UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~September 30, 2011~~March 31, 2012

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

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE

04-3072771

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(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 and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

Large accelerated filer x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

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

As of ~~October 24, 2011,~~April 23, 2012, there were ~~104,494,374~~209,830,719 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Part I. Financial Information

Item 1. Financial Statements

Condensed Consolidated ~~Statement of Operations for the Three Months~~Balance Sheet at March 31, 2012 and ~~Nine Months Ended September 30,~~December 31, 2011 ~~and 2010~~	3

Condensed Consolidated ~~Balance Sheet at September 30,~~Statement of Operations for the Three Months Ended March 31, 2012 and 2011 ~~and December 31, 2010~~	4

Condensed Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011	5

Condensed Consolidated Statement of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~	56

Notes to the Condensed Consolidated Financial Statements	67

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	20

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk	3228

Item 4. Controls and Procedures	3430

Part II. Other Information

Item 1. Legal Proceedings	3531

Item 1A. Risk Factors	3531

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3531

Item 6. Exhibits	3632

Signatures	3733

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED ~~STATEMENT OF OPERATIONS~~BALANCE SHEET (Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In thousands, except per share amounts)

2011

2010

2011

2010

OPERATING REVENUES

Natural Gas

$
218,521

$
192,026

$
588,976

$
526,424

Brokered Natural Gas

9,467

11,675

38,947

49,896

Crude Oil and Condensate

33,158

19,234

79,792

60,427

Other

971

1,127

4,124

3,901

262,117

224,062

711,839

640,648

OPERATING EXPENSES

Brokered Natural Gas Cost

8,204

10,281

33,362

43,342

Direct Operations

27,292

26,466

76,878

73,796

Transportation and Gathering

19,768

4,932

48,710

13,488

Taxes Other Than Income

7,042

8,489

21,070

31,135

Exploration

20,190

9,665

31,090

28,324

Impairment of Oil and Gas Properties

—

35,789

—

35,789

Depreciation, Depletion and Amortization

90,293

85,355

250,642

235,579

General and Administrative

27,949

21,077

78,254

49,675

200,738

202,054

540,006

511,128

Gain / (Loss) on Sale of Assets

3,854

265

36,408

5,411

INCOME FROM OPERATIONS

65,233

22,273

208,241

134,931

Interest Expense and Other

18,517

16,758

53,928

47,439

Income Before Income Taxes

46,716

5,515

154,313

87,492

Income Tax Expense

18,234

1,617

58,268

33,215

NET INCOME

$
28,482

$
3,898

$
96,045

$
54,277

Earnings Per Share

Basic

$
0.27

$
0.04

$
0.92

$
0.52

Diluted

$
0.27

$
0.04

$
0.91

$
0.52

Weighted-Average Shares Outstanding

Basic

104,285

103,955

104,232

103,889

Diluted

105,460

105,225

105,316

105,144

Dividends Per Common Share

$
0.03

$
0.03

$
0.09

$
0.09

	March 31,			December 31,
(In thousands, except share amounts)	2012			2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	32,328		$	29,911
Accounts Receivable, Net	95,120			114,381
Income Taxes Receivable	—			1,388
Inventories	12,230			21,278
Derivative Instruments	196,683			174,263
Other Current Assets	3,366			4,579
Total Current Assets	339,727			345,800
Properties and Equipment, Net (Successful Efforts Method)	4,011,203			3,934,584
Derivative Instruments	22,259			21,249
Other Assets	29,605			29,860
	$	4,402,794		$	4,331,493

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	213,188		$	217,294
Income Taxes Payable	799			—
Deferred Income Taxes	61,871			55,132
Accrued Liabilities	46,296			70,918
Total Current Liabilities	322,154			343,344
Postretirement Benefits	39,591			38,708
Long-Term Debt	1,012,000			950,000
Deferred Income Taxes	814,189			802,592
Asset Retirement Obligation	61,284			60,142
Other Liabilities	28,620			31,939
Total Liabilities	2,277,838			2,226,725

Commitments and Contingencies

Stockholders’ Equity
Common Stock:
Authorized — 240,000,000 Shares of $0.10 Par Value in 2012 and 2011 Issued—209,829,748 Shares and 209,019,458 Shares in 2012 and 2011, respectively	20,983			20,902
Additional Paid-in Capital	716,965			724,377
Retained Earnings	1,272,432			1,258,291
Accumulated Other Comprehensive Income	117,925			104,547
Less Treasury Stock, at Cost:
404,400 Shares in 2012 and 2011, respectively	(3,349		)	(3,349		)
Total Stockholders’ Equity	2,124,956			2,104,768
	$	4,402,794		$	4,331,493

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED ~~BALANCE SHEET~~STATEMENT OF OPERATIONS (Unaudited)

September 30,

December 31,

(In thousands, except share amounts)

2011

2010

ASSETS

Current Assets

Cash and Cash Equivalents

$
62,928

$
55,949

Accounts Receivable, Net

101,612

94,488

Income Taxes Receivable

10,158

—

Inventories

28,296

29,667

Derivative Instruments

100,489

16,926

Other Current Assets

6,554

5,978

Total Current Assets

310,037

203,008

Properties and Equipment, Net (Successful Efforts Method)

4,103,317

3,762,760

Other Assets

59,043

39,263

$
4,472,397

$
4,005,031

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts Payable

$
207,798

$
229,981

Income Taxes Payable

—

25,957

Deferred Income Taxes

31,975

—

Accrued Liabilities

49,204

47,897

Total Current Liabilities

288,977

303,835

Pension and Postretirement Benefits

39,443

34,053

Long-Term Debt

1,205,000

975,000

Deferred Income Taxes

785,146

714,953

Asset Retirement Obligation

74,784

72,311

Other Liabilities

35,877

32,179

Total Liabilities

2,429,227

2,132,331

Commitments and Contingencies

Stockholders’ Equity

Common Stock:

Authorized – 240,000,000 Shares of $0.10 Par Value in 2011 and 2010 Issued–104,492,690 Shares and 104,210,084 Shares in 2011 and 2010, respectively

10,449

10,421

Additional Paid-in Capital

730,985

720,920

Retained Earnings

1,235,059

1,148,391

Accumulated Other Comprehensive Income/(Loss)

70,026

(3,683
)
Less Treasury Stock, at Cost:

202,200 Shares in 2011 and 2010, respectively

(3,349
)
(3,349
)
Total Stockholders’ Equity

2,043,170

1,872,700

$
4,472,397

$
4,005,031

	Three Months Ended
	March 31,
(In thousands, except per share amounts)	2012			2011

OPERATING REVENUES
Natural Gas	$	206,782		$	170,098
Brokered Natural Gas	13,444			18,408
Crude Oil and Condensate	49,981			18,592
Other	1,929			1,928
	272,136			209,026
OPERATING EXPENSES
Brokered Natural Gas Cost	11,872			15,362
Direct Operations	27,320			27,007
Transportation and Gathering	30,258			12,868
Taxes Other Than Income	18,583			8,151
Exploration	4,001			6,308
Depreciation, Depletion and Amortization	110,357			77,124
General and Administrative	22,549			24,299
	224,940			171,119
Gain / (Loss) on Sale of Assets	(535		)	(1,517		)
INCOME FROM OPERATIONS	46,661			36,390
Interest Expense and Other	16,917			17,367
Income Before Income Taxes	29,744			19,023
Income Tax Expense	11,426			6,137
NET INCOME	$	18,318		$	12,886

Earnings Per Share
Basic	$	0.09		$	0.06
Diluted	$	0.09		$	0.06

Weighted-Average Shares Outstanding
Basic	209,128			208,288
Diluted	210,813			210,640

Dividends per common share	$	0.02		$	0.02

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF ~~CASH FLOWS~~COMPREHENSIVE INCOME (Unaudited)

Nine Months Ended
September 30,

(In thousands)

2011

2010

CASH FLOWS FROM OPERATING ACTIVITIES

Net Income

$
96,045

$
54,277

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

Depreciation, Depletion and Amortization

250,642

235,579

Impairment of Oil and Gas Properties

—

35,789

Deferred Income Tax Expense

57,381

30,465

(Gain) / Loss on Sale of Assets

(36,408
)
(5,411
)
Exploration Expense

13,851

10,473

Unrealized Loss / (Gain) on Derivative Instruments

950

(162
)
Amortization of Debt Issuance Costs

3,317

8,298

Stock-Based Compensation, Pension and Other

42,432

12,886

Changes in Assets and Liabilities:

Accounts Receivable, Net

(7,124
)
4,842

Income Taxes

(36,115
)
4,937

Inventories

1,371

(4,353
)
Other Current Assets

(832
)
3,070

Accounts Payable and Accrued Liabilities

(9,941
)
(14,252
)
Other Assets and Liabilities

(203
)
(8,838
)
Stock-Based Compensation Tax Benefit

—

(108
)
Net Cash Provided by Operating Activities

375,366

367,492

CASH FLOWS FROM INVESTING ACTIVITIES

Capital Expenditures

(668,987
)
(658,123
)
Proceeds from Sale of Assets

82,109

21,033

Net Cash Used in Investing Activities

(586,878
)
(637,090
)

CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings from Debt

330,000

300,000

Repayments of Debt

(100,000
)
(10,000
)
Dividends Paid

(9,379
)
(9,348
)
Capitalized Debt Issuance Costs

(1,025
)
(13,696
)
Other

(1,105
)
72

Net Cash Provided by Financing Activities

218,491

267,028

Net Increase / (Decrease) in Cash and Cash Equivalents

6,979

(2,570
)
Cash and Cash Equivalents, Beginning of Period

55,949

40,158

Cash and Cash Equivalents, End of Period

$
62,928

$
37,588

	Three Months Ended
	March 31,
(In thousands)	2012				2011

Net Income		$	18,318			$	12,886

Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $21,600 and $5,008, respectively		(34,070		)		(8,171		)
Changes in Fair Value of Hedge Positions, net of taxes of $(27,523) and $(4,778), respectively		43,205				7,795
Defined Benefit Pension and Postretirement Plans:
Amortization of Net Obligation at Transition, net of taxes of $0 and $(59), respectively	—				99
Amortization of Prior Service Cost, net of taxes of $(43) and $(118), respectively	68				199
Amortization of Net Loss, net of taxes of $(2,647) and $(1,194), respectively	4,175	4,243			2,009	2,307
Foreign Currency Translation Adjustment, net of taxes of $0 and $0, respectively		—				(2		)
Total Other Comprehensive Income / (Loss)		13,378				1,929

Comprehensive Income / (Loss)		$	31,696			$	14,815

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Three Months Ended
	March 31,
(In thousands)	2012			2011

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	18,318		$	12,886
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	110,357			77,124
Deferred Income Tax Expense	9,724			6,543
(Gain) / Loss on Sale of Assets	535			1,517
Exploration Expense	49			493
Unrealized (Gain) / Loss on Derivative Instruments	(42		)	(17		)
Amortization of Debt Issuance Costs	1,064			1,120
Stock-Based Compensation, Pension and Other	(1,470		)	12,614
Changes in Assets and Liabilities:
Accounts Receivable, Net	19,261			3,902
Income Taxes	2,187			(24,202		)
Inventories	9,048			8,861
Other Current Assets	518			1,014
Accounts Payable and Accrued Liabilities	(38,149		)	(9,615		)
Other Assets and Liabilities	380			(1,027		)
Net Cash Provided by Operating Activities	131,780			91,213

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures	(188,547		)	(203,169		)
Proceeds from Sale of Assets	1,280			5,043
Net Cash Used in Investing Activities	(187,267		)	(198,126		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from Debt	90,000			110,000
Repayments of Debt	(28,000		)	(30,000		)
Dividends Paid	(4,177		)	(3,122		)
Other	81			(1,018		)
Net Cash Provided by Financing Activities	57,904			75,860

Net Increase / (Decrease) in Cash and Cash Equivalents	2,417			(31,053		)
Cash and Cash Equivalents, Beginning of Period	29,911			55,949
Cash and Cash Equivalents, End of Period	$	32,328		$	24,896

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies ~~used~~disclosed in its Annual Report on Form 10-K for the year ended December 31, ~~2010~~2011 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Certain reclassifications have been made to prior year statements to conform towith current year presentation. These reclassifications have no impact on previously reported net income.

~~With respect~~On January 3, 2012, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the ~~unaudited financial information~~2-for-1 split of the Company’s common stock.

