Coterra Energy Inc. - Quarter Report: 2013 September (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 September 30, 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 October 21, 2013, there were 421,959,520 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 September 30, 2013 and December 31, 2012		3

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2013 and 2012		4

Condensed Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012		5

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 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		20

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

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31

Item 4.	Controls and Procedures	32

Part II. Other Information

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 6.	Exhibits	33

Signatures		34

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

	September 30,			December 31,
(In thousands, except share amounts)	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	27,932		$	30,736
Accounts receivable, net	178,479			172,419
Income taxes receivable	1,972			—
Inventories	20,839			14,173
Derivative instruments	56,831			50,824
Other current assets	3,703			2,158
Total current assets	289,756			270,310
Properties and equipment, net (Successful efforts method)	4,690,176			4,310,977
Derivative instruments	8,708			—
Other assets	42,752			35,026
	$	5,031,392		$	4,616,313

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	335,349		$	312,480
Current portion of long-term debt	—			75,000
Accrued liabilities	59,234			49,789
Income taxes payable	—			1,667
Deferred income taxes	4,690			5,203
Total current liabilities	399,273			444,139
Postretirement benefits	41,041			38,864
Long-term debt	1,162,000			1,012,000
Deferred income taxes	986,943			882,672
Asset retirement obligation	70,525			67,016
Other liabilities	42,876			40,175
Total liabilities	2,702,658			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—421,959,520 shares and 420,859,462 shares in 2013 and 2012, respectively	42,196			42,086
Additional paid-in capital	698,383			695,566
Retained earnings	1,558,260			1,373,264
Accumulated other comprehensive income / (loss)	33,244			23,880
Less treasury stock, at cost:
808,800 shares in 2013 and 2012, respectively	(3,349		)	(3,349		)
Total stockholders’ equity	2,328,734			2,131,447
	$	5,031,392		$	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					Nine Months Ended
	September 30,					September 30,
(In thousands, except per share amounts)	2013		2012			2013		2012

OPERATING REVENUES
Natural gas	$	341,901	$	231,896		$	1,004,085	$	639,729
Crude oil and condensate	84,209		57,870			220,090		165,317
Brokered natural gas	7,165		5,238			26,302		23,831
Other	2,575		1,870			8,338		5,790
	435,850		296,874			1,258,815		834,667
OPERATING EXPENSES
Direct operations	32,923		28,269			101,398		84,895
Transportation and gathering	60,803		34,430			159,672		97,827
Brokered natural gas cost	5,913		4,258			21,006		20,380
Taxes other than income	11,532		10,436			34,583		39,873
Exploration	3,891		9,303			12,444		29,548
Depreciation, depletion and amortization	168,980		110,448			469,022		335,421
General and administrative	24,697		23,829			82,009		93,249
	308,739		220,973			880,134		701,193
Gain / (loss) on sale of assets	4,421		(126		)	4,601		67,042
INCOME FROM OPERATIONS	131,532		75,775			383,282		200,516
Interest expense and other	15,796		16,219			48,752		51,631
Income before income taxes	115,736		59,556			334,530		148,885
Income tax expense	45,847		22,948			132,703		58,021
NET INCOME	$	69,889	$	36,608		$	201,827	$	90,864

Earnings per share
Basic	$	0.17	$	0.09		$	0.48	$	0.22
Diluted	$	0.17	$	0.09		$	0.48	$	0.22

Weighted-average shares outstanding
Basic	420,986		419,312			420,664		418,866
Diluted	423,453		422,452			422,824		421,994

Dividends per common share	$	0.02	$	0.01		$	0.04	$	0.03

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						Nine Months Ended
	September 30,						September 30,
(In thousands)	2013			2012			2013			2012

Net income	$	69,889		$	36,608		$	201,827		$	90,864

Other comprehensive income / (loss), net of taxes:
Reclassification adjustment for settled hedge contracts (1)	(11,942		)	(37,294		)	(22,372		)	(115,943		)
Changes in fair value of hedge contracts (2)	(1,447		)	(24,361		)	31,417			30,091
Pension and postretirement benefits:
Amortization of prior service cost (3)	—			—			—			135
Amortization of net loss (4)	70			79			319			8,428
Total other comprehensive income / (loss)	(13,319		)	(61,576		)	9,364			(77,289		)
Comprehensive income / (loss)	$	56,570		$	(24,968	)	$	211,191		$	13,575

(1) Net of income taxes of $7,742 and $23,644 for the three months ended September 30, 2013 and 2012, respectively, and $14,504 and $73,507 for the nine months ended September 30, 2013 and 2012, respectively.

(2) Net of income taxes of $937 and $15,444 for the three months ended September 30, 2013 and 2012, respectively, and $(20,366) and $(19,208) for the nine months ended September 30, 2013 and 2012, respectively.

(3) Net of income taxes of $0 and $0 for the three months ended September 30, 2013 and 2012, respectively, and $0 and $(86) for the nine months ended September 30, 2013 and 2012, respectively.

