Edgar Filing: CABOT OIL & GAS CORP

COG-06.30.2015-10Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2015

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 ý 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 ý 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 ý

As of July 20, 2015, there were 413,807,968 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 (Unaudited) at June 30, 2015 and December 31, 2014		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and Six Months Ended June 30, 2015 and 2014		4

Condensed Consolidated Statement of Comprehensive Income (Unaudited) for the Three and Six Months Ended June 30, 2015 and 2014		5

Condensed Consolidated Statement of Cash Flows (Unaudited) for the Six Months Ended June 30, 2015 and 2014		6

Notes to the Condensed Consolidated Financial Statements		7

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

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

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29

Item 4.	Controls and Procedures	31

Part II. Other Information

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

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

Item 6.	Exhibits	32

Signatures		33

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)



(In thousands, except share amounts)	June 30, 2015			December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	$	15,231		$	20,954
Accounts receivable, net	138,354			239,009
Inventories	20,423			14,026
Derivative instruments	76,178			137,603
Other current assets	4,807			1,855
Total current assets	254,993			413,447
Properties and equipment, net (Successful efforts method)	5,132,655			4,925,711
Equity method investments	81,075			68,029
Other assets	36,197			30,529
	$	5,504,920		$	5,437,716

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	218,633		$	400,076
Accrued liabilities	57,465			63,669
Deferred income taxes	2,754			35,273
Total current liabilities	278,852			499,018
Postretirement benefits	37,314			35,827
Long-term debt	1,995,000			1,752,000
Deferred income taxes	878,069			843,876
Asset retirement obligations	134,763			124,655
Other liabilities	35,006			39,607
Total liabilities	3,359,004			3,294,983

Commitments and contingencies

Stockholders' equity
Common stock:
Authorized — 960,000,000 shares of $0.10 par value in 2015 and 2014, respectively
Issued — 423,700,648 shares and 422,915,258 shares in 2015 and 2014, respectively	42,370			42,292
Additional paid-in capital	717,327			710,432
Retained earnings	1,695,205			1,698,995
Accumulated other comprehensive income (loss)	(2,151		)	(2,151		)
Less treasury stock, at cost:
9,892,680 shares in 2015 and 2014, respectively	(306,835		)	(306,835		)
Total stockholders' equity	2,145,916			2,142,733
	$	5,504,920		$	5,437,716

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 June 30,						Six Months Ended June 30,
(In thousands, except per share amounts)	2015			2014			2015		2014
OPERATING REVENUES
Natural gas	$	224,806		$	437,761		$	584,997	$	870,571
Crude oil and condensate	81,233			86,341			143,791		145,485
Gain (loss) on derivative instruments	(6,819		)	(2,329		)	27,304		(2,329		)
Brokered natural gas	3,813			8,140			8,640		21,293
Other	3,264			3,274			6,330		7,970
	306,297			533,187			771,062		1,042,990
OPERATING EXPENSES
Direct operations	36,112			35,605			72,129		71,439
Transportation and gathering	98,295			83,976			219,531		161,741
Brokered natural gas	2,885			7,031			6,624		18,891
Taxes other than income	11,611			12,816			22,891		25,860
Exploration	5,298			4,676			14,030		11,150
Depreciation, depletion and amortization	152,513			157,563			328,009		304,981
General and administrative	19,978			20,127			42,507		41,763
	326,692			321,794			705,721		635,825
Earnings (loss) on equity method investments	1,512			756			2,933		756
Gain (loss) on sale of assets	(79		)	(1,496		)	59		(2,781		)
INCOME (LOSS) FROM OPERATIONS	(18,962		)	210,653			68,333		405,140
Interest expense	24,168			16,334			47,734		32,891
Income (loss) before income taxes	(43,130		)	194,319			20,599		372,249
Income tax (benefit) expense	(15,622		)	75,899			7,852		146,798
NET INCOME (LOSS)	$	(27,508	)	$	118,420		$	12,747	$	225,451

Earnings (loss) per share
Basic	$	(0.07	)	$	0.28		$	0.03	$	0.54
Diluted	$	(0.07	)	$	0.28		$	0.03	$	0.54

Weighted-average common shares outstanding
Basic	413,713			417,291			413,530		417,097
Diluted	413,713			419,092			414,878		418,742

Dividends per common share	$	0.02		$	0.02		$	0.04	$	0.04

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 June 30,					Six Months Ended June 30,
(In thousands)	2015			2014		2015		2014
Net income (loss)	$	(27,508	)	$	118,420	$	12,747	$	225,451
Other comprehensive income (loss), net of taxes:
Reclassification adjustment for settled cash flow hedge contracts⁽¹⁾	—			13,807		—		56,372
Changes in fair value of cash flow hedge contracts⁽²⁾	—			—		—		(80,175		)
Total other comprehensive income (loss)	—			13,807		—		(23,803		)
Comprehensive income (loss)	$	(27,508	)	$	132,227	$	12,747	$	201,648


(1)	Net of income taxes of $(9,149) and $(37,359) for the three and six months ended June 30, 2014, respectively.


(2)	Net of income taxes of $53,135 for the six months ended June 30, 2014.

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)



	Six Months Ended June 30,
(In thousands)	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	12,747		$	225,451
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	328,009			304,981
Deferred income tax expense	7,160			118,453
(Gain) loss on sale of assets	(59		)	2,781
Exploratory dry hole cost	178			2,154
(Gain) loss on derivative instruments	(27,304		)	2,329
Net cash received (paid) in settlement of derivative instruments	88,730			(15,262		)
Amortization of debt issuance costs	2,337			2,252
Stock-based compensation and other	11,602			8,689
Changes in assets and liabilities:
Accounts receivable, net	99,897			9,588
Income taxes	(2,184		)	(23,352		)
Inventories	(6,397		)	5,554
Other current assets	(2,953		)	15
Accounts payable and accrued liabilities	(65,023		)	(39,084		)
Other assets and liabilities	(2,663		)	753
Stock-based compensation tax benefit	(5,486		)	(20,354		)
Net cash provided by operating activities	438,591			584,948

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(645,092		)	(617,613		)
Acquisitions	(16,300		)	—
Proceeds from sale of assets	3,002			(755		)
Restricted cash	—			28,094
Investment in equity method investments	(10,114		)	(22,230		)
Net cash used in investing activities	(668,504		)	(612,504		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	642,000			611,000
Repayments of debt	(399,000		)	(565,000		)
Dividends paid	(16,537		)	(16,679		)
Stock-based compensation tax benefit	5,486			20,354
Capitalized debt issuance costs	(7,838		)	—
Other	79			91
Net cash provided by financing activities	224,190			49,766

Net (decrease) increase in cash and cash equivalents	(5,723		)	22,210
Cash and cash equivalents, beginning of period	20,954			23,400
Cash and cash equivalents, end of period	$	15,231		$	45,610

Supplemental non-cash transactions:
Change in accrued capital costs	(134,875		)	(32,616		)

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, 2014 (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 the current year presentation. These reclassifications have no impact on previously reported net income.