WithrespecttotheunauditedfinancialinformationoftheCompanyasof ~~September 30,~~ March31,2012andforthethreemonthsendedMarch31,2012and2011,PricewaterhouseCoopersLLPreportedthattheyhaveappliedlimitedproceduresinaccordancewithprofessionalstandardsforareviewofsuchinformation.However,theirseparatereportdatedApril27,2012appearinghereinstatesthattheydidnotauditandtheydonotexpressanopiniononthatunauditedfinancialinformation.Accordingly,thedegreeofrelianceontheirreportonsuchinformationshouldberestrictedinlightofthelimitednatureofthereviewproceduresapplied.PricewaterhouseCoopersLLPisnotsubjecttotheliabilityprovisionsofSection11oftheSecuritiesActof1933fortheirreportonthe ~~three~~ unauditedfinancialinformationbecausethatreportisnota“report”ora“part”oftheregistrationstatementpreparedorcertifiedbyPricewaterhouseCoopersLLPwithinthemeaningofSections7and ~~nine months ended September 30, 2011 and 2010, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review~~ 11of such information. However, their separate report dated October 28, 2011 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

~~Recently Issued~~Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and ~~IFRS.~~IFRSs.” The amendments in ~~ASU No. 2011-04~~this update generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ~~ASU No. 2011-04~~This update results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and IFRS. The amendments ~~in ASU No. 2011-04 are to be applied prospectively. For public entities, the amendments~~ are effective for interim and annual periods beginning after December 15, ~~2011. Early application by public entities is~~2011 and are to be applied prospectively. This update did not ~~permitted. The Company does not expect this guidance to~~ have ~~a significant~~any impact on ~~its~~the Company’s consolidated financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive ~~Income,~~Income.” ~~requiring most entities~~This update was amended in December 2011 by ASU No. 2011-12, “Deferral of the Effective Date for Amendments to ~~present items~~the Presentation of ~~net income and~~Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.” This update defers only those changes in update 2011-05 that relate to the presentation of reclassification adjustments. All other requirements in update 2011-05 are not affected by this update, including the requirement to report comprehensive income either in ~~one~~a single continuous ~~statement—referred to as the~~financial statement ~~of comprehensive income—~~or in two separate but consecutive ~~statements of net income~~financial statements. ASU No. 2011-05 and ~~other comprehensive income. The new requirements~~2011-12 are effective ~~for public entities~~ for fiscal years (including interim periods) beginning after December 15, 2011. The Company has elected to present two separate but consecutive financial statements. These updates did not have any impact on the Company’s consolidated financial position, results of operations or cash flows.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. The

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Company does not expect this guidance to have ~~a significant~~any impact on its consolidated financial position, results of operations or cash flows.

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2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

	September 30,			December 31,			March 31,			December 31,
(In thousands)	2011			2010			2012			2011

Proved Oil and Gas Properties	$	5,377,363		$	4,794,650		$	5,185,986		$	5,006,846
Unproved Oil and Gas Properties	505,131			490,181				483,846			478,942
Gathering and Pipeline Systems	237,666			237,043			238,281			238,660
Land, Building and Other Equipment	79,109			86,248			81,350			80,908
	6,199,269			5,608,122			5,989,463			5,805,356
Accumulated Depreciation, Depletion and Amortization	(2,095,952		)	(1,845,362		)	(1,978,260		)	(1,870,772		)
	$	4,103,317		$	3,762,760		$	4,011,203		$	3,934,584

At ~~September 30, 2011,~~March 31, 2012, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In the third quarter of 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to fair value of approximately $15.4 million using discounted future cash flows. The fair value of these fields was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820. Refer to Note 8 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010).

Haynesville/Bossier Shale Joint ~~Ventures~~Venture

During the first ~~nine~~three months of 2011, the Company entered into ~~two~~a participation ~~agreements~~agreement with a third ~~parties~~party related to certain of its Haynesville and Bossier ~~Shale~~shale leaseholds in east Texas. Under the terms of the participation ~~agreements,~~agreement, the third ~~parties~~party agreed to fund 100% of the cost to drill and complete certain Haynesville and Bossier ~~Shale~~shale wells in the related leaseholds over a multi-year period in exchange for a 75% working interest in the leaseholds. During the first ~~nine months~~quarter of 2011, the Company received a reimbursement of drilling costs incurred of approximately ~~$11.2~~$5.9 million associated with ~~the~~ wells that had commenced drilling prior to the execution of the participation ~~agreements.~~

In May 2011, the Company sold certain of its Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. The Company received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.

~~Other Divestitures~~

In July 2011, the Company entered into a purchase and sale agreement to sell certain oil and gas properties located in Colorado, Utah and Wyoming to BreitBurn Energy Partners L.P. for $285 million. This transaction closed on October 6, 2011 and is subject to certain post-closing adjustments scheduled to occur in the fourth quarter of 2011. The net book value associated with the oil and gas properties and the related asset retirement obligation held for sale as of September 30, 2011 were $291.3 million and $12.1 million, respectively, and are included in Properties and Equipment, Net and Asset Retirement Obligation, respectively, in the Condensed Consolidated Balance Sheet.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the proposed sale of these properties. The impairment charge was included in Gain / (Loss) on Sale of Assets in the Condensed Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of these properties were considered Level 2 in the fair value hierarchy.agreement.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	September 30,			December 31,			March 31,			December 31,
(In thousands)	2011			2010			2012			2011

ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	98,661		$	91,077		$	91,742		$	111,306
Joint Interest Accounts	5,871			4,901			3,840			5,417
Other Accounts	810			2,603			778			1,003
	105,342			98,581			96,360			117,726
Allowance for Doubtful Accounts	(3,730		)	(4,093		)	(1,240		)	(3,345		)
	$	101,612		$	94,488		$	95,120		$	114,381
INVENTORIES
Natural Gas in Storage	$	18,633		$	13,371		$	3,854		$	13,513
Tubular Goods and Well Equipment	10,150			17,072			7,539			7,146
Pipeline Imbalances	(487		)	(776		)
Other							837			619
	$	28,296		$	29,667		$	12,230		$	21,278
OTHER CURRENT ASSETS
Drilling Advances	$	821		$	2,796
Prepaid Balances	3,499			2,925			1,371			2,290
Restricted Cash	2,234			—			1,907			2,234
Deferred Income Taxes	—			257
Other							88			55
	$	6,554		$	5,978		$	3,366		$	4,579
OTHER ASSETS
Rabbi Trust Deferred Compensation Plan	15,503			15,788			$	11,644		$	10,838
Debt Issuance Costs	18,744			22,061
Derivative Instruments	23,453			—
Debt Issuance Cost							16,616			17,680
Other Accounts	1,343			1,414			1,345			1,342
	$	59,043		$	39,263		$	29,605		$	29,860
ACCOUNTS PAYABLE
Trade Accounts	$	18,570		$	27,401		$	14,052		$	18,253
Natural Gas Purchases	6,047			3,596			1,966			3,012
Royalty and Other Owners	43,025			36,034			39,574			48,113
Accrued Capital Costs	127,489			146,824			136,860			138,122
Taxes Other Than Income	2,477			2,655			11,847			2,076
Drilling Advances							385			1,489
Wellhead Gas Imbalances	4,498			5,142			2,351			2,312
Other Accounts	5,692			8,329			6,153			3,917
	$	207,798		$	229,981		$	213,188		$	217,294
ACCRUED LIABILITIES
Employee Benefits	$	15,921		$	10,790		$	5,858		$	26,035
Pension and Postretirement Benefits	1,688			1,688			5,917			6,331
Taxes Other Than Income	15,151			14,576			11,562			12,297
Interest Payable	15,708			19,488			14,875			24,701
Derivative Contracts							6,538			385
Other Accounts	736			1,355			1,546			1,169
	$	49,204		$	47,897		$	46,296		$	70,918
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	24,362		$	21,600		$	19,183		$	20,187
Derivative Instruments	—			2,180
Derivative Contracts							1,481			—
Other Accounts	11,515			8,399			7,956			11,752
	$	35,877		$	32,179		$	28,620		$	31,939

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4. LONG-TERM DEBT

The Company’s debt consisted of the following:

(In thousands)

September 30,
2011

December 31,
2010

Long-Term Debt

7.33% Weighted-Average Fixed Rate Notes

$
95,000

$
95,000

6.51% Weighted-Average Fixed Rate Notes

425,000

425,000

9.78% Notes

67,000

67,000

5.58% Weighted-Average Fixed Rate Notes

175,000

175,000

Credit Facility

443,000

213,000

$
1,205,000

$
975,000

The Company’s revolving credit facility provides for an available line of credit of $900 million and contains an accordion feature allowing the Company to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. Effective April 1, 2011, the lenders under the Company’s revolving credit facility approved an increase in the Company’s Borrowing Base from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the credit facility. The Company’s plan to sell certain oil and gas properties located in Colorado, Utah and Wyoming, triggered an interim redetermination of the Company’s Borrowing Base and the $1.7 billion Borrowing Base was reaffirmed by the lenders effective September 27, 2011.

(In thousands)	March 31, 2012		December 31, 2011
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	95,000
6.51% Weighted-Average Fixed Rate Notes	425,000		425,000
9.78% Notes	67,000		67,000
5.58% Weighted-Average Fixed Rate Notes	175,000		175,000
Credit Facility	250,000		188,000
	$	1,012,000	$	950,000

At ~~September 30, 2011,~~March 31, 2012, the Company had ~~$443.0~~$250.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of ~~4.0%~~3.6% and ~~$456.8~~$649.0 million available for future borrowings. ~~In addition, the Company had letters of credit outstanding at September 30, 2011 of $0.3 million.~~

5. EARNINGS PER COMMON SHARE

Basic EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.

The following is a calculation of basic and diluted weighted-average shares outstanding:

Three Months Ended

Nine Months Ended

Three Months Ended

September 30,

March 31,

(In thousands)

2011

2010

2011

2010

2012

2011

Weighted-Average Shares - Basic

104,285

103,955

104,232

103,889

209,128

208,288

Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period

1,175

1,270

1,084

1,255

1,685

2,352

Weighted-Average Shares - Diluted

105,460

105,225

105,316

105,144

210,813

210,640

Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect

—

220

708

6. COMMITMENTS AND CONTINGENCIES

~~Contingencies~~Constitution Pipeline Company, LLC

In February 2012, the Company entered into a Precedent Agreement with Constitution Pipeline Company, LLC (Constitution), at the time a wholly owned subsidiary of Williams Partners L.P., to develop and construct a 120 mile large diameter pipeline to transport its production in northeast Pennsylvania to both the New England and New York markets. Under the terms of the Precedent Agreement, the Company will have transportation rights for up to approximately 500,000 Mcf per day of capacity on the newly constructed pipeline and the right to acquire a 25% equity interest in the project, subject to regulatory approval and certain terms and conditions to be determined.

In April 2012, the Company entered into an Amended and Restated Limited Liability Company Agreement (LLC Agreement) with Constitution. Under the terms of the LLC Agreement, the Company agreed to invest approximately $187 million in exchange for a 25% equity interest, subject to a contribution cap of $250 million. The investment, which is expected to occur over the next three years, will fund the development and construction of the pipeline and related facilities.

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Legal Matters

Preferential Purchase Right Litigation

In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit seeks unspecified damages arising out of the Company’s 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleges breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement, to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court dated February 2007. Plaintiff appealed the ruling to the Pennsylvania Superior Court, where the ruling in favor of the Company was reversed and remanded to the trial court in March 2008. The Company appealed the Superior Court ruling to the Pennsylvania Supreme Court, but in December 2008 that Court declined to review. Effective July 2008, Linn Energy, LLC sold the subject properties to XTO Energy, Inc., giving rise to a second lawsuit for unspecified damages filed in September 2009 by EXCO—North Coast Energy, Inc., as successor in interest to Power Gas Marketing & Transmission, Inc., against the Company, Linn Energy, LLC and XTO Energy, Inc. The second lawsuit has been consolidated into the first lawsuit. A bench trial on the merits, should one be necessary, has been set for early June 2012.

The Company believes that the plaintiff’s claims lack merit and does not consider a loss related to this matter to be probable; however, due to the inherent uncertainties of litigation a loss is possible. In the event that the Company is found liable, the potential loss is currently estimated to be less than $15 million.

Other

The Company is also a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position or cash flow; however, operating results could be significantly impacted in reporting periods in which such matters are resolved.

Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. ~~All known liabilities are accrued~~The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While ~~the outcome and impact of such legal proceedings on~~management believes these reserves to be adequate, it is reasonably possible that the Company ~~cannot be predicted~~could incur additional losses with ~~certainty, management~~respect to those matters in which reserves have been established. The Company believes that any such amount above the ~~resolution of these proceedings through settlement or adverse judgment will~~amounts accrued is not ~~have a~~ material ~~adverse effect on~~to the ~~Company’s condensed consolidated financial position or cash flow. Operating results, however,~~Condensed Consolidated Financial Statements. Future changes in facts and circumstances could ~~be significantly impacted~~result in the ~~reporting periods in which such matters are resolved.~~

~~Table~~actual liability exceeding the estimated ranges of ~~Contents~~loss and amounts accrued.

