Coterra Energy - 10-Q quarterly report FY2015 Q3

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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 September 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 October 19, 2015, there were 413,874,655 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 September 30, 2015 and December 31, 2014		3

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

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

Condensed Consolidated Statement of Cash Flows (Unaudited) for the Nine Months Ended September 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		19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31

Item 4.	Controls and Procedures	33

Part II. Other Information

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

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

Item 6.	Exhibits	34

Signatures		35

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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)	September 30, 2015			December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	$	8,773		$	20,954
Accounts receivable, net	119,743			235,397
Income taxes receivable	16,218			3,612
Inventories	18,283			14,026
Derivative instruments	48,445			137,603
Other current assets	3,959			1,855
Total current assets	215,421			413,447
Properties and equipment, net (Successful efforts method)	5,141,404			4,925,711
Equity method investments	93,408			68,029
Other assets	34,439			30,529
	$	5,484,672		$	5,437,716

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	191,341		$	400,076
Current portion of long-term debt	20,000			—
Accrued liabilities	39,123			63,669
Income taxes payable	2,448			—
Deferred income taxes	12,673			35,273
Total current liabilities	265,585			499,018
Postretirement benefits	38,018			35,827
Long-term debt	2,017,000			1,752,000
Deferred income taxes	874,702			843,876
Asset retirement obligations	138,889			124,655
Other liabilities	28,741			39,607
Total liabilities	3,362,935			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 — 423,767,060 shares and 422,915,258 shares in 2015 and 2014, respectively	42,377			42,292
Additional paid-in capital	716,930			710,432
Retained earnings	1,671,416			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	2,121,737			2,142,733
	$	5,484,672		$	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 September 30,					Nine Months Ended September 30,
(In thousands, except per share amounts)	2015			2014		2015			2014
OPERATING REVENUES
Natural gas	$	222,963		$	347,970	$	807,960		$	1,218,540
Crude oil and condensate	59,014			82,563		202,804			228,047
Gain (loss) on derivative instruments	17,364			71,906		44,668			69,577
Brokered natural gas	4,010			6,501		12,650			27,794
Other	1,945			3,077		8,277			11,049
	305,296			512,017		1,076,359			1,555,007
OPERATING EXPENSES
Direct operations	34,818			37,802		106,947			109,241
Transportation and gathering	102,121			85,966		321,652			247,707
Brokered natural gas	3,020			5,680		9,643			24,570
Taxes other than income	11,407			10,933		34,298			36,794
Exploration	4,930			8,812		18,960			19,963
Depreciation, depletion and amortization	144,326			154,013		472,335			458,995
General and administrative	11,102			19,579		53,611			61,342
	311,724			322,785		1,017,446			958,612
Earnings (loss) on equity method investments	1,648			1,063		4,581			1,819
Gain (loss) on sale of assets	3,756			46		3,814			(2,735		)
INCOME (LOSS) FROM OPERATIONS	(1,024		)	190,341		67,308			595,479
Interest expense	24,510			17,422		72,244			50,312
Income (loss) before income taxes	(25,534		)	172,919		(4,936		)	545,167
Income tax (benefit) expense	(10,020		)	72,131		(2,169		)	218,928
NET INCOME (LOSS)	$	(15,514	)	$	100,788	$	(2,767	)	$	326,239

Earnings (loss) per share
Basic	$	(0.04	)	$	0.24	$	(0.01	)	$	0.78
Diluted	$	(0.04	)	$	0.24	$	(0.01	)	$	0.78

Weighted-average common shares outstanding
Basic	413,846			416,173		413,636			416,785
Diluted	413,846			418,093		413,636			418,468

Dividends per common share	$	0.02		$	0.02	$	0.06		$	0.06

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 September 30,					Nine Months Ended September 30,
(In thousands)	2015			2014		2015			2014
Net income (loss)	$	(15,514	)	$	100,788	$	(2,767	)	$	326,239
Other comprehensive income (loss), net of taxes:
Reclassification adjustment for settled cash flow hedge contracts⁽¹⁾	—			12,965		—			69,337
Changes in fair value of cash flow hedge contracts⁽²⁾	—			—		—			(80,175		)
Total other comprehensive income (loss)	—			12,965		—			(10,838		)
Comprehensive income (loss)	$	(15,514	)	$	113,753	$	(2,767	)	$	315,401


(1)	Net of income taxes of $(8,592) and $(45,951) for the three and nine months ended September 30, 2014, respectively.