(4) Net of income taxes of $(46) and $(53) for the three months ended September 30, 2013 and 2012, respectively, and $(206) and $(5,347) for the nine months ended September 30, 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)

	Nine Months Ended
	September 30,
(In thousands)	2013			2012

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	201,827		$	90,864
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	469,022			335,421
Deferred income tax expense	107,235			42,714
(Gain) / loss on sale of assets	(4,601		)	(67,042		)
Exploration expense	807			12,118
Unrealized (gain) / loss on derivative instruments	—			449
Amortization of debt issuance costs	2,767			4,300
Stock-based compensation, pension and other	36,684			37,518
Changes in assets and liabilities:
Accounts receivable, net	(6,321		)	10,747
Inventories	(6,665		)	3,582
Other current assets	(1,547		)	(1,125		)
Accounts payable and accrued liabilities	(19,837		)	(16,391		)
Income taxes	(3,639		)	205
Other assets and liabilities	228			1,752
Stock-based compensation tax benefit	(9,284		)	—
Net cash provided by operating activities	766,676			455,112

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(843,528		)	(669,198		)
Proceeds from sale of assets	15,174			132,740
Investment in equity method investment	(8,624		)	(4,488		)
Net cash used in investing activities	(836,978		)	(540,946		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	585,000			280,000
Repayments of debt	(510,000		)	(168,000		)
Stock-based compensation tax benefit	9,284			—
Dividends paid	(16,830		)	(12,561		)
Capitalized debt issuance costs	—			(5,005		)
Other	44			(1,010		)
Net cash provided by financing activities	67,498			93,424

Net (decrease) / increase in cash and cash equivalents	(2,804		)	7,590
Cash and cash equivalents, beginning of period	30,736			29,911
Cash and cash equivalents, end of period	$	27,932		$	37,501

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.

On July 23, 2013, the Board of Directors declared a 2-for-1 stock split of the Company’s common stock in the form of a stock dividend. The stock dividend was distributed on August 14, 2013 to shareholders of record on August 6, 2013. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock.

With respect to the unaudited financial information of the Company as of September 30, 2013 and for the three and nine months ended September 30, 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 October 25, 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 a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

Recent Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” The amendments in this update clarify the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company does not expect this guidance to have a material impact on 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. 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.

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2. PROPERTIES AND EQUIPMENT, NET

Properties and equipment, net are comprised of the following:

	September 30,			December 31,
(In thousands)	2013			2012

Proved oil and gas properties	$	6,522,753		$	5,724,940
Unproved oil and gas properties	444,353			467,483
Gathering and pipeline systems	240,285			239,656
Land, building and other equipment	92,740			86,137
	7,300,131			6,518,216
Accumulated depreciation, depletion and amortization	(2,609,955		)	(2,207,239		)
	$	4,690,176		$	4,310,977

At September 30, 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.

Divestitures

In June 2012, the Company sold a 35% non-operated working interest associated with certain of its Pearsall Shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka Gas Co., Ltd. (Osaka) for total consideration of approximately $251.0 million. The Company received $125.0 million in cash proceeds and Osaka agreed to fund 85% of the Company’s share of future drilling and completion costs associated with these leaseholds until it has paid approximately $126.0 million in accordance with a joint development agreement entered into at the closing. The Company recognized a $67.0 million gain on sale of assets associated with this sale. The drilling and completion carry under the joint development agreement will terminate two years after the closing of the transaction; however, based on the Company’s current drilling and completion activities in the Pearsall Shale, the Company expects that the carry will be fully satisfied in the fourth quarter of 2013.

Subsequent Event

In October 2013, the Company entered into purchase and sale agreements to sell certain proved and unproved oil and gas properties located in the Oklahoma and Texas panhandles for approximately $160.0 million and west Texas for approximately $28.0 million. These transactions are expected to close in the fourth quarter 2013, subject to customary closing conditions and adjustments.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	September 30,			December 31,
(In thousands)	2013			2012

Accounts receivable, net
Trade accounts	$	173,096		$	165,070
Joint interest accounts	5,452			5,659
Other accounts	1,612			2,817
	180,160			173,546
Allowance for doubtful accounts	(1,681		)	(1,127		)
	$	178,479		$	172,419
Inventories
Natural gas in storage	$	11,732		$	7,494
Tubular goods and well equipment	9,136			6,392
Other accounts	(29		)	287
	$	20,839		$	14,173
Other current assets
Prepaid balances and other	3,703			2,158
	$	3,703		$	2,158
Other assets
Deferred compensation plan	$	11,865		$	10,608
Debt issuance cost	14,652			17,420
Equity method investment	16,154			6,915
Other accounts	81			83
	$	42,752		$	35,026
Accounts payable
Trade accounts	$	24,295		$	5,097
Natural gas purchases	6,389			4,892
Royalty and other owners	75,896			66,321
Accrued capital costs	175,828			164,862
Taxes other than income	10,479			19,164
Drilling advances	35,686			44,203
Producer gas imbalances	1,381			1,602
Other accounts	5,395			6,339
	$	335,349		$	312,480
Accrued liabilities
Employee benefits	$	32,870		$	16,011
Postretirement benefits	1,304			1,304
Taxes other than income	10,576			8,735
Interest payable	11,560			22,329
Other accounts	2,924			1,410
	$	59,234		$	49,789
Other liabilities
Deferred compensation plan	$	31,800		$	23,893
Other accounts	11,076			16,282
	$	42,876		$	40,175

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4. DEBT AND CREDIT AGREEMENTS

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

(In thousands)	September 30, 2013		December 31, 2012
Total debt
7.33% weighted-average fixed rate notes	$	20,000	$	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	475,000		325,000
Current maturities
7.33% weighted-average fixed rate notes	—		(75,000		)
Long-term debt, excluding current maturities	$	1,162,000	$	1,012,000

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. The Company’s commitments under the credit facility of $900.0 million remained unchanged. At September 30, 2013, the Company had $475.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.4% and $424.0 million available for future borrowings.