Environmental Matters

Pennsylvania Department of Environmental Protection

On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) ~~entered into~~executed a ~~single settlement agreement~~consent order (Consent Order) ~~covering~~addressing a number of ~~separate, unrelated~~ environmental issues ~~occurring~~identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of 13 water ~~wells~~supplies in Susquehanna County, Pennsylvania. ~~The~~As part of the settlement, the Company paid an aggregate $120,000 civil penalty with respect to ~~all~~ the matters ~~covered~~addressed by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and the PaDEP ~~reached agreement on modifications to the~~executed a modified Consent Order (First Modified Consent Order). ~~In the~~The First Modified Consent Order ~~the PaDEP and the Company agreed~~provided that the Company ~~will provide~~would make available a permanent source of potable water to 14 households, most of which the Company ~~has~~had already been supplying with water. The First Modified Consent Order included the following conditions: (i) the Company ~~agreed to~~would plug and abandon three vertical natural gas wells ~~in close proximity to two of the households~~ and ~~to bring into compliance~~would undertake certain remedial measures on a fourth well in ~~the~~a nine square mile area ~~of concern~~ in Susquehanna ~~County. The~~County; (ii) the Company ~~agreed to~~would complete these actions prior to ~~any~~ new natural gas well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of ~~concern. The~~concern; and (iii) the Company would also ~~agreed to~~ postpone drilling of new natural gas wells in the area of concern until ~~all obligations under~~certain terms of the consent orders ~~are~~were fulfilled. In addition, the First Modified Consent Order included a condition that the Company ~~agreed to~~would take certain other actions if requested by the PaDEP and agreed to by the Company, which could include the plugging and abandonment of up to 10 additional wells. ~~Under~~As part of the settlement, the Company paid a $240,000 civil

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penalty and the First Modified Consent Order included a provision that the Company ~~paid a $240,000 civil penalty and agreed to~~would pay an additional $30,000 per month until ~~all obligations~~certain terms under the First Modified Consent Order ~~are~~were satisfied.

On July 19, 2010, the Company and the PaDEP ~~entered~~executed a Second Modification to Consent Order (Second Modified Consent Order) ~~under which the Company and the PaDEP agreed~~acknowledging that the Company ~~has satisfactorily~~ plugged and abandoned the three vertical natural gas wells and ~~brought~~completed work on the fourth natural gas well ~~into compliance.~~to the PaDEP’s satisfaction. As a result, the ~~Company and the~~ PaDEP agreed ~~that the PaDEP will~~to commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company ~~continues~~continued to provide temporary potable water and ~~offers~~offered to provide gas/water separators to ~~the~~ 14 households. No penalties were assessed under the Second Modified Consent Order.

As ~~required by~~outlined in the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to ~~the~~ 14 households. ~~As required by the First Modified Consent Order, on~~On August 5, 2010, the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s natural gas well drilling and development activities ~~are~~were not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

~~Despite the Company’s vigorous efforts to comply with the various consent orders, in~~In a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and ~~determined~~stated its determination that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company ~~in accordance with the First Modified Consent Order,~~ to plug or take ~~other~~ remedial actions at the remaining 10 natural gas wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water ~~system to permanently eliminate the continuing adverse affect to those water supplies.~~systems.

~~The Company believed that it was in full compliance with the various consent orders.~~ In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 natural gas wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. The Company believed that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders. The Company also asserted its belief that the Consent Order, First Modified Consent Order and Second Modified Consent Order were unlawful and not legally binding or enforceable.

On December 15, 2010, the Company entered into a ~~global~~consent order and settlement agreement ~~and new consent order~~ with the PaDEP ~~(Global Settlement Agreement)~~(CO&SA), which according to its terms supersedes and/or replaces the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the ~~Global Settlement Agreement,~~CO&SA, among other things, the Company agreed to ~~pay~~place a total of $4.2 million into ~~separate~~ escrow accounts for the benefit of each ~~affected household,~~of the identified households, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, ~~remediate~~perform remedial measures for two natural gas wells in the ~~affected~~ area of concern, provide pressure, water quality and water well headspace data to the PaDEP and offer water treatment to the ~~affected~~ households. The ~~Global Settlement Agreement settles~~CO&SA settled all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the natural gas wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to seek to begin hydraulic fracturing and to commence drilling new wells in the affected areas after providing the PaDEP with ~~well pressure data.~~certain data and information. Under the ~~Global Settlement Agreement,~~CO&SA, the Company has no obligation to connect the impacted water supplies to a community public water system.

On January 11, 2011, certain of the affected households appealed the ~~Global Settlement Agreement~~CO&SA to the Pennsylvania Environmental Hearing ~~Board. A hearing on the merits of this appeal is not expected to occur until 2012.~~Board (PEHB).

~~As of the date of this report, the~~The Company is in continuing discussions with the PaDEP to address the results of the Company’s natural gas well ~~pressure tests,~~test data, water quality sampling and water well headspace screenings. The Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected

~~Table of Contents~~

households. On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners ~~who are subject to the Global Settlement Agreement~~ are no longer ~~required.~~necessary.

On November 18, 2011, certain of the affected households appealed to the PEHB the PaDEP’s October 18, 2011 determination that temporary water deliveries were no longer necessary to the property owners and on November 23, 2011 filed a Petition for Supersedeas in the appeal. On December 9, 2011, the PEHB denied the Petition for Supersedeas and consolidated the appeal of the CO&SA with the appeal of the October 18, 2011 determination. A hearing on the consolidated matter is expected to occur in 2012.

As of ~~September 30, 2011,~~March 31, 2012, the Company has paid $1.3 million in settlement of fines and penalties tosought or claimed by the PaDEP related to this matter, paid ~~$2.0~~$2.3 million (through the escrow process) to ~~seven~~ten of the affected households and accrued a ~~$2.2~~$1.9 million settlement liability that represents the unpaid escrow balance, which is included in Other Liabilities in the Condensed Consolidated Balance Sheet.

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~~Transportation Agreements~~United States Environmental Protection Agency

~~During~~By letter dated January 6, 2012, the ~~first nine months~~United States Environmental Protection Agency (EPA) sent a Required Submission of ~~2011,~~Information—Dimock Township Drinking Water Contamination letter to the Company pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended ~~certain gas transportation~~(CERCLA). The Required Submission of Information requests all documents, water sampling results and ~~gathering agreements with third party pipelines that increased the minimum daily quantity, increased the transportation fee and/or extended the term of the agreement.~~

~~Future minimum obligations under gas transportation agreements as of September 30, 2011 are as follows:~~

(In thousands)

2011

$
11,969

2012

57,066

2013

56,965

2014

56,965

2015

56,965

Thereafter

555,268

$
795,198

~~For further information on~~any other correspondence related to the Company’s ~~gas transportation agreements, please refer to Note 8~~activities in the area of concern. The Company does not agree that the ~~Notes~~Submission of Information is required; however, the Company is providing information pursuant to the ~~Consolidated Financial Statements in the Form 10-K.~~

~~Drilling Rig Commitments~~

As of September 30, 2011, the Company has a three-year drilling rig commitment for its capital program in the Marcellus Shale in northeast Pennsylvania commencing in the fourth quarter of 2011. As of September 30, 2011, the aggregate minimum future drilling rig commitment was approximately $20.4 million.request.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. As of ~~September 30, 2011,~~March 31, 2012, the Company had 4239 derivative contracts open: 2723 natural gas price swap arrangements, six natural gas basis swap arrangements, five crude oil swap arrangements and five natural gas collar ~~arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap~~ arrangements. During the first ~~nine~~three months of ~~2011,~~2012, the Company entered into 31two new derivative contracts covering anticipated ~~natural gas and~~ crude oil production for ~~2011,~~ 2012 and 2013.

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As of ~~September 30, 2011,~~March 31, 2012, the Company had the following outstanding commodity derivatives:

Commodity and Derivative Type

Weighted-Average Contract Price

Volume

Contract Period

Weighted-Average Contract Price

Volume

Contract Period

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24

per Mcf

3,254

Mmcf

Oct. 2011 - Dec. 2011

$5.22

per Mcf

72,129

Mmcf

Apr. 2012 - Dec. 2012

Natural Gas Swaps

$5.18

per Mcf

98,302

Mmcf

Oct. 2011 - Dec. 2012

Natural Gas Swaps

$5.28

per Mcf

17,854

Mmcf

Jan. 2012 - Dec. 2012

Natural Gas Collars

$6.17 Ceiling/ $5.13 Floor

per Mcf

17,805

Mmcf

Jan. 2013 - Dec. 2013

$6.20 Ceiling/
$5.15 Floor

per Mcf

17,729

Mmcf

Jan. 2013 - Dec. 2013

Crude Oil Collars

$93.25 Ceiling / $80.00 Floor

per Bbl

Mbbl

Oct. 2011- Dec. 2011

Crude Oil Swaps

$106.20

per Bbl

Mbbl

Oct. 2011 - Dec. 2011

$99.30

per Bbl

1,100

Mbbl

Apr. 2012 - Dec. 2012

Crude Oil Swaps

$105.00

per Bbl

366

Mbbl

Jan. 2012 - Dec. 2012

$100.33

per Bbl

732

Mbbl

Jan. 2013 - Dec. 2013

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.27

) per Mcf

16,123

Mmcf

Jan. 2012 - Dec. 2012

$(0.25

)

per Mcf

12,805

Mmcf

Apr. 2012 - Dec. 2012

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income / (Loss) in Stockholders’ Equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in fair value of derivatives designated as hedges, and the change in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural Gas Revenue and Crude Oil and Condensate Revenue, as appropriate, in the Condensed Consolidated Statement of Operations.

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The following disclosures reflect the impact of derivative instruments on the Company’s condensed consolidated financial statements:

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

		Fair Value Asset (Liability)							Fair Value Asset (Liability)
(In thousands)	Balance Sheet Location	September 30, 2011			December 31, 2010			Balance Sheet Location	March 31, 2012			December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity Contracts	Derivative Instruments (current assets)	$	102,908		$	16,926		Derivative Instruments (current assets)	$	199,071		$	177,389
Commodity Contracts	Other Assets	24,164			—			Accrued Liabilities	(6,538		)	(385		)
Commodity Contracts								Derivative Instruments (non-current assets)	22,259			21,249
Commodity Contracts								Other Liabilities	(1,481		)	—
		127,072			16,926				213,311			198,253
Derivatives Not Designated as Hedging Instruments
Commodity Contracts	Derivative Instruments (current assets)	(2,419		)	—			Derivative Instruments (current assets)	(2,388		)	(3,126		)
Commodity Contracts	Other Assets	(711		)	—
Commodity Contracts	Other Liabilities	—			(2,180		)
		(3,130		)	(2,180		)		$	210,923		$	195,127
		$	123,942		$	14,746

At ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010,~~2011, unrealized gains of ~~$127.1~~$213.3 million ($~~78.8~~130.5 million, net of tax) and ~~$16.9~~$198.3 million ($~~10.5~~121.3 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income / (Loss). Based upon estimates at ~~September 30, 2011,~~March 31, 2012, the Company expects to reclassify ~~$63.8~~$117.8 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income / (Loss) to the Condensed Consolidated Statement of Operations over the next 12 months.

~~Table of Contents~~

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective
Portion)

Location of Gain (Loss)
Reclassified from

Amount of Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)

Derivatives Designated as
Hedging Instruments

Three Months Ended
September 30,

Nine Months Ended
September 30,

Accumulated OCI into
Income

Three Months Ended
September 30,

Nine Months Ended
September 30,

(In thousands)

2011

2010

2011

2010

(In thousands)

2011

2010

2011

2010

Commodity Contracts

$
98,143

$
24,758

$
159,030

$
79,514

Natural Gas Revenues

$
21,170

$
39,461

$
48,318

$
109,714

Crude Oil and Condensate Revenues

1,382

5,160

566

14,522

$
22,552

$
44,621

$
48,884

$
124,236

Three Months Ended

Three Months Ended
March 31,

March 31,

2012

2011

2012

2011

Location of Gain (Loss)

Amount of Gain (Loss)

Derivatives Designated as
Hedging Instruments
(In thousands)

Amount of Gain (Loss)
Recognized in OCI on Derivative
(Effective Portion)

Reclassified from
Accumulated OCI into
Income

Reclassified from Accumulated
OCI into Income (Effective
Portion)

Commodity Contracts

70,728

12,573

Natural Gas Revenues

56,996

13,481

Crude Oil and Condensate Revenues

(1,326

)

(302

)

55,670

13,179

For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2012 and 2011, ~~and 2010,~~ respectively, there was no ineffectiveness recorded in our Condensed Consolidated Statement of Operations related to our derivative instruments.

Derivatives Not Designated as
Hedging Instruments

Location of Gain (Loss)
Recognized in Income on

Three Months Ended
September 30,

Nine Months Ended
September 30,

Location of Gain (Loss) Recognized

Three Months Ended
March 31,

(In thousands)

Derivatives

2011

2010

2011

2010

in Income on Derivative

2012

2011

Commodity Contracts

Natural Gas Revenues

(64

)

(193

)

(950

)

162

Natural Gas Revenues

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Additional Disclosures about Derivative Instruments and Hedging Activities

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligation under the agreement. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with all of its counterparties that allow it to offset payables against receivables from separate derivative contracts with that counterparty.

The counterparties to the Company’s derivative instruments are also lenders under its credit facility. The Company’s credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liability in certain situations.

8. FAIR VALUE MEASUREMENTS

~~Accounting Standards Codification (ASC)~~ASC 820, “Fair Value Measurements and Disclosures,” established a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by generally accepted accounting principles (GAAP) to be measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. ASC 820 establishes formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.

The Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. For further information regarding the fair value hierarchy, refer to Note 1413 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a nonrecurring basis. During the nine month period ended September 30, 2010, the Company recorded an impairment related to certain oil and gas properties. Refer to Note 2 for additional disclosures related to fair value associated with the impaired properties.

~~Table of Contents~~

As none of the Company’s ~~other~~ non-financial assets and liabilities were impaired as of ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~ and no other ~~fair value measurements~~assets or liabilities were required to be ~~recognized~~measured at fair value on a non-recurring basis, additional disclosures are not provided.

Financial Assets and Liabilities

~~Our~~The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring ~~basis as of September 30, 2011 and December 31, 2010:~~basis:

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of September 30, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of March 31, 2012
Assets
Rabbi Trust Deferred Compensation Plan	$	15,503	$	—	$	—	$	15,503	$	11,644	$	—	$	—	$	11,644
Derivative Contracts	—		—		123,942		123,942		—		—		218,942		218,942
Total Assets	$	15,503	$	—	$	123,942	$	139,445	$	11,644	$	—	$	218,942	$	230,586

Liabilities
Rabbi Trust Deferred Compensation Plan	$	24,362	$	—	$	—	$	24,362	$	19,183	$	—	$	—	$	19,183
Derivative Contracts	—		—		—		—		—		8,019		—		8,019
Total Liabilities	$	24,362	$	—	$	—	$	24,362	$	19,183	$	8,019	$	—	$	27,202

(In thousands)

Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs (Level 2)

Significant
Unobservable
Inputs (Level 3)

Balance as of
December 31,
2010

Assets

Rabbi Trust Deferred Compensation Plan

$
15,788

$
—

$
—

$
15,788

Derivative Contracts

—

—

16,926

16,926

Total Assets

$
15,788

$
—

$
16,926

$
32,714

Liabilities

Rabbi Trust Deferred Compensation Plan

$
21,600

$
—

$
—

$
21,600

Derivative Contracts

—

—

2,180

2,180

Total Liabilities

$
21,600

$
—

$
2,180

$
23,780

Table of Contents

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2011
Assets
Rabbi Trust Deferred Compensation Plan	$	10,838	$	—	$	—	$	10,838
Derivative Contracts	—		—		195,512		195,512
Total Assets	$	10,838	$	—	$	195,512	$	206,350

Liabilities
Rabbi Trust Deferred Compensation Plan	$	20,187	$	—	$	—	$	20,187
Derivative Contracts	—		—		385		385
Total Liabilities	$	20,187	$	—	$	385	$	20,572

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available.

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using ~~valuation models~~an income approach that ~~consider~~considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

The ~~impact of non-performance risk relative~~significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the ~~Company’s derivative contracts was $1.5 million and $0.5 million at September 30, 2011 and December 31, 2010, respectively.~~

~~Table of Contents~~specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
(In thousands)	2011			2010			2011			2010			2012			2011
Balance at beginning of period	$	48,415		$	87,803		$	14,746		$	112,307		$	195,127		$	14,746
Total Gains / (Losses) (Realized or Unrealized):
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (1)	22,488			44,428			47,934			124,398			57,038			13,197
Included in Other Comprehensive Income	75,591			(19,863		)	110,146			(44,722		)	22,692			(606		)
Settlements	(22,552		)	(44,621		)	(48,884		)	(124,236		)	(56,300		)	(13,179		)
Transfers In and/or Out of Level 3	—			—			—			—			385			—
Balance at end of period	$	123,942		$	67,747		$	123,942		$	67,747		$	218,942		$	14,158

(1) ~~A loss~~ Unrealized gains of ~~$0.1 million~~$42 thousand and ~~$1.0 million~~$17 thousand for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2012 and 2011, respectively, ~~and a loss of $0.2 million and a gain of $0.2 million for the three and nine months ended September 30, 2010, respectively, was unrealized and~~were included in Natural Gas Revenues in the Condensed Consolidated Statement of Operations.

There were no transfers between Level 1 and Level 2 measurements for the three ~~and nine~~ months ended ~~September 30, 2011~~March 31, 2012 and ~~2010.~~2011.

Fair Value of Other Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.

Table of Contents

The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all ~~of the~~fixed-rate notes and the credit facility is based on interest rates currently available to the Company. The Company’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

September 30, 2011

December 31, 2010

(In thousands)

Carrying
Amount

Estimated Fair
Value

Carrying
Amount

Estimated Fair
Value

Long-Term Debt

$
1,205,000

$
1,339,410

$
975,000

$
1,100,830

~~Table of Contents~~

March 31, 2012

December 31, 2011

(In thousands)

Carrying
Amount

Estimated Fair
Value

Carrying
Amount

Estimated Fair
Value

Long-Term Debt

1,012,000

1,150,853

950,000

1,082,531

9. ACCUMULATED COMPREHENSIVE INCOME / (LOSS)

Comprehensive Income / (Loss) includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income / (Loss). The following tables illustrate the calculation of Comprehensive Income / (Loss) for the three and nine months ended September 30, 2011 and 2010:

Three Months Ended

September 30,

(In thousands)

2011

2010

Net Income

$
28,482

$
3,898

Other Comprehensive Income / (Loss), net of taxes:

Reclassification Adjustment for Settled Contracts, net of taxes of $8,570 and $17,158, respectively

(13,982
)

(27,463
)
Changes in Fair Value of Hedge Positions, net of taxes of $(37,314) and $(9,608), respectively

60,829

15,150

Defined Benefit Pension and Postretirement Plans:

Effect of Plan Termination and Amendment, net of taxes of $0 and $(752), respectively

$
—

$
1,242

Net Loss due to Remeasurement, net of taxes of $1,614 and $0, respectively

(2,487
)

—

Settlement, net of taxes of $(930) and $(785), respectively

1,516

1,280

Amortization of Net Obligation at Transition, net of taxes of $(60) and $(60), respectively

98

98

Amortization of Prior Service Cost, net of taxes of $(87) and $(82), respectively

141

131

Amortization of Net Loss, net of taxes of $(954) and $(1,248), respectively

1,559

827

2,038

4,789

Foreign Currency Translation Adjustment, net of taxes of $(6) and $6, respectively

31

(42
)
Total Other Comprehensive Income / (Loss)

47,705

(7,566
)

Comprehensive Income / (Loss)

$
76,187

$
(3,668
)

Nine Months Ended

September 30,

(In thousands)

2011

2010

Net Income

$
96,045

$
54,277

Other Comprehensive Income / (Loss), net of taxes:

Reclassification Adjustment for Settled Contracts, net of taxes of $18,576 and $46,695, respectively

(30,308
)

(77,541
)
Changes in Fair Value of Hedge Positions, net of taxes of $(60,423) and $(30,730), respectively

98,607

48,784

Defined Benefit Pension and Postretirement Plans:

Effect of Plan Termination and Amendment, net of taxes of $0 and $(752), respectively

—

$
1,242

Net Loss due to Remeasurement, net of taxes of $1,614 and $0, respectively

(2,487
)

—

Settlement, net of taxes of $(930) and $(785), respectively

1,516

1,280

Amortization of Net Obligation at Transition, net of taxes of $(180) and $(180), respectively

294

294

Amortization of Prior Service Cost, net of taxes of $(328) and $(97), respectively

534

158

Amortization of Net Loss, net of taxes of $(3,390) and $(1,818), respectively

5,530

5,387

2,966

5,940

Foreign Currency Translation Adjustment, net of taxes of $(9) and $(47), respectively

23

78

Total Other Comprehensive Income / (Loss)

73,709

(22,739
)

Comprehensive Income / (Loss)

$
169,754

$
31,538

~~Table of Contents~~

Changes in the components of Accumulated Other Comprehensive ~~Income/~~Income / (Loss), net of taxes, for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 were as follows:

(In thousands)

Net Gains /
(Losses) on Cash
Flow Hedges

Defined Benefit
Pension and
Postretirement
Plans

Foreign Currency
Translation
Adjustment

Total

Balance at December 31, 2010

$
10,494

$
(14,122
)
$
(55
)
$
(3,683
)
Net change in unrealized gain on cash flow hedges, net of taxes of ($41,847)

68,299

—

—

68,299

Net change in defined benefit pension and postretirement plans, net of taxes of ($3,214)

—

5,387

—

5,387

Change in foreign currency translation adjustment, net of taxes of $(9)

—

—

23

23

Balance at September 30, 2011

$
78,793

$
(8,735
)
$
(32
)
$
70,026

(In thousands)	Net Gains / (Losses) on Cash Flow Hedges		Defined Benefit Pension and Postretirement Plans			Total
Balance at December 31, 2011	$	121,358	$	(16,811	)	$	104,547
Net change in unrealized gain on cash flow hedges, net of taxes of $(5,923)	9,135		—			9,135
Net change in defined benefit pension and postretirement plans, net of taxes of $(2,690)	—		4,243			4,243
Balance at March 31, 2012	$	130,493	$	(12,568	)	$	117,925

10. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs, included in General and Administrative Expense in the Condensed Consolidated Statement of Operations, were as follows:

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
(In thousands)	2011			2010			2011			2010			2012			2011
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	—		$	571		$	—		$	2,365
Interest Cost	650			885			2,251			2,870			$	461		$	801
Expected Return on Plan Assets	(945		)	(1,091		)	(3,265		)	(3,171		)	(874		)	(1,160		)
Amortization of Prior Service Cost	228			213			862			255			111			317
Amortization of Net Loss	2,373			3,128			8,498			4,310			6,542			3,062
Curtailment Loss	—			424			—			424
Settlement	2,446			2,065			2,446			2,065
Net Periodic Pension Cost	$	4,752		$	6,195		$	10,792		$	9,118		$	6,240		$	3,020

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	335		$	316		$	1,004		$	949		$	523		$	335
Interest Cost	467			424			1,402			1,271			418			467
Amortization of Net Loss	140			158			422			474			280			141
Amortization of Net Obligation at Transition	158			158			474			474			—			158
Total Postretirement Benefit Cost	$	1,100		$	1,056		$	3,302		$	3,168		$	1,221		$	1,101

~~Employer Contributions~~17

~~The funding levels~~Table of the pension and postretirement benefit plans are in compliance with standards set by applicable law or regulation. The Company does not have any required minimum funding obligations for its qualified pension plan in 2011. The Company previously disclosed in its financial statements for the year ended December 31, 2010 that it had not determined if any additional discretionary funding would be made in 2011. During the nine months ended September 30, 2011, the Company did not make any contributions to its qualified and non-qualified pension plans; discretionary contributions may, however, be made prior to December 31, 2011.Contents

Termination and Amendment of Qualified ~~and Non-Qualified~~ Pension ~~Plans~~Plan

In July 2010, the Company notified its employees of its plan to terminate its qualified pension plan, with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective

~~Table of Contents~~

September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law. ~~Because no further benefits will accrue~~

On March 14, 2012, the Internal Revenue Service provided the Company with a favorable determination letter for the termination of the Company’s qualified pension plan. The Company expects to liquidate the trust under the qualified pension plan ~~after September 30, 2010,~~in the ~~Company’s related non-qualified pension plan was effectively frozen and no additional benefits will be accrued under those arrangements after September 30, 2010.~~ second quarter of 2012.

For further information regarding termination and amendment of ~~qualified and non-qualified~~the Company’s pension plans, refer to Note 65 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Employer Contributions

The funding levels of the pension and postretirement benefit plans are in compliance with standards set by applicable law or regulation. As stated above, the Company expects to liquidate the trust under the qualified pension plan in the second quarter of 2012.

11. STOCK-BASED COMPENSATION

Stock-based compensation expense (including the supplemental employee incentive plan) during the first ~~nine~~three months of 2012 and 2011 ~~and 2010~~ was ~~$29.3~~$1.7 million and ~~$8.9~~$8.1 million, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. ~~Stock-based compensation expense in the third quarter of 2011 and 2010 was $10.0 million and $3.8 million, respectively.~~

Restricted Stock Awards

During the first ~~nine~~three months of ~~2011, 5,300~~2012, 750 restricted stock awards were granted with a weighted-average grant date per share value of ~~$35.39.~~$33.66. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate assumption of ~~7.0%~~6.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first ~~nine~~three months of ~~2011, 29,701~~2012, 38,304 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of ~~$41.75.~~$36.55. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and will be issued when the director ceases to be a director of the Company.

Stock Appreciation Rights

During the first ~~nine~~three months of ~~2011, 95,750~~2012, 120,442 stock appreciation rights (SARs) were granted to employees. These awards allow the employee to receive common stock of the Company equal to the intrinsic value over the ~~$40.74~~$35.18 strike price during the contractual term of seven years. The Company calculates the fair value using a Black-Scholes model. The assumptions used in the Black-Scholes fair value calculation on the date of grant for SARs are as follows:

Weighted-Average Value per Stock Appreciation Right Granted During the Period	$	18.94		$	16.31
Assumptions:

Assumptions
Stock Price Volatility	52.7		%	55.3		%
Risk Free Rate of Return	2.3		%	0.9		%
Expected Dividend Yield	0.3		%	0.3		%
Expected Term (in years)	5.0			5.0

Table of Contents

Performance Share Awards

During the first ~~nine~~three months of ~~2011,~~2012, three types of performance share awards were granted to employees for a total of ~~394,757~~518,602 performance shares, which included ~~92,696 performance share awards based on market conditions and 302,061~~401,141 performance share awards based on performance conditions measured against the Company’s internal performance ~~metrics.~~metrics and 117,461 performance share awards based on market conditions. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for all performance share awards. The performance period for the awards granted in 2012 commenced on January 1, 2012 and ends on December 31, 2014. Refer to Note 11 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards.

