Coterra Energy Inc. - Quarter Report: 2013 March (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2013

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

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE		04-3072771
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

Large accelerated filer x		Accelerated filer o

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

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

As of April 22, 2013, there were 210,750,374 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Part I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheet at March 31, 2013 and December 31, 2012	3

Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2013 and 2012	4

Condensed Consolidated Statement of Comprehensive Income for the Three Months Ended March 31, 2013 and 2012	5

Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2013 and 2012	6

Notes to the Condensed Consolidated Financial Statements	7

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	18

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3. Quantitative and Qualitative Disclosures about Market Risk	25

Item 4. Controls and Procedures	27

Part II. Other Information

Item 1. Legal Proceedings	27

Item 1A. Risk Factors	28

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 6. Exhibits	28

Signatures	29

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

	March 31,			December 31,
(In thousands, except share amounts)	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	20,457		$	30,736
Accounts receivable, net	172,661			172,419
Inventories	11,278			14,173
Deferred income taxes	29,095			—
Derivative instruments	4,215			50,824
Other current assets	1,174			2,158
Total current assets	238,880			270,310
Properties and equipment, net (Successful efforts method)	4,412,772			4,310,977
Other assets	36,184			35,026
	$	4,687,836		$	4,616,313

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	299,733		$	312,480
Current portion of long-term debt	75,000			75,000
Accrued liabilities	42,553			49,597
Income taxes payable	3,878			1,667
Deferred income taxes	—			5,203
Derivative instruments	26,100			192
Total current liabilities	447,264			444,139
Postretirement benefits	39,636			38,864
Long-term debt	1,052,000			1,012,000
Deferred income taxes	910,608			882,672
Asset retirement obligation	69,093			67,016
Derivative instruments	3,799			—
Other liabilities	42,222			40,175
Total liabilities	2,564,622			2,484,866

Commitments and contingencies

Stockholders’ equity
Common stock:
Authorized — 480,000,000 shares of $0.10 par value in 2013 and 2012, respectively
Issued—210,749,418 shares and 210,429,731 shares in 2013 and 2012, respectively	21,075			21,043
Additional paid-in capital	715,896			716,609
Retained earnings	1,411,887			1,373,264
Accumulated other comprehensive income / (loss)	(22,295		)	23,880
Less treasury stock, at cost:
404,400 shares in 2013 and 2012, respectively	(3,349		)	(3,349		)
Total stockholders’ equity	2,123,214			2,131,447
	$	4,687,836		$	4,616,313

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

	Three Months Ended
	March 31,
(In thousands, except per share amounts)	2013			2012

OPERATING REVENUES
Natural gas	$	293,793		$	206,782
Crude oil and condensate	65,655			49,981
Brokered natural gas	10,893			13,444
Other	2,944			1,929
	373,285			272,136
OPERATING EXPENSES
Direct operations	31,497			27,320
Transportation and gathering	46,221			30,258
Brokered natural gas cost	8,389			11,872
Taxes other than income	11,687			18,583
Exploration	4,024			4,001
Depreciation, depletion and amortization	148,653			110,357
General and administrative	35,704			22,549
	286,175			224,940
Gain / (loss) on sale of assets	(96		)	(535		)
INCOME FROM OPERATIONS	87,014			46,661
Interest expense and other	16,255			16,917
Income before income taxes	70,759			29,744
Income tax expense	27,935			11,426
NET INCOME	$	42,824		$	18,318

Earnings per share
Basic	$	0.20		$	0.09
Diluted	$	0.20		$	0.09

Weighted-average shares outstanding
Basic	210,150			209,128
Diluted	211,376			210,813

Dividends per common share	$	0.02		$	0.02

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

	Three Months Ended
	March 31,
(In thousands)	2013			2012

Net income	$	42,824		$	18,318

Other comprehensive income / (loss), net of taxes:
Reclassification adjustment for settled hedge contracts (1)	(9,325		)	(34,070		)
Changes in fair value of hedge contracts (2)	(36,975		)	43,205
Pension and postretirement benefits:
Amortization of prior service cost (3)	—			68
Amortization of net loss (4)	125			4,175
Total other comprehensive income / (loss)	(46,175		)	13,378
Comprehensive income / (loss)	$	(3,351	)	$	31,696

(1) Net of income taxes of $6,045 and $21,600 for the three months ended March 31, 2013 and 2012, respectively.

(2) Net of income taxes of $23,971 and $(27,523) for the three months ended March 31, 2013 and 2012, respectively.

(3) Net of income taxes of $0 and $(43) for the three months ended March 31, 2013 and 2012, respectively.

(4) Net of income taxes of $(80) and $(2,647) for the three months ended March 31, 2013 and 2012, respectively.