(2)	Net of income taxes of $53,135 for the nine months ended September 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)



	Nine Months Ended September 30,
(In thousands)	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(2,767	)	$	326,239
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	472,335			458,995
Deferred income tax expense	8,226			181,439
(Gain) loss on sale of assets	(3,814		)	2,735
Exploratory dry hole cost	184			6,454
(Gain) loss on derivative instruments	(44,668		)	(69,577		)
Net cash received (paid) in settlement of derivative instruments	133,827			24,811
Amortization of debt issuance costs	3,395			3,378
Stock-based compensation and other	7,041			13,304
Changes in assets and liabilities:
Accounts receivable, net	112,712			30,418
Income taxes	(10,158		)	(23,430		)
Inventories	(4,256		)	3,737
Other current assets	(2,106		)	(147		)
Accounts payable and accrued liabilities	(83,432		)	(9,712		)
Other assets and liabilities	(1,565		)	607
Stock-based compensation tax benefit	—			(6,001		)
Net cash provided by operating activities	584,954			943,250

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(819,839		)	(964,741		)
Acquisitions	(16,312		)	(15,826		)
Proceeds from sale of assets	7,380			3,913
Restricted cash	—			28,094
Investment in equity method investments	(20,798		)	(28,784		)
Net cash used in investing activities	(849,569		)	(977,344		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	790,000			1,802,000
Repayments of debt	(505,000		)	(1,337,000		)
Treasury stock repurchases	—			(119,767		)
Dividends paid	(24,812		)	(25,018		)
Stock-based compensation tax benefit	—			6,001
Capitalized debt issuance costs	(7,838		)	(5,626		)
Other	84			91
Net cash provided by financing activities	252,434			320,681

Net (decrease) increase in cash and cash equivalents	(12,181		)	286,587
Cash and cash equivalents, beginning of period	20,954			23,400
Cash and cash equivalents, end of period	$	8,773		$	309,987

Supplemental non-cash transactions:
Change in accrued capital costs	(159,102		)	35,702

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 (loss).

With respect to the unaudited financial information of the Company as of September 30, 2015 and for the three and nine months ended September 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 October 23, 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 (the Act) 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 and annual periods beginning after December 15, 2015. 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 August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods 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, 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.

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2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	September 30, 2015			December 31, 2014
Proved oil and gas properties	$	8,701,932		$	7,984,979
Unproved oil and gas properties	415,355			492,208
Gathering and pipeline systems	243,089			241,272
Land, building and other equipment	116,801			109,758
	9,477,177			8,828,217
Accumulated depreciation, depletion and amortization	(4,335,773		)	(3,902,506		)
	$	5,141,404		$	4,925,711

At September 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

The Company holds a 25% equity interest in Constitution Pipeline Company, LLC (Constitution) and a 20% equity interest in Meade Pipeline Co LLC (Meade). Activity related to these equity method investments is as follows:



	Constitution				Meade						Total
	Nine Months Ended September 30,				Nine Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2015		2014		2015			2014			2015		2014
Balance at beginning of period	$	64,269	$	26,892	$	3,760		$	—		$	68,029	$	26,892
Contributions	13,500		26,575		7,298			2,209			20,798		28,784
Earnings (loss) on equity method investments	4,608		1,938		(27		)	(119		)	4,581		1,819
Balance at end of period	$	82,377	$	55,405	$	11,031		$	2,090		$	93,408	$	57,495

The following table represents summarized financial information for Constitution as derived from the respective unaudited financial statements of Constitution for the nine months ended September 30, 2015 and 2014, respectively:



	Nine Months Ended September 30, 2015
(In thousands)	2015		2014
Revenues	$	—	$	—
Income (loss) from continuing operations	$	19,366	$	9,723
Net income	$	19,366	$	9,723

The Company records the activity for its equity method investments on a one month lag; however, the above summarized financial information represents Constitution's operations for the nine months ended September 30, 2015 and 2014, respectively. 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.

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4. Debt and Credit Agreements

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



(In thousands)	September 30, 2015			December 31, 2014
Total debt
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	425,000			140,000
Current maturities
7.33% weighted-average fixed rate notes	(20,000		)	—
Long-term debt, excluding current maturities	$	2,017,000		$	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 September 30, 2015.

Revolving credit facility

At September 30, 2015, the Company had $425.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 2.1% 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 September 30, 2015 and 2014 was approximately 2.1% and 2.2%, respectively, and for the nine months ended September 30, 2015 and 2014 was approximately 2.2%.

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 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.

The Company incurred $7.8 million of debt issuance costs in connection with the amendment to the revolving credit facility, which were capitalized and will be amortized over the term of the amended credit facility. The remaining unamortized

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costs of $8.3 million will be amortized over the term of the amended revolving credit facility in accordance with ASC-470-50, "Debt Modifications and Extinguishments."