Awards Based on Performance Conditions. The performance awards based on internal metrics had a grant date per share value of $35.18, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock. Of the ~~302,061 performance-based~~401,141 performance awards ~~92,696 of the~~based on internal metrics, 117,461 shares have a three-year graded performance period. For these shares, one-third of the shares are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited.

For the remaining ~~209,365 performance-based~~283,680 performance awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. ~~Refer to Note 12~~An employee will earn one-third of the ~~Notes to the Consolidated Financial Statements in the Form 10-K~~award granted for ~~further description of the various types of performance share awards.~~

~~The performance period for the awards based on~~each internal performance ~~metrics commenced on January 1, 2011 and ends on December 31, 2013 and~~metric that the grant date per share value for these awards was $40.74, which is based on the average of the high and low stock price on the grant date. The actual number of shares issued on each anniversary date following the grant date orCompany meets at the end of the

~~Table of Contents~~

performance ~~period, as applicable, will be determined~~period. These performance criteria are based on the Company’s average production, average finding costs and average reserve replacement over the three-year performance ~~against the performance criteria set by the Company’s Compensation Committee.~~ period.

Based on the Company’s probability assessment at ~~September 30, 2011,~~March 31, 2012, it is considered probable that ~~the~~ criteria for ~~the performance-based~~these awards will be met. ~~The Company used an annual forfeiture rate assumption ranging from 0% to 7% for purposes of recognizing stock-based compensation expense for all performance-based share awards.~~

Awards Based on Market Conditions. The 117,461 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three-year performance period. ~~The~~These performance shares ~~based on market conditions~~ have both an equity and liability component. The ~~following assumptions were used for the performance shares based on market conditions using a Monte Carlo model to value the liability and equity components of the awards. The~~ equity portion of the ~~2011~~2012 awards was valued on the grant date (February ~~17, 2011)~~16, 2012) and was not marked to market. The liability portion of the awards was valued as of ~~September 30, 2011~~March 31, 2012 on a mark-to-market basis.

Grant Date

September 30, 2011

Value per Share

$
31.23

$39.90 - $57.46

Assumptions:

Stock Price Volatility

62.0
%
41.94% - 60.91%

Risk Free Rate of Return

1.3
%
0.02% - 0.29%

Expected Dividend Yield

0.2
%
0.2%

The following assumptions were used to value the equity and liability components of the Company’s performance share awards based on market conditions using a Monte Carlo model:

	Grant Date		March 31, 2012
Value per Share	$28.31		$10.20 - $25.90
Assumptions:
Stock Price Volatility	46.7	%	44.8% - 55.8	%
Risk Free Rate of Return	0.4	%	0.2% - 0.5	%
Expected Dividend Yield	0.2	%	0.3	%

12. ASSET RETIREMENT OBLIGATION

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation during the three months ended March 31, 2012 is as follows:

(In thousands)
Carrying amount of asset retirement obligations at December 31, 2010	$	72,311
Carrying amount of asset retirement obligations at beginning of period				$	60,142
Liabilities incurred	897			560
Liabilities settled	(1,040		)	(162		)
Accretion expense	2,616			744
Carrying amount of asset retirement obligations at September 30, 2011	$	74,784
Carrying amount of asset retirement obligations at end of period				$	61,284

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of ~~September 30, 2011,~~March 31, 2012, and the related condensed consolidated statements of operations and comprehensive income for the three month ~~and nine month~~ periods ended ~~September 30,~~March 31, 2012 and 2011, ~~and 2010,~~ and the condensed consolidated statement of cash flows for the ~~nine~~three month periods ended ~~September 30, 2011~~March 31, 2012 and ~~2010.~~2011. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, ~~2010,~~2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and of cash flows for the year then ended (not presented herein), and in our report dated February 28, ~~2011,~~2012, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, ~~2010,~~2011, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

~~October 28, 2011~~April 27, 2012

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

The following review of operations for the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~ should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, ~~2010~~2011 (Form 10-K).

AsOn January 3, 2012, the Board of Directors declared a ~~result~~2-for-1 split of our production growth and the commencement of various transportation and gathering agreements in 2011, we began separately reporting our transportation and gathering costs as a component of operating expensescommon stock in the ~~Condensed Consolidated Statement~~form of ~~Operations. Previously reported transportation~~a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and ~~gathering costs were reflected as a component of Natural Gas Revenues and~~per share data have been ~~reclassified~~retroactively adjusted to ~~conform~~give effect to ~~current year presentation. Accordingly, previously reported operating revenues and operating expenses have increased with no impact on previously reported net income.~~the 2-for-1 split of our common stock.

Overview

On an equivalent basis, our production for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 increased by ~~42%~~58% compared to the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011. For the ~~nine~~three months ended ~~September 30, 2011,~~March 31, 2012, we produced ~~132.7~~59.7 Bcfe compared to ~~93.2~~37.7 Bcfe for the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011. Natural gas production was ~~127.2~~56.4 Bcf and crude oil/condensate/NGL production was ~~920~~538 Mbbls for the first ~~nine~~three months of ~~2011.~~2012. Natural gas production increased by ~~43%~~55% when compared to the first ~~nine~~three months of ~~2010,~~2011, which had production of ~~89.2~~36.4 Bcf. This increase was primarily a result of increased production in ~~northeast Pennsylvania~~the Marcellus shale associated with our ~~Marcellus Shale~~ drilling program and upgrades to the Lathrop compressor station in Susquehanna County, Pennsylvania, which included the commissioning of new compression during the latter part of the first ~~nine months of~~quarter in 2011. Partially offsetting the production increase in ~~northeast Pennsylvania~~Marcellus shale were decreases in production primarily in east ~~and south~~ Texas due to reduced drilling activity and normal production declines, the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011 and a continued shift from gas to oil ~~projects.~~projects outside of the Marcellus shale. Crude oil/condensate/NGL production increased by ~~39%~~138%, to ~~920~~538 Mbbls, when compared to the first ~~nine~~three months of ~~2010,~~2011, which had production of ~~660~~226 Mbbls. This increase was primarily the result of increased production associated with our Eagle Ford ~~Shale~~shale drilling program in south ~~Texas.~~Texas and the Marmaton oil play in Oklahoma.

Our average realized natural gas price for the first ~~nine~~three months of ~~2011~~2012 was ~~$4.64~~$3.65 per Mcf, ~~21%~~22% lower than the ~~$5.90~~$4.68 per Mcf price realized in the first ~~nine~~three months of ~~2010.~~2011. Our average realized crude oil price for the first ~~nine~~three months of ~~2011~~2012 was ~~$89.69~~$96.67 per Bbl, ~~8% lower~~11% higher than the ~~$97.43~~$87.15 per Bbl price realized in the first ~~nine~~three months of ~~2010.~~2011. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our ~~future revenues,~~ capital program, production volumes or ~~production volumes.~~future revenues.

Natural gas commodity prices have decreased from an average price of $4.04 per Mmbtu in 2011 to an average price of $2.72 per Mmbtu for the first three months of 2012. Natural gas commodity prices were $3.36 per Mmbtu in December 2011 and have continued to decline to $2.19 per Mmbtu in April 2012. Natural gas commodity prices represent the first of the month Henry Hub index price per Mmbtu. Any further decline in natural gas commodity prices or quantities would have a negative impact on our financial results.

Operating revenues for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 increased by ~~$71.2~~$63.1 million, or ~~11%~~30%, from the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 2011. Natural gas revenues, excluding unrealized gains/losses from the change in fair value of our derivatives not designated as hedges, increased by ~~$63.7~~$36.7 million, or ~~12%~~22%, for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 as compared to the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 as the increase in natural gas production more than offset the lower realized natural gas prices. Crude oil and condensate revenues increased by ~~$19.4~~$31.4 million, or ~~32%~~169%, for the first ~~nine~~three months of ~~2011~~2012 as compared to the first ~~nine~~three months of ~~2010,~~2011, due to increased crude oil production ~~partially offset by lower~~that outpaced the increase in realized crude oil prices. Brokered natural gas revenues decreased by ~~$10.9~~$5.0 million, or ~~22%~~27%, due to a decreased sales price and decreased brokered volumes.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. For ~~2011,~~2012, we expect to spend approximately ~~$825~~$750 to ~~$875~~$790 million in ~~capital and exploration expenditures, using proceeds from the sale of assets to supplement our cash flows from operations in order to fund incremental~~ capital and exploration expenditures. We believe our existing cash on hand, operating cash flows ~~in 2011, proceeds from asset sales~~ and borrowings ~~from~~under our credit facility, if required, will be more than sufficient to fund our capital and exploration spending in ~~2011.~~the current year. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly. For the ~~nine~~three months ended ~~September 30, 2011,~~March 31, 2012, we invested approximately ~~$666.7~~$192.1 million in our exploration and development efforts.

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During the first ~~nine~~three months of ~~2011,~~2012, we drilled 8531 gross development wells with a success rate of 100% compared to 24 gross wells ~~(73~~(19 development, ~~five~~three exploratory and ~~seven~~two extension wells) with a success rate of ~~99% compared to 83 gross wells (69 development, four exploratory and 10 extension wells) with a success rate of 98%~~100% for the comparable period of the prior year. For the full year of ~~2011,~~2012, we plan to drill approximately ~~140~~120 to 130 gross ~~(100 net)~~ wells.

Our 2012 strategy will remain consistent with 2011. While we consider acquisitions from time to time, we ~~continue to~~ remain focused on ~~our strategies of~~ pursuing drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline

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and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. For 2012, we have allocated our planned program for capital and exploration expenditures primarily to the Marcellus shale in northeast Pennsylvania, the Eagle Ford oil shale in south Texas and, to a lesser extent, the Marmaton oil play in Oklahoma. We believe these strategies are appropriate for our portfolio of projects and the current ~~industry~~commodity pricing environment and will continue to add shareholder value over the long-term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 were funds generated from the sale of natural gas and crude oil production (including hedge realizations), and net borrowings under our credit ~~facility and the sales of properties and other assets.~~facility. These cash flows were primarily used to fund our ~~development~~capital and exploration expenditures ~~in addition to~~and payment of ~~dividends and repayment of debt.~~dividends. See below for additional discussion and analysis of cash flow.

We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. Commodity prices continue to experience increased volatility. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

Our working capital is also substantially influenced by variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate availability under our credit facility and liquidity available to meet our working capital requirements.

	Nine Months Ended						Three Months Ended
	September 30,						March 31,
(In thousands)	2011			2010			2012			2011
Cash Flows Provided by Operating Activities	$	375,366		$	367,492		$	131,780		$	91,213
Cash Flows Used in Investing Activities	(586,878		)	(637,090		)	(187,267		)	(198,126		)
Cash Flows Provided by Financing Activities	218,491			267,028			57,904			75,860
Net Increase / (Decrease) in Cash and Cash Equivalents	$	6,979		$	(2,570	)	$	2,417		$	(31,053	)

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating expenses. Net cash provided by operating activities in the first ~~nine~~three months of ~~2011~~2012 increased by ~~$7.9~~$40.6 million over the first ~~nine~~three months of ~~2010.~~2011. This increase was primarily due to increased operating income in ~~2011~~2012 as a result of higher operating revenues ~~and an increase in the gain on sale of assets~~ that outpaced the increase in operating expenses. This increase ~~was offset by~~in operating income coupled with changes in working capital and long-term assets and liabilities ~~which decreased~~increased operating cash flows. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas ~~and crude oil~~ prices. Equivalent production volumes increased by ~~42%~~58% for the ~~nine~~three months ended ~~September 30, 2011~~March 31, 2012 compared to the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by ~~21%~~22% for the first ~~nine~~three months of ~~2011~~2012 compared to the first ~~nine~~three months of ~~2010.~~2011. Average realized crude oil prices ~~decreased~~increased by 8%11% compared to the same period.

See “Results of Operations” for additional information relative to commodity price, production and operating expense movements. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may decline in future periods.

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Investing Activities. The primary use of cash in investing activities was capital ~~spending.~~and exploration expenditures. We established our ~~2011~~2012 capital budget based on our current estimate of future commodity prices and cash flows. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted. Cash flows used in investing activities decreased by ~~$50.2~~$10.9 million for the first ~~nine~~three months of ~~2011~~2012 compared to the first ~~nine~~three months of ~~2010.~~2011. The decrease was primarily due ~~to higher~~a decrease of $14.6 million in capital and exploration expenditures, partially offset by lower proceeds from sale of assets of ~~$61.1 million slightly offset by an increase of $10.9 million in capital and exploration expenditures.~~$3.8 million.

