Edgar Filing: CABOT OIL & GAS CORP

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 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 April 23, 2012, there were 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 Balance Sheet at March 31, 2012 and December 31, 2011	3

Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2012 and 2011	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 Three Months Ended March 31, 2012 and 2011	6

Notes to the Condensed Consolidated Financial Statements	7

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	28

Item 4. Controls and Procedures	30

Part II. Other Information

Item 1. Legal Proceedings	31

Item 1A. Risk Factors	31

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 6. Exhibits	32

Signatures	33

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

	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 STATEMENT OF OPERATIONS (Unaudited)

	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 COMPREHENSIVE INCOME (Unaudited)

	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 disclosed in its Annual Report on Form 10-K for the year ended December 31, 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 with current year presentation. These reclassifications have no impact on previously reported net income.

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 2-for-1 split of the Company’s common stock.

With respect to the unaudited financial information of the Company as of March 31, 2012 and for the three months ended March 31, 2012 and 2011, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated April 27, 2012 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.

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 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. 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 are effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. This update did not have any impact on 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.” This update was amended in December 2011 by ASU No. 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of 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 a single continuous financial statement or in two separate but consecutive financial statements. ASU No. 2011-05 and 2011-12 are effective 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 any impact on its consolidated financial position, results of operations or cash flows.

2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

	March 31,			December 31,
(In thousands)	2012			2011

Proved Oil and Gas Properties	$	5,185,986		$	5,006,846
Unproved Oil and Gas Properties		483,846			478,942
Gathering and Pipeline Systems	238,281			238,660
Land, Building and Other Equipment	81,350			80,908
	5,989,463			5,805,356
Accumulated Depreciation, Depletion and Amortization	(1,978,260		)	(1,870,772		)
	$	4,011,203		$	3,934,584

At 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.

Haynesville/Bossier Shale Joint Venture

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

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31,			December 31,
(In thousands)	2012			2011

ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	91,742		$	111,306
Joint Interest Accounts	3,840			5,417
Other Accounts	778			1,003
	96,360			117,726
Allowance for Doubtful Accounts	(1,240		)	(3,345		)
	$	95,120		$	114,381
INVENTORIES
Natural Gas in Storage	$	3,854		$	13,513
Tubular Goods and Well Equipment	7,539			7,146
Other	837			619
	$	12,230		$	21,278
OTHER CURRENT ASSETS
Prepaid Balances	1,371			2,290
Restricted Cash	1,907			2,234
Other	88			55
	$	3,366		$	4,579
OTHER ASSETS
Rabbi Trust Deferred Compensation Plan	$	11,644		$	10,838
Debt Issuance Cost	16,616			17,680
Other Accounts	1,345			1,342
	$	29,605		$	29,860
ACCOUNTS PAYABLE
Trade Accounts	$	14,052		$	18,253
Natural Gas Purchases	1,966			3,012
Royalty and Other Owners	39,574			48,113
Accrued Capital Costs	136,860			138,122
Taxes Other Than Income	11,847			2,076
Drilling Advances	385			1,489
Wellhead Gas Imbalances	2,351			2,312
Other Accounts	6,153			3,917
	$	213,188		$	217,294
ACCRUED LIABILITIES
Employee Benefits	$	5,858		$	26,035
Pension and Postretirement Benefits	5,917			6,331
Taxes Other Than Income	11,562			12,297
Interest Payable	14,875			24,701
Derivative Contracts	6,538			385
Other Accounts	1,546			1,169
	$	46,296		$	70,918
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	19,183		$	20,187
Derivative Contracts	1,481			—
Other Accounts	7,956			11,752
	$	28,620		$	31,939

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4. LONG-TERM DEBT

The Company’s debt consisted of the following:

(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 March 31, 2012, the Company had $250.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.6% and $649.0 million available for future borrowings.