5. Derivative Instruments and Hedging Activities

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 September 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 September 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

17.9

Bcf

Oct. 2015 - Dec. 2015

$3.86 - $3.91

3.87

$4.27 - $4.43

4.35

Natural gas

17.9

Bcf

Oct. 2015 - Dec. 2015

3.92

Natural gas

4.5

Bcf

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	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
Commodity contracts	Derivative instruments (current assets)	$	48,445	$	137,603	$	—	$	—

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



(In thousands)	September 30, 2015		December 31, 2014
Derivative assets
Gross amounts of recognized assets	$	48,445	$	137,603
Gross amounts offset in the statement of financial position	—		—
Net amounts of assets presented in the statement of financial position	48,445		137,603
Gross amounts of financial instruments not offset in the statement of financial position	—		2,338
Net amount	$	48,445	$	139,941

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

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



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

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	2015		2014			2015		2014
Natural gas revenues	$	—	$	(21,427	)	$	—	$	(114,304	)
Crude oil and condensate revenues	—		(130		)	—		(984		)
	$	—	$	(21,557	)	$	—	$	(115,288	)

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations



	Three Months Ended September 30,						Nine Months Ended September 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	$	—		$	(21,427	)	$	—		$	(43,747	)
Crude oil and condensate	—			(130		)	—			(766		)
Gain (loss) on derivative instruments	45,097			40,073			133,827			24,811
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(27,733		)	31,833			(89,159		)	44,766
	$	17,364		$	50,349		$	44,668		$	25,064

	$	17,364		$	50,349		$	44,668		$	(45,711	)

For the three and nine months ended September 30, 2014, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations related to derivative instruments designated as cash flow hedges.

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.

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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 September 30, 2015
Assets
Deferred compensation plan	$	12,586	$	—	$	—	$	12,586
Derivative instruments	—		16,152		32,293		48,445
Total assets	$	12,586	$	16,152	$	32,293	$	61,031
Liabilities
Deferred compensation plan	$	24,263	$	—	$	—	$	24,263
Total liabilities	$	24,263	$	—	$	—	$	24,263



(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 instruments	—		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 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.

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:



	Nine Months Ended September 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	23,867			(33,804		)
Included in other comprehensive income	—			(21,068		)
Settlements	(77,532		)	74,271
Transfers in and/or out of Level 3	—			—
Balance at end of period	$	32,293		$	15,489

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	(53,665	)	$	40,467

There were no transfers between Level 1 and Level 2 measurements for the nine months ended September 30, 2015 and 2014.

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 September 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.

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 amount and fair value of debt is as follows:



	September 30, 2015						December 31, 2014
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
Debt	$	2,037,000		$	2,007,444		$	1,752,000	$	1,850,867
Current maturities	(20,000		)	(20,775		)	—		—
Long-term debt, excluding current maturities	$	2,017,000		$	1,986,669		$	1,752,000	$	1,850,867

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7. Asset Retirement Obligations

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



(In thousands)	Nine Months Ended September 30, 2015
Balance at beginning of period	$	126,655
Liabilities incurred	9,230
Liabilities settled	(83		)
Accretion expense	5,087
Balance at end of period	$	140,889

As of September 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.

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 (benefit) expense in the third quarter of 2015 and 2014 was $(2.9) million and $5.7 million, respectively, and $11.6 million and $15.1 million during the first nine months of 2015 and 2014, respectively. Stock-based compensation expense is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

During the first nine months of 2014, the Company recognized a $6.0 million tax benefit related to the federal tax deduction in excess of book compensation cost for employee stock-based compensation. The Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable. There was no tax benefit recognized from stock-based compensation during the first nine months of 2015.

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.

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Restricted Stock Awards

During the first nine 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 nine months of 2015, 49,447 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $28.02. 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.

During the first nine months of 2015, 230,068 shares of common stock were issued pursuant to previously granted restricted stock units at a weighted-average grant date per unit value of $13.45 to two directors upon their departure from the Company's Board of Directors.

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.

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 nine 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 September 30, 2015, it is considered probable that the criteria for these awards will be met.

Hybrid Performance Share Awards. During the first nine 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 September 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 nine 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.

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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			September 30, 2015
Fair value per performance share award	$	19.29		$7.66 - $10.04
Assumptions:
Stock price volatility	32.3		%	29.8% - 39.2%
Risk free rate of return	1.0		%	0.0% - 0.7%
Expected dividend yield	0.3		%	0.4	%

Supplemental Employee Incentive Plan

The Company recognized stock-based compensation (benefit) expense related to the Company’s Supplemental Employee Incentive Plan IV (SEIP IV) of $(0.1) million and $0.2 million for the three months ended September 30, 2015 and 2014, respectively, and $(0.2) million and $3.3 million for the nine months ended September 30, 2015 and 2014, respectively, 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 SEIP IV.

The interim trigger date for the SEIP IV lapsed on September 30, 2015. There were no amounts paid with respect to that trigger date as the Company's common stock did equal or exceed the interim price goal of $55.00 per share.