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Three Months Ended
	March 31,
(In thousands)	2013			2012

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	42,824		$	18,318
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	148,653			110,357
Deferred income tax expense	23,574			9,724
(Gain) / loss on sale of assets	96			535
Exploration expense	666			49
Unrealized (gain) / loss on derivative instruments	—			(42		)
Amortization of debt issuance costs	897			1,064
Stock-based compensation, pension and other	17,655			(1,470		)
Changes in assets and liabilities:
Accounts receivable, net	(243		)	19,261
Inventories	2,896			9,048
Other current assets	983			518
Accounts payable and accrued liabilities	(27,885		)	(38,149		)
Income taxes	4,349			2,187
Other assets and liabilities	358			380
Stock-based compensation tax benefit	(2,138		)	—
Net cash provided by operating activities	212,685			131,780

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(260,169		)	(188,547		)
Proceeds from sale of assets	486			1,280
Investment in equity method investment	(1,250		)	—
Net cash used in investing activities	(260,933		)	(187,267		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	135,000			90,000
Repayments of debt	(95,000		)	(28,000		)
Stock-based compensation tax benefit	2,138			—
Dividends paid	(4,201		)	(4,177		)
Other	32			81
Net cash provided by financing activities	37,969			57,904

Net (decrease) / increase in cash and cash equivalents	(10,279		)	2,417
Cash and cash equivalents, beginning of period	30,736			29,911
Cash and cash equivalents, end of period	$	20,457		$	32,328

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2012 (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, 2013 and for the three months ended March 31, 2013 and 2012, 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 26, 2013 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of the registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

Recent Accounting Pronouncements

Effective January 1, 2013, the Company adopted the amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This guidance impacted the disclosures associated with the Company’s commodity derivatives (Note 7) and did not impact its consolidated financial position, results of operations or cash flows.

Effective January 1, 2013, the Company adopted the amended disclosure requirements prescribed in ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This guidance impacted the Company’s disclosures associated with items reclassified from accumulated other comprehensive income / (loss) (Note 9) and did not impact its consolidated financial position, results of operations or cash flows.

2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

	March 31,			December 31,
(In thousands)	2013			2012

Proved oil and gas properties	$	5,969,544		$	5,724,940
Unproved oil and gas properties	463,455			467,483
Gathering and pipeline systems	239,791			239,656
Land, building and other equipment	88,484			86,137
	6,761,274			6,518,216
Accumulated depreciation, depletion and amortization	(2,348,502		)	(2,207,239		)
	$	4,412,772		$	4,310,977

At March 31, 2013, 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.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31,			December 31,
(In thousands)	2013			2012

Accounts receivable, net
Trade accounts	$	167,405		$	165,070
Joint interest accounts	4,826			5,659
Other accounts	1,555			2,817
	173,786			173,546
Allowance for doubtful accounts	(1,125		)	(1,127		)
	$	172,661		$	172,419
Inventories
Natural gas in storage	$	3,425		$	7,494
Tubular goods and well equipment	8,011			6,392
Other accounts	(158		)	287
	$	11,278		$	14,173
Other current assets
Prepaid balances and other	1,174			2,158
	$	1,174		$	2,158
Other assets
Deferred compensation plan	$	11,372		$	10,608
Debt issuance cost	16,523			17,420
Equity method investment	8,211			6,915
Other accounts	78			83
	$	36,184		$	35,026
Accounts payable
Trade accounts	$	11,006		$	14,037
Natural gas purchases	2,331			4,892
Royalty and other owners	71,028			66,321
Accrued capital costs	154,498			164,862
Taxes other than income	13,504			10,224
Drilling advances	40,607			44,203
Producer gas imbalances	1,628			1,602
Other accounts	5,131			6,339
	$	299,733		$	312,480
Accrued liabilities
Employee benefits	$	17,346		$	16,011
Postretirement benefits	1,304			1,304
Taxes other than income	8,959			8,735
Interest payable	12,650			22,329
Other accounts	2,294			1,218
	$	42,553		$	49,597
Other liabilities
Deferred compensation plan	$	29,429		$	23,893
Other accounts	12,793			16,282
	$	42,222		$	40,175

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4. DEBT AND CREDIT AGREEMENTS

The Company’s debt and credit agreements consisted of the following:

(In thousands)	March 31, 2013			December 31, 2012
Total 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	365,000			325,000
Current maturities
7.33% weighted-average fixed rate notes	(75,000		)	(75,000		)
Long-term debt, excluding current maturities	$	1,052,000		$	1,012,000

At March 31, 2013, the Company had $365.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.3% and $534.0 million available for future borrowings.

Effective April 17, 2013, the lenders under the Company’s revolving credit facility approved an increase in the Company’s borrowing base from $1.7 billion to $2.3 billion as part of the annual redetermination under the terms of the credit facility.

5. EARNINGS PER COMMON SHARE

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

	Three Months Ended
	March 31,
(In thousands)	2013	2012
Weighted-average shares - basic	210,150	209,128
Dilution effect of stock appreciation rights and stock awards at end of period	1,226	1,685
Weighted-average shares - diluted	211,376	210,813

Weighted-average stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	184	82

6. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. There have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 8 in the Notes to Consolidated Financial Statements included in the Form 10-K.