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
	March 31,
(In thousands)	2012	2011
Weighted-Average Shares - Basic	209,128	208,288
Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period	1,685	2,352
Weighted-Average Shares - Diluted	210,813	210,640

Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect	82	708

6. COMMITMENTS AND 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. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances could result in the actual liability exceeding the estimated ranges of 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) executed a consent order (Consent Order) addressing a number of environmental issues 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 supplies in Susquehanna County, Pennsylvania. As part of the settlement, the Company paid an aggregate $120,000 civil penalty with respect to the matters addressed by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and the PaDEP executed a modified Consent Order (First Modified Consent Order). The First Modified Consent Order provided that the Company would make available a permanent source of potable water to 14 households, most of which the Company had already been supplying with water. The First Modified Consent Order included the following conditions: (i) the Company would plug and abandon three vertical natural gas wells and would undertake certain remedial measures on a fourth well in a nine square mile area in Susquehanna County; (ii) the Company would complete these actions prior to 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; and (iii) the Company would also postpone drilling of new natural gas wells in the area of concern until certain terms of the consent orders were fulfilled. In addition, the First Modified Consent Order included a condition that the Company 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. 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 would pay an additional $30,000 per month until certain terms under the First Modified Consent Order were satisfied.

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

As outlined in the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to 14 households. 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 were not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

In a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and 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 to plug or take remedial actions at the remaining 10 natural gas wells and to contact the PaDEP to discuss connecting the impacted water supplies into community public water systems.

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 consent order and settlement agreement with the PaDEP (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 CO&SA, among other things, the Company agreed to place a total of $4.2 million into escrow accounts for the benefit of each of the identified households, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, perform remedial measures for two natural gas wells in the area of concern, provide pressure, water quality and water well headspace data to the PaDEP and offer water treatment to the households. The 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 certain data and information. Under the 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 CO&SA to the Pennsylvania Environmental Hearing Board (PEHB).

The Company is in continuing discussions with the PaDEP to address the results of the Company’s natural gas well 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 households. On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners are no longer 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 March 31, 2012, the Company has paid $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter, paid $2.3 million (through the escrow process) to ten of the affected households and accrued a $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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United States Environmental Protection Agency

By letter dated January 6, 2012, the United States Environmental Protection Agency (EPA) sent a Required Submission of Information—Dimock Township Drinking Water Contamination letter to the Company pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA). The Required Submission of Information requests all documents, water sampling results and any other correspondence related to the Company’s activities in the area of concern. The Company does not agree that the Submission of Information is required; however, the Company is providing information pursuant to the 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 March 31, 2012, the Company 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, the Company entered into two new derivative contracts covering anticipated crude oil production for 2012 and 2013.

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

Commodity and Derivative Type	Weighted-Average Contract Price			Volume		Contract Period
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$5.22		per Mcf	72,129	Mmcf	Apr. 2012 - Dec. 2012
Natural Gas Collars	$6.20 Ceiling/ $5.15 Floor		per Mcf	17,729	Mmcf	Jan. 2013 - Dec. 2013
Crude Oil Swaps	$99.30		per Bbl	1,100	Mbbl	Apr. 2012 - Dec. 2012
Crude Oil Swaps	$100.33		per Bbl	732	Mbbl	Jan. 2013 - Dec. 2013

Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(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)
(In thousands)	Balance Sheet Location	March 31, 2012			December 31, 2011
Derivatives Designated as Hedging Instruments
Commodity Contracts	Derivative Instruments (current assets)	$	199,071		$	177,389
Commodity Contracts	Accrued Liabilities	(6,538		)	(385		)
Commodity Contracts	Derivative Instruments (non-current assets)	22,259			21,249
Commodity Contracts	Other Liabilities	(1,481		)	—
		213,311			198,253
Derivatives Not Designated as Hedging Instruments
Commodity Contracts	Derivative Instruments (current assets)	(2,388		)	(3,126		)
		$	210,923		$	195,127

At March 31, 2012 and December 31, 2011, unrealized gains of $213.3 million ($130.5 million, net of tax) and $198.3 million ($121.3 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income / (Loss). Based upon estimates at March 31, 2012, the Company expects to reclassify $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.

