Edgar Filing: CABOT OIL & GAS CORP

COG-09.30.2014-10Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2014

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 20, 2014, there were 413,019,880 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS



		Page
Part I. Financial Information

Item 1.	Financial Statements

Condensed Consolidated Balance Sheet at September 30, 2014 and December 31, 2013		3

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2014 and 2013		4

Condensed Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2014 and 2013		5

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2014 and 2013		6

Notes to the Condensed Consolidated Financial Statements		7

Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information		21

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	34

Part II. Other Information

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 6.	Exhibits	35

Signatures		36

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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, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	309,987		$	23,400
Restricted cash	—			28,094
Accounts receivable, net	191,270			222,476
Inventories	13,731			17,468
Deferred income taxes	53,725			81,855
Other current assets	19,233			5,606
Total current assets	587,946			378,899
Properties and equipment, net (Successful efforts method)	5,130,213			4,546,227
Equity method investments	57,495			26,892
Other assets	31,610			29,062
	$	5,807,264		$	4,981,080

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	379,787		$	288,801
Accrued liabilities	44,843			87,513
Income taxes payable	8,161			31,591
Total current liabilities	432,791			407,905
Postretirement benefits	35,936			33,554
Long-term debt	1,612,000			1,147,000
Deferred income taxes	1,208,036			1,067,912
Asset retirement obligation	114,241			73,853
Other liabilities	37,789			46,254
Total liabilities	3,440,793			2,776,478

Commitments and contingencies

Stockholders’ equity
Common stock:
Authorized — 960,000,000 and 480,000,000 shares of $0.10 par value in 2014 and 2013, respectively
Issued — 422,912,560 and 422,014,681 shares in 2014 and 2013, respectively	42,291			42,201
Additional paid-in capital	713,087			710,940
Retained earnings	1,929,026			1,627,805
Accumulated other comprehensive income (loss)	(19,199		)	(8,361		)
Less treasury stock, at cost:
9,638,980 and 5,618,166 shares in 2014 and 2013, respectively	(298,734		)	(167,983		)
Total stockholders’ equity	2,366,471			2,204,602
	$	5,807,264		$	4,981,080

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)	2014		2013		2014			2013
OPERATING REVENUES
Natural gas	$	347,970	$	341,901	$	1,218,540		$	1,004,085
Crude oil and condensate	82,563		84,209		228,047			220,090
Gain (loss) on derivative instruments	71,906		—		69,577			—
Brokered natural gas	6,501		7,165		27,794			26,302
Other	3,077		2,575		11,049			8,338
	512,017		435,850		1,555,007			1,258,815
OPERATING EXPENSES
Direct operations	37,802		32,923		109,241			101,398
Transportation and gathering	85,966		60,803		247,707			159,672
Brokered natural gas	5,680		5,913		24,570			21,006
Taxes other than income	10,933		11,532		36,794			34,583
Exploration	8,812		3,891		19,963			12,444
Depreciation, depletion and amortization	154,013		168,980		458,995			469,022
General and administrative	19,579		24,697		61,342			82,009
	322,785		308,739		958,612			880,134
Earnings (loss) on equity method investments	1,063		278		1,819			614
Gain (loss) on sale of assets	46		4,421		(2,735		)	4,601
INCOME FROM OPERATIONS	190,341		131,810		595,479			383,896
Interest expense	17,422		16,074		50,312			49,366
Income before income taxes	172,919		115,736		545,167			334,530
Income tax expense	72,131		45,847		218,928			132,703
NET INCOME	$	100,788	$	69,889	$	326,239		$	201,827

Earnings per share
Basic	$	0.24	$	0.17	$	0.78		$	0.48
Diluted	$	0.24	$	0.17	$	0.78		$	0.48

Weighted-average common shares outstanding
Basic	416,173		420,986		416,785			420,664
Diluted	418,093		423,453		418,468			422,824

Dividends per common share	$	0.02	$	0.02	$	0.06		$	0.04

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	2014		2013			2014			2013
Net income	$	100,788	$	69,889		$	326,239		$	201,827

Other comprehensive income (loss), net of taxes:
Reclassification adjustment for settled cash flow hedge contracts⁽¹⁾	12,965		(11,942		)	69,337			(22,372		)
Changes in fair value of cash flow hedge contracts⁽²⁾	—		(1,447		)	(80,175		)	31,417
Postretirement benefits:
Amortization of net loss⁽³⁾	—		70			—			319
Total other comprehensive income (loss)	12,965		(13,319		)	(10,838		)	9,364

Comprehensive income (loss)	$	113,753	$	56,570		$	315,401		$	211,191


(1)	Net of income taxes of $(8,592) and $7,742 for the three months ended September 30, 2014 and 2013, respectively, and $(45,951) and $14,504 for the nine months ended September 30, 2014 and 2013, respectively.