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Legal Matters

Preferential Purchase Right Litigation

In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit sought unspecified damages arising out of the Company’s 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleged breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court in February 2007. Plaintiff appealed the ruling to the Pennsylvania Superior Court, where the ruling in favor of the Company was reversed and remanded to the trial court in March 2008. The Company appealed the Superior Court ruling to the Pennsylvania Supreme Court, but in December 2008 that Court declined to review. Effective July 2008, Linn Energy, LLC sold the subject properties to XTO Energy, Inc., giving rise to a second lawsuit for unspecified damages filed in September 2009 by EXCO—North Coast Energy, Inc., as successor in interest to Power Gas Marketing & Transmission, Inc., against the Company, Linn Energy, LLC and XTO Energy, Inc. The second lawsuit was consolidated into the first lawsuit. In April 2013, the trial court ruled in the Company’s favor in both cases, holding that no preferential purchase right existed. The Company has been notified by the plaintiff that they will not appeal the trial court ruling.

Other

The Company is also a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows.

Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

Environmental Matters

Pennsylvania Department of Environmental Protection

On December 15, 2010, the Company entered into a consent order and settlement agreement (CO&SA) with the Pennsylvania Department of Environmental Protection (PaDEP), addressing a number of environmental issues originally identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of water supplies to 14 households in Susquehanna County, Pennsylvania. During 2010 and 2011, the Company paid a total of $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter. On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB). On October 17, 2011, the Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households pursuant to prior consent orders with the PaDEP. The PaDEP concurred that temporary water deliveries to the property owners are no longer necessary. On November 18, 2011, certain of the affected households appealed this order to the PEHB, which appeal was later consolidated with the CO&SA appeal. All appellants have accepted their portion of the $2.2 million that was placed into escrow in 2011 for their benefit and on October 18, 2012 had dismissed their appeal to the PEHB. Subsequent to the withdrawal of the appeals, the PEHB allowed three groups of appellants to reinstate their appeal. A hearing related to the reinstated appeal is expected to occur in the first half 2013.

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The Company is in continuing discussions with the PaDEP to address the results of the Company’s natural gas well test data, water quality sampling and water well headspace screenings, which were required pursuant to the CO&SA. On August 21, 2012, the PaDEP notified the Company that it could commence completion operations on existing wells within the concerned area.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations related to its 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, 2013, the Company had the following outstanding commodity derivatives:

Commodity and Derivative Type	Weighted-Average Contract Price	Volume	Contract Period
Derivatives Designated as Hedging Instruments
Natural gas collars	$3.09 Floor / $4.12 Ceiling per Mcf	26.7 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.35 Floor / $4.01 Ceiling per Mcf	26.7 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.40 Floor / $4.12 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.60 Floor / $3.99 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.60 Floor / $4.17 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.76 Floor / $4.16 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.86 Floor / $4.34 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.96 Floor / $4.41 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$5.15 Floor / $6.20 Ceiling per Mcf	13.4 Bcf	Apr. 2013 - Dec. 2013
Natural gas collars	$3.60 Floor / $4.58 Ceiling per Mcf	31.1 Bcf	Apr. 2013 - Dec. 2014
Natural gas collars	$3.96 Floor / $4.56 Ceiling per Mcf	31.1 Bcf	Apr. 2013 - Dec. 2014
Natural gas collars	$3.86 Floor / $4.66 Ceiling per Mcf	17.7 Bcf	Jan. 2014 - Dec. 2014
Natural gas collars	$4.12 Floor / $4.64 Ceiling per Mcf	35.5 Bcf	Jan. 2014 - Dec. 2014
Crude oil swaps	$101.90 per Bbl	825 Mbbl	Apr. 2013 - Dec. 2013

The changes in the fair value of derivatives designated as hedges that are effective are 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, if any, 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 in the Condensed Consolidated Statement of Operations.

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

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet

		Fair Values of Derivative Instruments
		Derivative Assets				Derivative Liabilities
(In thousands)		March 31, 2013		December 31, 2012		March 31, 2013		December 31, 2012
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments (current assets)	$	4,215	$	50,824	$	—	$	—
Commodity contracts	Derivative instruments (current liabilities)	—		—		26,100		192
Commodity contracts	Derivative instruments (non-current liabilities)	—		—		3,799		—
		$	4,215	$	50,824	$	29,899	$	192

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At March 31, 2013 and December 31, 2012, unrealized losses of $25.7 million ($15.6 million, net of tax) and unrealized gains of $50.6 million ($30.7 million, net of tax), respectively, were recorded in accumulated other comprehensive income / (loss) in stockholder’s equity in the Condensed Consolidated Balance Sheet. Based upon estimates at March 31, 2013, the Company expects to reclassify $13.3 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.

Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet

(In thousands)	March 31, 2013			December 31, 2012
Derivative Assets
Gross amounts of recognized assets	$	18,353		$	54,454
Gross amounts offset in the statement of financial position	(14,138		)	(3,630		)
Net amounts of assets presented in the statement of financial position	4,215			50,824
Gross amounts of financial instruments not offset in the statement of financial position	832			1,892
Net amount	$	5,047		$	52,716

Derivative Liabilities
Gross amounts of recognized liabilities	$	44,037		$	3,822
Gross amounts offset in the statement of financial position	(14,138		)	(3,630		)
Net amounts of liabilities presented in the statement of financial position	29,899			192
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	29,899		$	192

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

Derivatives Designated	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)					Location of Gain (Loss) Reclassified from Accumulated OCI into	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
as Hedging Instruments	Three Months Ended March 31,					Income	Three Months Ended March 31,
(In thousands)	2013			2012		(In thousands)	2013		2012
Commodity Contracts	$	(60,946	)	$	70,728	Natural gas revenues	$	13,328	$	56,996
						Crude oil and condensate revenues	2,042		(1,326		)
							$	15,370	$	55,670

For the three months ended March 31, 2013 and 2012, respectively, there was no ineffectiveness recorded in our Condensed Consolidated Statement of Operations related to our derivative instruments.

Derivatives Not Designated as	Location of Gain (Loss)	Three Months Ended
Hedging Instruments	Recognized in Income on	March 31,
(In thousands)	Derivatives	2013		2012
Commodity Contracts	Natural gas revenues	$	—	$	42

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 each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty.

Certain 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.

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8. FAIR VALUE MEASUREMENTS

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. The authoritative guidance also established a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values. For further information regarding the fair value hierarchy, refer to Note 14 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were impaired as of March 31, 2013 and 2012 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures are not provided.

The estimated fair value of the Company’s asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligation is deemed to use Level 3 inputs.

Financial Assets and Liabilities

The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis:

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		March 31, 2013
Assets
Deferred compensation plan	$	11,372	$	—	$	—	$	11,372
Derivative instruments	—		4,215		—		4,215
Total assets	$	11,372	$	4,215	$	—	$	15,587

Liabilities
Deferred compensation plan	$	29,429	$	—	$	—	$	29,429
Derivative instruments	—		—		29,899		29,899
Total liabilities	$	29,429	$	—	$	29,899	$	59,328

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		December 31, 2012
Assets
Deferred compensation plan	$	10,608	$	—	$	—	$	10,608
Derivative instruments	—		9,473		41,351		50,824
Total assets	$	10,608	$	9,473	$	41,351	$	61,432

Liabilities
Deferred compensation plan	$	23,893	$	—	$	—	$	23,893
Derivative instruments	—		—		192		192
Total liabilities	$	23,893	$	—	$	192	$	24,085

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

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

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

	Three Months Ended
	March 31,
(In thousands)	2013			2012
Balance at beginning of period	$	41,159		$	195,127
Total gains / (losses) (realized or unrealized):
Included in earnings (1)	13,328			57,038
Included in other comprehensive income	(71,058		)	22,692
Settlements	(13,328		)	(56,300		)
Transfers in and/or out of level 3	—			385
Balance at end of period	$	(29,899	)	$	218,942

(1) Unrealized gains of $42,000 for the three months ended March 31, 2012 were included in natural gas revenues in the Condensed Consolidated Statement of Operations. There were no unrealized gains or losses for the three months ended March 31, 2013.

Fair Value of Other Financial Instruments

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

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

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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, 2013						December 31, 2012
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Total debt	$	1,127,000		$	1,249,576		$	1,087,000		$	1,213,474
Current maturities	(75,000		)	(76,279		)	(75,000		)	(77,175		)
Long-term debt, excluding current maturities	$	1,052,000		$	1,173,297		$	1,012,000		$	1,136,299

9. ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

Changes in accumulated other comprehensive income / (loss) by component, net of tax, were as follows:

(In thousands)	Net Gains (Losses) on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	30,717		$	(6,837	)	$	23,880
Other comprehensive income before reclassifications	(36,975		)	—			(36,975		)
Amounts reclassified from accumulated other comprehensive income	(9,325		)	125			(9,200		)
New current-period other comprehensive income	(46,300		)	125			(46,175		)
Balance at March 31, 2013	$	(15,583	)	$	(6,712	)	$	(22,295	)

Amounts reclassified from accumulated other comprehensive income / (loss) into the Condensed Consolidated Statement of Operations were as follows:

(In thousands)	Three Months Ended March 31, 2013			Affected Line Item in the Statement Where Net Income is Presented
Net gains / (losses) on cash flow hedges
Commodity contracts	$	13,328		Natural gas revenues
Commodity contracts	2,042			Crude oil and condensate revenues

Postretirement benefits
Amortization of net loss	(205		)	General and administrative expense
	$	15,165		Total before tax
	$	(5,965	)	Tax (expense) / benefit
Total reclassifications for the period	$	9,200		Net of tax

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10. PENSION AND POSTRETIREMENT BENEFITS

The components of net periodic benefit costs, included in general and administrative expense in the Condensed Consolidated Statement of Operations, were as follows:

	Three Months Ended
	March 31,
(In thousands)	2013		2012
Qualified Pension Plan
Interest cost	$	—	$	461
Expected return on plan assets	—		(874		)
Amortization of prior service cost	—		111
Amortization of net loss	—		6,542
Net periodic pension cost	$	—	$	6,240

Postretirement Benefits
Service cost	$	415	$	523
Interest cost	395		418
Amortization of net loss	205		280
Total postretirement benefit cost	$	1,015	$	1,221

11. STOCK-BASED COMPENSATION

Stock-based compensation expense during the first three months of 2013 and 2012 was $18.7 million and $1.7 million, respectively, and is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

Restricted Stock Units

During the first three months of 2013, 22,560 restricted stock units were granted to non-employee directors of the Company with a grant date per unit value of $53.23. The fair value of these units is measured based on 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.