5. EARNINGS PER COMMON SHARE

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(In thousands)	2013	2012	2013	2012
Weighted-average shares - basic	420,986	419,312	420,664	418,866
Dilution effect of stock appreciation rights and stock awards at end of period	2,467	3,140	2,160	3,128
Weighted-average shares - diluted	423,453	422,452	422,824	421,994

Weighted-average shares excluded from diluted earnings per share due to the anti-dilutive effect	1	92	3	204

6. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. Except for certain new and amended transportation agreements and two new drilling rig commitments described below, there have been no material changes to the Company’s 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.

Transportation Agreements

During the first nine months of 2013, the Company entered into or amended certain natural gas transportation agreements associated with the Company’s production in Pennsylvania. These agreements increased the Company’s future aggregate obligations under its transportation commitments by approximately $49.4 million compared to those amounts in disclosed in Note 8 in the Notes to Consolidated Financial Statements included in the Form 10-K.

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Drilling Rig Commitments

During the first nine months of 2013, the Company entered into two drilling rig commitments for its capital program in the Marcellus Shale. One agreement commenced in the third quarter of 2013 with an initial term of two years and the other agreement is expected to commence in the fourth quarter of 2013 with an initial term of three years. The future minimum commitments under all of the Company’s drilling rig commitments as of September 30, 2013 are approximately $3.4 million in 2013, $14.9 million in 2014, $6.8 million in 2015 and $4.4 million in 2016.

Legal Matters

The Company is a defendant in various legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on its 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. It is expected that the PEHB will hold a hearing with respect to the appellants’ appeal in the first quarter of 2014.

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 where such derivatives do not subject 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.

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As of September 30, 2013, the Company had the following outstanding commodity derivatives:

				Collars							Swaps
				Floor				Ceiling
Type of Contract	Volume		Contract Period	Range		Weighted- Average		Range	Weighted- Average		Weighted- Average
Collar Agreements
Natural gas	4.5	Bcf	Oct. 2013 - Dec. 2013	$	—	$	5.15	$6.18-$6.23	$	6.20
Natural gas	54.5	Bcf	Oct. 2013 - Dec. 2013	$3.09-$4.37		$	3.63	$3.98-$5.02	$	4.27
Natural gas	44.4	Bcf	Oct. 2013 - Dec. 2014	$3.60-$3.96		$	3.78	$4.55-$4.59	$	4.57
Natural gas	124.1	Bcf	Jan. 2014 - Dec. 2014	$3.86-$4.37		$	4.19	$4.63-$4.80	$	4.70

Swap Agreements
Crude oil	276	Mbbl	Oct. 2013 - Dec. 2013								$	101.90

Natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

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)	Balance Sheet Location	September 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments (current assets)	$	56,831	$	50,824	$	—	$	—
Commodity contracts	Derivative instruments (non-current assets)	8,708		—		—		—
Commodity contracts	Accrued Liabilities	—		—		—		192
		$	65,539	$	50,824	$	—	$	192

At September 30, 2013 and December 31, 2012, unrealized gains of $65.5 million ($39.8 million, net of tax) and $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 September 30, 2013, the Company expects to reclassify $34.5 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.

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

(In thousands)	September 30, 2013			December 31, 2012
Derivative Assets
Gross amounts of recognized assets	$	66,473		$	54,454
Gross amounts offset in the statement of financial position	(934		)	(3,630		)
Net amounts of assets presented in the statement of financial position	65,539			50,824
Gross amounts of financial instruments not offset in the statement of financial position	—			1,892
Net amount	$	65,539		$	52,716

Derivative Liabilities
Gross amounts of recognized liabilities	$	934		$	3,822
Gross amounts offset in the statement of financial position	(934		)	(3,630		)
Net amounts of liabilities presented in the statement of financial position	—			192
Gross amounts of financial instruments not offset in the statement of financial position	390			—
Net amount	$	390		$	192

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

Derivatives Designated as Hedging Instruments

	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2013			2012			2013		2012
Commodity Contracts	$	(2,384	)	$	(39,805	)	$	51,783	$	49,299

	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Location of Gain (Loss) Reclassified	Three Months Ended September 30,					Nine Months Ended September 30,
from Accumulated OCI into Income	2013			2012		2013		2012
Natural gas revenues	$	20,766		$	57,139	$	33,822	$	183,867
Crude oil and condensate revenues	(1,082		)	3,799		3,054		5,583
	$	19,684		$	60,938	$	36,876	$	189,450

For the three and nine months ended September 30, 2013 and 2012, respectively, there was no ineffectiveness recorded in the Company’s Condensed Consolidated Statement of Operations related to its derivative instruments designated as hedges.

Derivatives Not Designated as Hedging Instruments

	Location of Gain (Loss) Recognized in Income on	Three Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	Derivatives	2013		2012			2013		2012
Commodity Contracts	Natural gas revenues	$	—	$	(149	)	$	—	$	(449	)

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.

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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 liabilities in certain situations.