Financing Activities. Cash flows provided by financing activities decreased by ~~$48.5~~$18.0 million from the first ~~nine~~three months of ~~2010~~2011 to the first ~~nine~~three months of ~~2011.~~2012. This was primarily due to ~~an increase~~a decrease in borrowings and repayments of debt, ~~partially offset by higher borrowings,~~ resulting in lower net ~~borrowings, and lower capitalized debt issuance costs in the first nine months of 2011 compared to the first nine months of 2010.~~

~~Table of Contents~~borrowings.

At ~~September 30, 2011,~~March 31, 2012, we had ~~$443.0~~$250.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of ~~4.0%~~3.6%. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. ~~Effective April 1, 2011, the lenders under our credit facility approved an increase in the~~The borrowing base under the credit facility ~~from $1.5 billion to~~is $1.7 billion as part of the annual redetermination under the terms of the credit facility. Our plan to sell certain oil and gas properties located in Colorado, Utah and Wyoming, triggered an interim redetermination of the Company’s Borrowing Base and the $1.7 billion Borrowing Base was reaffirmed by the lenders effective September 27, 2011.billion. As of ~~September 30, 2011,~~March 31, 2012, our available credit under our credit facility was ~~$456.8~~$649.0 million.

We are in compliance in all material respects with our debt covenants as of ~~September 30, 2011.~~March 31, 2012.

We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes that, with ~~operating~~internally generated cash flow from operations, existing cash on hand and availability under our revolving credit facility, ~~and proceeds from the sale of assets,~~if required, we have the capacity to finance our spending plans, service our debt obligations as they become due and maintain our strong financial position.

Capitalization

Information about our capitalization is as follows:

	September 30,			December 31,			March 31,			December 31,
(Dollars in millions)	2011			2010
(Dollars in thousands)							2012			2011

Debt (1)	$	1,205.0		$	975.0		$	1,012,000		$	950,000
Stockholders’ Equity	2,043.2			1,872.7			2,124,956			2,104,768
Total Capitalization	$	3,248.2		$	2,847.7		$	3,136,956		$	3,054,768

Debt to Capitalization	37.1		%	34.2		%	32		%	31		%

Cash and Cash Equivalents	$	62.9		$	55.9		$	32,328		$	29,911

(1) Includes ~~$443.0~~$250.0 million and ~~$213.0~~$188.0 million of borrowings outstanding under our revolving credit facility at ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010,~~2011, respectively.

During the ~~nine~~three months ended ~~September 30, 2011,~~March 31, 2012, we paid dividends of ~~$9.4~~$4.2 million ($~~0.09~~0.02 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

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Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of capital and exploration expenditures:

Nine Months Ended

September 30,

(In millions)

2011

2010

Capital Expenditures

Drilling and Facilities

$
561.0

$
445.8

Leasehold Acquisitions

60.9

109.9

Acquisitions

—

0.8

Pipeline and Gathering

7.2

29.4

Other

6.5

6.6

635.6

592.5

Exploration Expense

31.1

28.3

Total

$
666.7

$
620.8

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	Three Months Ended
	March 31,
(In thousands)	2012			2011
Capital Expenditures
Drilling and Facilities	$	173,368		$	145,745
Leasehold Acquisitions	15,147			16,998
Pipeline and Gathering	(428		)	5,158
	188,087			167,901
Exploration Expense	4,001			6,308
Total	$	192,088		$	174,209

For the full year of ~~2011,~~2012, we plan to drill approximately ~~140~~120 to 130 gross ~~(100 net)~~ wells. This ~~2011~~2012 drilling program ~~is part of approximately $825~~includes between $750 to ~~$875~~$790 million in total planned capital and exploration expenditures. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. ~~For further information, please refer~~There have been no material changes to our contractual obligations described under “Transportation Agreements” ~~and~~, “Drilling Rig Commitments” ~~under~~and “Hydraulic Fracturing Services Commitments” in Note ~~6 in the Notes to the Condensed Consolidated Financial Statements and Note 8~~7 in the Notes to Consolidated Financial Statements included in our 2011 Form 10-K.

In February 2012, we entered into a Precedent Agreement with Constitution Pipeline Company, LLC (Constitution), at that time a wholly owned subsidiary of Williams Partners L.P., to develop and construct a 120 mile large diameter pipeline to transport our production in northeast Pennsylvania to both the New England and New York markets. In April 2012, we entered into an Amended and Restated Limited Liability Company Agreement with Constitution. Refer to Note 6 in the Notes to Condensed Consolidated Financial Statements for further details.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our 2011 Form 10-K for further discussion of our critical accounting policies.

~~Recently Issued~~Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.” The amendments in ~~ASU No. 2011-04~~this update generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ~~ASU No. 2011-04~~This update results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and ~~IFRSs.~~IFRS. The ~~amendments in ASU No. 2011-04 are to be applied prospectively. For public entities, the~~ amendments are effective for interim and annual periods beginning after December 15, ~~2011. Early application by public entities is~~2011 and are to be applied prospectively. This update did not ~~permitted. We do not expect this guidance to~~ have ~~a significant~~any impact on our consolidated financial position, results of operations or cash flows.

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2011-05 are not affected by this update, including the requirement to report comprehensive income either in ~~one~~a single continuous ~~statement—referred to as the~~financial statement ~~of comprehensive income—~~or in two separate but consecutive ~~statements of net income~~financial statements. ASU No. 2011-05 and ~~other comprehensive income. The new requirements~~2011-12 are effective ~~for public entities~~ for fiscal years (including interim periods) beginning after December 15, 2011. We elected to present two separate but consecutive financial statements. These updates did not have any impact on our consolidated financial position, results of operations or cash flows.

Results of Operations

~~Third~~First Quarter of ~~2011~~2012 and ~~2010~~2011 Compared

We reported net income in the ~~third~~first quarter of ~~2011~~2012 of ~~$28.5~~$18.3 million, or ~~$0.27~~$0.09 per share, compared to net income in the ~~third~~first quarter of ~~2010~~2011 of ~~$3.9~~$12.9 million, or ~~$0.04~~$0.06 per share. Net income increased in the ~~third~~first quarter of ~~2011~~2012 by ~~$24.6~~$5.4 million, primarily due to an increase in operating revenues ~~and gain on sale of assets and a decrease in operating expenses~~ partially offset by increases in ~~interest expense and~~operating expenses as well as income tax expense.

Operating revenues increased by ~~$38.1~~$63.1 million due to increased natural gas and crude oil and condensate revenues partially offset by decreased brokered natural gas revenues. Operating expenses ~~decreased~~increased by ~~$1.3~~$53.8 million ~~between periods~~ primarily due to ~~a decrease~~an increase in ~~impairment of oil~~depreciation, depletion, and ~~gas properties, lower brokered natural gas cost~~amortization, increases in direct operating expenses, transportation and gathering expenses and taxes other than income, partially offset by ~~increases in transportation and gathering expenses,~~lower brokered natural gas cost, exploration expense and general and administration ~~expense, depreciation, depletion, and amortization and direct operating expenses.~~expense. In addition, net income was impacted during the ~~third~~first quarter by ~~an increase~~higher income tax expense, partially offset by a decrease in ~~gain~~loss on sale of assets and ~~higher income tax and~~lower interest expense.

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Revenue, Price and Volume Variances

Below is a discussion of revenue, price and volume variances.

~~Revenue Variances (In thousands)~~

	Three Months Ended September 30,				Variance					Three Months Ended March 31,				Variance
	2011		2010		Amount			Percent
Revenue Variances (In thousands)										2012		2011		Amount			Percent
Natural Gas (1)	$	218,585	$	192,219	$	26,366		14	%	$	206,740	$	170,081	$	36,659		22%
Brokered Natural Gas	9,467		11,675		(2,208		)	(19	)%	13,444		18,408		(4,964		)	(27)%
Crude Oil and Condensate	33,158		19,234		13,924			72	%	49,981		18,592		31,389			169%
Other	971		1,127		(156		)	(14	)%	1,929		1,928		1			—%

(1)Natural Gas Revenues exclude the unrealized ~~loss~~gains of ~~$0.1~~$42 thousand and ~~$0.2 million~~of $17 thousand from the change in fair value of our derivatives not designated as hedges in ~~2011~~2012 and ~~2010,~~2011, respectively.

										Increase											Increase
	Three Months Ended September 30,				Variance					(Decrease)			Three Months Ended March 31,				Variance				(Decrease)
	2011		2010		Amount			Percent		(In thousands)			2012		2011		Amount			Percent	(In thousands)
Price Variances
Natural Gas (1)	$	4.58	$	5.52	$	(0.94	)	(17	)%	$	(44,757	)	$	3.65	$	4.68	$	(1.03	)	(22)%	$	(57,193	)
Crude Oil and Condensate (2)	$	86.89	$	98.26	$	(11.37	)	(12	)%	(4,339		)	$	96.67	$	87.15	$	9.52		11%	4,894
Total										$	(49,096	)									$	(52,299	)
Volume Variances
Natural Gas (Mmcf)	47,707		34,850		12,857			37	%	$	71,123		56,434		36,371		20,063			55%	$	93,852
Crude Oil and Condensate (Mbbl)	382		196		186			95	%	18,263			517		213		304			143%	26,495
Total										$	89,386										$	120,347

(1)These prices include the realized impact of derivative instrument settlements, which increased the price by ~~$0.44~~$1.00 per Mcf in ~~2011~~2012 and by ~~$1.13~~$0.37 per Mcf in ~~2010.~~2011.

(2)These prices include the realized impact of derivative instrument settlements, which ~~increased~~decreased the price by ~~$3.62~~$2.57 per Bbl in ~~2011~~2012 and by ~~$26.33~~$1.42 per Bbl in ~~2010.~~2011.

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Natural Gas Revenues

The increase in natural gas revenues of ~~$26.4~~$36.7 million, excluding the impact of unrealized losses discussed above, is primarily due to increased production during the ~~third~~first quarter of ~~2011,~~2012, partially offset by lower realized natural gas prices. The increased production iswas primarily ~~due to~~a result of increased production in the Marcellus shale associated with our ~~Marcellus Shale~~ drilling program ~~in northeast Pennsylvania~~ and ~~the start up of additional compressors at~~upgrades to the Lathrop compressor station in Susquehanna County, ~~Pennsylvania. This~~Pennsylvania, which included the commissioning of new compression during the latter part of the first quarter in 2011. Partially offsetting the production increase ~~is partially offset by~~in Marcellus shale were decreases in production primarily in east ~~and south~~ Texas due to reduced drilling activity and normal production declines, the sale of oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter of 2011 and a continued shift from gas to oil ~~projects.~~projects outside of the Marcellus shale. The previously reported fire at the Lathrop compressor station in late March 2012 had no material impact on our natural gas revenues.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of ~~$13.9~~$31.4 million is primarily due to increased production ~~due to~~associated with our Eagle Ford ~~Shale~~shale drilling program in south Texas ~~partially offset by lower~~and the Marmaton oil play in Oklahoma coupled with higher realized oil prices.

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Brokered Natural Gas Revenue and Cost

												Price and														Price and
	Three Months Ended											Volume			Three Months Ended											Volume
	September 30,						Variance					Variances			March 31,								Variance			Variances
	2011			2010			Amount			Percent		(In thousands)			2012				2011				Amount		Percent	(In thousands)
Brokered Natural Gas��Sales
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$		4.99	$		5.14	$	(0.15	)	(3	)%	$	(285	)	$	4.06			$		5.28		$	(1.22)	(23)%	$	(4,054	)
Volume Brokered (Mmcf)	x	1,899		x	2,272		(373		)	(16	)%	(1,923		)	x		3,311		x	3,489			(178)		(5)%	(910		)
Brokered Natural Gas Revenues (In thousands)	$		9,467	$		11,675						$	(2,208	)	$	13,444			$		18,408					$	(4,964	)

Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$		4.32	$		4.53	$	(0.21	)	(5	)%	$	398		$	3.59			$		4.40		$	(0.81)	(18)%	$	2,706
Volume Brokered (Mmcf)	x	1,899		x		2,272	(373		)	(16	)%	1,679			x			3,311	x			3,489	(178)		(5)%	784
Brokered Natural Gas Cost (In thousands)	$		8,204	$		10,281						$	2,077		$	11,872			$		15,362					$	3,490

Brokered Natural Gas Margin (In thousands)	$		1,263	$		1,394						$	(131	)	$	1,572			$		3,046					$	(1,474	)

The decreased brokered natural gas margin of ~~$0.1~~$1.5 million is primarily a result of a decrease in ~~brokered volumes coupled with~~sales price that outpaced a decrease in the purchase price ~~that outpaced the sales price.~~

~~Impact of Derivative Instruments on Operating Revenues~~

~~The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:~~

Three Months Ended

September 30,

2011

2010

(In thousands)

Realized

Unrealized

Realized

Unrealized

Operating Revenues - Increase / (Decrease) to Revenue

Cash Flow Hedges

Natural Gas

$
21,170

$
—

$
39,461

$
—

Crude Oil

1,382

—

5,160

—

Total Cash Flow Hedges

22,552

—

44,621

—

Other Derivative Financial Instruments

Natural Gas Basis Swaps

—

(64
)
—

(193
)
Total Other Derivative Financial Instruments

—

(64
)
—

(193
)

Total Cash Flow Hedges and Other Derivative Financial Instruments

$
22,552

$
(64
)
$
44,621

$
(193
)

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We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our derivative contract counterparties are Bank of Montreal, BNP Paribas, JPMorgan Chase, Goldman Sachs and Bank of America.