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



	September 30, 2015
Stock price volatility	39.3	%
Risk free rate of return	0.6	%
Annual salary increase rate	4.0	%
Annual turnover rate	4.6	%

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 September 30,		Nine Months Ended September 30,
(In thousands)	2015	2014	2015	2014
Weighted-average shares - basic	413,846	416,173	413,636	416,785
Dilution effect of stock appreciation rights and stock awards at end of period	—	1,920	—	1,683
Weighted-average shares - diluted	413,846	418,093	413,636	418,468

Weighted-average stock awards and shares excluded from diluted EPS due to the anti-dilutive effect	1,692	—	1,390	461

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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 September 30,					Nine Months Ended September 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	$	—	$	(21,427	)	$	—	$	(114,304	)	Natural gas revenues
Commodity contracts	—		(130		)	—		(984		)	Crude oil and condensate revenues
	—		(21,557		)	—		(115,288		)	Total before tax
	—		8,592			—		45,951			Tax benefit (expense)
Total reclassifications for the period	$	—	$	(12,965	)	$	—	$	(69,337	)	Net of tax

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12. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:



(In thousands)	September 30, 2015			December 31, 2014
Accounts receivable, net
Trade accounts	$	114,154		$	227,835
Joint interest accounts	1,585			2,245
Other accounts	5,001			6,515
	120,740			236,595
Allowance for doubtful accounts	(997		)	(1,198		)
	$	119,743		$	235,397

Inventories
Tubular goods and well equipment	$	15,016		$	10,675
Natural gas in storage	3,205			3,281
Other accounts	62			70
	$	18,283		$	14,026

Other assets
Deferred compensation plan	$	12,586		$	13,115
Debt issuance costs	21,791			17,349
Other accounts	62			65
	$	34,439		$	30,529

Accounts payable
Trade accounts	$	33,312		$	54,949
Natural gas purchases	1,859			2,407
Royalty and other owners	75,976			97,298
Accrued capital costs	63,324			222,426
Taxes other than income	12,432			16,806
Drilling advances	81			88
Other accounts	4,357			6,102
	$	191,341		$	400,076

Accrued liabilities
Employee benefits	$	12,501		$	22,815
Taxes other than income	10,694			7,128
Interest payable	13,595			30,677
Other accounts	2,333			3,049
	$	39,123		$	63,669

Other liabilities
Deferred compensation plan	$	24,263		$	28,932
Other accounts	4,478			10,675
	$	28,741		$	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 September 30, 2015, and the related condensed consolidated statements of operations and of comprehensive income for the three-month and nine-month periods ended September 30, 2015 and September 30, 2014 and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2015 and September 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

October 23, 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 nine month periods ended September 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).

Financial and Operating Overview

Financial and operating results for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 are as follows:


•	Equivalent production increased 71.6 Bcfe, or 19%, from 379.9 Bcfe (1,392 Mmcfe per day) to 451.5 Bcfe (1,654 Mmcfe per day).


•	Natural gas production increased 58.9 Bcf, or 16%, from 364.3 Bcf to 423.2 Bcf, primarily as the result of higher production in the Marcellus Shale associated with our drilling program in Pennsylvania.


•	Crude oil/condensate/NGL production increased 2.1 Mmbbls, or 81%, from 2.6 Mmbbls to 4.7 Mmbbls, as a 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.


•	Average realized natural gas price (including the effects of derivative settlements) was $2.23 per Mcf, 35% lower than the $3.41 per Mcf realized in the comparable period of the prior year.


•	Average realized crude oil price (including the effects of derivative settlements) was $48.00 per Bbl, 51% lower than the $97.05 per Bbl realized in the comparable period of the prior year.


•	Drilled 114 gross wells (105.5 net) with a success rate of 100% compared to 125 gross wells (108.5 net) with a success rate of 99% for the comparable period of the prior year.


•	Total capital and exploration expenditures were $695.8 million, compared to $1.0 billion in the comparable period of the prior year.


•	Average rig count during 2015 was approximately 3.7 rigs in the Marcellus Shale and approximately 2.1 rigs in the Eagle Ford Shale, compared to an average rig count in the Marcellus Shale of approximately 6.1 rigs and approximately 2.4 rigs in the Eagle Ford Shale in the comparable period of the prior year.

Market Conditions and Commodity Prices

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. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. As a result, we cannot accurately predict future commodity 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. In addition, location differentials have increased in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. We expect prices to remain volatile for the remainder of year. 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 have continued to remain low or decline during 2015 compared to 2014. In the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge. However, following the impairment recorded in the fourth quarter of 2014, we do not believe that further impairment of our oil and gas properties is reasonably likely to occur in the near future.

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 associated with our derivative instruments, we will likely experience volatility in our earnings 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.

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We believe we are positioned to endure the current cyclical downturn in the oil and gas industry and the continued volatility in current and future commodity prices by:


•	Continuing to exercise discipline in our capital program by reducing our capital and exploration expenditures and number of wells drilled compared to the prior year.


•	Continuing to optimize our drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production.


•	Continuing to possess a strong balance sheet with sufficient availability under our revolving credit facility to meet our spending plans.