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 September 30, 2013 and 2012 and no other assets or liabilities were required to be measured at fair value on a non-recurring basis, additional disclosures were 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)		September 30, 2013
Assets
Deferred compensation plan	$	11,865	$	—	$	—	$	11,865
Derivative instruments	—		93		65,446		65,539
Total assets	$	11,865	$	93	$	65,446	$	77,404

Liabilities
Deferred compensation plan	$	31,800	$	—	$	—	$	31,800
Total liabilities	$	31,800	$	—	$	—	$	31,800

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(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		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

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. Estimates are verified using relevant NYMEX futures contracts and/or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative transactions, while non-performance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In thousands)	2013			2012			2013			2012
Balance at beginning of period	$	83,878		$	129,213		$	41,159		$	195,127
Total gains / (losses) (realized or unrealized):
Included in earnings (1)	20,766			56,990			33,822			183,418
Included in other comprehensive income	(18,432		)	(85,466		)	24,287			(153,008		)
Settlements	(20,766		)	(55,915		)	(33,822		)	(181,100		)
Transfers in and/or out of level 3	—			—			—			385
Balance at end of period	$	65,446		$	44,822		$	65,446		$	44,822

(1) There were no unrealized gains or losses for the three and nine months ended September 30, 2013. Unrealized losses of $0.1 million and $0.4 million for the three and nine months ended September 30, 2012, respectively, were included in natural gas revenues in the Condensed Consolidated Statement of Operations.

There were no transfers between Level 1 and Level 2 measurements for the three and nine months ended September 30, 2013 and 2012.

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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.

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

	September 30, 2013				December 31, 2012
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value
Total debt	$	1,162,000	$	1,258,627	$	1,087,000		$	1,213,474
Current maturities	—		—		(75,000		)	(77,175		)
Long-term debt, excluding current maturities	$	1,162,000	$	1,258,627	$	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	31,417			—			31,417
Amounts reclassified from accumulated other comprehensive income	(22,372		)	319			(22,053		)
Net current-period other comprehensive income	9,045			319			9,364
Balance at September 30, 2013	$	39,762		$	(6,518	)	$	33,244

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

(In thousands)	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013			Affected Line Item in the Condensed Consolidated Statement of Operations
Net gains / (losses) on cash flow hedges
Commodity contracts	$	20,766		$	33,822		Natural gas revenues
Commodity contracts	(1,082		)	3,054			Crude oil and condensate revenues

Postretirement benefits
Amortization of net loss	(116		)	(525		)	General and administrative expense
	19,568			36,351			Total before tax
	(7,696		)	(14,298		)	Tax (expense) / benefit
Total reclassifications for the period	$	11,872		$	22,053		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				Nine Months Ended
	September 30,				September 30,
(In thousands)	2013		2012		2013		2012
Qualified Pension Plan (1)
Interest cost	$	—	$	—	$	—	$	922
Expected return on plan assets	—		—		—		(1,748		)
Settlement	—		—		—		7,111
Amortization of prior service cost	—		—		—		221
Amortization of net loss	—		—		—		13,083
Net periodic pension cost	$	—	$	—	$	—	$	19,589

Postretirement Benefits
Service cost	$	455	$	234	$	1,285	$	1,280
Interest cost	355		351		1,145		1,187
Amortization of net loss	116		132		525		692
Total postretirement benefit cost	$	926	$	717	$	2,955	$	3,159

(1) On July 13, 2012, the Company made a final distribution of benefits from the qualified pension plan.

11. STOCK-BASED COMPENSATION

Stock-based compensation expense during the first nine months of 2013 and 2012 was $41.0 million and $23.4 million, respectively, and is included in general and administrative expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the third quarter of 2013 and 2012 was $12.2 million and $10.4 million, respectively.

Restricted Stock Awards

During the first nine months of 2013, 5,700 restricted stock awards were granted to employees with a weighted-average grant date per share value of $35.56. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate assumption of 6.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first nine months of 2013, 49,042 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $27.19. 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 nine months of 2013, three types of performance share awards were granted to employees for a total of 804,500 performance shares, which included 549,520 performance share awards based on performance conditions measured against the Company’s internal performance metrics and 254,980 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 its 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 $26.62, 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 549,520 performance awards granted based on internal metrics, 169,980 shares have a three-year graded performance period. For these shares, 25% of the shares vest on each of the first and second

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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.

For the remaining 379,540 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 September 30, 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 254,980 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against fifteen 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 is not marked to market. The liability portion of the awards was valued as of September 30, 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		September 30, 2013
Value per Share	$	23.06	$22.17 - $36.98
Assumptions:
Stock Price Volatility	43.8%		26.2% - 42.8%
Risk Free Rate of Return	0.4%		0.0% - 0.4%
Expected Dividend Yield	0.2%		0.1%

Supplemental Employee Incentive Plan

On May 1, 2012, the Company’s Board of Directors adopted the Supplemental Employee Incentive Plan III (SEIP III) to replace the previously adopted Supplemental Employee Incentive Plan II that expired on June 30, 2012. For further information regarding the terms of the SEIP III, 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 $4.1 million and $1.6 million for the three months ended September 30, 2013 and 2012 and $9.2 million and a benefit of $0.1 million for the nine months ended September 30, 2013 and 2012, respectively, 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 $25 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 SEIP III, 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 SEIP III.

On August 27, 2013, the Company achieved the price goal of $37.50 per share prior to the final trigger date. Accordingly, a total distribution of approximately $11.1 million was made to the Company’s eligible employees under the SEIP III, of which 25% of the total distribution, or $2.8 million, was paid in September 2013 and the remaining 75%, or $8.3 million, was deferred until August 2014 in accordance with the SEIP III.

On September 19, 2013, the Company’s Board of Directors adopted the Supplemental Employee Incentive Plan IV (SEIP IV) to replace the SEIP III with an effective date of October 1, 2013. The SEIP IV provides for a payout if, for any 20 trading days out of any 60 consecutive trading days, the closing price per share of the Company’s common stock equals or exceeds the price goal of $55 per share by September 30, 2015 (interim trigger date) or $80 per share by September 30, 2017 (final trigger date). The remaining provisions of the SEIP IV are consistent with the provisions of the SEIP III as disclosed in Note 12 of the Notes to the Consolidated Financial Statements in the Form 10-K.