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

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 months ended March 31, 2012 and 2011, 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	Three Months Ended March 31,
(In thousands)	in Income on Derivative	2012		2011
Commodity Contracts	Natural Gas Revenues	$	42	$	17

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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

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

Financial Assets and Liabilities

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:

(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 March 31, 2012
Assets
Rabbi Trust Deferred Compensation Plan	$	11,644	$	—	$	—	$	11,644
Derivative Contracts	—		—		218,942		218,942
Total Assets	$	11,644	$	—	$	218,942	$	230,586

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

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(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 an income approach that 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 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 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
	March 31,
(In thousands)	2012			2011
Balance at beginning of period	$	195,127		$	14,746
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (1)	57,038			13,197
Included in Other Comprehensive Income	22,692			(606		)
Settlements	(56,300		)	(13,179		)
Transfers In and/or Out of Level 3	385			—
Balance at end of period	$	218,942		$	14,158

(1) Unrealized gains of $42 thousand and $17 thousand for the three months ended March 31, 2012 and 2011, respectively, 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 months ended March 31, 2012 and 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.

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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 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:

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)

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

(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
	March 31,
(In thousands)	2012			2011
Qualified and Non-Qualified Pension Plans
Interest Cost	$	461		$	801
Expected Return on Plan Assets	(874		)	(1,160		)
Amortization of Prior Service Cost	111			317
Amortization of Net Loss	6,542			3,062
Net Periodic Pension Cost	$	6,240		$	3,020

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	523		$	335
Interest Cost	418			467
Amortization of Net Loss	280			141
Amortization of Net Obligation at Transition	—			158
Total Postretirement Benefit Cost	$	1,221		$	1,101

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Termination and Amendment of Qualified Pension 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 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.

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 in the second quarter of 2012.

For further information regarding termination and amendment of the Company’s pension plans, refer to Note 5 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 three months of 2012 and 2011 was $1.7 million and $8.1 million, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations.

Restricted Stock Awards

During the first three months of 2012, 750 restricted stock awards were granted with a weighted-average grant date per share value of $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 6.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first three months of 2012, 38,304 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of $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 three months of 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 $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	$	16.31

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

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Performance Share Awards

During the first three months of 2012, three types of performance share awards were granted to employees for a total of 518,602 performance shares, which included 401,141 performance share awards based on performance conditions measured against the Company’s internal performance 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 401,141 performance awards 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 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. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria are based on the Company’s average production, average finding costs and average reserve replacement over the three-year performance period.

Based on the Company’s probability assessment at March 31, 2012, it is considered probable that criteria for these awards will be met.

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. These performance shares have both an equity and liability component. The equity portion of the 2012 awards was valued on the grant date (February 16, 2012) and was not marked to market. The liability portion of the awards was valued as of March 31, 2012 on a mark-to-market basis.

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

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 beginning of period	$	60,142
Liabilities incurred	560
Liabilities settled	(162		)
Accretion expense	744
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 March 31, 2012, and the related condensed consolidated statements of operations and comprehensive income for the three month periods ended March 31, 2012 and 2011, and the condensed consolidated statement of cash flows for the three month periods ended March 31, 2012 and 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, 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, 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, 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

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 month periods ended March 31, 2012 and 2011 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, 2011 (Form 10-K).

On January 3, 2012, the Board of Directors declared a 2-for-1 split of our 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 2-for-1 split of our common stock.

Overview

On an equivalent basis, our production for the three months ended March 31, 2012 increased by 58% compared to the three months ended March 31, 2011. For the three months ended March 31, 2012, we produced 59.7 Bcfe compared to 37.7 Bcfe for the three months ended March 31, 2011. Natural gas production was 56.4 Bcf and crude oil/condensate/NGL production was 538 Mbbls for the first three months of 2012. Natural gas production increased by 55% when compared to the first three months of 2011, which had production of 36.4 Bcf. This increase was primarily a result of increased production in the Marcellus shale associated with our 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 quarter in 2011. Partially offsetting the production increase in Marcellus shale were decreases in production primarily in east 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 outside of the Marcellus shale. Crude oil/condensate/NGL production increased by 138%, to 538 Mbbls, when compared to the first three months of 2011, which had production of 226 Mbbls. This increase was primarily the result of increased production associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

Our average realized natural gas price for the first three months of 2012 was $3.65 per Mcf, 22% lower than the $4.68 per Mcf price realized in the first three months of 2011. Our average realized crude oil price for the first three months of 2012 was $96.67 per Bbl, 11% higher than the $87.15 per Bbl price realized in the first three months of 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 capital program, production volumes or 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 three months ended March 31, 2012 increased by $63.1 million, or 30%, from the three months ended 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 $36.7 million, or 22%, for the three months ended March 31, 2012 as compared to the three months ended 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 $31.4 million, or 169%, for the first three months of 2012 as compared to the first three months of 2011, due to increased crude oil production that outpaced the increase in realized crude oil prices. Brokered natural gas revenues decreased by $5.0 million, or 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 2012, we expect to spend approximately $750 to $790 million in capital and exploration expenditures. We believe our existing cash on hand, operating cash flows and borrowings under our credit facility, if required, will be more than sufficient to fund our capital and exploration spending in 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 three months ended March 31, 2012, we invested approximately $192.1 million in our exploration and development efforts.