Outlook

Our full year 2015 drilling program includes approximately $875.0 million in capital and exploration expenditures and approximately $35.5 million in expected contributions to our equity method investments and is expected to be funded by operating cash flow, borrowings under our revolving credit facility and existing cash. 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. 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.

As a result of substantially lower natural gas and crude oil prices in 2015 compared to 2014, we have reduced our current year budgeted capital and exploration expenditures. In addition, we plan to operate an average of approximately 5.4 rigs in 2015, a decrease from an average of approximately 8.9 rigs in 2014. During the first nine months of 2015, we have strategically curtailed production levels in the Marcellus Shale due to lower price realizations in the region; however, we anticipate an increase in fourth quarter 2015 production over third quarter 2015 as a result of increased demand in winter months and the expected addition of new takeaway capacity and long-term sales agreements.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the nine months ended September 30, 2015 were 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.

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.

Subsequent to the April 2015 redetermination of our borrowing base, commodity prices have continued to decline. We do not expect the recent commodity price declines to result in a significant reduction of our future borrowing base and related commitments under the revolving credit facility. In the event our borrowing base or commitments are reduced, unless prices continue to decline significantly from current price levels, we do not believe that the such reduction would have a significant impact on our ability to service our debt and fund our drilling program and related operations.

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.

We were in compliance with all restrictive financial covenants for both the revolving credit facility and fixed rate notes as of September 30, 2015. See our Form 10-K for further discussion of our restrictive financial covenants.

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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 natural gas and crude oil prices and other factors as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced commodity 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.



	Nine Months Ended September 30,
(In thousands)	2015			2014
Cash flows provided by operating activities	$	584,954		$	943,250
Cash flows used in investing activities	(849,569		)	(977,344		)
Cash flows provided by financing activities	252,434			320,681
Net (decrease) increase in cash and cash equivalents	$	(12,181	)	$	286,587

Operating Activities. Net cash provided by operating activities in the first nine months of 2015 decreased by $358.3 million over the first nine 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 35% and 51%, respectively, for the first nine months of 2015 compared to the first nine months of 2014. Equivalent production increased by 19% for the first nine months of 2015 compared to the first nine months of 2014 due to higher natural gas production in the Marcellus Shale and higher oil production in the Eagle Ford Shale.

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.

Investing Activities. Cash flows used in investing activities decreased by $127.8 million for the first nine months of 2015 compared to the first nine months of 2014. The decrease was due to $144.4 million of lower capital expenditures and acquisition costs, $8.0 million lower capital contributions associated with our equity method investments and $3.5 million higher proceeds from the sale of assets. These decreases were partially offset by $28.1 million of changes in restricted cash balances.

Financing Activities. Cash flows provided by financing activities decreased by $68.2 million for the first nine months of 2015 compared to the first nine months of 2014. This decrease was primarily due to $180.0 million of lower net borrowings, a decrease of $6.0 million in tax benefits associated with our stock-based compensation and higher capitalized debt issuance costs of $2.2 million related to the amendment of our credit facility in April 2015. These decreases were partially offset by lower treasury stock repurchases of $119.8 million as no shares were repurchased in 2015.

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Capitalization

Information about our capitalization is as follows:



(Dollars in thousands)	September 30, 2015			December 31, 2014
Debt ⁽¹⁾	$	2,037,000		$	1,752,000
Stockholders' equity	2,121,737			2,142,733
Total capitalization	$	4,158,737		$	3,894,733
Debt to total capitalization	49		%	45		%
Cash and cash equivalents	$	8,773		$	20,954


(1)	Includes $425.0 million and $140.0 million of borrowings outstanding under our revolving credit facility at September 30, 2015 and December 31, 2014, respectively, and $20.0 million of current portion of long-term debt at September 30, 2015.

During the nine months ended September 30, 2015 and 2014, we paid dividends of $24.8 million ($0.06 per share) and $25.0 million ($0.06 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. In 2015, our budgeted capital and exploration expenditures are expected to exceed cash flows from operations, requiring us to fund a portion of our capital and exploration expenditures through borrowings under our revolving credit facility.

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



	Nine Months Ended September 30,
(In thousands)	2015		2014
Capital expenditures
Drilling and facilities	$	639,274	$	936,887
Leasehold acquisitions	16,430		43,582
Property acquisitions	16,312		15,826
Pipeline and gathering	1,807		723
Other	3,042		12,797
	676,865		1,009,815
Exploration expenditures	18,960		19,963
Total	$	695,825	$	1,029,778

In 2015, we plan to spend approximately $875.0 million in total capital and exploration expenditures, compared to $1.6 billion (excluding property acquisitions of $214.7 million) in 2014. See “Financial and Operating 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 and annual periods beginning after December 15, 2015. 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 August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods 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, 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

Third Quarters of 2015 and 2014 Compared

We reported a net loss in the third quarter of 2015 of $15.5 million, or $0.04 per share, compared to net income of $100.8 million, or $0.24 per share, in the third quarter of 2014. The decrease in net income was primarily due to lower operating revenues and higher interest expense, partially offset by lower income taxes and operating expenses and higher gain (loss) on sale of assets.