Performance Share Awards

During the first three months of 2013, three types of performance share awards were granted to employees for a total of 402,250 performance shares, which included 274,760 performance share awards based on performance conditions measured against the Company’s internal performance metrics and 127,490 performance share awards based on market conditions. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for all performance share awards. The performance period for the awards granted in 2013 commenced on January 1, 2013 and ends on December 31, 2015. 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.

Awards Based on Performance Conditions. The performance awards based on internal metrics had a grant date per share value of $53.23, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock. Of the 274,760 performance awards based on internal metrics, 84,990 shares have a three-year graded performance period. For these shares, 25% of the shares vest on each of the first and second anniversary dates following the date of the grant and 50% of the shares vest on the third anniversary date following the date of the 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 anniversary date will be forfeited.

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For the remaining 189,770 performance awards, the actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria are based on the Company’s average production, average finding costs and average reserve replacement over the three-year performance period.

Based on the Company’s probability assessment at March 31, 2013, it is considered probable that the criteria for the performance awards based on performance conditions will be met.

Awards Based on Market Conditions. The 127,490 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three-year performance period. These performance shares have both an equity and liability component. The equity portion of the 2013 awards was valued on the grant date (February 21, 2013) and was not marked to market. The liability portion of the awards was valued as of March 31, 2013 on a mark-to-market basis.

The following assumptions were used to determine the grant date fair value of the equity component and the period-end fair value of the liability component of the Company’s performance share awards based on market conditions using a Monte Carlo model:

	Grant Date		March 31, 2013
Value per Share	$46.12		$40.86 - $67.51
Assumptions:
Stock Price Volatility	43.8	%	33.0% - 46.1%
Risk Free Rate of Return	0.4	%	0.1% - 0.3%
Expected Dividend Yield	0.2	%	0.1%

Supplemental Employee Incentive Plan

On May 1, 2012, the Company’s Board of Directors adopted a new Supplemental Employee Incentive Plan (“Plan”) to replace the previously adopted supplemental employee incentive plan that expired on June 30, 2012. For further information regarding the terms of the Plan, refer to Note 12 of the Notes to the Consolidated Financial Statements in the Form 10-K. The Company recognized stock-based compensation expense of $3.4 million for the three months ended March 31, 2013 and a benefit of $1.7 million for the three months ended March 31, 2012, which is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

On February 11, 2013, the Company achieved the price goal of $50 per share prior to the interim trigger date. Accordingly, a total distribution of approximately $6.8 million was made to the Company’s eligible employees under the Plan, of which 25% of the total distribution, or $1.7 million, was paid in February 2013 and the remaining 75%, or $5.1 million, was deferred until August 2014 in accordance with the Plan.

12. ASSET RETIREMENT OBLIGATION

Activity related to the Company’s asset retirement obligation is as follows:

(In thousands)
Balance at December 31, 2012	$	67,016
Liabilities incurred	1,396
Liabilities settled	(195		)
Accretion expense	876
Balance at March 31, 2013	$	69,093

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of March 31, 2013, and the related condensed consolidated statements of operations and of comprehensive income for the three-month periods ended March 31, 2013 and 2012 and the condensed consolidated statement of cash flows for the three-month periods ended March 31, 2013 and 2012. 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, 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and of cash flows for the year then ended (not presented herein), and in our report dated February 28, 2013, 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, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

April 26, 2013

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

The following review of operations for the three month periods ended March 31, 2013 and 2012 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, 2012 (Form 10-K).

Overview

On an equivalent basis, our production for the three months ended March 31, 2013 increased by 50% compared to the three months ended March 31, 2012. For the three months ended March 31, 2013, we produced 89.3 Bcfe, or 992.3 Mmcfe per day, compared to 59.7 Bcfe, or 655.7 Mmcfe per day, for three months ended March 31, 2012. Natural gas production increased by 28.8 Bcf, or 51%, to 85.2 Bcf for the first three months of 2013 compared to 56.4 Bcf for the first three months of 2012. This increase was primarily the result of increased production in the Marcellus Shale associated with our drilling program and continued expansion of infrastructure in the area. This increase was partially offset by decreases in production in Texas, Oklahoma and West Virginia due to reduced natural gas drilling and normal production declines. Crude oil/condensate/NGL production increased by 153 Mbbls, or 28%, from 538 Mbbls in the first three months of 2012 to 691 Mbbls in the first three months of 2013. This increase was primarily the result of increased production resulting from our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for the first three months of 2013 was $3.45 per Mcf, 5% lower than the $3.65 per Mcf price realized in the first three months of 2012. Our average realized crude oil price for the first three months of 2013 was $104.03 per Bbl, 8% higher than the $96.67 per Bbl price realized in the first three months of 2012. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. 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.