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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	3,945
Liabilities settled	(800		)
Liabilities divested	(341		)
Accretion expense	2,705
Balance at September 30, 2013	$	72,525

As of September 30, 2013, approximately $2.0 million, which represents the current portion of the Company’s asset retirement obligation, is included in accrued liabilities in the Condensed Consolidated Balance Sheet.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of September 30, 2013, and the related condensed consolidated statements of operations and of comprehensive income for the three and nine month periods ended September 30, 2013 and 2012 and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 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

October 25, 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 and nine month periods ended September 30, 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).

On July 23, 2013, the Board of Directors declared a 2-for-1 stock split of our common stock in the form of a stock dividend. The stock dividend was distributed on August 14, 2013 to shareholders of record on August 6, 2013. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of our common stock.

Overview

On an equivalent basis, our production for the nine months ended September 30, 2013 increased by 54% compared to the nine months ended September 30, 2012. For the nine months ended September 30, 2013, we produced 291.7 Bcfe, or 1,068.3 Mmcfe per day, compared to 188.9 Bcfe, or 689.5 Mmcfe per day, for the nine months ended September 30, 2012. Natural gas production increased by 99.1 Bcf, or 56%, to 277.5 Bcf for the first nine months of 2013 compared to 178.4 Bcf for the first nine months of 2012. This increase was the result of higher 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 592 Mbbls, or 34%, from 1,760 Mbbls in the first nine months of 2012 to 2,352 Mbbls in the first nine months of 2013. This increase was the result of higher production resulting from our oil-focused drilling program in south Texas and, to a lesser extent, 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 nine months of 2013 was $3.62 per Mcf, 1% higher than the $3.57 per Mcf price realized in the first nine months of 2012. Our average realized crude oil price for the first nine months of 2013 was $103.07 per Bbl, 3% higher than the $100.30 per Bbl price realized in the first nine 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 natural gas and crude oil reserves at economical costs are critical to our long-term success.

During the first nine months of 2013, we drilled 134 gross wells (110.7 net) with a success rate of 98% compared to 104 gross wells (81.5 net) with a success rate of 97% for the comparable period of the prior year. For the nine months ended September 30, 2013, our total capital and exploration spending was $867.4 million compared to $712.9 million for the nine months ended September 30, 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, to a lesser extent, the Marmaton oil play in Oklahoma. For the full year 2013, we plan to drill approximately 185 to 195 gross wells (155 to 165 net). Our 2013 drilling program includes between $1.1 billion and $1.2 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, proceeds generated from pending asset sales 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 nine months ended September 30, 2013 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments), net borrowings under our credit facility and proceeds from the sales of certain oil and gas properties during the year. 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

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

	Nine Months Ended
	September 30,
(In thousands)	2013			2012
Cash flows provided by operating activities	$	766,676		$	455,112
Cash flows used in investing activities	(836,978		)	(540,946		)
Cash flows provided by financing activities	67,498			93,424
Net (decrease) / increase in cash and cash equivalents	$	(2,804	)	$	7,590

Operating Activities. Net cash provided by operating activities in the first nine months of 2013 increased by $311.6 million over the first nine 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 natural gas and crude oil prices. Equivalent production volumes increased by 54% for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. Average realized natural gas prices increased by 1% and average realized crude oil prices increased by 3% for the first nine months of 2013 compared to the first nine 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 $296.0 million for the first nine months of 2013 compared to the first nine months of 2012. The increase was due to $174.3 million of higher capital expenditures, $117.6 million of lower proceeds from sale of assets and an increase of $4.1 million in capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution).

Financing Activities. Cash flows provided by financing activities decreased by $25.9 million for the first nine months of 2013 compared to the first nine months of 2012. This decrease was primarily due to $37.0 million of lower net borrowings and a $4.3 million increase in dividend payments, partially offset by an increase of $9.3 million in tax benefits associated with our stock-based compensation and a $5.0 million decrease in capitalized debt issuance costs.

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. Our commitments under the credit facility of $900.0 million remained unchanged. At September 30, 2013, we had $475.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.4% and $424.0 million available for future borrowings.

We were in compliance with all restrictive financial covenants in both the revolving credit facility and senior notes as of September 30, 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:

	September 30,		December 31,
(Dollars in thousands)	2013		2012

Debt (1)	$	1,162,000	$	1,087,000
Stockholders’ equity	2,328,734		2,131,447
Total capitalization	$	3,490,734	$	3,218,447

Debt to capitalization	33%		34%

Cash and cash equivalents	$	27,932	$	30,736

(1) Includes $75.0 million of current portion of long-term debt at December 31, 2012 and $475.0 million and $325.0 million of borrowings outstanding under our revolving credit facility at September 30, 2013 and December 31, 2012, respectively.

During the nine months ended September 30, 2013, we paid dividends of $16.8 million ($0.04 per share) on our common stock. In July 2013, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.01 per share to $0.02 per share. 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:

	Nine Months Ended
	September 30,
(In thousands)	2013		2012
Capital expenditures
Drilling and facilities	$	793,601	$	602,820
Leasehold acquisitions	55,023		74,426
Pipeline and gathering	579		(365		)
Other	5,712		6,457
	854,915		683,338
Exploration expense	12,444		29,548
Total	$	867,359	$	712,886

For the full year of 2013, we plan to drill approximately 185 to 195 gross wells (155 to 165 net). Our 2013 drilling program includes between $1.1 billion and $1.2 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. Except for certain new and amended transportation agreements and two new drilling rig commitments described in Note 6 to the Condensed Consolidated Financial Statements included in this Form 10-Q, 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

In July 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” The amendments in this update clarify the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. We do not expect this guidance to have a material impact on our consolidated financial position, results of operations or cash flows.

