIBITS

Exhibit No.	Description	Method of Filing

10.1	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Randall L. Crawford	Filed herewith as Exhibit 10.1

10.2	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Lewis B. Gardner	Filed herewith as Exhibit 10.2

10.3	Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Steven T. Schlotterbeck	Filed herewith as Exhibit 10.3

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

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

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

101	Interactive Data File	Filed herewith as Exhibit 101