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 ¨

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 ¨

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):

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

As of ~~April 26,~~July 25, 2011, there were ~~104,466,838~~104,488,502 shares of Common Stock, Par Value $.10 Per Share, outstanding.


	Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
(In thousands, except per share amounts)	2011			2010		2011		2010		2011		2010
OPERATING REVENUES
Natural Gas	$	170,098		$	169,870	$	200,357	$	164,528	$	370,455	$	334,399
Brokered Natural Gas		18,408			24,873		11,072		13,348		29,480		38,221
Crude Oil and Condensate		18,592			19,982		28,042		21,211		46,634		41,193
Other		1,928			1,620		1,225		1,154		3,153		2,774

		209,026			216,345		240,696		200,241		449,722		416,587
OPERATING EXPENSES
Brokered Natural Gas Cost		15,362			21,268		9,796		11,793		25,158		33,061
Direct Operations		27,007			22,983		22,579		24,347		49,586		47,330
Transportation and Gathering		12,868			3,789		16,074		4,767		28,942		8,557
Taxes Other Than Income		8,151			10,805		5,877		11,841		14,028		22,646
Exploration		6,308			8,426		4,592		10,233		10,900		18,659
Depreciation, Depletion and Amortization		77,124			73,498		83,225		76,726		160,349		150,224
General and Administrative		24,299			15,746		26,006		12,853		50,305		28,599

		171,119			156,515		168,149		152,560		339,268		309,076
Gain / (Loss) on Sale of Assets		(1,517	)		759		34,071		4,387		32,554		5,146

INCOME FROM OPERATIONS		36,390			60,589		106,618		52,068		143,008		112,657
Interest Expense and Other		17,367			14,912		18,044		15,769		35,411		30,681

Income Before Income Taxes		19,023			45,677		88,574		36,299		107,597		81,976
Income Tax Expense		6,137			16,981		33,897		14,617		40,034		31,598

NET INCOME	$	12,886		$	28,696	$	54,677	$	21,682	$	67,563	$	50,378

Earnings Per Share
Basic	$	0.12		$	0.28	$	0.53	$	0.21	$	0.65	$	0.49
Diluted	$	0.12		$	0.27	$	0.52	$	0.21	$	0.64	$	0.48
Weighted-Average Shares Outstanding
Basic		104,144			103,794		104,264		103,915		104,204		103,855
Diluted		105,320			104,978		105,337		104,964		105,088		104,838
Dividends per common share	$	0.03		$	0.03
Dividends Per Common Share						$	0.03	$	0.03	$	0.06	$	0.06

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


(In thousands, except share amounts)	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and Cash Equivalents	$	24,896		$	55,949		$	39,314		$	55,949
Accounts Receivable, Net		90,586			94,488			117,314			94,488
Income Taxes Receivable		3,323			—			7,893			—
Inventories		20,806			29,667			24,044			29,667
Deferred Income Taxes								—			257
Derivative Instruments		17,194			16,926			40,344			16,926
Other Current Assets		4,733			5,978			6,929			5,721

Total Current Assets		161,538			203,008			235,838			203,008
Properties and Equipment, Net (Successful Efforts Method)		3,847,047			3,762,760			3,967,716			3,762,760
Other Assets		39,822			39,263			46,606			39,263

	$	4,048,407		$	4,005,031		$	4,250,160		$	4,005,031


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	199,649		$	229,981		$	223,838		$	229,981
Income Taxes Payable		5,078			25,957			—			25,957
Deferred Income Taxes								9,778			—
Accrued Liabilities		36,975			47,897			53,108			47,897

Total Current Liabilities		241,702			303,835			286,724			303,835
Pension and Postretirement Benefits		34,502			34,053			34,869			34,053
Long-Term Debt		1,055,000			975,000			1,095,000			975,000
Deferred Income Taxes		722,369			714,953			757,612			714,953
Asset Retirement Obligation		73,039			72,311			74,048			72,311
Other Liabilities		35,775			32,179			35,708			32,179

Total Liabilities		2,162,387			2,132,331			2,283,961			2,132,331


Commitments and Contingencies (Note 6)
Commitments and Contingencies
Stockholders’ Equity
Common Stock:
Authorized—240,000,000 Shares of $0.10 Par Value in 2011 and 2010 Issued—104,456,232 Shares and 104,210,084 Shares in 2011 and 2010, respectively		10,446			10,421
Authorized—240,000,000 Shares of $0.10 Par Value in 2011 and 2010 Issued—104,467,059 Shares and 104,210,084 Shares in 2011 and 2010, respectively								10,447			10,421
Additional Paid-in Capital		722,521			720,920			727,021			720,920
Retained Earnings		1,158,156			1,148,391			1,209,705			1,148,391
Accumulated Other Comprehensive Income		(1,754	)		(3,683	)
Accumulated Other Comprehensive Income/(Loss)								22,375			(3,683	)
Less Treasury Stock, at Cost:
202,200 Shares in 2011 and 2010, respectively		(3,349	)		(3,349	)		(3,349	)		(3,349	)

Total Stockholders’ Equity		1,886,020			1,872,700			1,966,199			1,872,700

	$	4,048,407		$	4,005,031		$	4,250,160		$	4,005,031

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


	Three Months Ended March 31,							Six Months Ended June 30,
(In thousands)	2011				2010			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	12,886			$	28,696		$	67,563		$	50,378
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		77,124				73,498			160,349			150,224
Deferred Income Tax Expense		6,543				15,716			36,886			29,091
(Gain) / Loss on Sale of Assets		1,517				(759	)		(32,554	)		(5,146	)
Exploration Expense		493				8,426			504			8,426
Unrealized Loss / (Gain) on Derivative Instruments		(17	)			587			886			(355	)
Amortization of Debt Issuance Costs		1,120				1,068			2,253			2,136
Stock-Based Compensation Expense and Other		8,936				4,210			19,576			6,219
Changes in Assets and Liabilities:				��
Accounts Receivable, Net		3,902				(13,189	)		(22,826	)		1,200
Income Taxes		(24,202	)			(5,110	)		(33,850	)		5,083
Inventories		8,861				10,319			5,623			4,456
Other Current Assets		1,014				2,664			(1,208	)		1,061
Accounts Payable and Accrued Liabilities		(9,615	)			(12,913	)		10,821			(5,937	)
Other Assets and Liabilities		2,651				2,884			6,678			(3,658	)

Net Cash Provided by Operating Activities		91,213				116,097			220,701			243,178

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(203,169	)			(235,403	)		(404,214	)		(454,143	)
Proceeds from Sale of Assets		5,043				803			54,336			16,742

Net Cash Used in Investing Activities		(198,126	)			(234,600	)		(349,878	)		(437,401	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from Debt		110,000				110,000			220,000			210,000
Repayments of Debt		(30,000	)			—			(100,000	)		—
Dividends Paid		(3,122	)			(3,112	)		(6,250	)		(6,228	)
Capitalized Debt Issuance Costs		(1,025	)			—			(1,025	)		(1,986	)
Other		7				(38	)		(183	)		(36	)

Net Cash Provided by Financing Activities		75,860				106,850			112,542			201,750

Net (Decrease) / Increase in Cash and Cash Equivalents		(31,053	)			(11,653	)		(16,635	)		7,527
Cash and Cash Equivalents, Beginning of Period		55,949				40,158			55,949			40,158

Cash and Cash Equivalents, End of Period	$	24,896			$	28,505		$	39,314		$	47,685

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

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report on Form 10-K for the year ended December 31, 2010 (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.