With respect to the unaudited financial information of the Company as of June 30, 2015 and for the three and six months ended June 30, 2015 and 2014, 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 July 24, 2015 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 March 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however, early adoption is permitted. The Company does not believe the adoption of this guidance will have a material effect on its financial position, results of operations or cash flows.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB finalized the delay of the effective date by one year, making the new standard effective for interim periods and annual period beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption; however, the entities reporting under U.S. GAAP are not permitted to adopt the standard earlier than the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	June 30, 2015			December 31, 2014
Proved oil and gas properties	$	8,531,171		$	7,984,979
Unproved oil and gas properties	451,332			492,208
Gathering and pipeline systems	242,371			241,272
Land, building and other equipment	114,809			109,758
	9,339,683			8,828,217
Accumulated depreciation, depletion and amortization	(4,207,028		)	(3,902,506		)
	$	5,132,655		$	4,925,711

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At June 30, 2015, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.

3. Equity Method Investments

Activity related to the Company's equity method investments is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2015			2014			2015			2014
Constitution Pipeline Company, LLC
Contributions	$	3,000		$	15,250		$	6,000		$	21,000
Earnings (loss) on equity method investments	1,528			854			2,955			854
	$	4,528		$	16,104		$	8,955		$	21,854
Meade Pipeline Co LLC
Contributions	$	2,036		$	1,043		$	4,114		$	1,230
Earnings (loss) on equity method investments	(16		)	(98		)	(22		)	(98		)
	$	2,020		$	945		$	4,092		$	1,132
Total
Contributions	$	5,036		$	16,293		$	10,114		$	22,230
Earnings (loss) on equity method investments	1,512			756			2,933			756
	$	6,548		$	17,049		$	13,047		$	22,986

For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.

4. Debt and Credit Agreements

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



(In thousands)	June 30, 2015		December 31, 2014
7.33% weighted-average fixed rate notes	$	20,000	$	20,000
6.51% weighted-average fixed rate notes	425,000		425,000
9.78% fixed rate notes	67,000		67,000
5.58% weighted-average fixed rate notes	175,000		175,000
3.65% weighted-average fixed rate notes	925,000		925,000
Revolving credit facility	383,000		140,000
	$	1,995,000	$	1,752,000

The Company was in compliance with all restrictive financial covenants for both the revolving credit facility and fixed rate notes as of June 30, 2015.

Revolving credit facility

At June 30, 2015, the Company had $383.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.0% and had unused commitments of $1.4 billion. The Company’s weighted-average effective interest rate under the revolving credit facility for the three months ended June 30, 2015 and 2014 was approximately 2.2% and 2.1%, respectively, and for the six months ended June 30, 2015 and 2014 was approximately 2.3% and 2.2%, respectively.

Effective April 17, 2015, the Company amended its revolving credit facility to extend the maturity date from May 2017 to April 2020 and change the mechanism under which interest rate margins are determined for outstanding borrowings. The revolving credit facility, as amended, provides for an increase in the borrowing base from $3.1 billion to $3.4 billion and an increase in commitments from $1.4 billion to $1.8 billion. The amended credit facility also provides for an accordion feature, which allows the Company to increase the available credit line up to an additional $500 million if one or more of the

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existing or new banks agree to provide such increased amount. The borrowing base is redetermined annually under the terms of the revolving credit facility on April 1. In addition, either the Company or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties.

Interest rates under the amended credit facility are based on Eurodollar (LIBOR) or alternate base rate (ABR) indications, plus a margin. The associated margins are based on the Company's leverage ratio as shown below:



	Leverage Ratio⁽¹⁾
	<1.0x		≥1.0x and <2.0x		≥2.0x and <3.0x		≥3.0x
Eurodollar loans	1.50	%	1.75	%	2.00	%	2.25	%
ABR loans	0.50	%	0.75	%	1.00	%	1.25	%

⁽¹⁾The ratio of debt and other liabilities to Consolidated EBITDAX, as defined in the credit agreement.

Upon the Company achieving an investment grade rating from either Moody's or S&P, the associated margins will be adjusted and determined based on the Company's respective credit rating on a prospective basis.

The amended credit facility also provides for a commitment fee on the unused available balance at annual rates ranging from 0.30% to 0.50%. The other terms and conditions of the amended facility are generally consistent with the terms and conditions of the revolving credit facility prior to its amendment as disclosed in Note 5 of the Notes to the Consolidated Financial Statements in the Form 10-K.

5. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivatives to manage its exposure to price fluctuations on natural gas and crude oil production. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. 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.

Through March 31, 2014, the Company elected to designate its commodity derivatives as cash flow hedges for accounting purposes. Effective April 1, 2014, the Company elected to discontinue hedge accounting for its commodity derivatives on a prospective basis. As a result of discontinuing hedge accounting, the unrealized loss included in accumulated other comprehensive income (loss) as of April 1, 2014 of $73.4 million ($44.2 million net of tax) was frozen and reclassified into natural gas and crude oil and condensate revenues in the Condensed Consolidated Statement of Operations throughout the remainder of 2014 as the underlying hedged transactions occurred. As of June 30, 2015 and December 31, 2014, there were no gains or losses deferred in accumulated other comprehensive income (loss) associated with the Company's commodity derivatives.