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During the first three months of 2012, we drilled 31 gross development wells with a success rate of 100% compared to 24 gross wells (19 development, three exploratory and two extension wells) with a success rate of 100% for the comparable period of the prior year. For the full year of 2012, we plan to drill approximately 120 to 130 gross wells.

Our 2012 strategy will remain consistent with 2011. While we consider acquisitions from time to time, we remain focused on pursuing drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline 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 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 three months ended 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. These cash flows were primarily used to fund our capital and exploration expenditures and payment of 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.

	Three Months Ended
	March 31,
(In thousands)	2012			2011
Cash Flows Provided by Operating Activities	$	131,780		$	91,213
Cash Flows Used in Investing Activities	(187,267		)	(198,126		)
Cash Flows Provided by Financing Activities	57,904			75,860
Net Increase / (Decrease) in Cash and Cash Equivalents	$	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 three months of 2012 increased by $40.6 million over the first three months of 2011. This increase was primarily due to increased operating income in 2012 as a result of higher operating revenues that outpaced the increase in operating expenses. This increase in operating income coupled with changes in working capital and long-term assets and liabilities 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 prices. Equivalent production volumes increased by 58% for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by 22% for the first three months of 2012 compared to the first three months of 2011. Average realized crude oil prices increased by 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 and exploration expenditures. We established our 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 $10.9 million for the first three months of 2012 compared to the first three months of 2011. The decrease was primarily due a decrease of $14.6 million in capital and exploration expenditures, partially offset by lower proceeds from sale of assets of $3.8 million.

Financing Activities. Cash flows provided by financing activities decreased by $18.0 million from the first three months of 2011 to the first three months of 2012. This was primarily due to a decrease in borrowings and repayments of debt, resulting in lower net borrowings.

At March 31, 2012, we had $250.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 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. The borrowing base under the credit facility is $1.7 billion. As of March 31, 2012, our available credit under our credit facility was $649.0 million.

We are in compliance in all material respects with our debt covenants as of 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 internally generated cash flow from operations, existing cash on hand and availability under our revolving credit facility, 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:

	March 31,			December 31,
(Dollars in thousands)	2012			2011

Debt (1)	$	1,012,000		$	950,000
Stockholders’ Equity	2,124,956			2,104,768
Total Capitalization	$	3,136,956		$	3,054,768

Debt to Capitalization	32		%	31		%

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

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

During the three months ended March 31, 2012, we paid dividends of $4.2 million ($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:

	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 2012, we plan to drill approximately 120 to 130 gross wells. This 2012 drilling program includes between $750 to $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. There have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Hydraulic Fracturing Services Commitments” in Note 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.

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 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. 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 are effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. This update did not have 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 a single continuous financial statement or in two separate but consecutive financial statements. ASU No. 2011-05 and 2011-12 are effective 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

First Quarter of 2012 and 2011 Compared

We reported net income in the first quarter of 2012 of $18.3 million, or $0.09 per share, compared to net income in the first quarter of 2011 of $12.9 million, or $0.06 per share. Net income increased in the first quarter of 2012 by $5.4 million, primarily due to an increase in operating revenues partially offset by increases in operating expenses as well as income tax expense.