With respect to the unaudited financial information of the Company as of ~~March 31,~~June 30, 2011 and for the three and six months ended ~~March 31,~~June 30, 2011 and 2010, 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~~July 29, 2011 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

In May 2011, the Financial Accounting Standards Board (FASB) issued 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 IFRSs. The amendments in this Update are to be applied prospectively. For public entities, the amendments are effective during interim and annual periods beginning after December 15, 2011. Early application by public entities is not permitted. The Company does not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

In June 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income,” requiring most entities to present items of net income and other comprehensive income either in one continuous statement—referred to as the statement of comprehensive income—or in two separate, but consecutive, statements of net income and other comprehensive income. The new requirements are effective for public entities for fiscal years (including interim periods) beginning after December 15, 2011. The Company does not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.


(In thousands)	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010
Proved Oil and Gas Properties	$	4,943,135		$	4,794,650		$	5,152,151		$	4,794,650
Unproved Oil and Gas Properties		501,649			490,181			492,258			490,181
Gathering and Pipeline Systems		237,093			237,043			237,333			237,043
Land, Building and Other Equipment		84,046			86,248			78,943			86,248

		5,765,923			5,608,122			5,960,685			5,608,122
Accumulated Depreciation, Depletion and Amortization		(1,918,876	)		(1,845,362	)		(1,992,969	)		(1,845,362	)

	$	3,847,047		$	3,762,760		$	3,967,716		$	3,762,760

At ~~March 31,~~June 30, 2011, 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.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

During the first ~~three~~six months of 2011, the Company entered into atwo participation ~~agreement and a purchase and sale agreement~~agreements with third parties related to certain of its Haynesville and Bossier Shale leaseholds in East Texas. ~~In April 2011, the Company entered into a participation agreement related to the same area with an additional third party.~~ Under the terms of the participation agreements, the third parties will 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~~six months of 2011, Cabot received a reimbursement of drilling costs of approximately ~~$5.9~~$11.2 million associated with the participation ~~agreement that closed during~~agreements.

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

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

In June 2010, primarily as a result of the Company’s decision to divest of certain oil and gas properties in Colorado, an impairment loss of approximately $5.8 million was recognized. The impairment charge was included in Gain / (Loss) on Sale of Assets in the Condensed Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement ~~Cabot expects~~the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of these properties were considered level 2 in the fair value hierarchy.

In July 2011, the Company entered into a purchase and sale agreement to ~~receive approximately $45 million to $50~~sell certain oil and gas properties located in Colorado, Utah and Wyoming for $285 million in ~~cash at closing, which~~cash. This transaction is expected to ~~occur~~close in the ~~second~~fourth quarter of 2011, subject to customary closing conditions and adjustments.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)


(In thousands)	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	89,454		$	91,077		$	109,924		$	91,077
Joint Interest Accounts		4,358			4,901			10,368			4,901
Other Accounts		394			2,603			759			2,603

		94,206			98,581			121,051			98,581
Allowance for Doubtful Accounts		(3,620	)		(4,093	)		(3,737	)		(4,093	)

	$	90,586		$	94,488		$	117,314		$	94,488

INVENTORIES
Natural Gas in Storage	$	5,524		$	13,371		$	10,605		$	13,371
Tubular Goods and Well Equipment		14,082			17,072			12,941			17,072
Pipeline Imbalances		1,200			(776	)		498			(776	)

	$	20,806		$	29,667		$	24,044		$	29,667

OTHER CURRENT ASSETS
Drilling Advances	$	561		$	2,796		$	25		$	2,796
Prepaid Balances		1,913			2,925			4,670			2,925
Restricted Cash		2,234			—			2,234			—
Deferred Income Taxes		25			257

	$	4,733		$	5,978		$	6,929		$	5,721

OTHER ASSETS
Rabbi Trust Deferred Compensation Plan		16,391			15,788			16,231			15,788
Debt Issuance Costs		20,928			22,061			19,808			22,061
Derivative Instruments		1,163			—			9,231			—
Other Accounts		1,340			1,414			1,336			1,414

	$	39,822		$	39,263		$	46,606		$	39,263

ACCOUNTS PAYABLE
Trade Accounts	$	30,472		$	27,401		$	24,758		$	27,401
Natural Gas Purchases		3,276			3,596			7,519			3,596
Royalty and Other Owners		39,873			36,034			47,956			36,034
Accrued Capital Costs		112,035			146,824			129,652			146,824
Taxes Other Than Income		1,168			2,655			(219	)		2,655
Drilling Advances		520			523			498			523
Wellhead Gas Imbalances		4,901			5,142			4,376			5,142
Other Accounts		7,404			7,806			9,298			7,806

	$	199,649		$	229,981		$	223,838		$	229,981

ACCRUED LIABILITIES
Employee Benefits	$	3,918		$	10,790		$	8,475		$	10,790
Pension and Postretirement Benefits		1,688			1,688			1,688			1,688
Taxes Other Than Income		14,446			14,576			15,695			14,576
Interest Payable		15,259			19,488			24,915			19,488
Derivative Instruments								1,160			—
Other Accounts		1,664			1,355			1,175			1,355

	$	36,975		$	47,897		$	53,108		$	47,897

OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	24,570		$	21,600		$	26,399		$	21,600
Derivative Instruments		4,199			2,180			—			2,180
Other Accounts		7,006			8,399			9,309			8,399

	$	35,775		$	32,179		$	35,708		$	32,179

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

At March 31, 2011, the Company had $293.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.9% and $606.7 million available for future borrowings. In addition, the Company had letters of credit outstanding at March 31, 2011 of $0.3 million.

Effective April 1, 2011, the lenders under the Company’s revolving credit facility approved an increase in the Company’s Borrowing Base from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the credit facility.

At June 30, 2011, the Company had $333.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.3% and $566.8 million available for future borrowings. In addition, the Company had letters of credit outstanding at June 30, 2011 of $0.3 million.

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 for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2011		2010		2011		2010		2011		2010
Weighted-Average Shares—Basic		104,144		103,794		104,264		103,915		104,204		103,855
Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period		1,176		1,184		1,073		1,049		884		983

Weighted-Average Shares—Diluted		105,320		104,978		105,337		104,964		105,088		104,838

Weighted-Average Stock Awards and Shares
Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect		354		287		1		634		72		429

The Company is a defendant in various legal proceedings arising in the normal course of business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s condensed consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)~~

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

On April 15, 2010, the Company and the PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, the PaDEP and the Company agreed that the Company will provide a permanent source

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by the PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

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

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

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

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 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.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay a total of $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the 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 begin hydraulic fracturing in the affected areas after providing the PaDEP with well pressure data and to commence drilling new wells in the affected area in the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)~~

As of the date of this report, the Company is in continuing discussions with the PaDEP to address the results of our well pressure tests, water quality sampling and well headspace screenings. We have requested PaDEP approval to resume hydraulic fracturing and new well drilling operations in the affected area.

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

As of ~~March 31,~~June 30, 2011, the Company has paid $1.3 million in fines and penalties to the PaDEP related to this matter, paid $2.0 million to seven of the affected households and accrued a $2.2 million settlement liability ~~related to this matter~~that represents the unpaid escrow balance, which is included in Other Liabilities in the Condensed Consolidated Balance Sheet.

During the first ~~three months~~half of 2011, the Company ~~entered into no new firm~~amended certain gas transportation ~~arrangements~~and gathering agreements with ~~third-party pipelines.~~ third party pipelines that increased the minimum daily quantity, increased the transportation fee and/or extended the term of the agreement.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

For further information on the Company’s ~~firm~~ gas transportation ~~arrangements,~~agreements, please refer to Note 8 of the Notes to the Consolidated Financial Statements in the Form 10-K.