As of June 30, 2015, the Company had the following outstanding commodity derivatives:

Collars

Swaps

Floor

Ceiling

Type of Contract

Volume

Contract Period

Range

Weighted-Average

Range

Weighted- Average

Natural gas

35.7

Bcf

Jul. 2015 - Dec. 2015

$3.86 - $3.91

3.87

$4.27 - $4.43

4.35

Natural gas

35.7

Bcf

Jul. 2015 - Dec. 2015

3.92

Natural gas

17.9

Bcf

Jul. 2015 - Oct. 2015

3.36

In the table above, natural gas prices are stated per Mcf.

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet



		Fair Values of Derivative Instruments
		Derivative Assets				Derivative Liabilities
(In thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014		June 30, 2015		December 31, 2014
Commodity contracts	Derivative instruments (current assets)	$	76,178	$	137,603	$	—	$	—

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



(In thousands)	June 30, 2015		December 31, 2014
Derivative Assets
Gross amounts of recognized assets	$	76,178	$	137,603
Gross amounts offset in the statement of financial position	—		—
Net amounts of assets presented in the statement of financial position	76,178		137,603
Gross amounts of financial instruments not offset in the statement of financial position	—		2,338
Net amount	$	76,178	$	139,941

Effect of Derivative Instruments on Accumulated Other Comprehensive Income (Loss)

The amount of gain (loss) recognized in accumulated other comprehensive income (loss) on derivatives (effective portion) is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2015		2014		2015		2014
Commodity contracts	$	—	$	—	$	—	$	(133,310	)

The amount of gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) is as follows:



	Three Months Ended June 30,					Six Months Ended June 30,
(In thousands)	2015		2014			2015		2014
Natural gas revenues	$	—	$	(22,320	)	$	—	$	(92,877	)
Crude oil and condensate revenues	—		(636		)	—		(854		)
	$	—	$	(22,956	)	$	—	$	(93,731	)

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Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations



	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2015			2014			2015			2014
Derivatives Designated as Hedges
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	—		$	—		$	(70,557	)
Crude oil and condensate	—			—			—			(218		)
	$	—		$	—		$	—		$	(70,775	)
Derivatives Not Designated as Hedges
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	(22,320	)	$	—		$	(22,320	)
Crude oil and condensate	—			(636		)	—			(636		)
Gain (loss) on derivative instruments	51,045			(15,262		)	88,730			(15,262		)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(57,864		)	12,933			(61,426		)	12,933
	$	(6,819	)	$	(25,285	)	$	27,304		$	(25,285	)

	$	(6,819	)	$	(25,285	)	$	27,304		$	(96,060	)

For the three and six months ended June 30, 2014, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations related to derivative instruments designated as cash flow hedges. In addition, the Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.

6. Fair Value Measurements

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. For further information regarding the fair value hierarchy, refer to Note 1 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, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were measured at fair value as of June 30, 2015 and 2014, additional disclosures were not required.

The estimated fair value of the Company’s asset retirement obligations 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 obligations was classified as Level 3 in the fair value hierarchy.

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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)		Balance at June 30, 2015
Assets
Deferred compensation plan	$	13,282	$	—	$	—	$	13,282
Derivative contracts	—		28,180		47,998		76,178
Total assets	$	13,282	$	28,180	$	47,998	$	89,460
Liabilities
Deferred compensation plan	$	30,130	$	—	$	—	$	30,130
Total liabilities	$	30,130	$	—	$	—	$	30,130



(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at December 31, 2014
Assets
Deferred compensation plan	$	13,115	$	—	$	—	$	13,115
Derivative contracts	—		51,645		85,958		137,603
Total assets	$	13,115	$	51,645	$	85,958	$	150,718
Liabilities
Deferred compensation plan	$	28,932	$	—	$	—	$	28,932
Total liabilities	$	28,932	$	—	$	—	$	28,932

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 commodity prices, 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 most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are 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.

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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:



	Six Months Ended June 30,
(In thousands)	2015			2014
Balance at beginning of period	$	85,958		$	(3,910	)
Total gains (losses) (realized or unrealized):
Realized and unrealized gains (losses) included in earnings	12,662			(77,935		)
Included in other comprehensive income	—			(38,412		)
Settlements	(50,622		)	93,342
Transfers in and/or out of Level 3	—			—
Balance at end of period	$	47,998		$	(26,915	)

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	(37,961	)	$	15,407

There were no transfers between Level 1 and Level 2 measurements for the three and six months ended June 30, 2015 and 2014.

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 amount reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents approximates fair value due to the short-term maturities of these instruments. Cash and cash equivalents are classified as Level 1 in the fair value hierarchy.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of 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 revolving 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 revolving credit facility is based on interest rates currently available to the Company. The Company’s debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.

The carrying amounts and fair values of debt are as follows:



	June 30, 2015				December 31, 2014
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt	$	1,995,000	$	2,028,913	$	1,752,000	$	1,850,867

7. Asset Retirement Obligations

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



(In thousands)	Six Months Ended June 30, 2015
Balance at beginning of period	$	126,655
Liabilities incurred	6,969
Liabilities settled	(203		)
Accretion expense	3,342
Balance at end of period	$	136,763

As of both June 30, 2015 and December 31, 2014, approximately $2.0 million is included in accrued liabilities in the Condensed Consolidated Balance Sheet, which represents the current portion of the Company’s asset retirement obligations.

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8. Commitments and Contingencies

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. There have been no material changes to the Company’s contractual obligations described under “Transportation and Gathering Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 in the Notes to Consolidated Financial Statements included in the Form 10-K.

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 would not be 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.

9. Stock-based Compensation

General

Stock-based compensation expense during the first six months of 2015 and 2014 was $14.5 million and $9.4 million, respectively, and is included in general and administrative expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the second quarter of 2015 and 2014 was $8.6 million and $6.3 million, respectively.

During the first six months of 2015 and 2014, the Company recognized a $5.5 million and $20.4 million tax benefit related to the federal tax deduction in excess of book compensation cost for employee stock-based compensation, respectively. The Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable.

Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards and the applicable award terms.

Restricted Stock Awards

During the first six months of 2015, 3,400 restricted stock awards were granted to employees with a weighted-average grant date per share value of $28.55. The fair value of restricted stock grants is based on the closing stock price on the grant date. The Company used an annual forfeiture rate assumption of 5.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first six months of 2015, 47,320 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $27.96. The fair value of these units is measured based on the closing stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.