During the first three months of 2013, we drilled 32 gross wells (25.9 net) with a success rate of 97% compared to 31 gross wells (23.4 net) with a success rate of 100% for the comparable period of the prior year. For the three months ended March 31, 2013, our total capital and exploration spending was $253.5 million compared to $192.1 million for the three months ended March 31, 2012. The increase in capital spending was primarily due to our Marcellus Shale horizontal drilling program in northeast Pennsylvania, the Eagle Ford and Pearsall Shale in south Texas and the Marmaton oil play in Oklahoma. For the full year 2013, we plan to drill approximately 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million and $1.0 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our credit facility. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the three months ended March 31, 2013 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments) and net borrowings under our credit facility. These cash flows were primarily used to fund our capital and exploration expenditures and payment of dividends. See below for additional discussion and analysis of cash flow.

Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been and continue to be volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of

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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. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

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

	Three Months Ended
	March 31,
(In thousands)	2013			2012
Cash flows provided by operating activities	$	212,685		$	131,780
Cash flows used in investing activities	(260,933		)	(187,267		)
Cash flows provided by financing activities	37,969			57,904
Net (decrease) / increase in cash and cash equivalents	$	(10,279	)	$	2,417

Operating Activities. Net cash provided by operating activities in the first three months of 2013 increased by $80.9 million over the first three months of 2012. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and unfavorable changes in working capital and long-term assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 50% for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Average realized crude oil prices increased by 8% while average realized natural gas prices decreased by 5% for the first three months of 2013 compared to the first three months of 2012.

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

Investing Activities. Cash flows used in investing activities increased by $73.7 million for the first three months of 2013 compared to the first three months of 2012. The increase was primarily due an increase of $71.6 million in capital expenditures and $1.3 million of capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution). This increase was partially offset by a decrease of $0.8 million in proceeds from sale of assets.

Financing Activities. Cash flows provided by financing activities decreased by $19.9 million for the first three months of 2013 compared to the first three months of 2012. This decrease was primarily due to $22.0 million of lower net borrowings ($67.0 million increase in repayments of debt offset by $45.0 million increase in borrowings), partially offset by an increase of $2.1 million in tax benefits associated with our stock-based compensation.

At March 31, 2013, we had $365.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.3% and $534.0 million available for future borrowings. Effective April 17, 2013, the lenders under our revolving credit facility approved an increase in our borrowing base from $1.7 billion to $2.3 billion as part of the annual redetermination under the terms of the revolving credit facility.

We were in compliance with all restrictive financial covenants in both the revolving credit facility and senior notes as of March 31, 2013.

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

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Capitalization

Information about our capitalization is as follows:

	March 31,		December 31,
(Dollars in thousands)	2013		2012

Debt (1)	$	1,127,000	$	1,087,000
Stockholders’ equity	2,123,214		2,131,447
Total capitalization	$	3,250,214	$	3,218,447

Debt to capitalization	35%		34%

Cash and cash equivalents	$	20,457	$	30,736

(1) Includes $75.0 million of current portion of long-term debt at March 31, 2013 and December 31, 2012 and $365.0 million and $325.0 million of borrowings outstanding under our revolving credit facility at March 31, 2013 and December 31, 2012, respectively.

During the three months ended March 31, 2013, we paid dividends of $4.2 million ($0.02 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

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

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

	Three Months Ended
	March 31,
(In thousands)	2013		2012
Capital expenditures
Drilling and facilities	$	233,143	$	173,368
Leasehold acquisitions	16,177		15,147
Pipeline and gathering	108		(428		)
	249,428		188,087
Exploration expense	4,024		4,001
Total	$	253,452	$	192,088

For the full year of 2013, we plan to drill approximately 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million to $1.0 billion in total planned capital and exploration expenditures. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 8 in the Notes to Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted 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.

Recent Accounting Pronouncements

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This guidance impacted the disclosures associated with our commodity derivatives and did not impact our consolidated financial position, results of operations or cash flows.

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This guidance impacted our disclosures associated with items reclassified from accumulated other comprehensive income / (loss) and did not impact our consolidated financial position, results of operations or cash flows.

Results of Operations

First Quarters of 2013 and 2012 Compared

We reported net income in the first quarter of 2013 of $42.8 million, or $0.20 per share, compared to $18.3 million, or $0.09 per share, in the first quarter of 2012. The increase in net income was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices and higher operating expenses.

Revenue, Price and Volume Variances

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

	Three Months Ended March 31,				Variance
Revenue Variances (In thousands)	2013		2012		Amount			Percent
Natural gas (1)	$	293,793	$	206,740	$	87,053		42%
Crude oil and condensate	65,655		49,981		15,674			31%
Brokered natural gas	10,893		13,444		(2,551		)	(19%	)
Other	2,944		1,929		1,015			53%

(1) Natural gas revenues exclude the unrealized gain of $42,000 from the change in fair value of our derivatives not designated as hedges in 2012. There were no unrealized gains or losses in 2013.