As of ~~March 31,~~June 30, 2011, the Company does not have any outstanding drilling commitments with initial terms greater than one year.

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,~~June 30, 2011, the Company had 3142 derivative contracts open: 2127 natural gas price swap arrangements, five natural gas collar arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap arrangements. During the first ~~three months~~half of 2011, the Company entered into 2031 new derivative contracts covering anticipated natural gas and crude oil production ~~and natural gas production~~ for 2011, 2012 and ~~2012.~~

In April 2011, the company entered into five natural gas collar arrangements with weighted average floor and ceiling prices of $5.13 and $6.17 per Mcf, respectively. The collar arrangements cover 17,805 Mmcf of anticipated natural gas production for 2013.

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

Commodity and Derivative Type

Weighted-Average
Contract Price

Volume

Contract Period

Weighted-Average
Contract Price

Volume

Contract Period

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24

per Mcf

9,726

Mmcf

Apr. 2011 - Dec. 2011

$6.24

per Mcf

6,508

Mmcf

Jul. 2011 - Dec. 2011

Natural Gas Swaps

$5.15

per Mcf

93,805

Mmcf

Apr. 2011 - Dec. 2012

$5.18

per Mcf

118,049

Mmcf

Jul. 2011 - Dec. 2012

Natural Gas Swaps

$5.28

per Mcf

17,854

Mmcf

Jan. 2012 - Dec. 2012

$5.28

per Mcf

17,854

Mmcf

Jan. 2012 - Dec. 2012

Natural Gas Collars

$6.17 Ceiling/$5.13 Floor

per Mcf

17,805

Mmcf

Jan. 2013 - Dec. 2013

Crude Oil Collars

$93.25 Ceiling / $80.00 Floor

per Bbl

275

Mbbl

Apr. 2011 - Dec. 2011

$93.25 Ceiling /$80.00 Floor

per Bbl

184

Mbbl

Jul. 2011 - Dec. 2011

Crude Oil Swaps

$106.20

per Bbl

275

Mbbl

Apr. 2011 - Dec. 2011

$106.20

per Bbl

184

Mbbl

Jul. 2011 - Dec. 2011

Crude Oil Swaps

$105.00

per Bbl

366

Mbbl

Jan. 2012 - Dec. 2012

$105.00

per Bbl

366

Mbbl

Jan. 2012 - Dec. 2012

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$ (0.27)

per Mcf

16,123

Mmcf

Jan. 2012 - Dec. 2012

$(0.27)

per Mcf

16,123

Mmcf

Jan. 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.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

The following schedules reflect the fair value of derivative instruments on the Company’s condensed consolidated financial statements:

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

At ~~March 31,~~June 30, 2011 and December 31, 2010, unrealized gains of ~~$16.3~~$51.5 million ($~~10.1~~31.9 million, net of tax) and $16.9 million ($10.5 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive ~~Income.~~Income / (Loss). Based upon estimates at ~~March 31,~~June 30, 2011, the Company expects to reclassify ~~$11.0~~$25.3 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

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


Derivatives Not Designated as Hedging Instruments (In thousands)	Location of Gain (Loss) Recognized in Income on Derivative	Three Months Ended March 31,					Location of Gain (Loss) Recognized in Income on Derivative	Three Months Ended June 30,					Six Months Ended June 30,
	Location of Gain (Loss) Recognized in Income on Derivative	2011		2010			Location of Gain (Loss) Recognized in Income on Derivative	2011			2010		2011			2010
Natural Gas Commodity Contracts	Natural Gas Revenues	$	17	$	(587	)
Commodity Contracts							Natural Gas Revenues	$	(903	)	$	942	$	(886	)	$	355

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.

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)~~

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.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Accounting Standards Codification (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, and accordingly, Level 1 measurements should be used whenever possible.

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 14 of the Notes to the Consolidated Financial Statements in the Form 10-K.

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a nonrecurring basis. During the three and six month periods ended June 30, 2010, the Company recorded an impairment related to certain oil and gas properties held for sale. Refer to Note 2 for additional disclosures related to fair value associated with the impaired properties. As none of the Company’s other non-financial assets and liabilities were impaired as of ~~March 31,~~June 30, 2011 and 2010 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures ~~were~~are not provided.

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

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)


(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, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of June 30, 2011
Assets
Rabbi Trust Deferred Compensation Plan	$	16,391	$	—	$	—	$	16,391	$	16,231	$	—	$	—	$	16,231
Derivative Contracts		—		—		18,357		18,357		—		—		49,575		49,575

Total Assets	$	16,391	$	—	$	18,357	$	34,748	$	16,231	$	—	$	49,575	$	65,806

Liabilities
Rabbi Trust Deferred Compensation Plan	$	24,570	$	—	$	—	$	24,570	$	26,399	$	—	$	—	$	26,399
Derivative Contracts		—		—		4,199		4,199		—		—		1,160		1,160

Total Liabilities	$	24,570	$	—	$	4,199	$	28,769	$	26,399	$	—	$	1,160	$	27,559


(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010
Assets
Rabbi Trust Deferred Compensation Plan	$	15,788	$	—	$	—	$	15,788	$	15,788	$	—	$	—	$	15,788
Derivative Contracts		—		—		16,926		16,926		—		—		16,926		16,926

Total Assets	$	15,788	$	—	$	16,926	$	32,714	$	15,788	$	—	$	16,926	$	32,714

Liabilities
Rabbi Trust Deferred Compensation Plan	$	21,600	$	—	$	—	$	21,600	$	21,600	$	—	$	—	$	21,600
Derivative Contracts		—		—		2,180		2,180		—		—		2,180		2,180

Total Liabilities	$	21,600	$	—	$	2,180	$	23,780	$	21,600	$	—	$	2,180	$	23,780

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

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, 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 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. As of ~~March 31,~~both June 30, 2011 and December 31, 2010, the impact of non-performance risk relative to the Company’s derivative contracts was ~~$0.2 million and~~ $0.1 ~~million, respectively.~~million.

The following table sets forth a reconciliation of changes for the ~~three-month~~three- and six-month periods ended ~~March 31,~~June 30, 2011 and 2010 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2011			2010			2011			2010			2011			2010
Balance at beginning of period	$	14,746		$	112,307		$	14,158		$	135,532		$	14,746		$	112,307
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings⁽¹⁾		13,197			32,438			12,249			47,534			25,446			79,972
Included in Other Comprehensive Income		(606	)		23,811			35,161			(48,672	)		34,555			(24,861	)
Settlements		(13,179	)		(33,024	)		(13,153	)		(46,591	)		(26,332	)		(79,615	)
Transfers In and/or Out of Level 3		—			—			—			—			—			—

Balance at end of period	$	14,158		$	135,532		$	48,415		$	87,803		$	48,415		$	87,803

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

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 the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the notes and credit facility is based on interest rates currently available to the Company.