Performance Share Awards

The performance period for the awards granted in 2015 commenced on January 1, 2015 and ends on December 31, 2017. The Company used an annual forfeiture rate assumption ranging from 0% to 5% for purposes of recognizing stock-based compensation expense for its performance share awards.

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Performance Share Awards Based on Internal Performance Metrics

The fair value of performance award grants based on internal performance metrics is based on the closing stock price on the grant date and represents the right to receive up to 100% of the award in shares of common stock.

Employee Performance Share Awards. During the first six months of 2015, 349,780 Employee Performance Share Awards were granted at a grant date per share value of $27.71. The performance metrics are set by the Company’s compensation committee and are based on the Company’s average production, average finding costs and average reserve replacement over a three-year performance period. Based on the Company’s probability assessment at June 30, 2015, it is considered probable that the criteria for these awards will be met.

Hybrid Performance Share Awards. During the first six months of 2015, 194,947 Hybrid Performance Share Awards were granted at a grant date per share value of $27.71. The 2015 awards vest 25% on each of the first and second anniversary dates and 50% on the third anniversary, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date, as set by the Company’s compensation committee. If the Company does not meet the performance metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited. Based on the Company’s probability assessment at June 30, 2015, it is considered probable that the criteria for these awards will be met.

Performance Share Awards Based on Market Conditions

These awards have both an equity and liability component, with the right to receive up to the first 100% of the award in shares of common stock and the right to receive up to an additional 100% of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.

TSR Performance Share Awards. During the first six months of 2015, 292,421 TSR Performance Share Awards were granted and are earned, or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group over a three-year performance period.

The following assumptions were used to determine the grant date fair value of the equity component (February 19, 2015) and the period-end fair value of the liability component of the TSR Performance Share Awards:



	Grant Date			June 30, 2015
Fair value per performance share award	$	19.29		$14.60 - $19.30
Assumptions:
Stock price volatility	32.3		%	25.6% - 29.0%
Risk free rate of return	1.0		%	0.1% - 0.8%
Expected dividend yield	0.3		%	0.3	%

Supplemental Employee Incentive Plan

The Company recognized stock-based compensation expense of $1.6 million for the three months ended June 30, 2014. Stock-based compensation (benefit) expense recognized in the second quarter of 2015 was immaterial. The Company recognized stock-based compensation (benefit) expense of $(0.1) million and $3.1 million for the six months ended June 30, 2015 and 2014, respectively, related to the Company’s Supplemental Employee Incentive Plan, which is included in general and administrative expense in the Condensed Consolidated Statement of Operations. Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for additional information on the provisions of the Plan.

The following assumptions were used to determine the period-end fair value of the Supplemental Employee Incentive Plan IV liability using a Monte Carlo simulation model:



	June 30, 2015
Stock price volatility	30.3	%
Risk free rate of return	0.7	%
Annual salary increase rate	4.0	%
Annual turnover rate	4.6	%

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10. Earnings per Common Share

Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period 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.

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



	Three Months Ended June 30,		Six Months Ended June 30,
(In thousands)	2015	2014	2015	2014
Weighted-average shares - basic	413,713	417,291	413,530	417,097
Dilution effect of stock appreciation rights and stock awards at end of period	—	1,801	1,348	1,645
Weighted-average shares - diluted	413,713	419,092	414,878	418,742

Weighted-average stock awards and shares excluded from diluted EPS due to the anti-dilutive effect	1,655	2	400	409

11. Accumulated Other Comprehensive Income (Loss)

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



	Three Months Ended June 30,					Six Months Ended June 30,					Affected Line Item in the Condensed
(In thousands)	2015		2014			2015		2014			Consolidated Statement of Operations
Gain (Loss) on Cash Flow Hedges
Commodity contracts	$	—	$	(22,320	)	$	—	$	(92,877	)	Natural gas revenues
Commodity contracts	—		(636		)	—		(854		)	Crude oil and condensate revenues
	—		(22,956		)	—		(93,731		)	Total before tax
	—		9,149			—		37,359			Tax benefit (expense)
Total reclassifications for the period	$	—	$	(13,807	)	$	—	$	(56,372	)	Net of tax

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12. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:



(In thousands)	June 30, 2015			December 31, 2014
Accounts receivable, net
Trade accounts	$	130,729		$	227,835
Joint interest accounts	1,388			2,245
Income taxes receivable	5,797			3,612
Other accounts	1,440			6,515
	139,354			240,207
Allowance for doubtful accounts	(1,000		)	(1,198		)
	$	138,354		$	239,009

Inventories
Tubular goods and well equipment	$	17,750		$	10,675
Natural gas in storage	2,651			3,281
Other accounts	22			70
	$	20,423		$	14,026

Other assets
Deferred compensation plan	$	13,282		$	13,115
Debt issuance cost	22,850			17,349
Other accounts	65			65
	$	36,197		$	30,529

Accounts payable
Trade accounts	$	37,627		$	54,949
Natural gas purchases	3,138			2,407
Royalty and other owners	75,759			97,298
Accrued capital costs	87,551			222,426
Taxes other than income	8,818			16,806
Drilling advances	81			88
Other accounts	5,659			6,102
	$	218,633		$	400,076

Accrued liabilities
Employee benefits	$	12,871		$	22,815
Taxes other than income	11,663			7,128
Interest payable	30,143			30,677
Other accounts	2,788			3,049
	$	57,465		$	63,669

Other liabilities
Deferred compensation plan	$	30,130		$	28,932
Other accounts	4,876			10,675
	$	35,006		$	39,607

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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 June 30, 2015, and the related condensed consolidated statements of operations and of comprehensive income for the three-month and six-month periods ended June 30, 2015 and June 30, 2014 and the condensed consolidated statement of cash flows for the six-month periods ended June 30, 2015 and June 30, 2014. 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, 2014, 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 27, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2014, 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

July 24, 2015

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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 six month periods ended June 30, 2015 and 2014 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, 2014 (Form 10-K).