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 September 30,				Variance
Revenue Variances (In thousands)	2015		2014		Amount			Percent
Natural gas	$	222,963	$	347,970	$	(125,007	)	(36	)%
Crude oil and condensate	59,014		82,563		(23,549		)	(29	)%
Gain (loss) on derivative instruments	17,364		71,906		(54,542		)	(76	)%
Brokered natural gas	4,010		6,501		(2,491		)	(38	)%
Other	1,945		3,077		(1,132		)	(37	)%
	$	305,296	$	512,017	$	(206,721	)	(40	)%

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	Three Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2015		2014		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	1.68	$	2.75	$	(1.07	)	(39	)%	$	(142,332	)
Crude oil and condensate ⁽²⁾	$	43.71	$	94.68	$	(50.97	)	(54	)%	(68,805		)
Total										$	(211,137	)
Volume Variances
Natural gas (Bcf)	133.0		126.7		6.3			5	%	$	17,325
Crude oil and condensate (Mbbl)	1,350		872		478			55	%	45,256
Total										$	62,581


(1)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.17 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 $0.15 per Bbl. There was no impact in 2015.

Natural Gas Revenues

The decrease in natural gas revenues of $125.0 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 $23.5 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

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 September 30,
(In thousands)	2015			2014
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	(21,427	)
Crude oil and condensate	—			(130		)
Gain (loss) on derivative instruments	45,097			40,073
	$	45,097		$	18,516
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(27,733		)	31,833
	$	17,364		$	50,349

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Brokered Natural Gas Revenue and Cost



	Three Months Ended September 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)	$	2.95	$	4.31	$	(1.36	)	(32	)%	$	(1,847	)
Volume brokered (Mmcf)	x	1,358	x	1,508	(150		)	(10	)%	(644		)
Brokered natural gas (In thousands)	$	4,010	$	6,501						$	(2,491	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.22	$	3.77	$	(1.55	)	(41	)%	$	2,105
Volume brokered (Mmcf)	x	1,358	x	1,508	(150		)	(10	)%	555
Brokered natural gas (In thousands)	$	3,020	$	5,680						$	2,660

Brokered natural gas margin (In thousands)	$	990	$	821						$	169

The $0.2 million increase in brokered natural gas margin is a result of a decrease in purchase price that outpaced the decrease in sales price, partially offset by lower brokered volumes.

Operating and Other Expenses



	Three Months Ended September 30,					Variance
(In thousands)	2015			2014		Amount			Percent
Operating and Other Expenses
Direct operations	$	34,818		$	37,802	$	(2,984	)	(8	)%
Transportation and gathering	102,121			85,966		16,155			19	%
Brokered natural gas	3,020			5,680		(2,660		)	(47	)%
Taxes other than income	11,407			10,933		474			4	%
Exploration	4,930			8,812		(3,882		)	(44	)%
Depreciation, depletion and amortization	144,326			154,013		(9,687		)	(6	)%
General and administrative	11,102			19,579		(8,477		)	(43	)%
	$	311,724		$	322,785	$	(11,061	)	(3	)%

Earnings (loss) on equity method investments	$	1,648		$	1,063	$	585		55	%
Gain (loss) on sale of assets	3,756			46		3,710			8,065	%
Interest expense	24,510			17,422		7,088			41	%
Income tax (benefit) expense	(10,020		)	72,131		(82,151		)	(114	)%

Total costs and expenses from operations decreased by $11.1 million, or 3%, in the third quarter of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:


•	Direct operations decreased $3.0 million largely due to cost reductions from suppliers, improved operational efficiencies and lower workover and plugging and abandonment costs in 2015 compared to 2014. These decreases were partially offset by higher operating costs associated with the south Texas asset acquisitions in the fourth quarter of 2014.


•	Transportation and gathering increased $16.2 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 throughout 2014.


•	Brokered natural gas decreased $2.7 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

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•

Taxes other than income increased $0.5 million primarily due to $1.2 million of higher ad valorem taxes due to increased activity in south Texas. This increase is partially offset by $1.3 million lower production taxes resulting from lower crude oil prices, partially offset by higher oil production in south Texas. The remaining increases and decreases in taxes other than income were not individually significant.


•	Exploration expense decreased $3.9 million as a result of $4.3 million lower exploratory dry hole costs, partially offset by a $1.0 million higher costs associated with the purchase of well data and mapping services. The remaining increases and decreases in other expenses were not individually significant.