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, 2011				December 31, 2010				June 30, 2011				December 31, 2010
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt	$	1,055,000	$	1,171,552	$	975,000	$	1,100,830	$	1,095,000	$	1,231,089	$	975,000	$	1,100,830

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Comprehensive Income / (Loss) includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive ~~Income.~~Income/(Loss). The following tables illustrate the calculation of Comprehensive ~~Income~~Income/(Loss) for the three and six months ended ~~March 31,~~June 30, 2011 and 2010:

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)~~

~~Changes in the components of Accumulated Other Comprehensive Income, net of taxes, for the three months ended March 31, 2011 were as follows:~~

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Changes in the components of Accumulated Other Comprehensive Income/ (Loss), net of taxes, for the six months ended June 30, 2011 were as follows:

The components of net periodic benefit costs for the three and six months ended ~~March 31,~~June 30, 2011 and 2010 were as follows:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2011			2010			2011			2010			2011			2010
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	—		$	896		$	—		$	896		$	—		$	1,794
Interest Cost		801			994			800			993			1,601			1,985
Expected Return on Plan Assets		(1,160	)		(1,039	)		(1,160	)		(1,039	)		(2,320	)		(2,080	)
Amortization of Prior Service Cost		317			21			316			21			633			42
Amortization of Net Loss		3,062			591			3,062			591			6,124			1,182

Net Periodic Pension Cost	$	3,020		$	1,463		$	3,018		$	1,462		$	6,038		$	2,923


Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	335		$	392		$	334		$	316		$	669		$	633
Interest Cost		467			487			468			424			935			847
Amortization of Net Loss		141			253			141			62			282			316
Amortization of Net Obligation at Transition		158			158			158			158			316			316

Total Postretirement Benefit Cost	$	1,101		$	1,290		$	1,101		$	960		$	2,202		$	2,112

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

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. Because no further benefits will accrue under the qualified pension plan after September 30, 2010, the Company’s related non-qualified pension plan was effectively frozen and no additional benefits will be accrued under those arrangements after September 30, 2010. For further information regarding termination and amendment of qualified and non-qualified pension plans, refer to Note 6 of the Notes to the Consolidated Financial Statements in the Form 10-K.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Stock-based compensation expense (including the supplemental employee incentive plan) during the first ~~three~~six months of 2011 and 2010 was ~~$8.1~~$19.3 million and ~~$3.2~~$5.1 million, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the second quarter of 2011 and 2010 was $11.2 million and $1.9 million, respectively.

During the first ~~three~~six months of 2011, ~~3,300~~7,300 restricted stock awards were granted with a weighted-average grant date per share value of ~~$40.69.~~$43.62. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate assumption of 7.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

During the first ~~three~~six months of 2011, ~~27,615~~29,701 restricted stock units were granted to non-employee directors of the Company with a grant date per share value of ~~$40.56.~~$41.75. 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.

During the first ~~three~~six months of 2011, 95,750 stock appreciation rights (SARs) were granted to employees. These awards allow the employee to receive common stock of the Company equal to the intrinsic value over the $40.74 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 Rights Granted During the Period	$	18.94
Assumptions
Weighted-Average Value per Stock Appreciation Right Granted During the Period				$	18.94
Assumptions:
Stock Price Volatility		52.7	%		52.7	%
Risk Free Rate of Return		2.3	%		2.3	%
Expected Dividend Yield		0.3	%		0.3	%
Expected Term (in years)		5.0			5.0

During the first ~~three~~six months of 2011, three types of performance share awards were granted to employees for a total of 394,757 performance shares, which included 92,696 performance share awards based on market conditions and 302,061 performance share awards based on performance conditions measured against the Company’s internal performance metrics. Of the 302,061 performance-based awards 92,696 of the shares have a three-year graded performance period. For these shares, one-third of the shares, are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited. For the remaining 209,365 performance-based awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. Refer to Note 12 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of performance share awards.

The performance period for the awards based on internal performance metrics commenced on January 1, 2011 and ends on December 31, 2013 and the grant date per share value for these awards was $40.74, which is based on the average of the high and low stock price on the grant date. The actual number of shares issued on each anniversary date following the grant date or at the end of the performance period, as applicable, will be determined based on the Company’s performance against the performance criteria set by the Company’s Compensation Committee. Based on the Company’s probability assessment at ~~March 31,~~June 30, 2011, it is considered probable that the criteria for the performance-based awards will be met. The Company used an annual forfeiture rate assumption ranging from 0% to 7% for purposes of recognizing stock-based compensation expense for all performance-based share awards.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

The following assumptions were used for the performance shares based on market conditions using a Monte Carlo model to value the liability and equity components of the awards. The equity portion of the 2011 awards was valued on the grant date (February 17, 2011) and was not marked to market. The liability portion of the awards was valued as of ~~March 31,~~June 30, 2011 on a mark-to-market basis.

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)~~


	Grant Date			March 31, 2011		Grant Date			June 30, 2011
Value per Share	$	31.23			$2.46 - $26.15	$	31.23		$	16.04 - $48.63
Assumptions
Assumptions:
Stock Price Volatility		62.0	%		34.85% - 62.59%		62.0	%		37.08% - 47.38%
Risk Free Rate of Return		1.3	%		0.24% - 1.17%		1.3	%		0.10% - 0.63%
Expected Dividend Yield		0.2	%		0.4%		0.2	%		0.2%

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation ~~during the three months ended March 31, 2011~~ is as follows:

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

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

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

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

ITEM 2.

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

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

As a result of our production growth and the commencement of various ~~firm~~ transportation and gathering agreements in 2011, we began separately reporting our transportation and gathering costs as a component of operating expenses in the Condensed Consolidated Statement of Operations. Previously reported transportation and gathering costs were reflected as a component of Natural Gas Revenues and have been reclassified to conform to current year presentation. Accordingly, previously reported operating revenues and operating expenses have increased with no impact on previously reported net income.

On an equivalent basis, our production for the ~~three~~six months ended ~~March 31,~~June 30, 2011 increased by ~~41%~~45% compared to the ~~three~~six months ended ~~March 31,~~June 30, 2010. For the ~~three~~six months ended ~~March 31,~~June 30, 2011, we produced ~~37.7~~82.7 Bcfe compared to ~~of 26.7~~57.1 Bcfe for the ~~three~~six months ended ~~March 31,~~June 30, 2010. Natural gas production was ~~36.4~~79.5 Bcf and crude oil/condensate/NGL production was ~~226~~529 Mbbls for the first ~~three months~~half of 2011. Natural gas production increased by ~~43%~~46% when compared to the first ~~three months~~half of 2010, which had production of ~~25.4~~54.4 Bcf. This increase was primarily a result of increased production in the North region associated with the drilling program and ~~the start up of additional compressors at~~upgrades to the Lathrop compressor station, which included the commissioning of new compression during the first ~~quarter~~six months of 2011 in Susquehanna County, Pennsylvania. Partially offsetting the production increase in the North region were decreases in production in the South region due to normal production declines and a shift from gas to oil projects. Crude oil/condensate/NGL production increased by 4%14%, to ~~226~~529 Mbbls, when compared to the first ~~three months~~half of 2010, which had production of ~~217~~465 Mbbls. This increase was primarily the result of increased production in the South region associated with the drilling program in the Eagle Ford Shale in South Texas, partially offset by a slight decrease in production in the North.

Our average realized natural gas price for the first ~~three months~~half of 2011 was ~~$4.68~~$4.67 per Mcf, ~~30%~~24% lower than the ~~$6.71~~$6.15 per Mcf price realized in the first ~~three months~~half of 2010. Our average realized crude oil price for the first ~~three months~~half of 2011 was ~~$87.15~~$91.80 per Bbl, ~~11%~~5% lower than the ~~$97.40~~$97.04 per Bbl price realized in the first ~~three months~~half of 2010. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our future revenues, capital program or production volumes.