Overview

On an equivalent basis, our production for the six months ended June 30, 2015 increased by 25% compared to the six months ended June 30, 2014. For the six months ended June 30, 2015, we produced 309.4 Bcfe, or 1,709 Mmcfe per day, compared to 247.5 Bcfe, or 1,367 Mmcfe per day, for the six months ended June 30, 2014. Natural gas production increased by 52.6 Bcf, or 22%, to 290.2 Bcf for the first six months of 2015 compared to 237.6 Bcf for the first six months of 2014. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program in Pennsylvania. Crude oil/condensate/NGL production increased by 1.6 Mmbbls, or 95%, to 3.2 Mmbbls in the first six months of 2015 from 1.6 Mmbbls in the first six months of 2014. This increase was the result of higher production associated with our oil-focused Eagle Ford Shale drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.

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 six months of 2015 was $2.32 per Mcf, 36% lower than the $3.60 per Mcf realized in the first six months of 2014. Our average realized crude oil price for the first six months of 2015 was $50.00 per Bbl, 49% lower than the $98.39 per Bbl realized in the first six months of 2014. These realized prices include gains and losses resulting from the settlement of commodity derivatives. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, 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, crude oil and NGL prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or 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.

We account for our derivative instruments on a mark-to-market basis with changes in fair value recognized in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments, we will likely experience volatility in our earnings from time to time due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 5 to the Condensed Consolidated Financial Statements for more information.

During the first six months of 2015, we drilled 87 gross wells (78.5 net) with a success rate of 100% compared to 76 gross wells (62.0 net) with a success rate of 100% for the comparable period of the prior year. Our total capital and exploration expenditures were $540.4 million for the six months ended June 30, 2015 compared to $594.0 million for the six months ended June 30, 2014. We allocate our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources.

Our full year 2015 drilling program includes approximately $900.0 million in capital and exploration expenditures and approximately $38.3 million in expected contributions to our equity method investments and is expected to be funded by operating cash flow, existing cash and borrowings under our revolving 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 six months ended June 30, 2015 were from funds generated from the sale of natural gas and crude oil production and net borrowings under our revolving credit facility. These cash flows were primarily used to fund our capital and exploration expenditures (including contributions to our equity method investments), interest payments on debt and payment of dividends. See below for additional discussion and analysis of cash flow.

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Effective April 17, 2015, we amended our revolving credit facility to extend the maturity date from May 2017 to April 2020 and to change the mechanism under which interest rate margins are determined for outstanding borrowings. The revolving credit facility, as amended, provides for an increase in the borrowing base from $3.1 billion to $3.4 billion and an increase in commitments from $1.4 billion to $1.8 billion. The amended credit facility also provides for an accordion feature, which allows us to increase the available credit line up to an additional $500 million if one or more of the existing or new banks agree to provide such increased amount. The borrowing base is redetermined annually under the terms of the revolving credit facility on April 1. In addition, either we or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details regarding our debt.

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, existing cash on hand and availability under our revolving credit facility, we have the capacity to finance our spending plans and maintain our strong financial position.

Cash Flows

Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, including seasonal influences and demand; however, the impact of other risks and uncertainties, such as decreases in crude oil and natural gas prices and other factors 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 revolving credit facility and liquidity available to meet our working capital requirements.



	Six Months Ended June 30,
(In thousands)	2015			2014
Cash flows provided by operating activities	$	438,591		$	584,948
Cash flows used in investing activities	(668,504		)	(612,504		)
Cash flows provided by financing activities	224,190			49,766
Net (decrease) increase in cash and cash equivalents	$	(5,723	)	$	22,210

Operating Activities. Net cash provided by operating activities in the first six months of 2015 decreased by $146.4 million over the first six months of 2014. This decrease was primarily due to lower operating revenues and higher operating expenses (excluding non-cash expenses), partially offset by favorable changes in working capital and other assets and liabilities. The decrease in operating revenues was primarily due to a decrease in realized natural gas and crude oil prices, partially offset by an increase in equivalent production. Average realized natural gas and crude oil prices decreased by 36% and 49%, respectively, for the first six months of 2015 compared to the first six months of 2014. Equivalent production increased by 25% for the first six months of 2015 compared to the first six months of 2014 due to higher natural gas and oil production.

See “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. 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 $56.0 million for the first six months of 2015 compared to the first six months of 2014. The increase was due to $27.5 million of higher capital expenditures, $28.1 million of changes in restricted cash balances and a $16.3 million increase in acquisition expenditures related to the acquisition of certain remaining leases associated with our south Texas asset acquisition that closed in the fourth quarter of 2014, partially offset by $12.1 million lower capital contributions associated with our equity method investments and $3.8 million higher proceeds from the sale of assets.

Financing Activities. Cash flows provided by financing activities increased by $174.4 million for the first six months of 2015 compared to the first six months of 2014. This increase was primarily due to $197.0 million of higher net borrowings, partially offset by a decrease of $14.9 million in tax benefits associated with our stock-based compensation and an increase of $7.8 million in capitalized debt issuance cost related to the amendment of our credit facility in April 2015.

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Capitalization

Information about our capitalization is as follows:



(Dollars in thousands)	June 30, 2015			December 31, 2014
Debt ⁽¹⁾	$	1,995,000		$	1,752,000
Stockholders' equity	2,145,916			2,142,733
Total capitalization	$	4,140,916		$	3,894,733
Debt to capitalization	48		%	45		%
Cash and cash equivalents	$	15,231		$	20,954


(1)	Includes $383.0 million and $140.0 million of borrowings outstanding under our revolving credit facility at June 30, 2015 and December 31, 2014, respectively.

During the six months ended June 30, 2015 and 2014, we paid dividends of $16.5 million ($0.04 per share) and $16.7 million ($0.04 per share) on our common stock, respectively. 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 expenditures, excluding any significant property acquisitions, with cash generated from operations and, if required, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.

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



	Six Months Ended June 30,
(In thousands)	2015		2014
Capital expenditures
Drilling and facilities	$	494,002	$	547,980
Leasehold acquisitions	12,825		26,584
Property acquisitions	16,300		—
Pipeline and gathering	1,089		227
Other	2,122		8,043
	526,338		582,834
Exploration expenditures	14,030		11,150
Total	$	540,368	$	593,984

For the full year of 2015, we plan to drill approximately 125 gross wells (115.0 net). In 2015, we plan to spend approximately $900.0 million in total capital and exploration expenditures, compared to $1.6 billion (excluding property acquisitions of $214.7 million) in 2014. See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation and Gathering Agreements”, “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 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 March 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for interim periods and annual period beginning after December 15, 2015; however, early adoption is permitted. We do not believe the adoption of this guidance will have a material effect on our financial position, results of operations or cash flows.