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in 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

Third Quarters of 2013 and 2012 Compared

We reported net income in the third quarter of 2013 of $69.9 million, or $0.17 per share, compared to $36.6 million, or $0.09 per share, in the third quarter of 2012. The increase in net income was due to an increase in equivalent production and higher realized crude oil prices, partially offset by higher operating expenses and lower natural gas prices.

Revenue, Price and Volume Variances

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

	Three Months Ended September 30,				Variance
Revenue Variances (In thousands)	2013		2012		Amount		Percent
Natural gas (1)	$	341,901	$	232,045	$	109,856	47%
Crude oil and condensate	84,209		57,870		26,339		46%
Brokered natural gas	7,165		5,238		1,927		37%
Other	2,575		1,870		705		38%

(1) Natural gas revenues exclude the unrealized loss of $0.1 million from the change in fair value of our derivatives not designated as hedges in 2012. There were no unrealized gains or losses in 2013.

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	Three Months Ended September 30,				Variance					Increase (Decrease)
	2013		2012		Amount			Percent		(In thousands)
Price Variances
Natural gas (1)	$	3.36	$	3.68	$	(0.32	)	(9%	)	$	(32,732	)
Crude oil and condensate (2)	$	103.76	$	101.34	$	2.42		2%		1,925
Total										$	(30,807	)
Volume Variances
Natural gas (Bcf)	101.7		62.7		39.0			62%		$	142,588
Crude oil and condensate (Mbbl)	812		571		241			42%		24,414
Total										$	167,002

(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $0.20 per Mcf and $0.91 per Mcf in 2013 and 2012,

(2) These prices include the realized impact of derivative instrument settlements, which decreased the price by $1.33 per Bbl in 2013 and increased the price by $6.65 per Bbl in 2012.

Natural Gas Revenues

The increase in natural gas revenues of $109.9 million, excluding the impact of the unrealized losses on derivative instruments discussed above, is due to higher production partially offset by lower realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program and expanded infrastructure in the area, partially offset by lower production in Texas, Oklahoma and West Virginia due to reduced natural gas drilling in these areas and normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $26.3 million is due to higher production associated with our oil-focused drilling program in south Texas and, to a lesser extent, Oklahoma and slightly higher realized crude oil prices.

Brokered Natural Gas Revenue and Cost

								Price and
	Three Months Ended							Volume
	September 30,				Variance			Variances
	2013		2012		Amount		Percent	(In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	4.22	$	3.28	$	0.94	29%	$	1,592
Volume brokered (Mmcf)	x	1,697	x	1,595	102		6%	335
Brokered natural gas (In thousands)	$	7,165	$	5,238				$	1,927

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	3.48	$	2.67	$	0.81	30%	$	(1,383	)
Volume brokered (Mmcf)	x	1,697	x	1,595	102		6%	(272		)
Brokered natural gas (In thousands)	$	5,913	$	4,258				$	(1,655	)

Brokered natural gas margin (In thousands)	$	1,252	$	980				$	272

The $0.3 million increase in brokered natural gas margin is a result of an increase in sales price that outpaced the increase in purchase price and higher brokered volumes.

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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 September 30,
(In thousands)	2013			2012
Cash Flow Hedges
Natural gas	$	20,766		$	57,139
Crude oil	(1,082		)	3,799
Other Derivative Financial Instruments
Natural gas basis swaps	—			(149		)
	$	19,684		$	60,789

Operating and Other Expenses

	Three Months Ended September 30,					Variance
(In thousands)	2013			2012		Amount			Percent
Operating and Other Expenses
Direct operations	$	32,923		28,269		$	4,654		16%
Transportation and gathering	60,803			34,430		26,373			77%
Brokered natural gas	5,913			4,258		1,655			39%
Taxes other than income	11,532			10,436		1,096			11%
Exploration	3,891			9,303		(5,412		)	(58%	)
Depreciation, depletion and amortization	168,980			110,448		58,532			53%
General and administrative	24,697			23,829		868			4%
Total operating expense	$	308,739		$	220,973	$	87,766		40%

(Gain) / loss on sale of assets	$	(4,421	)	$	126	$	4,547		3609%
Interest expense and other	15,796			16,219		(423		)	(3%	)
Income tax expense	45,847			22,948		22,899			100%

Total costs and expenses from operations increased by $87.8 million, or 40%, in the third quarter of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

· Direct operations increased $4.7 million largely due to higher operating costs primarily driven by higher production. In addition, we experienced higher costs associated with oil separation and processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas and higher outside-operated property expenses.

· Transportation and gathering increased $26.4 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements throughout the second half of 2012, primarily in northeast Pennsylvania and south Texas.

· Brokered natural gas increased $1.7 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

· Taxes other than income increased $1.1 million due to higher production taxes as a result of an increase in oil production in south Texas and higher drilling impact fees associated with our Marcellus Shale drilling activities. These increases were partially offset by lower franchise and ad valorem taxes.

· Exploration expense decreased $5.4 million as a result of lower geophysical and geological costs of $2.9 million due to a decrease in the acquisition and processing of seismic data and lower exploratory dry hole costs of $1.3 million associated with a non-operated exploratory well that was drilled in 2012.