Operating revenues for the ~~three~~six months ended ~~March 31,~~June 30, 2011 ~~decreased~~increased by ~~$7.3~~$33.1 million, or 3%8%, from the ~~three~~six months ended ~~March 31,~~June 30, 2010. Natural gas revenues, excluding unrealized gains/losses from the change in fair value of our basis swaps, ~~decreased~~increased by ~~$0.4~~$37.3 million, or ~~less than 1%~~11%, for the ~~three~~six months ended ~~March 31,~~June 30, 2011 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2010 as the increase in natural gas production more than offset the lower realized natural gas ~~prices more than offset the higher natural gas production.~~prices. Crude oil and condensate revenues ~~decreased~~increased by ~~$1.4~~$5.4 million, or 7%13%, for the first ~~three~~six months of 2011 as compared to the first ~~three~~six months of 2010, due to ~~decreases in~~increased crude oil production partially offset by lower realized crude oil ~~prices and partially offset by higher crude oil production.~~prices. Brokered natural gas revenues decreased by ~~$6.5~~$8.7 million, or ~~26%~~23%, due to a decreased sales price and decreased brokered volumes.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. For 2011, we expect to spend approximately $600 million in capital and exploration expenditures, net of proceeds from the sale of assets that may be used to fund incremental capital and exploration expenditures. We believe our cash on hand, operating cash flow in 2011, proceeds from asset sales and borrowings from our credit facility will be sufficient to fund our remaining budgeted capital and exploration spending in 2011. 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~~six months ended ~~March 31,~~June 30, 2011, we invested approximately ~~$174.2~~$397.4 million in our exploration and development efforts.

During the first ~~three~~six months of 2011, we drilled 2452 gross wells ~~(19~~(45 development, ~~three~~four exploratory and ~~two~~three extension wells) with a success rate of 100% compared to 2445 gross wells ~~(20~~(41 development, two exploratory and two extension wells) with a success rate of ~~96%~~98% for the comparable period of the prior year. For the full year of 2011, we plan to drill approximately ~~110~~150 gross ~~(83.1~~(98.7 net) wells.

While we consider acquisitions from time to time, we continue to remain focused on our strategies of pursuing lower risk 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. We believe these strategies are appropriate for our portfolio of projects and the current industry 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.

Our primary sources of cash for the ~~three~~six months ended ~~March 31,~~June 30, 2011 were funds generated from the sale of natural gas and crude oil production (including hedge realizations), borrowings under our credit facility and the sales of properties and other assets. These cash flows were primarily used to fund our development and exploration expenditures, in addition to payment of dividends and repayment of debt. 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 ~~facilityand~~facility and liquidity available to meet our working capital requirements.


	Three Months Ended March 31,						Six Months Ended June 30,
(In thousands)	2011			2010			2011			2010
Cash Flows Provided by Operating Activities	$	91,213		$	116,097		$	220,701		$	243,178
Cash Flows Used in Investing Activities		(198,126	)		(234,600	)		(349,878	)		(437,401	)
Cash Flows (Used in) / Provided by Financing Activities		75,860			106,850
Cash Flows Provided by Financing Activities								112,542			201,750

Net (Decrease) / Increase in Cash and Cash Equivalents	$	(31,053	)	$	(11,653	)	$	(16,635	)	$	7,527

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating ~~costs.~~expenses. Net cash provided by operating activities in the first ~~three~~six months of 2011 decreased by ~~$24.9~~$22.5 million over the first ~~three~~six months of 2010. This decrease was ~~mainly~~primarily due to ~~lower~~changes in working capital partially offset by increased operating income in 2011 as a result of higher operating ~~costs~~revenues and ~~lower~~an increase in the gain on sale of assets that outpaced the increase in operating ~~revenues.~~expenses. The ~~decrease~~increase in operating revenues was primarily due to an increase in equivalent production partially offset by lower realized natural gas and crude oil ~~prices partially offset~~prices. Equivalent production volumes increased by ~~an increase in equivalent~~45% for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by ~~30%~~24% for the first ~~three~~six months of 2011 compared to the first ~~three~~six months of 2010. Average realized crude oil prices decreased by ~~11%~~5% compared to the same period. Equivalent production volumes increased by 41% for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 as a result of higher natural gas production and a slight increase in crude oil production. See “Results of Operations” for additional information relative to commodity price, production and operating ~~cost~~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.

Investing Activities. The primary use of cash in investing activities was capital spending. We established our 2011 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 ~~$36.5~~$87.5 million for the first ~~three~~six months of 2011 compared to the first ~~three~~six months of 2010. The decrease was primarily due to a decrease of ~~$32.2~~$49.9 million in capital and exploration expenditures and higher proceeds from sale of assets of ~~$4.2~~$37.6 million.

Financing Activities. Cash flows provided by financing activities decreased by ~~$31.0~~$89.2 million from the first ~~three~~six months of 2010 to the first ~~three~~six months of 2011. This was primarily due to an increase in repayments of debt ~~and an increase in cash paid for capitalized debt issuance cost of $1.0 million~~partially offset by higher borrowings in the first ~~three~~six months of ~~2011.~~2011 compared to the first six months of 2010.

At ~~March 31,~~June 30, 2011, we had ~~$293.0~~$333.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of ~~4.9%~~4.3%. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. Effective April 1, 2011, the lenders under our credit facility approved an increase in the borrowing base under the facility from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the credit facility. As of ~~March 31,~~June 30, 2011, our available credit under our credit facility was ~~$607~~$566.8 million.

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

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


(Dollars in millions)	March 31, 2011			December 31, 2010			June 30, 2011			December 31, 2010

Debt⁽¹⁾	$	1,055.0		$	975.0		$	1,095.0		$	975.0

Stockholders’ Equity		1,886.0			1,872.7			1,966.2			1,872.7

Total Capitalization	$	2,941.0		$	2,847.7		$	3,061.2		$	2,847.7


Debt to Capitalization		35.9	%		34.2	%		35.8	%		34.2	%

Cash and Cash Equivalents	$	24.9		$	55.9		$	39.3		$	55.9

During the ~~three~~six months ended ~~March 31,~~June 30, 2011, we paid dividends of ~~$3.1~~$6.3 million ($~~0.03~~0.06 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

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,				Six Months Ended June 30,
(In millions)	2011		2010		2011		2010
Capital Expenditures

Drilling and Facilities	$	145.7	$	128.4	$	345.8	$	261.6
Leasehold Acquisitions		17.0		48.1		30.0		90.3
Acquisitions						—		0.8
Pipeline and Gathering		5.2		6.0		5.7		18.1
Other		—		2.9		5.0		4.5

		167.9		185.4		386.5		375.3
Exploration Expense		6.3		8.4		10.9		18.7

Total	$	174.2	$	193.8	$	397.4	$	394.0

For the full year of 2011, we plan to drill approximately ~~110~~150 gross ~~(83.1~~(98.7 net) wells. This 2011 drilling program includes approximately $600 million in total capital and exploration expenditures, net of proceeds from the sale of assets that may be used to fund incremental 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.

We have various contractual obligations in the normal course of our operations. ~~There have been no material changes~~For further information, please refer to ~~our contractual obligations from those disclosed~~“Transportation Agreements” under Note 6 in the Notes to the Condensed Consolidated Financial Statements and Note 8 in the Notes to Consolidated Financial Statements included in our ~~2010 Form~~ 10-K.

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 Form 10-K for further discussion of our critical accounting policies.

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

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income,” requiring most entities to present items of net income and other comprehensive income either in one continuous statement—referred to as the statement of comprehensive income—or in two separate, but consecutive, statements of net income and other comprehensive income. The new requirements are effective for public entities for fiscal years (including interim periods) beginning after December 15, 2011. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

We reported net income in the ~~first~~second quarter of 2011 of ~~$12.9~~$54.7 million, or ~~$0.12~~$0.53 per share, compared to net income in the ~~first~~second quarter of 2010 of ~~$28.7~~$21.7 million, or ~~$0.28~~$0.21 per share. Net income ~~decreased~~increased in the ~~first~~second quarter of 2011 by ~~$15.8~~$33.0 million, primarily due to ~~a decrease~~an increase in operating revenues and ~~an increase~~gain on sale of assets partially offset by increases in operating expenses, interest expense and ~~interest~~income tax expense.