										Increase
	Three Months Ended March 31,				Variance					(Decrease)
	2013		2012		Amount			Percent		(In thousands)
Price Variances
Natural gas (1)	$	3.45	$	3.65	$	(0.20	)	(5%	)	$	(17,142	)
Crude oil and condensate (2)	$	104.03	$	96.67	$	7.36		8%		4,643
Total										$	(12,499	)
Volume Variances
Natural gas (Bcf)	85.2		56.4		28.8			51%		$	104,195
Crude oil and condensate (Mbbl)	631		517		114			22%		11,031
Total										$	115,226

(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $0.16 per Mcf in 2013 and by $1.00 per Mcf in 2012.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $3.24 per Bbl in 2013 and decreased the price by $2.57 per Bbl in 2012.

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Natural Gas Revenues

The increase in natural gas revenues of $87.1 million, excluding the impact of the unrealized losses discussed above, is primarily due to increased production partially offset by lower realized natural gas prices. The increased production was primarily a result of higher production in the Marcellus Shale associated with our drilling program and expanded infrastructure, partially offset by decreases in production primarily in Texas, Oklahoma and West Virginia due reduced natural gas drilling and normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $15.7 million is primarily due to increased production associated with our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma, coupled with higher realized oil prices.

Brokered Natural Gas Revenue and Cost

										Price and
	Three Months Ended									Volume
	March 31,				Variance					Variances
	2013		2012		Amount			Percent		(In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	3.55	$	4.06	$	(0.51	)	(13%	)	$	(1,560	)
Volume brokered (Mmcf)	x	3,067	x	3,311	(244		)	(7%	)	(991		)
Brokered natural gas (In thousands)	$	10,893	$	13,444						$	(2,551	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.74	$	3.59	$	(0.85		(24%	)	$	2,608
Volume brokered (Mmcf)	x	3,067	x	3,311	(244			(7%	)	875
Brokered natural gas (In thousands)	$	8,389	$	11,872						$	3,483

Brokered natural gas margin (In thousands)	$	2,504	$	1,572						$	932

The increased brokered natural gas margin of $0.9 million is primarily a result a decrease in purchase price that outpaced the decrease in sales price, partially offset by lower brokered volumes.

Impact of Derivative Instruments on Operating Revenues

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

	Three Months Ended March 31,
(In thousands)	2013		2012

Cash Flow Hedges
Natural gas	$	13,328	$	56,996
Crude oil	2,042		(1,326		)
Other Derivative Financial Instruments
Natural gas basis swaps	—		42
	$	15,370	$	55,712

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Operating and Other Expenses

	Three Months Ended March 31,				Variance
(In thousands)	2013		2012		Amount			Percent
Operating and Other Expenses
Direct operations	$	31,497	$	27,320	$	4,177		15%
Transportation and gathering	46,221		30,258		15,963			53%
Brokered natural gas	8,389		11,872		(3,483		)	(29%	)
Taxes other than income	11,687		18,583		(6,896		)	(37%	)
Exploration	4,024		4,001		23			1%
Depreciation, depletion and amortization	148,653		110,357		38,296			35%
General and administrative	35,704		22,549		13,155			58%
Total operating expense	$	286,175	$	224,940	$	61,235		27%

(Gain) / loss on sale of assets	$	96	$	535	$	(439	)	(82%	)
Interest expense and other	16,255		16,917		(662		)	(4%	)
Income tax expense	27,935		11,426		16,509			144%

Total costs and expenses from operations increased by $61.2 million, or 27%, in the first quarter of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

· Direct operations increased $4.2 million largely due to higher operating costs primarily driven by increased production. Contributing to the increase are higher employee related costs, partially offset by decreased workover activity.

· Transportation and gathering increased $16.0 million due to higher throughput due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering agreements throughout 2012 primarily in northeast Pennsylvania and south Texas.

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

· Taxes other than income decreased $6.9 million primarily due to lower impact fees associated with our Marcellus Shale production. The first quarter of 2012 included the initial assessment of impact fees associated with 2011 and prior period wells.

· Depreciation, depletion and amortization increased $38.3 million, of which $49.9 million was due to higher equivalent production volumes for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012, partially offset by a decrease of $10.7 million due to a lower DD&A rate of $1.56 per Mcfe for the quarter ended March 31, 2013 compared to $1.68 Mfce for the quarter ended March 31, 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs. The increase in depreciation and depletion was partially offset by a decrease in amortization of unproved properties of $1.1 million.

· General and administrative increased $13.2 million primarily due to $17.0 million of higher stock-based compensation expense associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price for the first quarter 2013 compared to the first quarter of 2012, partially offset by $6.2 million of lower pension expense associated with the liquidation of our pension plan that occurred in the second quarter of 2012.

Interest Expense and Other

Interest expense and other decreased $0.7 million primarily due a to lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.3% during the first quarter of 2013 compared to approximately 4.0% during the first quarter of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based

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on daily balances of approximately $361.6 million during the first quarter of 2013 compared to approximately $235.4 million during the first quarter of 2012.