•

Depreciation, depletion and amortization decreased $9.7 million, of which $31.1 million was due to a lower DD&A rate of $0.89 per Mcfe for the third quarter of 2015 compared to $1.11 per Mcfe for the third quarter of 2014, partially offset by a $10.7 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to lower cost 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 fields. The decrease in depletion was partially offset by an increase in amortization of unproved properties of $10.2 million in the third quarter of 2015 due to an increase in amortization rates as a result of ongoing evaluation of our unproved properties and the acquisition of undeveloped leaseholds in south Texas in late 2014.


•	General and administrative decreased $8.5 million due to $8.6 million of lower stock-based compensation expense as a result of a decline in the Company's stock price during the third quarter of 2015 compared to the third quarter of 2014. The remaining increases and decreases in other expenses were not individually significant.

Gain (Loss) on Sale of Assets

An aggregate gain of $3.8 million was recognized in the third quarter of 2015 primarily due to due to the sale of certain of our unproved oil and gas properties in east Texas. There were no significant gains or losses on the sale of assets recognized in the third quarter of 2014.

Interest Expense

Interest expense increased $7.1 million due to $7.3 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 $0.4 million. These increases were partially offset by lower interest expense of $0.5 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $413.6 million and approximately $476.6 million during the third quarter of 2015 and 2014, respectively, and a slightly lower weighted-average effective interest rate of approximately 2.1% during 2015 compared to approximately 2.2% in 2014.

Income Tax (Benefit) Expense

Income tax expense decreased $82.2 million primarily due to lower pretax income and a slightly lower effective tax rate. The effective tax rate for the third quarter of 2015 and 2014 was 39.2% and 41.7%, respectively. The decrease in the effective tax rate is primarily due to a decrease in the blended state statutory tax rate as a result of changes in our state apportionment factors in the states in which we operate.

First Nine Months of 2015 and 2014 Compared

We reported a net loss in the first nine months of 2015 of $2.8 million, or $0.01 per share, compared to net income of $326.2 million, or $0.78 per share, in the first nine months of 2014. The decrease in net income was due to lower operating revenues and higher operating expenses and interest expense, partially offset by a higher gain on sale of assets and 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.



	Nine Months Ended September 30,				Variance
Revenue Variances (In thousands)	2015		2014		Amount			Percent
Natural gas	$	807,960	$	1,218,540	$	(410,580	)	(34	)%
Crude oil and condensate	202,804		228,047		(25,243		)	(11	)%
Gain (loss) on derivative instruments	44,668		69,577		(24,909		)	(36	)%
Brokered natural gas	12,650		27,794		(15,144		)	(54	)%
Other	8,277		11,049		(2,772		)	(25	)%
	$	1,076,359	$	1,555,007	$	(478,648	)	(31	)%



	Nine Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2015		2014		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	1.91	$	3.35	$	(1.44	)	(43	)%	$	(607,895	)
Crude oil and condensate ⁽²⁾	$	48.00	$	97.21	$	(49.21	)	(51	)%	(207,901		)
Total										$	(815,796	)
Volume Variances
Natural gas (Bcf)	423.2		364.3		58.9			16	%	$	197,315
Crude oil and condensate (Mbbl)	4,225		2,346		1,879			80	%	182,658
Total										$	379,973


(1)	Prices in 2014 include the impact of cash flow hedge settlements during the period, which decreased the price by $0.31 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 $0.42 per Bbl. There was no impact in 2015.

Natural Gas Revenues

The decrease in natural gas revenues of $410.6 million is due to lower natural gas prices, partially offset by higher 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 $25.2 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



	Nine Months Ended September 30,
(In thousands)	2015			2014
Cash received (paid) on settlement of derivative instruments
Natural gas	$	—		$	(114,304	)
Crude oil and condensate	—			(984		)
Gain (loss) on derivative instruments	133,827			24,811
	$	133,827		$	(90,477	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(89,159		)	44,766
	$	44,668		$	(45,711	)

Brokered Natural Gas Revenue and Cost



	Nine Months Ended September 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)	$	3.03	$	4.76	$	(1.73	)	(36	)%	$	(7,224	)
Volume brokered (Mmcf)	x	4,176	x	5,835	(1,659		)	(28	)%	(7,920		)
Brokered natural gas (In thousands)	$	12,650	$	27,794						$	(15,144	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.31	$	4.21	$	(1.90	)	(45	)%	$	7,934
Volume brokered (Mmcf)	x	4,176	x	5,835	(1,659		)	(28	)%	6,993
Brokered natural gas (In thousands)	$	9,643	$	24,570						$	14,927

Brokered natural gas margin (In thousands)	$	3,007	$	3,224						$	(217	)