Operating revenues ~~decreased~~increased by ~~$7.3~~$40.5 million ~~largely~~ due to ~~decreases in brokered~~increased natural gas ~~revenues~~ and crude oil and condensate revenues partially offset by decreased brokered natural gas revenues. Operating expenses increased by ~~$14.6~~$15.6 million between periods primarily due to increases in general and administrative expenses, transportation and gathering expenses and depreciation, depletion, and amortization, ~~general and administrative expenses and direct operations,~~ partially offset by lower taxes other than income, exploration expense, brokered natural gas cost ~~lower exploration expense~~ and ~~taxes other than income.~~direct operating expenses. In addition, net income was impacted during the ~~first~~second quarter by increased gain on sale of assets, partially offset by higher ~~interest expense and lower~~ income tax ~~expense. Income tax expense was lower during the first quarter of 2011 due to lower pretax income~~ and ~~a lower effective tax rate.~~interest expense.


	Three Months Ended March 31,				Variance						Three Months Ended June 30,				Variance
Revenue Variances (In thousands)	2011		2010		Amount			Percent			2011		2010		Amount			Percent
Natural Gas⁽¹⁾	$	170,081	$	170,457	$	(376	)		0	%	$	201,260	$	163,586	$	37,674			23	%
Brokered Natural Gas		18,408		24,873		(6,465	)		(26	%)		11,072		13,348		(2,276	)		(17	%)
Crude Oil and Condensate		18,592		19,982		(1,390	)		(7	%)		28,042		21,211		6,831			32	%
Other		1,928		1,620		308			19	%		1,225		1,154		71			6	%


	Three Months Ended March 31,				Variance						Increase (Decrease)			Three Months Ended June 30,				Variance						Increase (Decrease) (In thousands)
	2011		2010		Amount			Percent			(In thousands)			2011		2010		Amount			Percent			Increase (Decrease) (In thousands)
Price Variances
Natural Gas⁽¹⁾	$	4.68	$	6.71	$	(2.03	)		(30	%)	$	(73,939	)	$	4.67	$	5.65	$	(0.98	)		(17	%)	$	(42,414	)
Crude Oil and Condensate⁽²⁾	$	87.15	$	97.40	$	(10.25	)		(11	%)		(2,176	)	$	95.17	$	96.70	$	(1.53	)		(2	%)		(451	)

Total											$	(76,115	)											$	(42,865	)

Volume Variances
Natural Gas (Mmcf)		36,371		25,392		10,979			43	%	$	73,563			43,128		28,961		14,167			49	%	$	80,088
Crude Oil and Condensate (Mbbl)		213		205		8			4	%		786			295		219		76			35	%		7,282

Total											$	74,349												$	87,370

The ~~decrease~~increase in ~~Natural Gas Revenues~~natural gas revenues of ~~$0.4~~$37.7 million, excluding the impact of unrealized gains and losses discussed above, is primarily due to increased production during the second quarter of 2011 in Susquehanna County, Pennsylvania, partially offset by lower realized natural gas ~~prices, partially offset by~~prices. The increased production is primarily due to increased production in the North region associated with the drilling program and the start up of additional compressors at the Lathrop compressor station ~~during the first quarter of 2011~~ in Susquehanna County, ~~Pennsylvania. Partially offsetting the production increase in the North region were~~partially offset by decreases in production in the South region due to normal production declines and a shift from gas to oil projects.

The ~~decrease~~increase in ~~Crude Oil~~crude oil and ~~Condensate Revenues~~condensate revenues of $6.8 million is primarily due to ~~lower realized oil prices, partially offset by~~ increased production in the South region associated with the drilling program in the Eagle Ford Shale in South ~~Texas.~~Texas, partially offset by lower realized oil prices.


	Three Months Ended March 31,				Variance						Price and Volume Variances (In thousands)			Three Months Ended June 30,				Variances						Price and Volume Variance (In thousands)
	2011		2010		Amount			Percent			Price and Volume Variances (In thousands)			2011		2010		Amount			Percent			Price and Volume Variance (In thousands)
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	5.28	$	6.23	$	(0.95	)		(15	%)	$	(3,318	)	$	5.10	$	5.04	$	0.06			1	%	$	130
Volume Brokered (Mmcf)	x	3,489	x	3,995		(506	)		(13	%)		(3,147	)	x	2,173	x	2,649		(476	)		-18	%		(2,406	)

Brokered Natural Gas Revenues(In thousands)	$	18,408	$	24,873							$	(6,465	)	$	11,072	$	13,348							$	(2,276	)


Brokered Natural Gas Purchases
Purchase Price($/Mcf)	$	4.40	$	5.32	$	(0.92	)		(17	%)	$	3,203		$	4.51	$	4.45	$	0.06			1	%	$	(126	)
Volume Brokered(Mmcf)	x	3,489	x	3,995		(506	)		(13	%)		2,703		x	2,173	x	2,649		(476	)		-18	%		2,123

Brokered Natural Gas Cost(In thousands)	$	15,362	$	21,268							$	5,906		$	9,796	$	11,793							$	1,997


Brokered Natural Gas Margin(In thousands)	$	3,046	$	3,605							$	(559	)	$	1,276	$	1,555							$	(279	)

The decreased brokered natural gas margin of ~~$0.6~~$0.3 million is a result of primarily a decrease in brokered ~~volumes coupled with a decrease in sales price that outpaced the decrease in purchase price.~~volumes.

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


	March 31,										Three Months Ended June 30,
	2011					2010					2011						2010
(In thousands)	Realized			Unrealized		Realized		Unrealized			Realized			Unrealized			Realized		Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	13,481		$	—	$	28,441	$	—
Natural Gas											$	13,667		$	—		$	41,812	$	—
Crude Oil		(302	)		—		4,583		—			(514	)		—			4,779		—
																			��
Total Cash Flow Hedges		13,179			—		33,024		—			13,153			—			46,591		—


Other Derivative Financial Instruments
Natural Gas Basis Swaps		—			17		—		(587	)		—			(903	)		—		942

Total Other Derivative Financial Instruments		—			17		—		(587	)		—			(903	)		—		942


Total Cash Flow Hedges and Other Derivative Financial Instruments	$	13,179		$	17	$	33,024	$	(587	)	$	13,153		$	(903	)	$	46,591	$	942

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 primary derivative contract counterparties are Bank of Montreal, BNP Paribas, JPMorgan Chase, Goldman Sachs and Bank of America.


	Three Months Ended March 31,					Variance						Three Months Ended June 30,				Variance
(In thousands)	2011		2010			Amount			Percent			2011		2010		Amount			Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	15,362	$	21,268		$	(5,906	)		(28	%)	$	9,796	$	11,793	$	(1,997	)		(17	%)
Direct Operations		27,007		22,983			4,024			18	%		22,579		24,347		(1,768	)		(7	%)
Transportation and Gathering		12,868		3,789			9,079			240	%		16,074		4,767		11,307			237	%
Taxes Other Than Income		8,151		10,805			(2,654	)		(25	%)		5,877		11,841		(5,964	)		(50	%)
Exploration		6,308		8,426			(2,118	)		(25	%)		4,592		10,233		(5,641	)		(55	%)
Depreciation, Depletion and Amortization		77,124		73,498			3,626			5	%		83,225		76,726		6,499			8	%
General and Administrative		24,299		15,746			8,553			54	%		26,006		12,853		13,153			102	%

Total Operating Expense	$	171,119	$	156,515		$	14,604			9	%	$	168,149	$	152,560	$	15,589			10	%
(Gain) / Loss on Sale of Assets	$	1,517	$	(759	)	$	2,276			(300	%)
Gain / (Loss) on Sale of Assets												$	34,071	$	4,387	$	29,684			677	%
Interest Expense and Other		17,367		14,912			2,455			16	%		18,044		15,769		2,275			14	%
Income Tax Expense		6,137		16,981			(10,844	)		(64	%)		33,897		14,617		19,280			132	%

Total costs and expenses from operations increased by ~~$14.6~~$15.6 million, or 9%10%, in the ~~first~~second quarter of 2011 compared to the same period of 2010. The primary reasons for this fluctuation are as follows:

General and Administrative increased by $13.2 million primarily due to $9.3 million higher stock-based compensation expense primarily associated with the mark to market of the liability portion of our performance shares as a result of our higher stock price of $66.31 as of June 30, 2011 compared to $31.22 as of June 30, 2010. Higher incentive compensation expense and professional service costs also contributed to the increase.