~~Operating and Other Expenses~~

Three Months Ended
September 30,

Variance

(In thousands)

2011

2010

Amount

Percent

Operating and Other Expenses

Brokered Natural Gas Cost

$
8,204

$
10,281

$
(2,077
)
(20
)%
Direct Operations

27,292

26,466

826

3
%
Transportation and Gathering

19,768

4,932

14,836

301
%
Taxes Other Than Income

7,042

8,489

(1,447
)
(17
)%
Exploration

20,190

9,665

10,525

109
%
Impairment of Oil and Gas Properties

—

35,789

(35,789
)
(100
)%
Depreciation, Depletion and Amortization

90,293

85,355

4,938

6
%
General and Administrative

27,949

21,077

6,872

33
%
Total Operating Expense

$
200,738

$
202,054

$
(1,316
)
(1
)%

(Gain) / Loss on Sale of Assets

$
(3,854
)
$
(265
)
$
3,589

1354
%
Interest Expense and Other

18,517

16,758

1,759

10
%
Income Tax Expense

18,234

1,617

16,617

1028
%

~~Total costs and expenses from operations decreased by $1.3 million, or 1%, in the third quarter of 2011 compared to the same period of 2010. The primary reasons for this fluctuation are as follows:~~

·Impairment of Oil and Gas Properties decreased by $35.8 million from the third quarter of 2011 compared to the third quarter of 2010 due to the impairment of two south Texas fields recognized in the third quarter of 2010 because of continued price declines and normal production declines. There were no impairments in third quarter of 2011.

·~~Brokered Natural Gas Costs decreased $2.1 million. See the preceding table titled “~~~~Brokered Natural Gas Revenue and Cost~~~~” for further analysis.~~

·Taxes Other Than Income decreased $1.5 million primarily due to lower ad valorem and franchise tax expense partially offset by higher production tax expense due to fewer tax credits and related refunds on qualifying wells received in the third quarter of 2011 compared to 2010.

·Transportation and Gathering increased by $14.8 million primarily due to the commencement of various firm transportation and gathering arrangements in the first nine months of 2011 in Susquehanna County, Pennsylvania.

·~~Exploration Expense increased $10.5 million primarily due to dry hole costs related to an exploratory well in Montana partially offset by lower geophysical and geological costs.~~

·~~General and Administrative increased by $6.9 million primarily due to $6.2 million higher stock-based compensation expense primarily associated~~coupled with the mark to market of the liability portion of our performance shares as a result of our higher average stock price for the month of September 2011 compared to the average stock price for the month of September 2010.

·Depreciation, Depletion and Amortization increased by $4.9 million, of which $6.7 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes partially offset by a lower DD&A rate of $1.62 per Mcfe for three months ended September 30, 2011 compared to $2.06 per Mcfe for three months ended September 30, 2010. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of $2.3 million.

~~Gain / (Loss) on Sale of Assets~~

~~An aggregate gain of $3.9 million was recognized in the third quarter of 2011 primarily due to the sale of non-core assets as part of our ongoing asset portfolio management program.~~

~~Table of Contents~~

~~Income Tax Expense~~

Income tax expense increased by $16.6 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to increased pretax income and a higher effective tax rate. The effective tax rate for the third quarter of 2011 and 2010 was 39.0% and 29.3%, respectively. The effective tax rate was higher as a result of provision to return adjustments recorded in the third quarter 2011 having a lesser impact due to higher quarterly pretax income.

~~Interest Expense and Other~~

Interest expense and other increased by $1.8 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $407.7 million during the third quarter of 2011 compared to approximately $392.7 million during the third quarter of 2010. The increase in borrowings was partially offset by a lower weighted-average effective interest rate on the credit facility of approximately 3.7% during the third quarter of 2011 compared to approximately 3.8% during the third quarter of 2010. Furthermore, in December 2010 we issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the third quarter of 2011.

~~Nine Months of 2011 and 2010 Compared~~

We reported net income in the first nine months of 2011 of $96.0 million, or $0.92 per share, compared to net income in the first nine months of 2010 of $54.3 million, or $0.52 per share. Net income increased in the first nine months of 2011 by $41.8 million, primarily due to an increase in operating revenues and gain on sale of assets, partially offset by increases in operating expenses, interest expense and income tax expense.

Operating revenues increased by $71.2 million, largely due to increased natural gas and crude oil and condensate revenues, partially offset by decreased brokered natural gas revenues. Operating expenses increased by $28.9 million between periods primarily due to increases in transportation and gathering expenses, general and administrative expenses, depreciation, depletion and amortization and direct operations and exploration expense partially offset by a decrease in impairment of oil and gas properties and lower taxes other than income and brokered natural gas cost. In addition, net income was impacted during the first nine months by increased gain on sale of assets partially offset by higher interest expense and income tax expense.

~~Table of Contents~~

~~Revenue, Price and Volume Variances~~

~~Below is a discussion of revenue, price and volume variances.~~

~~Revenue Variances (In thousands)~~

Nine Months Ended September 30,

Variance

2011

2010

Amount

Percent

Natural Gas (1)

$
589,926

$
526,262

$
63,664

12
%
Brokered Natural Gas

38,947

49,896

(10,949
)
(22
)%
Crude Oil and Condensate

79,792

60,427

19,365

32
%
Other

4,124

3,901

223

6
%

~~(1)~~Natural Gas Revenues exclude the unrealized loss of $1.0 million and the unrealized gain of $0.2 million from the change in fair value of our derivatives not designated as hedges in 2011 and 2010, respectively.

Nine Months Ended September 30,

Variance

2011

2010

Amount

Percent

Price Variances

Natural Gas (1)

$
4.64

$
5.90

$
(1.26
)
(21
)%
Crude Oil and Condensate (2)

$
89.69

$
97.43

$
(7.74
)
(8
)%
Total

Volume Variances

Natural Gas (Mmcf)

127,206

89,203

38,003

43
%
Crude Oil and Condensate (Mbbl)

890

620

270

43
%
Total

~~(1)~~~~These prices include the realized impact of derivative instrument settlements, which increased the price by $0.38 per Mcf in 2011 and by $1.23 per Mcf in 2010.~~

~~(2)~~~~These prices include the realized impact of derivative instrument settlements, which increased the price by $0.64 per Bbl in 2011 and by $23.42 per Bbl in 2010.~~

~~Natural Gas Revenues~~

The increase in Natural Gas Revenues of $63.7 million is primarily due to increased production during the first nine months of 2011, partially offset by lower realized natural gas prices. The increased production is primarily due to increased production associated with our Marcellus Shale drilling program and upgrades to the compressors at the Lathrop compressor station in Susquehanna County, Pennsylvania during the first nine months of the year, partially offset by decreases in production primarily in east and south Texas due to normal production declines and a shift from gas to oil projects.

~~Crude Oil and Condensate Revenues~~

The increase in Crude Oil and Condensate Revenues of $19.4 million is primarily due to increased production partially offset by lower realized oil prices. The increase in production is primarily due to our drilling program in the Eagle Ford Shale in south Texas, partially offset by lower production in east Texas.

~~Table of Contents~~

~~Brokered Natural Gas Revenue and Cost~~

Price and

Nine Months Ended

Volume

September 30,

Variance

Variances

2011

2010

Amount

Percent

(In thousands)

Brokered Natural Gas Sales

Sales Price ($/Mcf)

$
5.15

$
5.60

$
(0.45
)
(8
)%
$
(3,402
)
Volume Brokered (Mmcf)

x
7,560

x
8,915

(1,355
)
(15
)%
(7,547
)
Brokered Natural Gas Revenues (In thousands)

$
38,947

$
49,896

$
(10,949
)

Brokered Natural Gas Purchases

Purchase Price ($/Mcf)

$
4.41

$
4.86

$
(0.45
)
(9
)%
$
3,380

Volume Brokered (Mmcf)

x
7,560

x
8,915

(1,355
)
(15
)%
6,600

Brokered Natural Gas Cost (In thousands)

$
33,362

$
43,342

$
9,980

Brokered Natural Gas Margin (In thousands)

$
5,585

$
6,554

$
(969
)

~~The decreased brokered natural gas margin of $1.0 million is primarily a result of~~ a decrease in brokered volumes.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to revenue from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

	Nine Months Ended
	September 30,
	2011					2010				Three Months Ended March 31,
(In thousands)	Realized		Unrealized			Realized		Unrealized		2012			2011

Operating Revenues - Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas	$	48,318	$	—		$	109,714	$	—	$	56,996		$	13,481
Crude Oil	566		—			14,522		—		(1,326		)	(302		)
Total Cash Flow Hedges	48,884		—			124,236		—

Other Derivative Financial Instruments
Other Financial Derivative Instruments
Natural Gas Basis Swaps	—		(950		)	—		162		42			17
Total Other Derivative Financial Instruments	—		(950		)	—		162
										$	55,712		$	13,196
Total Cash Flow Hedges and Other Derivative Financial Instruments	$	48,884	$	(950	)	$	124,236	$	162

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Operating and Other Expenses

	Nine Months Ended September 30,						Variance					Three Months Ended March 31,				Variance
(In thousands)	2011			2010			Amount			Percent		2012		2011		Amount		Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	33,362		$	43,342		$	(9,980	)	(23	)%	$	11,872	$	15,362	$	(3,490)	(23)%
Direct Operations	76,878			73,796			3,082			4	%	27,320		27,007		313		1%
Transportation and Gathering	48,710			13,488			35,222			261	%	30,258		12,868		17,390		135%
Taxes Other Than Income	21,070			31,135			(10,065		)	(32	)%	18,583		8,151		10,432		128%
Exploration	31,090			28,324			2,766			10	%	4,001		6,308		(2,307)		(37)%
Impairment of Oil and Gas Properties	—			35,789			(35,789		)	(100	)%
Depreciation, Depletion and Amortization	250,642			235,579			15,063			6	%	110,357		77,124		33,233		43%
General and Administrative	78,254			49,675			28,579			58	%	22,549		24,299		(1,750)		(7)%
Total Operating Expense	$	540,006		$	511,128		$	28,878		6	%	$	224,940	$	171,119	$	53,821	31%

(Gain) / Loss on Sale of Assets	$	(36,408	)	$	(5,411	)	$	30,997		573	%	$	535	$	1,517	$	(982)	(65)%
Interest Expense and Other	53,928			47,439			6,489			14	%	16,917		17,367		(450)		(3)%
Income Tax Expense	58,268			33,215			25,053			75	%	11,426		6,137		5,289		86%

Total costs and expenses from operations increased by ~~$28.9~~$53.8 million, or 6%31%, in the first ~~nine months~~quarter of ~~2011~~2012 compared to the same period of ~~2010.~~2011. The primary reasons for this fluctuation are as follows:

· Transportation and Gathering increased by $35.2 million primarily due to the commencement of various firm transportation and gathering arrangements in the first nine months of 2011 primarily in Susquehanna County, Pennsylvania.

·General and Administrative increased by $28.6 million primarily due to $19.2 million higher stock-based compensation expense primarily associated with the mark to market of the liability portion of our performance shares as a result of our higher average stock price for the month of September 2011 compared to the average stock price for the month of September 2010 and $5.9 million higher pension expense due to the acceleration of amortization of prior service costs and actuarial losses as a result of the plan termination and expected liquidation. Higher professional service costs also contributed to the increase.

·Depreciation, Depletion and Amortization increased by $15.1 million, of which $22.0 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset by a lower DD&A rate of $1.67 per Mcfe for nine months ended September 30, 2011 compared to $2.14 per Mcfe for nine months ended September 30, 2010 and a $1.6 million increase in amortization of asset retirement obligation costs. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of $8.5 million primarily due to a decrease in amortization rates due to a shift in our drilling and development activities.

·Direct Operations increased $3.1 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher workover and environmental and regulatory costs associated with the remediation of certain wells in northeast Pennsylvania as a result of the PaDEP Global Settlement. Offsetting these increases were lower compression expenses primarily due to the sale of our gathering system in northeast Pennsylvania in the fourth quarter of 2010 and increased use of centralized compression. Lease maintenance costs were also lower in the first nine months of 2011 compared to the same period of 2010.

·Exploration Expense increased $2.8 million primarily due to higher dry hole costs incurred related to an exploratory well in Montana in 2011, partially offset by lower geophysical and geological costs primarily due to a reduction in the acquisition of seismic data.

·Impairment of Oil and Gas Properties decreased by $35.8 million for the first nine months of 2011 compared to the first nine months of 2010 due to the impairment of two south Texas fields recognized in the first nine months of 2010 as a result of continued price declines and normal production declines. There were no impairments in the first nine months of 2011.