Income Tax Expense

Income tax expense increased $16.5 million primarily due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first quarter of 2013 and 2012 was 39.5% and 38.4%, respectively. The increase in the effective rate in 2013 was due to an increase in estimated state tax liabilities.

Forward-Looking Information

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A of the Form 10-K for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

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

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in 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 13 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our hedging arrangements.

Periodically, we enter into commodity derivative instruments, including collar and swap agreements, to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under 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. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

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As of March 31, 2013, we had the following outstanding commodity derivatives:

Commodity and Derivative Type

Weighted-Average Contract Price

Volume

Contract Period

Net Unrealized
Gain / (Loss)
(In thousands)

Natural gas collars

$3.09 Floor / $4.12 Ceiling

per Mcf

26.7

Bcf

Apr. 2013 - Dec. 2013

(8,177

)

Natural gas collars

$3.35 Floor / $4.01 Ceiling

per Mcf

26.7

Bcf

Apr. 2013 - Dec. 2013

(9,453

)

Natural gas collars

$3.40 Floor / $4.12 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(3,826

)

Natural gas collars

$3.60 Floor / $3.99 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(4,597

)

Natural gas collars

$3.60 Floor / $4.17 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(3,189

)

Natural gas collars

$3.76 Floor / $4.16 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(2,246

)

Natural gas collars

$3.86 Floor / $4.34 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(996

)

Natural gas collars

$3.96 Floor / $4.41 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

(904

)

Natural gas collars

$5.15 Floor / $6.20 Ceiling

per Mcf

13.4

Bcf

Apr. 2013 - Dec. 2013

13,370

Natural gas collars

$3.60 Floor / $4.58 Ceiling

per Mcf

31.1

Bcf

Apr. 2013 - Dec. 2014

(5,391

)

Natural gas collars

$3.96 Floor / $4.56 Ceiling

per Mcf

31.1

Bcf

Apr. 2013 - Dec. 2014

(2,324

)

Natural gas collars

$3.86 Floor / $4.66 Ceiling

per Mcf

17.7

Bcf

Jan. 2014 - Dec. 2014

(2,071

)

Natural gas collars

$4.12 Floor / $4.64 Ceiling

per Mcf

35.5

Bcf

Jan. 2014 - Dec. 2014

(468

)

Crude oil swaps

$101.90

per Bbl

825

Mbbl

Apr. 2013 - Dec. 2013

4,218

(26,054

)

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized gain position at March 31, 2013 and exclude the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our nonperformance risk is evaluated using a market credit spread provided by one of our banks.

During the first three months of 2013, crude oil swaps covered 270 Mbbl, or 43% of crude oil production at an average price of $101.90 per Bbl. Natural gas collars with a floor prices ranging from $3.09 to $5.15 per Mcf and ceiling prices ranging from $3.98 to $6.23 per Mcf covered 43.7 Bcf, or 51%, of our natural gas production at an average price of $3.72 per Mcf.

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 nonperformance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to nonperformance by third parties. Our derivative contract counterparties are Bank of America, Bank of Montreal, Goldman Sachs, JPMorgan Chase, and Morgan Stanley.

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

Fair Market Value of Financial Instruments

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

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

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

	March 31, 2013						December 31, 2012
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Total debt	$	1,127,000		$	1,249,576		$	1,087,000		$	1,213,474
Current maturities	(75,000		)	(76,279		)	(75,000		)	(77,175		)
Long-term debt, excluding current maturities	$	1,052,000		$	1,173,297		$	1,012,000		$	1,136,299

ITEM 4. Controls and Procedures

As of the end of the current reported period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our 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 our disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

There were no changes in our internal control over financial reporting that occurred during the first quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

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

Environmental Matters

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

From time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. 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, they may result in monetary sanctions individually or in the aggregate in excess of $100,000.

On June 27, 2012, we received a letter from the United States Army Corps of Engineers (USACE) regarding regulatory deficiencies associated with our construction of 60,000 linear feet of a natural gas pipeline in Susquehanna County, Pennsylvania in 2008. The Pennsylvania Department of Environmental Protection (PaDEP) also investigated this matter concurrently with the USACE’s investigation. The subject pipeline was sold to a third party in 2010. We and the third-party buyer have fully cooperated with both agencies’ investigations into whether construction of certain sections of the pipeline was in compliance with the Clean Water Act. This matter has been substantially resolved with both agencies and all environmental impacts have either been permitted or are in the process of being remediated with minimal expense to us.

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ITEM 1A. Risk Factors

For additional information about the risk factors that affect us, see Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2012.

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

Issuer Purchases of Equity Securities

The Board of Directors has authorized a share repurchase program under which we may purchase shares of our common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During the three months ended March 31, 2013, we did not repurchase any shares of our common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may be purchased under the plan as of March 31, 2013 was 9,590,600.

ITEM 6. Exhibits

Exhibit Number		Description

15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

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

32.1		906 Certification

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

	CABOT OIL & GAS CORPORATION
	(Registrant)

April 26, 2013	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

April 26, 2013	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

April 26, 2013	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)