Depreciation, Depletion and Amortization increased by ~~$3.6~~$6.5 million, of which ~~$9.2~~$6.6 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset by a lower DD&A ~~rate.~~rate of $1.63 per Mcfe for three months ended June 30, 2011 compared to $2.21 per Mcfe for three months ended June 30, 2010. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of ~~$6.1~~$0.1 million.

Direct Operations decreased $1.8 million largely due to lower compressor expenses in both the North and South regions primarily due to the sale of our gathering system in the North region in the fourth quarter of 2010, increased use of centralized compression and a shift in our drilling program, and decreased lease maintenance expense in both the North and South regions. Partially offsetting these decreases were increases in operating costs primarily driven by increased production. Higher workover and contract labor expense and increased plugging and abandonment expense as the result of increased regulatory requirements also contributed to higher operating costs.

An aggregate gain of $34.1 million was recognized in the second quarter of 2011 primarily due to the sale of oil and gas properties in East Texas. During the second quarter of 2010, a gain of $10.3 million was recognized on the sale of the Woodford shale prospect, offset by an impairment charge of $5.8 million on assets held for sale.

Income tax expense increased by $19.3 million in the second quarter of 2011 compared to the second quarter of 2010 primarily due to increased pretax income partially offset by a lower effective tax rate. The effective tax rate for the second quarter of 2011 and 2010 was 38.3% and 40.3%, respectively.

Interest expense and other increased by $2.3 million in the second quarter of 2011 compared to the second quarter of 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $342.0 million during the second quarter of 2011 compared to approximately $317.4 million during the second quarter of 2010. In addition, the weighted-average effective interest rate on the credit facility increased to approximately 3.8% during the second quarter of 2011 compared to approximately 3.68% during the second quarter of 2010. Furthermore, in December 2010 we also issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the second quarter of 2011.

We reported net income in the first six months of 2011 of $67.5 million, or $0.65 per share, compared to net income in the first six months of 2010 of $50.4 million, or $0.49 per share. Net income increased in the first six months of 2011 by $17.2 million, primarily due to an increase in operating revenues and gain on sale of assets, partially offset by increases in operating expenses, interest expense and income tax expense.

Operating revenues increased by $33.1 million, largely due to increased natural gas, crude oil and condensate and other revenues, partially offset by decreased brokered natural gas revenues. Operating expenses increased by $30.2 million between periods primarily due to increases in general and administrative expenses, transportation and gathering expenses, depreciation, depletion and amortization and direct operations partially offset by lower taxes other than income, brokered natural gas cost and exploration expense. In addition, net income was impacted during the first six months by increased gain on sale of assets partially offset by higher interest expense and income tax expense.


	Six Months Ended June 30,				Variance						Increase (Decrease) (In thousands)
	2011		2010		Amount			Percent			Increase (Decrease) (In thousands)
Price Variances
Natural Gas⁽¹⁾	$	4.67	$	6.15	$	(1.48	)		(24	%)	$	(117,578	)
Crude Oil and Condensate⁽²⁾	$	91.80	$	97.04	$	(5.24	)		(5	%)		(2,661	)

Total											$	(120,239	)

Volume Variances
Natural Gas (Mmcf)		79,499		54,353		25,146			46	%	$	154,875
Crude Oil and Condensate (Mbbl)		508		425		83			20	%		8,102

Total											$	162,977

The increase in Natural Gas Revenues of $37.3 million is primarily due to increased production during the first half of 2011, partially offset by lower realized natural gas prices. The increased production is primarily due to increased production in the North region associated with the drilling program and the start up of additional compressors at the Lathrop compressor station during the first half of the year in Susquehanna County, partially offset by decreases in production in the South region due to normal production declines and a shift from gas to oil projects.

The increase in Crude Oil and Condensate Revenues of $5.4 million is primarily due to increased production in the South region associated with the drilling program in the Eagle Ford Shale in South Texas, partially offset by lower realized oil prices.

The decreased brokered natural gas margin of $0.8 million is primarily a result of a decrease in brokered volumes coupled with a decrease in purchase price that outpaced the sales price.

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


	Six Months Ended June 30,
	2011						2010
(In thousands)	Realized			Unrealized			Realized		Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas	$	27,148		$	—		$	70,253	$	—
Crude Oil		(816	)		—			9,362		—

Total Cash Flow Hedges		26,332			—			79,615		—

Other Derivative Financial Instruments
Natural Gas Basis Swaps		—			(886	)		—		355

Total Other Derivative Financial Instruments		—			(886	)		—		355

Total Cash Flow Hedges and Other Derivative Financial Instruments	$	26,332		$	(886	)	$	79,615	$	355

Total costs and expenses from operations increased by $30.2 million, or 10%, in the first six months of 2011 compared to the same period of 2010. The primary reasons for this fluctuation are as follows:

General and Administrative increased by $21.7 million primarily due to $14.2 million higher stock-based compensation expense primarily associated with the mark to market of the liability portion of our performance shares as a result of our higher stock price of $66.31 as of June 30, 2011 compared to $31.22 as of June 30, 2010. Higher incentive compensation expense and professional service costs also contributed to the increase.

Depreciation, Depletion and Amortization increased by $10.1 million, of which $16.4 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset by a lower DD&A rate of $1.70 per Mcfe for six months ended June 30,2011 compared to $2.19 per Mcfe for six months ended June 30, 2010. The increase in depletion and depreciation was offset by a decrease in amortization of unproved properties of $6.2 million primarily due to a decrease in amortization rates due to a shift in our drilling and development activities.

Direct Operations increased $2.3 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher workover and environmental and regulatory costs in both the North and South regions and higher plugging and abandonment expense. Plugging and abandonment expense has increased in the South region due to increased plugging and abandonment activity as a result of an increase in regulatory requirements. Offsetting these increases were lower compression expenses in both the North and South regions primarily due to the sale of our gathering system in the North region in the fourth quarter of 2010, increased use of centralized compression and a shift in our drilling program.

~~(Gain)/Loss on sale~~An aggregate gain of ~~assets decreased by $2.3~~$32.6 million was recognized in the first ~~quarter~~half of 2011 ~~compared to~~on the ~~first quarter~~sale of ~~2010 primarily due to~~oil and gas properties in the East Texas and the sale of non-core assets as part of ~~the Company’s~~our ongoing asset portfolio management program. In the first half of 2010, a gain of $10.3 million was recognized on the sale of the Woodford shale prospect, offset by an impairment charges of $5.8 million on assets held for sales.

Income tax expense ~~decreased~~increased by ~~$10.8~~$8.4 million in the first ~~quarter~~six months of 2011 compared to the first six months of 2010 primarily due to ~~decreased~~increased pretax income ~~and~~partially offset by a lower effective tax rate. The effective tax rate for the first ~~quarter~~six months of 2011 and 2010 was ~~32.2%~~37.2% and ~~37.2%~~38.5%, respectively. The effective tax rate was lower due to a reduction in estimated state tax liabilities.