·Taxes Other Than Income decreased $10.1 million due to decreased production taxes as a result of tax refunds and credits received in 2011 on qualifying wells and lower ad valorem and business and occupational taxes partially offset by an increase in franchise taxes expense.

·Brokered Natural Gas Costs decreased ~~$10.0~~$3.5 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

·Direct Operations increased $0.3 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are lower expense recoveries from operated wells due to the sale of certain properties in Colorado, Utah and Wyoming in the fourth quarter 2011 and higher leased surface equipment and produced water disposal costs. Offsetting these increases were lower workover expenses, lower lease maintenance costs and lower outside-operated properties costs due to the sale of certain oil and gas properties in Colorado, Utah and Wyoming in the fourth quarter 2011.

·Transportation and Gathering increased by $17.4 million primarily due to an increase in production and a higher transportation rates, coupled with the commencement of various firm transportation and gathering arrangements subsequent to the end of the first quarter of 2011 and during the first three months of 2012 in northeast Pennsylvania.

·Taxes Other Than Income increased $10.4 million primarily due to additional costs associated with the passage of an “impact fee” in Pennsylvania on Marcellus shale production that was imposed by state legislature in February 2012.

·Exploration decreased $2.3 million primarily due to lower geophysical and geological costs due to fewer acquisitions and purchases of seismic data.

·Depreciation, Depletion and Amortization increased by $33.2 million, of which $39.1 million was due to higher equivalent production volumes partially offset by $5.8 million due to a lower DD&A rate of $1.68 per Mcfe for three months ended March 31, 2012 compared to $1.78 per Mcfe for three months ended March 31, 2011. The lower rate was due to the lower cost of reserve additions associated with our 2011 and 2012 drilling programs.

·General and Administrative decreased by $1.8 million primarily due to $6.5 million lower stock-based compensation expense primarily associated with the mark-to-market of our liability-based performance awards due to changes in our stock price for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 and a reduction of our supplemental incentive compensation liability. These decreases were partially offset by $3.2 million higher pension expense associated with the acceleration of amortization of the net actuarial loss as a result of the termination and anticipated liquidation of the plan in the second quarter 2012.

Interest Expense and Other

Interest expense and other decreased by $0.5 million primarily due to a decrease in weighted-average borrowings under our credit facility based on daily balances of approximately $235.4 million during the first quarter of 2012 compared to approximately $269.4 million during the first quarter of 2011 coupled with a lower

Table of Contents

~~Gain / (Loss)~~weighted-average effective interest rate on ~~Sale~~the credit facility of ~~Assets~~

~~An aggregate gain of $36.4 million was recognized in~~approximately 4.0% during the first ~~nine months~~quarter of ~~2011 on the sale of oil and gas properties in east Texas and the sale of non-core assets as part of our ongoing asset portfolio management program. In~~2012 compared to approximately 4.9% during the first ~~nine months~~quarter of ~~2010, a gain of $10.3 million was recognized on the sale of the Woodford shale prospect, offset by an impairment charge of $5.8 million on assets held for sale.~~2011.

Income Tax Expense

Income tax expense increased by ~~$25.1~~$5.3 million ~~in the first nine months of 2011 compared to the first nine months of 2010~~ primarily due to increased pretax income ~~partially offset by~~and a ~~lower~~higher effective tax rate. The effective tax rate for the first ~~nine months~~quarter of 2012 and 2011 was 38.4% and ~~2010 was 37.7% and 38.0%~~32.2%, respectively.

~~Interest Expense and Other~~

~~Interest expense and other increased by $6.5 million~~ The effective tax rate was lower in ~~the first nine months of~~ 2011 ~~compared to the first nine months of 2010 primarily~~ due to ~~an increase~~a reduction in weighted-average borrowings under our credit facility based on daily balances of approximately $340.2 million during the first nine months of 2011 compared to approximately $304.1 million during the first nine months of 2010. The weighted-average effective interest rate on the credit facility increased to approximately 4.0% during the first nine months of 2011 compared to approximately 3.8% during the first nine months of 2010. In addition, in December 2010, we issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the first nine months of 2011.estimated state tax liabilities.

Forward-Looking Information

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. ~~Such~~These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including ~~regional~~geographic basis differentials) of natural gas and ~~crude~~ oil, results ~~for~~of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed ~~herein~~in this document and in our other Securities and Exchange Commission filings. ~~Should~~If one or more of these risks or uncertainties materialize, or ~~should~~if underlying assumptions prove incorrect, actual outcomes may vary materially from those ~~indicated.~~included in this document.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

Our primary market risk is exposure to crude oil and natural gas prices. Realized prices are mainly driven by worldwide prices for crude oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us in periods of increasing prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 7 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

As of September 30, 2011, we had 42 derivative contracts open: 27 natural gas price swap arrangements, five natural gas collar arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap arrangements. During the first nine months of 2011, we entered into 31 new derivative contracts covering anticipated crude oil and natural gas production for 2011, 2012, and 2013.

~~Table of Contents~~

~~As of September 30, 2011, we had the following outstanding commodity derivatives:~~

Commodity and Derivative Type

Weighted-Average Contract Price

Volume

Contract Period

Net Unrealized
Gain / (Loss)

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24

per Mcf

3,254

Mmcf

Oct. 2011 - Dec. 2011

$
6,785

Natural Gas Swaps

$5.18

per Mcf

98,302

Mmcf

Oct. 2011 - Dec. 2012

86,650

Natural Gas Swaps

$5.28

per Mcf

17,854

Mmcf

Jan. 2012 - Dec. 2012

15,267

Natural Gas Collars

$6.17 Ceiling/ $5.13 Floor

per Mcf

17,805

Mmcf

Jan. 2013 - Dec. 2013

8,196

Crude Oil Collars

$93.25 Ceiling / $80.00 Floor

per Bbl

92

Mbbl

Oct. 2011- Dec. 2011

408

Crude Oil Swaps

$106.20

per Bbl

92

Mbbl

Oct. 2011 - Dec. 2011

2,466

Crude Oil Swaps

$105.00

per Bbl

366

Mbbl

Jan. 2012 - Dec. 2012

8,725

$
128,497

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.27
)
per Mcf

16,123

Mmcf

Jan. 2012 - Dec. 2012

(3,073
)

$
125,424

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized gain position at September 30, 2011 and exclude the impact of non-performance risk of $1.5 million. Non-performance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

~~From time to time,~~Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil ~~swap and collar agreements with counterparties~~production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge ~~price~~or mitigate risks to which we have actual or projected exposure or as permitted under our risk ~~associated with a portion~~management policies and not subjecting us to material speculative risks. All of our ~~production. These agreements~~derivatives are used for risk management purposes and are not held for trading purposes. Under ~~the price swaps,~~our swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under ~~the~~our collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us.

As of March 31, 2012, we had 39 derivative contracts open: 23 natural gas price swap arrangements, six natural gas basis swap arrangements, five crude oil swap arrangements and five natural gas collar arrangements. During the first three months of 2012, we entered into two new derivative contracts covering anticipated crude oil production for 2012 and 2013.

Table of Contents

As of March 31, 2012, we had the following outstanding commodity derivatives:

Commodity and Derivative Type	Weighted-Average Contract Price		Volume		Contract Period	Net Unrealized Gain / (Loss) (In thousands)

Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$5.22	per Mcf	72,129	Mmcf	Apr. 2012 - Dec. 2012	$	191,492
Natural Gas Collars	$6.20 Ceiling/ $5.15 Floor	per Mcf	17,729	Mmcf	Jan. 2013 - Dec. 2013	30,309
Crude Oil Swaps	$99.30	per Bbl	1,100	Mbbl	Apr. 2012 - Dec. 2012	(5,751			)
Crude Oil Swaps	$100.33	per Bbl	732	Mbbl	Jan. 2013 - Dec. 2013	(2,365			)
						$		213,685
Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.25)	per Mcf	12,805	Mmcf	Apr. 2012 - Dec. 2012	(2,382			)
						$		211,303

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized gain position at March 31, 2012 and exclude the impact of non-performance risk. Non-performance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

We had natural gas ~~price~~ swaps covering ~~51.9~~23.9 Bcf, or ~~41%~~42%, of our natural gas production for the first ~~nine~~three months of ~~2011 natural gas production~~2012 at an average price of ~~$5.36~~$5.22 per Mcf.

We had ~~one crude oil swap~~natural gas basis swaps covering ~~183 Mbbl,~~4.2 Bcf, or ~~21%~~8%, of our natural gas production for the first ~~nine~~three months of ~~2011 crude oil production,~~2012 at an average price of ~~$106.20~~$(0.25) per ~~Bbl.~~Mcf.

~~During the first nine months of 2011,~~We had crude oil ~~collars covered 273~~swaps covering 364 Mbbl, or ~~31%~~70%, of ~~total~~our crude oil production ~~with a weighted-average floor~~for the first three months of 2012 at an average price of ~~$80.00 per Bbl and a weighted-average ceiling price of $93.25~~$99.30 per Bbl.

We are exposed to market risk on ~~these open contracts,~~derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these ~~hedged~~derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the ~~commodity~~commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that ~~is hedged.~~can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our derivative contract counterparties are Bank of Montreal, BNP Paribas, JPMorgan Chase, Goldman Sachs and Bank of America.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

Fair Market Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these instruments.

The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new ~~issues~~issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to us.

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Table of Contents

We use available ~~marketing~~market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

	September 30, 2011				December 31, 2010				March 31, 2012				December 31, 2011
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt	$	1,205,000	$	1,339,410	$	975,000	$	1,100,830	$	1,012,000	$	1,150,853	$	950,000	$	1,082,531

ITEM 4. Controls and Procedures

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, ~~at a reasonable assurance level~~in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the ~~third~~first quarter of ~~2011~~2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

The information set forth under the heading ~~“Environmental~~“Legal Matters” in Note 6 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

We have received a number of Notices of Violation from the Pennsylvania Department of Environmental Protection (PaDEP) relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. We have responded to these Notices of Violation, have remediated the areas in question and are actively cooperating with the PaDEP. While we cannot predict with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

In August 2011, the Company received a subpoena from the New York Attorney General’s Office requesting documents and information regarding the Company’s shale and unconventional reservoir reserves calculations. The Company is providing documents and information responsive to the request and is cooperating with the Attorney General’s Office in the matter.

Environmental Matters

The information set forth under the heading “Environmental Matters” in Note 6 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

The Company has received a number of Notices of Violation from the Pennsylvania Department of Environmental Protection (PaDEP) relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. The Company has responded to these Notices of Violation, has remediated the areas in question and is actively cooperating with the PaDEP. While the Company cannot predict with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

ITEM 1A. Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2010.~~2011.

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

Issuer Purchases of Equity Securities

The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the ~~nine~~three months ended ~~September 30, 2011,~~March 31, 2012, the Company did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may ~~yet~~ be purchased under the plan as of ~~September 30, 2011~~March 31, 2012 was ~~4,795,300.~~9,590,600.

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ITEM 6. Exhibits

Exhibit Number		Description
15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

31.2		302 Certification - Vice President, Chief Financial Officer and Treasurer

32.1		906 Certification

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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.

	CABOT OIL & GAS CORPORATION
			(Registrant)

~~October 28, 2011~~April 27, 2012	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

~~October 28, 2011~~April 27, 2012	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

~~October 28, 2011~~April 27, 2012	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)

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(In thousands)	September 30, 2011		December 31, 2010
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	95,000
6.51% Weighted-Average Fixed Rate Notes	425,000		425,000
9.78% Notes	67,000		67,000
5.58% Weighted-Average Fixed Rate Notes	175,000		175,000
Credit Facility	443,000		213,000
	$	1,205,000	$	975,000

(In thousands)
2011	$	11,969
2012	57,066
2013	56,965
2014	56,965
2015	56,965
Thereafter	555,268
	$	795,198


	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)								Location of Gain (Loss) Reclassified from	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives Designated as Hedging Instruments	Three Months Ended September 30,				Nine Months Ended September 30,				Accumulated OCI into Income	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2011		2010		2011		2010		(In thousands)	2011		2010		2011		2010
Commodity Contracts	$	98,143	$	24,758	$	159,030	$	79,514	Natural Gas Revenues	$	21,170	$	39,461	$	48,318	$	109,714
									Crude Oil and Condensate Revenues	1,382		5,160		566		14,522
										$	22,552	$	44,621	$	48,884	$	124,236

	Nine Months Ended
	September 30,
(In millions)	2011		2010
Capital Expenditures
Drilling and Facilities	$	561.0	$	445.8
Leasehold Acquisitions	60.9		109.9
Acquisitions	—		0.8
Pipeline and Gathering	7.2		29.4
Other	6.5		6.6
	635.6		592.5
Exploration Expense	31.1		28.3
Total	$	666.7	$	620.8

	Nine Months Ended September 30,				Variance
	2011		2010		Amount			Percent
Natural Gas (1)	$	589,926	$	526,262	$	63,664		12	%
Brokered Natural Gas	38,947		49,896		(10,949		)	(22	)%
Crude Oil and Condensate	79,792		60,427		19,365			32	%
Other	4,124		3,901		223			6	%