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

Revenue, Price and Volume Variances

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

	Three Months Ended March 31,				Variance
Revenue Variances (In thousands)	2012		2011		Amount			Percent
Natural Gas (1)	$	206,740	$	170,081	$	36,659		22%
Brokered Natural Gas	13,444		18,408		(4,964		)	(27)%
Crude Oil and Condensate	49,981		18,592		31,389			169%
Other	1,929		1,928		1			—%

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

									Increase
	Three Months Ended March 31,				Variance				(Decrease)
	2012		2011		Amount			Percent	(In thousands)
Price Variances
Natural Gas (1)	$	3.65	$	4.68	$	(1.03	)	(22)%	$	(57,193	)
Crude Oil and Condensate (2)	$	96.67	$	87.15	$	9.52		11%	4,894
Total									$	(52,299	)
Volume Variances
Natural Gas (Mmcf)	56,434		36,371		20,063			55%	$	93,852
Crude Oil and Condensate (Mbbl)	517		213		304			143%	26,495
Total									$	120,347

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

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

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Natural Gas Revenues

The increase in natural gas revenues of $36.7 million, excluding the impact of unrealized losses discussed above, is primarily due to increased production during the first quarter of 2012, partially offset by lower realized natural gas prices. The increased production was primarily a result of increased production in the Marcellus shale associated with our 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 quarter in 2011. Partially offsetting the production increase in Marcellus shale were decreases in production primarily in east 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 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 $31.4 million is primarily due to increased production associated with our Eagle Ford shale drilling program in south Texas and the Marmaton oil play in Oklahoma coupled with higher realized oil prices.

Brokered Natural Gas Revenue and Cost

												Price and
	Three Months Ended											Volume
	March 31,								Variance			Variances
	2012				2011				Amount		Percent	(In thousands)
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	4.06			$		5.28		$	(1.22)	(23)%	$	(4,054	)
Volume Brokered (Mmcf)	x		3,311		x	3,489			(178)		(5)%	(910		)
Brokered Natural Gas Revenues (In thousands)	$	13,444			$		18,408					$	(4,964	)

Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$	3.59			$		4.40		$	(0.81)	(18)%	$	2,706
Volume Brokered (Mmcf)	x			3,311	x			3,489	(178)		(5)%	784
Brokered Natural Gas Cost (In thousands)	$	11,872			$		15,362					$	3,490

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

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

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

Cash Flow Hedges
Natural Gas	$	56,996		$	13,481
Crude Oil	(1,326		)	(302		)

Other Financial Derivative Instruments
Natural Gas Basis Swaps	42			17
	$	55,712		$	13,196

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Operating and Other Expenses

	Three Months Ended March 31,				Variance
(In thousands)	2012		2011		Amount		Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	11,872	$	15,362	$	(3,490)	(23)%
Direct Operations	27,320		27,007		313		1%
Transportation and Gathering	30,258		12,868		17,390		135%
Taxes Other Than Income	18,583		8,151		10,432		128%
Exploration	4,001		6,308		(2,307)		(37)%
Depreciation, Depletion and Amortization	110,357		77,124		33,233		43%
General and Administrative	22,549		24,299		(1,750)		(7)%
Total Operating Expense	$	224,940	$	171,119	$	53,821	31%

(Gain) / Loss on Sale of Assets	$	535	$	1,517	$	(982)	(65)%
Interest Expense and Other	16,917		17,367		(450)		(3)%
Income Tax Expense	11,426		6,137		5,289		86%

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

· Brokered Natural Gas Costs decreased $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

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weighted-average effective interest rate on the credit facility of approximately 4.0% during the first quarter of 2012 compared to approximately 4.9% during the first quarter of 2011.

Income Tax Expense

Income tax expense increased by $5.3 million primarily due to increased pretax income and a higher effective tax rate. The effective tax rate for the first quarter of 2012 and 2011 was 38.4% and 32.2%, respectively. The effective tax rate was lower in 2011 due to a reduction in 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. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed in this document and in our other Securities and Exchange Commission filings. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those 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.

Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under 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 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.

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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 swaps covering 23.9 Bcf, or 42%, of our natural gas production for the first three months of 2012 at an average price of $5.22 per Mcf.

We had natural gas basis swaps covering 4.2 Bcf, or 8%, of our natural gas production for the first three months of 2012 at an average price of $(0.25) per Mcf.

We had crude oil swaps covering 364 Mbbl, or 70%, of our crude oil production for the first three months of 2012 at an average price of $99.30 per Bbl.

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.

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 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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We use 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:

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

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, 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 first quarter of 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

The information set forth under the heading “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.

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, 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 three months ended 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 be purchased under the plan as of March 31, 2012 was 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)

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

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

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