May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB finalized the delay of the effective date by one year, making the new standard effective for interim periods and annual period beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption; however, the entities reporting under U.S. GAAP are not permitted to adopt the standard earlier than the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

Results of Operations

Second Quarters of 2015 and 2014 Compared

We reported a net loss in the second quarter of 2015 of $27.5 million, or $0.07 per share, compared to net income of $118.4 million, or $0.28 per share, in the second quarter of 2014. The decrease in net income was primarily due to lower operating revenues, higher operating expenses and interest expense, partially offset by lower income taxes.

Revenue, Price and Volume Variances

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.



	Three Months Ended June 30,						Variance
Revenue Variances (In thousands)	2015			2014			Amount			Percent
Natural gas	$	224,806		$	437,761		$	(212,955	)	(49	)%
Crude oil and condensate	81,233			86,341			(5,108		)	(6	)%
Gain (loss) on derivative instruments	(6,819		)	(2,329		)	(4,490		)	(193	)%
Brokered natural gas	3,813			8,140			(4,327		)	(53	)%
Other	3,264			3,274			(10		)	—	%
	$	306,297		$	533,187		$	(226,890	)	(43	)%

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	Three Months Ended June 30,				Variance					Increase (Decrease) (In thousands)
	2015		2014		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	1.75	$	3.59	$	(1.84	)	(51	)%	$	(236,649	)
Crude oil and condensate ⁽²⁾	$	56.10	$	99.36	$	(43.26	)	(44	)%	(62,627		)
Total										$	(299,276	)
Volume Variances
Natural gas (Bcf)	128.4		121.8		6.6			5	%	$	23,694
Crude oil and condensate (Mbbl)	1,448		869		579			67	%	57,519
Total										$	81,213


(1)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.18 per Mcf . There was no impact in 2015.


(2)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.73 per Bbl. There was no impact in 2015.

Natural Gas Revenues

The decrease in natural gas revenues of $213.0 million is due to lower natural gas prices, partially offset by higher production. The increase in production was associated with the positive results of our Marcellus Shale drilling program in Pennsylvania, partially offset by lower production in east Texas due to normal production declines.

Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $5.1 million is due to lower crude oil prices, partially offset by higher production. The increase in production was a result of our oil-focused drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.

Gain (Loss) on Derivative Instruments

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis. Changes in fair value and cash settlements of derivative instruments are recognized in operating revenues in the Condensed Consolidated Statement of Operations.

Impact of Derivative Instruments on Operating Revenues



	Three Months Ended June 30,
(In thousands)	2015			2014
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	(22,320	)
Crude oil and condensate	—			(636		)
Gain (loss) on derivative instruments	51,045			(15,262		)
	$	51,045		$	(38,218	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(57,864		)	12,933
	$	(6,819	)	$	(25,285	)

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Brokered Natural Gas Revenue and Cost



	Three Months Ended June 30,				Variance					Price and Volume Variances (In thousands)
	2015		2014		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	2.82	$	4.96	$	(2.14	)	(43	)%	$	(2,889	)
Volume brokered (Mmcf)	x	1,350	x	1,642	(292		)	(18	)%	(1,438		)
Brokered natural gas (In thousands)	$	3,813	$	8,140						$	(4,327	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.14	$	4.28	$	(2.14	)	(50	)%	$	2,889
Volume brokered (Mmcf)	x	1,350	x	1,642	(292		)	(18	)%	1,257
Brokered natural gas (In thousands)	$	2,885	$	7,031						$	4,146

Brokered natural gas margin (In thousands)	$	928	$	1,109						$	(181	)

The $0.2 million decrease in brokered natural gas margin is a result of lower brokered volumes.

Operating and Other Expenses



	Three Months Ended June 30,						Variance
(In thousands)	2015			2014			Amount			Percent
Operating and Other Expenses
Direct operations	$	36,112		$	35,605		$	507		1	%
Transportation and gathering	98,295			83,976			14,319			17	%
Brokered natural gas	2,885			7,031			(4,146		)	(59	)%
Taxes other than income	11,611			12,816			(1,205		)	(9	)%
Exploration	5,298			4,676			622			13	%
Depreciation, depletion and amortization	152,513			157,563			(5,050		)	(3	)%
General and administrative	19,978			20,127			(149		)	(1	)%
	$	326,692		$	321,794		$	4,898		2	%

Earnings (loss) on equity method investments	$	1,512		$	756		$	756		100	%
Gain (loss) on sale of assets	(79		)	(1,496		)	1,417			95	%
Interest expense	24,168			16,334			7,834			48	%
Income tax (benefit) expense	(15,622		)	75,899			(91,521		)	(121	)%

Total costs and expenses from operations increased by $4.9 million, or 2%, in the second quarter of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:


•	Direct operations increased $0.5 million largely due to higher operating costs as a result of higher production and production costs associated with the south Texas asset acquisitions in the fourth quarter of 2014. These cost increases were partially offset by cost reductions from suppliers, improved operational efficiencies and lower workover costs in 2015 compared to 2014.


•	Transportation and gathering increased $14.3 million due to higher throughput as a result of higher Marcellus Shale production, higher transportation rates and the commencement of various transportation and gathering agreements in the Marcellus Shale during 2014.


•	Brokered natural gas decreased $4.1 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

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•	Taxes other than income decreased $1.2 million primarily due to $0.9 million lower production taxes resulting from lower oil prices, partially offset by higher oil production in south Texas.

•

Depreciation, depletion and amortization decreased $5.1 million, of which $23.1 million was due to lower DD&A rate of $1.01 per Mcfe for the second quarter of 2015 compared to $1.18 per Mcfe for the second quarter of 2014, partially offset by a $12.3 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus Shale drilling program and the impairment charge recorded in the fourth quarter of 2014 associated with higher DD&A rate properties. These decreases were partially offset by an increase in amortization of unproved properties of $5.0 million in the second quarter of 2015 due to an increase in amortization rates as a result of ongoing evaluation of our unproved properties and undeveloped leasehold acquisitions during the year.