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· Depreciation, depletion and amortization increased $58.5 million, of which $65.9 million was due to higher equivalent production volumes for the third quarter of 2013 compared to the third quarter of 2012, partially offset by a decrease of $20.0 million due to a lower DD&A rate of $1.43 per Mcfe for the third quarter of 2013 compared to $1.62 per Mcfe for the third quarter of 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 program. In addition, amortization of unproved properties increased $12.5 million in the third quarter in 2013.

· General and administrative increased $0.9 million due to higher stock-based compensation expense of $2.5 million associated with amortization of costs associated with our supplemental employee incentive plan, partially offset by $1.3 million of lower legal and professional expenses.

(Gain) / Loss on Sale of Assets

An aggregate gain of $4.4 million was recognized in the third quarter of 2013 due to the sale of certain of our proved oil and gas properties in Oklahoma. There were no significant gains or losses on sale of assets recognized in the third quarter of 2012.

Income Tax Expense

Income tax expense increased $22.9 million primarily due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the third quarter of 2013 and 2012 was 39.6% and 38.5%, respectively.

First Nine Months of 2013 and 2012 Compared

We reported net income in the first nine months of 2013 of $201.8 million, or $0.48 per share, compared to $90.9 million, or $0.22 per share, in the first nine months of 2012. The increase in net income was due to an increase in equivalent production and higher realized natural gas and crude oil prices partially offset higher operating expenses.

Revenue, Price and Volume Variances

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

	Nine Months Ended September 30,				Variance
Revenue Variances (In thousands)	2013		2012		Amount		Percent
Natural gas (1)	$	1,004,085	$	640,178	$	363,907	57%
Crude oil and condensate	220,090		165,317		54,773		33%
Brokered natural gas	26,302		23,831		2,471		10%
Other	8,338		5,790		2,548		44%

(1) Natural gas revenues exclude the unrealized loss of $0.4 million from the change in fair value of our derivatives not designated as hedges in 2012. There were no unrealized gains or losses in 2013.

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	Nine Months Ended September 30,				Variance			Increase (Decrease)
	2013		2012		Amount		Percent	(In thousands)
Price Variances
Natural gas (1)	$	3.62	$	3.57	$	0.05	1%	$	13,875
Crude oil and condensate (2)	$	103.07	$	100.30	$	2.77	3%	5,941
Total								$	19,816
Volume Variances
Natural gas (Bcf)	277.5		178.4		99.1		56%	$	350,032
Crude oil and condensate (Mbbl)	2,135		1,648		487		30%	48,832
Total								$	398,864

(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $0.12 per Mcf and $1.03 per Mcf in 2013 and 2012, respectively.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $1.43 per Bbl in 2013 and $3.39 per Bbl in 2012, respectively.

Natural Gas Revenues

The increase in natural gas revenues of $363.9 million, excluding the impact of the unrealized losses on derivative instruments discussed above, is due to higher production during the first nine months of 2013 and higher realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program and expanded infrastructure in the area, partially offset by lower production in Texas, Oklahoma and West Virginia due reduced natural gas drilling in these areas and normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $54.8 million is due to higher production associated with our oil-focused drilling program in south Texas and, to a lesser extent, Oklahoma and higher realized crude oil prices.

Brokered Natural Gas Revenue and Cost

										Price and
	Nine Months Ended September 30,				Variance					Variances Volume
	2013		2012		Amount			Percent		(In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	4.06	$	3.54	$	0.52		15%		$	3,374
Volume brokered (Mmcf)	x	6,478	x	6,733	(255		)	(4%	)	(903		)
Brokered natural gas (In thousands)	$	26,302	$	23,831						$	2,471

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	3.24	$	3.03	$	0.21		7%		$	(1,398	)
Volume brokered (Mmcf)	x	6,478	x	6,733	(255		)	(4%	)	772
Brokered natural gas (In thousands)	$	21,006	$	20,380						$	(626	)

Brokered natural gas margin (In thousands)	$	5,296	$	3,451						$	1,845

The $1.8 million increase in brokered natural gas margin is a result of an increase in sales price that outpaced the increase in purchase price partially offset by lower brokered volumes.

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Impact of Derivative Instruments on Operating Revenues

	Nine Months Ended September 30,
(In thousands)	2013		2012
Cash Flow Hedges
Natural gas	$	33,822	$	183,867
Crude oil	3,054		5,583
Other Financial Derivative Instruments
Natural gas basis swaps	—		(449		)
	$	36,876	$	189,001

Operating and Other Expenses

	Nine Months Ended September 30,						Variance
(In thousands)	2013			2012			Amount			Percent
Operating and Other Expenses
Direct operations	$	101,398		$	84,895		$	16,503		19%
Transportation and gathering	159,672			97,827			61,845			63%
Brokered natural gas	21,006			20,380			626			3%
Taxes other than income	34,583			39,873			(5,290		)	(13%	)
Exploration	12,444			29,548			(17,104		)	(58%	)
Depreciation, depletion and amortization	469,022			335,421			133,601			40%
General and administrative	82,009			93,249			(11,240		)	(12%	)
Total operating expense	$	880,134		$	701,193		$	178,941		26%

(Gain) / loss on sale of assets	$	(4,601	)	$	(67,042	)	$	(62,441	)	(93%	)
Interest expense and other	48,752			51,631			(2,879		)	(6%	)
Income tax expense	132,703			58,021			74,682			129%

Total costs and expenses from operations increased by $178.9 million, or 26%, in the first nine months of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

· Direct operations increased $16.5 million largely due to higher operating costs primarily driven by higher production. In addition, we experienced higher costs associated with oil separation and processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas and higher outside-operated property expenses. Partially offsetting these increases was a decrease in workover activity.