Interest expense and other increased by ~~$2.5~~$4.7 million in the first ~~quarter~~six months of 2011 compared to the first ~~quarter~~six months of 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately ~~$269.4~~$305.9 million during the first ~~quarter~~six months of 2011 compared to approximately ~~$200.0~~$259.0 million during the first ~~quarter~~six months of 2010. The weighted-average effective interest rate on the credit facility increased to approximately ~~4.9%~~4.3% during the first ~~quarter~~six months of 2011 compared to approximately ~~3.8%~~3.7% during the first ~~quarter~~six months of 2010. In addition, in December 2010, we also issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in the first six months of 2011.

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

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.

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

As of ~~March 31,~~June 30, 2011, we had 3142 derivative contracts open: 2127 natural gas price swap arrangements, five natural gas collar arrangements, six natural gas basis swaps, one crude oil price collar arrangement and three crude oil price swap arrangements. During the first ~~three~~six months of 2011, ~~the Company~~we entered into 2031 new derivative contracts covering anticipated crude oil and natural gas production for 2011, 2012, and ~~2012.~~2013.

As of ~~March 31,~~June 30, 2011, we had the following outstanding commodity derivatives:

The amounts set forth under the net unrealized gain/(loss) column in the table above represent our total unrealized gain position at ~~March 31,~~June 30, 2011 and excludes the impact of non-performance risk of ~~$0.2~~$0.1 million. Non-performance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

From time to time, we enter into natural gas and crude oil swap and collar agreements with counterparties to hedge price risk associated with a portion of our production. These agreements are not held for trading purposes. Under the price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index,

such as the NYMEX gas and crude oil futures. Under the 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.

~~During the~~We had natural gas price swaps covering 28.9 Bcf, or 36%, of our first ~~three~~six months of 2011 natural ~~gas price swaps covered 11.8 Bcf, or 32%, of our first three months of 2011~~ gas production at an average price of ~~$5.44~~$5.39 per Mcf.

We had one crude oil ~~collar~~swap covering 9091 Mbbl, or ~~42%~~18%, of our first ~~three~~six months of 2011 crude oil production, at an average price of $106.20 per Bbl.

During the first six months of 2011, crude oil collars covered 181 Mbbl, or 36% of total crude oil production, with a weighted-average floor price of $80.00 per Bbl and a weighted-average ceiling price of $93.25 per Bbl.

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

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.

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

The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issues (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.

We use available marketing data and valuation methodologies to estimate the fair value of debt.


	March 31, 2011				December 31, 2010				June 30, 2011				December 31, 2010
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt	$	1,055,000	$	1,171,552	$	975,000	$	1,100,830	$	1,095,000	$	1,231,089	$	975,000	$	1,100,830

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level 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~~second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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.

We have received a number of Notices of Violation from the Pennsylvania Department of Environmental Protection (PaDEP) relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. We have responded to these Notices of Violation, have remediated the areas in question and are actively cooperating with the PaDEP. While we cannot predict

with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

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

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~~six months ended ~~March 31,~~June 30, 2011, 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 shares that may yet be purchased under the plan as of ~~March 31,~~June 30, 2011 was 4,795,300.

Effective January 1, 2011, the Company amended and restated the Deferred Compensation Plan to incorporate prior plan amendments and to provide for Company contributions that may not be made to the Company’s tax-qualified Savings Investment Plan as a result of limitations imposed by the Internal Revenue Code.

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.


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨		Smaller reporting company ¨


	Page
Part I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Statement of Operations for the Three Months and Six Months Ended ~~March 31,~~June 30, 2011 and 2010		3

Condensed Consolidated Balance Sheet at ~~March 31,~~June 30, 2011 and December 31, 2010		4

Condensed Consolidated Statement of Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2011 and 2010		5

Notes to the Condensed Consolidated Financial Statements		6

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information		1920

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2021

Item 3. Quantitative and Qualitative Disclosures about Market Risk		2630

Item 4. Controls and Procedures		2732

Part II. Other Information

Item 1. Legal Proceedings		2732

Item 1A. Risk Factors		2832

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		2832

Item 5. Other Information		32

Item 6. Exhibits		2833

Signatures		2934


(In thousands)	March 31, 2011		December 31, 2010
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	95,000
6.51% Weighted-Average Fixed Rate Notes		425,000		425,000
9.78% Notes		67,000		67,000
5.58% Weighted-Average Fixed Rate Notes		175,000		175,000
Credit Facility		293,000		213,000

	$	1,055,000	$	975,000


(In thousands)	June 30, 2011		December 31, 2010
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	95,000
6.51% Weighted-Average Fixed Rate Notes		425,000		425,000
9.78% Notes		67,000		67,000
5.58% Weighted-Average Fixed Rate Notes		175,000		175,000
Credit Facility		333,000		213,000

	$	1,095,000	$	975,000


(In thousands)
2011	$	25,562
2012		55,882
2013		55,816
2014		55,816
2015		55,816
Thereafter		548,898

	$	797,790


		Fair Value Asset (Liability)
(In thousands)	Balance Sheet Location	March 31, 2011			December 31, 2010
Derivatives Designated as Hedging Instruments
Natural Gas Commodity Contracts	Derivative Instruments (current assets)	$	22,889		$	18,669
Crude Oil Commodity Contracts	Derivative Instruments (current assets)		(5,169	)		(1,743	)
Natural Gas Commodity Contracts	Other Liabilities		(2,343	)		—
Natural Gas Commodity Contracts	Other Assets		1,163			—
Crude Oil Commodity Contracts	Other Liabilities		(220	)		—

			16,320			16,926
Derivatives Not Designated as Hedging Instruments
Natural Gas Commodity Contracts	Derivative Instruments (current assets)		(526	)
Natural Gas Commodity Contracts	Other Liabilities		(1,636	)		(2,180	)

			(2,162	)		(2,180	)

		$	14,158		$	14,746


Derivatives Designated as Hedging Instruments	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives Designated as Hedging Instruments	Three Months Ended March 31,							Three Months Ended March 31,
(In thousands)	2011			2010			(In thousands)	2011			2010
Natural Gas Commodity Contracts	$	16,521		$	57,204		Natural Gas Revenues	$	13,481		$	28,441
Crude Commodity Oil Contracts		(3,948	)		(377	)	Crude Oil and Condensate Revenues		(302	)		4,583

	$	12,573		$	56,827			$	13,179		$	33,024


	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment			Total
Balance at December 31, 2010	$	10,494		$	(14,122	)	$	(55	)	$	(3,683	)
Net change in unrealized gain on cash flow hedges, net of taxes of $230		(376	)		—			—			(376	)
Net change in defined benefit pension and postretirement plans, net of taxes of ($1,371)		—			2,307			—			2,307
Change in foreign currency translation adjustment, net of taxes of ($0)		—			—			(2	)		(2	)

Balance at March 31, 2011	$	10,118		$	(11,815	)	$	(57	)	$	(1,754	)


(In thousands)
Carrying amount of asset retirement obligation at December 31, 2010	$	72,311
Liabilities incurred		325
Liabilities settled		(457	)
Accretion expense		860

Carrying amount of asset retirement obligation at March 31, 2011	$	73,039


Exhibit Number		Description
*10.1		Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2011

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


	CABOT OIL & GAS CORPORATION
		(Registrant)

~~April~~ July 29, 2011	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

~~April~~ July 29, 2011	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

~~April~~ July 29, 2011	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)