•

General and administrative decreased $0.1 million due to $1.6 million lower expense associated with our supplemental employee incentive plan due to the change in fair value associated with the likelihood of our stock price achieving the trigger stock price specified in the plan and $1.0 million lower legal expenses. These decreases were partially offset by $4.0 million of higher stock-based compensation expense primarily due to a $4.3 million increase associated with the mark-to-market of our liability-based performance awards and the change in the liability associated with in our common stock held in the deferred compensation plan. The remaining increases and decreases in other expenses were not individually significant.

Earnings (loss) on equity method investments

The $0.8 million increase in equity method investments is the result of increased activity in 2015 compared to 2014.

Gain (Loss) on Sale of Assets

An aggregate loss of $1.5 million was recognized in the second quarter of 2014, primarily due to certain post-closing adjustments related to the sale of certain of our proved oil and gas properties in Oklahoma. There was no material gain (loss) on sale of assets in the second quarter of 2015.

Interest Expense

Interest expense increased $7.8 million due to $8.4 million of higher interest expense associated with our private placement in September 2014 of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65% and an increase in commitment fees on the unused portion of our revolving credit facility of $0.5 million. These increases were partially offset by lower interest expense of $1.1 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $346.3 million compared to approximately $574.2 million during the second quarter of 2015 and 2014, respectively, partially offset by a slightly higher weighted-average effective interest rate of approximately 2.2% during 2015 compared to approximately 2.1% in 2014, respectively.

Income Tax (Benefit) Expense

Income tax expense decreased $91.5 million due to lower pretax income and a lower effective tax rate. The effective tax rate for the second quarter of 2015 and 2014 was 36.2% and 39.1%, respectively. The decrease in the effective tax rate was primarily due to a change in our effective state income tax rates based on updated state apportionment factors in states in which we operate. The decrease in our state apportionment factors was primarily driven by a shift in the sourcing of revenues based on the location of customers to whom we ultimately sell our natural gas in the northeast United States.

First Six Months of 2015 and 2014 Compared

We reported net income in the first six months of 2015 of $12.7 million, or $0.03 per share, compared to $225.5 million, or $0.54 per share, in the first six months of 2014. The decrease in net income was due to lower operating revenues and higher operating expenses and interest expense, partially offset by lower income taxes.

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Revenue, Price and Volume Variances

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.



	Six Months Ended June 30,					Variance
Revenue Variances (In thousands)	2015		2014			Amount			Percent
Natural gas	$	584,997	$	870,571		$	(285,574	)	(33	)%
Crude oil and condensate	143,791		145,485			(1,694		)	(1	)%
Gain (loss) on derivative instruments	27,304		(2,329		)	29,633			1,272	%
Brokered natural gas	8,640		21,293			(12,653		)	(59	)%
Other	6,330		7,970			(1,640		)	(21	)%
	$	771,062	$	1,042,990		$	(271,928	)	(26	)%



	Six Months Ended June 30,				Variance					Increase (Decrease) (In thousands)
	2015		2014		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	2.02	$	3.66	$	(1.64	)	(45	)%	$	(478,090	)
Crude oil and condensate ⁽²⁾	$	50.00	$	98.70	$	(48.70	)	(49	)%	(140,022		)
Total										$	(618,112	)
Volume Variances
Natural gas (Bcf)	290.2		237.6		52.6			22	%	$	192,516
Crude oil and condensate (Mbbl)	2,876		1,474		1,402			95	%	138,328
Total										$	330,844


(1)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.39 per Mcf. There was no impact in 2015.


(2)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.58 per Bbl. There was no impact in 2015.

Natural Gas Revenues

The decrease in natural gas revenues of $285.6 million is due to lower natural gas prices, partially offset by higher production. The increase in production associated with the positive results of our Marcellus Shale drilling program in Pennsylvania.

Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $1.7 million is due to lower crude oil prices, partially offset by higher production. The increase in production was a result of our oil-focused Eagle Ford Shale drilling program in south Texas and production associated with the south Texas asset acquisitions in the fourth quarter of 2014.

Gain (Loss) on Derivative Instruments

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Impact of Derivative Instruments on Operating Revenues



	Six Months Ended June 30,
(In thousands)	2015			2014
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	(92,877	)
Crude oil and condensate	—			(854		)
Gain (loss) on derivative instruments	88,730			(15,262		)
	$	88,730		$	(108,993	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(61,426		)	12,933
	$	27,304		$	(96,060	)

Brokered Natural Gas Revenue and Cost



	Six Months Ended June 30,				Variance					Price and Volume Variances (In thousands)
	2015		2014		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	3.07	$	4.92	$	(1.85	)	(38	)%	$	(5,213	)
Volume brokered (Mmcf)	x	2,818	x	4,328	(1,510		)	(35	)%	(7,440		)
Brokered natural gas (In thousands)	$	8,640	$	21,293						$	(12,653	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.35	$	4.36	$	(2.01	)	(46	)%	$	5,664
Volume brokered (Mmcf)	x	2,818	x	4,328	(1,510		)	(35	)%	6,603
Brokered natural gas (In thousands)	$	6,624	$	18,891						$	12,267

Brokered natural gas margin (In thousands)	$	2,016	$	2,402						$	(386	)

The $0.4 million decrease in brokered natural gas margin is a result of lower brokered volumes partially offset by a decrease in purchase price that outpaced the decrease in sales price.

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Operating and Other Expenses



	Six Months Ended June 30,					Variance
(In thousands)	2015		2014			Amount			Percent
Operating and Other Expenses
Direct operations	$	72,129	$	71,439		$	690		1	%
Transportation and gathering	219,531		161,741			57,790			36	%
Brokered natural gas	6,624		18,891			(12,267		)	(65	)%
Taxes other than income	22,891		25,860			(2,969		)	(11	)%
Exploration	14,030		11,150			2,880			26	%
Depreciation, depletion and amortization	328,009		304,981			23,028			8	%
General and administrative	42,507		41,763			744			2	%
	$	705,721	$	635,825		$	69,896		11	%

Earnings (loss) on equity method investments	$	2,933	$	756		$	2,177		288	%
Gain (loss) on sale of assets	59		(2,781		)	2,840			102	%
Interest expense	47,734		32,891			14,843			45	%
Income tax expense	7,852		146,798			(138,946		)	(95	)%

Total costs and expenses from operations increased by $69.9 million, or 11%, in the first six months of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:


•	Direct operations increased $0.7 million largely due to higher operating costs as a result of higher production and production costs associated with the south Texas asset acquisitions in the fourth quarter of 2014. These cost increases were partially offset by cost reductions from suppliers, improved operational efficiencies and lower workover costs in 2015 compared to 2014.