The $0.2 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



	Nine Months Ended September 30,						Variance
(In thousands)	2015			2014			Amount			Percent
Operating and Other Expenses
Direct operations	$	106,947		$	109,241		$	(2,294	)	(2	)%
Transportation and gathering	321,652			247,707			73,945			30	%
Brokered natural gas	9,643			24,570			(14,927		)	(61	)%
Taxes other than income	34,298			36,794			(2,496		)	(7	)%
Exploration	18,960			19,963			(1,003		)	(5	)%
Depreciation, depletion and amortization	472,335			458,995			13,340			3	%
General and administrative	53,611			61,342			(7,731		)	(13	)%
	$	1,017,446		$	958,612		$	58,834		6	%

Earnings (loss) on equity method investments	$	4,581		$	1,819		$	2,762		152	%
Gain (loss) on sale of assets	3,814			(2,735		)	6,549			239	%
Interest expense	72,244			50,312			21,932			44	%
Income tax (benefit) expense	(2,169		)	218,928			(221,097		)	(101	)%

Total costs and expenses from operations increased by $58.8 million, or 6%, in the first nine months of 2015 compared to the same period of 2014. The primary reasons for this fluctuation are as follows:


•	Direct operations decreased $2.3 million largely due to cost reductions from suppliers, improved operational efficiencies and lower workover costs in 2015 compared to 2014. These decreases were partially offset by higher operating costs associated with the south Texas asset acquisitions in the fourth quarter of 2014.


•	Transportation and gathering increased $73.9 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 throughout 2014.


•	Brokered natural gas decreased $14.9 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.


•	Taxes other than income decreased $2.5 million due to $3.1 million lower production taxes resulting from lower crude oil prices, partially offset by higher oil production in south Texas. This decrease was partially offset by $1.5 million of higher ad valorem taxes due to increased activity in south Texas.


•	Exploration expense decreased $1.0 million as a result of lower exploratory dry hole costs of $6.4 million, partially offset by a $5.2 million charge related to the release of certain drilling rig contracts in south Texas in the first half of 2015.

•

Depreciation, depletion and amortization increased $13.3 million, of which $82.0 million was due to higher equivalent production volumes, offset by $85.2 million due to a lower DD&A rate of $0.96 per Mcfe for the first nine months of 2015 compared to $1.15 per Mcfe for the first nine months of 2014. The lower DD&A rate was primarily due to lower cost 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 fields. In addition, amortization of unproved properties increased $14.2 million as a result of ongoing evaluation of our unproved properties and the acquisition of undeveloped leaseholds in south Texas in late 2014. Accretion expense increased $1.6 million due to the acquisition of proved properties in south Texas in late 2014 and an increase in asset retirement obligations as a result of revisions of previous estimates recorded in the fourth quarter of 2014.


•	General and administrative decreased $7.7 million due to lower stock-based compensation expense of $3.5 million primarily due to a decline in the Company's stock price during the first nine months of 2015 compared to the first nine months of 2014. The remaining increases and decreases in other expenses were not individually significant.

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Gain (Loss) on Sale of Assets

An aggregate gain of $3.8 million was recognized in the first nine months of 2015 due to the sale of certain unproved oil and gas properties in east Texas. An aggregate loss of $2.7 million was recognized in the first nine 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.

Interest Expense

Interest expense increased $21.9 million due to $24.1 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 $1.4 million. These increases were partially offset by a decrease in interest expense of $3.6 million associated with our revolving credit facility due to a decrease in weighted-average borrowings based on daily balances of approximately $319.7 million and approximately $535.4 million during the first nine months of 2015 and 2014, respectively.

Income Tax (Benefit) Expense

Income tax expense decreased $221.1 million due to lower pretax income, partially offset by a higher effective tax rate. The effective tax rate for the first nine months of 2015 and 2014 was 43.9% and 40.2%, respectively. The increase in the effective tax rate was primarily due to changes in permanent taxable items and their relative rate impact in relation to pre-tax income (loss), partially offset by 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.

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

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agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

As of September 30, 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	17.9	Bcf	Oct. 2015 - Dec. 2015	$3.86 - $3.91	$	3.87	$4.27 - $4.43	$	4.35			$	21,478
Natural gas	17.9	Bcf	Oct. 2015 - Dec. 2015							$	3.92	23,727
Natural gas	4.5	Bcf	Oct. 2015							$	3.36	3,255
												$	48,460

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

The amounts set forth in the table above represent our derivative position at September 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 nine 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 53.0 Bcf, or 13%, of natural gas production at an average price of $3.87 per Mcf. Natural gas swaps covered 85.0 Mcf, or 20%, of natural gas production at an average price of $3.79 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 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 amount and estimated fair value of debt is as follows:



	September 30, 2015						December 31, 2014
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
Debt	$	2,037,000		$	2,007,444		$	1,752,000	$	1,850,867
Current maturities	(20,000		)	(20,775		)	—		—
Long-term debt, excluding current maturities	$	2,017,000		$	1,986,669		$	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 third 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 September 30, 2015 was 10.1 million shares.

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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)

October 23, 2015	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 23, 2015	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 23, 2015	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)

Coterra Energy - 10-Q quarterly report FY2015 Q3

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