· Transportation and gathering increased $61.8 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in the second half of 2012, primarily in northeast Pennsylvania and south Texas.

· Brokered natural gas increased $0.6 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

· Taxes other than income decreased $5.3 million due to lower drilling impact fees associated with our Marcellus Shale drilling activities. The first nine months of 2012 included the initial assessment of drilling impact fees associated with 2011 and prior period wells. This decrease is partially offset by higher production taxes as a result of an increase in oil production in south Texas.

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· Exploration expense decreased $17.1 million due to lower exploratory dry hole costs of $11.4 million associated with our Brown Dense/Smackover exploratory well in Union County, Arkansas that was recorded in the first nine months of 2012. There were no exploratory dry holes recorded in the first nine months of 2013. In addition, geophysical and geological expenses decreased by $5.6 million due to a decrease in the acquisition and processing of seismic data.

· Depreciation, depletion and amortization increased $133.6 million, of which $171.6 million was due to higher equivalent production volumes for the first nine months of 2013 compared to the first nine months of 2012, partially offset by a decrease of $50.8 million due to a lower DD&A rate of $1.50 per Mcfe for the first nine months of 2013 compared to $1.67 per Mcfe for the first nine months of 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs. In addition, amortization of unproved properties increased $12.4 million in the first nine months of 2013.

· General and administrative decreased $11.2 million due to lower pension expense of $19.6 million associated with the liquidation of our pension plan that occurred in the second quarter of 2012 and $7.0 million of lower legal and professional expenses. These decreases are partially offset by $17.5 million of higher stock-based compensation expense associated with the mark-to-market of our liability-based performance awards due to changes in our stock price for the first nine months of 2013 compared to the first nine months of 2012 and the achievement of the interim and final triggers of our supplemental incentive compensation plan during 2013.

(Gain) / Loss on Sale of Assets

An aggregate gain of $4.6 million was recognized in the first nine months of 2013, primarily due to the sale of certain of our proved oil and gas properties in Oklahoma. An aggregate gain of $67.0 million was recognized in the first nine months of 2012 due to the sale of certain of our Pearsall Shale undeveloped leaseholds in south Texas.

Interest Expense and Other

Interest expense and other decreased $2.9 million due to lower debt extinguishment costs of $1.3 million associated with our credit facility amendment in May 2012 and the repayment of $75 million of our 7.33% weighted-average fixed rate notes in July 2013. In addition, interest expense decreased due to a lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.3% during the first nine months of 2013 compared to approximately 3.2% during the first nine months of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately $408.2 million during the first nine months of 2013 compared to approximately $266.5 million during the first nine months of 2012.

Income Tax Expense

Income tax expense increased $74.7 million due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first nine months of 2013 and 2012 was 39.7% and 39.0%, respectively.

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.

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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.

As of September 30, 2013, we had the following outstanding commodity derivatives:

				Collars							Swaps		Estimated Fair
				Floor				Ceiling					Value Asset
						Weighted-			Weighted-		Weighted-		(Liability)
Type of Contract	Volume		Contract Period	Range		Average		Range	Average		Average		(In thousands)
Collar Agreements
Natural gas	4.5	Bcf	Oct. 2013 - Dec. 2013	$	—	$	5.15	$6.18-$6.23	$	6.20			$	7,208
Natural gas	54.5	Bcf	Oct. 2013 - Dec. 2013	$3.09-$4.37		$	3.63	$3.98-$5.02	$	4.27			8,930
Natural gas	44.4	Bcf	Oct. 2013 - Dec. 2014	$3.60-$3.96		$	3.78	$4.55-$4.59	$	4.57			5,550
Natural gas	124.1	Bcf	Jan. 2014 - Dec. 2014	$3.86-$4.37		$	4.19	$4.63-$4.80	$	4.70			43,881
													65,569
Swap Agreements
Crude oil	276	Mbbl	Oct. 2013 - Dec. 2013								$	101.90	93
													$	65,662

Natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

The amounts set forth under the estimated fair value column in the table above represent our total unrealized net gain position at September 30, 2013 and exclude the impact of non-performance risk. Non-performance risk is primarily evaluated by reviewing credit default swap spreads for the various financial institutions with which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

During the first nine months of 2013, crude oil swaps covered 819 Mbbl, or 38% of crude oil production at an average price of $101.90 per Bbl. Natural gas collars with floor prices ranging from $3.09 to $5.15 per Mcf and ceiling prices ranging from $3.98 to $6.23 per Mcf covered 173.8 Bcf, or 62.6%, of our natural gas production at an average price of $3.97 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 non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our derivative contract counterparties are Bank of America, Bank of Montreal, Goldman Sachs, JPMorgan Chase, and Morgan Stanley.

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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 commodity prices. See “Forward-Looking Information” for further details.

Fair 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.

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:

	September 30, 2013				December 31, 2012
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value
Total debt	$	1,162,000	$	1,258,627	$	1,087,000		$	1,213,474
Current maturities	—		—		(75,000		)	(77,175		)
Long-term debt, excluding current maturities	$	1,162,000	$	1,258,627	$	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 third 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.

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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 September 30, 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 September 30, 2013 was 19,181,200 after giving effect to the stock split effected in August 2013.

ITEM 6. Exhibits

Exhibit Number		Description

15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

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

32.1		906 Certification

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

	CABOT OIL & GAS CORPORATION
	(Registrant)

October 25, 2013	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 25, 2013	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

October 25, 2013	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)