•	Transportation and gathering increased $57.8 million due to higher throughput as a result of higher Marcellus Shale production, higher transportation rates and the commencement of various transportation and gathering agreements in the Marcellus Shale during 2014.


•	Brokered natural gas decreased $12.3 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.


•	Taxes other than income decreased $3.0 million due to $1.8 million lower production taxes resulting from lower oil prices, partially offset by higher oil production in south Texas and $0.9 million lower drilling impact fees associated with our Marcellus Shale drilling activities due to lower natural gas prices.


•	Exploration expense increased $2.9 million as a result of a $5.2 million charge related to the release of certain drilling rig contracts in south Texas, partially offset by lower exploratory dry hole costs of $2.1 million.

•

Depreciation, depletion and amortization increased $23.0 million, of which $72.0 million was due to higher equivalent production volumes, partially offset by $54.8 million due to a lower DD&A rate of $0.99 per Mcfe for the first six months of 2015 compared to $1.16 per Mcfe for the first six months of 2014. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus Shale drilling program and the impairment charge recorded in the fourth quarter of 2014 associated with higher DD&A rate properties. In addition, amortization of unproved properties increased $4.0 million as a result of ongoing evaluation of our unproved properties and undeveloped leasehold acquisitions during the year and accretion expense increased $1.3 million.

•

General and administrative increased $0.7 million due to higher stock-based compensation expense of $5.1 million primarily due to an $8.8 million increase associated with the mark-to-market of our liability-based performance awards and the change in liability associated with in our common stock held in the deferred compensation plan, partially offset by $3.2 million of lower expense associated with our supplemental employee incentive plan due to the change in fair value associated with the likelihood of our stock price achieving the

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trigger stock price specified in the plan and $1.7 million of lower employee-related costs. The remaining increases and decreases in other expenses were not individually significant.

Earnings (loss) on equity method investments

The $2.2 million increase in equity method investments is the result of increased activity in 2015 compared to 2014.

Gain (Loss) on Sale of Assets

An aggregate loss of $2.8 million was recognized in the first six months of 2014, primarily due to certain post-closing adjustments related to the sale of certain of our proved oil and gas properties in Oklahoma. There was no material gain (loss) on sale of assets in the first six months of 2015.

Interest Expense

Interest expense increased $14.8 million due to $16.7 million of higher interest expense associated with our private placement in September 2014 of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65% and higher commitment fees on the unused portion of our revolving credit facility of $1.0 million. These increases were partially offset by a decrease in interest expense of $3.1 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $272.0 million compared to approximately $565.2 million during the first six months of 2015 and 2014, respectively, partially offset by a slightly higher weighted-average effective interest rate of approximately 2.3% during 2015 compared to approximately 2.2% in 2014.

Income Tax Expense

Income tax expense decreased $138.9 million due to lower pretax income and a lower effective tax rate. The effective tax rate for the first six months of 2015 and 2014 was 38.1% and 39.4%, respectively. The decrease in the effective tax rate was primarily due to a change in our effective state income tax rates based on updated state apportionment factors in states in which we operate. The decrease in our state apportionment factors was primarily driven by a shift in the sourcing of revenues based on the location of customers to whom we ultimately sell our natural gas in the northeast United States.

Forward-Looking Information

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

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

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

Derivative Instruments and Risk Management Activities

Our risk management strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets through the use of commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our commodity derivatives generally cover a portion of our production and provide only partial price protection by limiting the benefit to us of increases in prices, while protecting us in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of our commodity derivatives. Please read the discussion below as well as Note 6 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative and risk management activities.

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Periodically, we enter into commodity derivatives, including collar and swap agreements, to protect against exposure to price declines related to our natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity derivatives 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 June 30, 2015, we had the following outstanding commodity derivatives:



				Collars						Swaps		Estimated Fair Value Asset (Liability) (In thousands)
				Floor			Ceiling
Type of Contract	Volume		Contract Period	Range	Weighted- Average		Range	Weighted- Average		Weighted- Average
Natural gas	35.7	Bcf	Jul. 2015 - Dec. 2015	$3.86 - $3.91	$	3.87	$4.27 - $4.43	$	4.35			$	32,359
Natural gas	35.7	Bcf	Jul. 2015 - Dec. 2015							$	3.92	35,860
Natural gas	17.9	Bcf	Jul. 2015 - Oct. 2015							$	3.36	8,008
												$	76,227

In the table above, natural gas prices are stated per Mcf.

The amounts set forth in the table above represent our derivative position at June 30, 2015 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Condensed Consolidated Financial Statements and is primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

During the first six months of 2015, natural gas collars with floor prices ranging from $3.86 to $3.91 per Mcf and ceiling prices ranging from $4.27 to $4.43 per Mcf covered 35.2 Bcf, or 12%, of natural gas production at an average price of $3.87 per Mcf. Natural gas swaps covered 53.7 Mcf, or 18%, of natural gas production at an average price of $3.85 per Mcf.

We are exposed to market risk on commodity 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 agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller.

Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.

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 Market Value of Other Financial Instruments

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

The fair value of 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 revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and the revolving credit facility is based on interest rates currently available to us.

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



	June 30, 2015				December 31, 2014
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt	$	1,995,000	$	2,028,913	$	1,752,000	$	1,850,867

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 second quarter of 2015 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 8 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

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.

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, 2014.

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

Issuer Purchases of Equity Securities

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. The maximum number of remaining shares that may be purchased under the plan as of June 30, 2015 was 10.1 million.

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ITEM 6. Exhibits



Exhibit Number		Description

15.1		Awareness letter of PricewaterhouseCoopers LLP.

31.1		302 Certification — Chairman, President and Chief Executive Officer.

31.2		302 Certification — Executive Vice President and Chief Financial Officer.

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)

July 24, 2015	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

July 24, 2015	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

July 24, 2015	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)