(2)	Net of income taxes of $937 for the three months ended September 30, 2013 and $53,135 and $(20,366) for the nine months ended September 30, 2014 and 2013, respectively.


(3)	Net of income taxes of $(46) and $(206) for the three and nine months ended September 30, 2013, respectively.

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

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)



	Nine Months Ended September 30,
(In thousands)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	326,239		$	201,827
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	458,995			469,022
Deferred income tax expense	181,439			107,235
(Gain) loss on sale of assets	2,735			(4,601		)
Exploration expense	6,454			807
Unrealized (gain) loss on derivative instruments	(44,766		)	—
Amortization of debt issuance costs	3,378			2,767
Stock-based compensation and other	13,304			36,684
Changes in assets and liabilities:
Accounts receivable, net	30,418			(6,321		)
Income taxes	(23,430		)	(3,639		)
Inventories	3,737			(6,665		)
Other current assets	(147		)	(1,547		)
Accounts payable and accrued liabilities	(9,712		)	(19,837		)
Other assets and liabilities	607			228
Stock-based compensation tax benefit	(6,001		)	(9,284		)
Net cash provided by operating activities	943,250			766,676

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(964,741		)	(843,400		)
Acquisitions	(15,826		)	(128		)
Proceeds from sale of assets	3,913			15,174
Restricted cash	28,094			—
Investment in equity method investments	(28,784		)	(8,624		)
Net cash used in investing activities	(977,344		)	(836,978		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	1,802,000			585,000
Repayments of debt	(1,337,000		)	(510,000		)
Treasury stock repurchases	(119,767		)	—
Dividends paid	(25,018		)	(16,830		)
Stock-based compensation tax benefit	6,001			9,284
Capitalized debt issuance costs	(5,626		)	—
Other	91			44
Net cash provided by financing activities	320,681			67,498

Net increase (decrease) in cash and cash equivalents	286,587			(2,804		)
Cash and cash equivalents, beginning of period	23,400			30,736
Cash and cash equivalents, end of period	$	309,987		$	27,932

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, 2013 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported net income.

With respect to the unaudited financial information of the Company as of September 30, 2014 and for the three and nine months ended September 30, 2014 and 2013, 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 24, 2014 appearing herein states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. The Company does not expect the adoption of this guidance to have a material impact 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. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern, as a new Sub-topic, Accounting Standards Codification Sub-topic 205.40. The new going concern standard codifies in generally accepted accounting principles (GAAP) management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for interim and annual periods beginning on or after December 15, 2016 and early adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its financial position or results of operations.

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2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	September 30, 2014			December 31, 2013
Proved oil and gas properties	$	7,405,851		$	6,362,570
Unproved oil and gas properties	354,882			375,428
Gathering and pipeline systems	240,705			239,958
Land, buildings and other equipment	105,143			94,243
	8,106,581			7,072,199
Accumulated depreciation, depletion and amortization	(2,976,368		)	(2,525,972		)
	$	5,130,213		$	4,546,227

At September 30, 2014, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

Subsequent Events

Acquisitions

In October 2014, the Company completed the acquisition of certain proved and unproved oil and gas properties in the Eagle Ford Shale in south Texas for approximately $210.0 million. Total cash consideration paid by the Company as of the closing date was approximately $186.2 million, subject to customary post-closing adjustments, which reflects the impact of customary purchase price adjustments and an adjustment for consents that the seller was unable to obtain for certain leaseholds prior to closing.

Divestitures

In October 2014, the Company completed the divestiture of certain proved and unproved oil and gas properties in east Texas to a third party for approximately $44.3 million. Total cash consideration received by the Company as of the closing date was approximately $39.9 million, subject to customary post-closing adjustments, which reflects the impact of customary purchase price adjustments. The net book value associated with the oil and gas properties held for sale as of September 30, 2014 was approximately $21.5 million and is included in properties and equipment, net in the Condensed Consolidated Balance Sheet.

3. Equity Method Investments

During the nine months ended September 30, 2014, the Company made contributions of approximately $28.8 million to its equity method investments ($26.6 million to Constitution Pipeline Company, LLC and $2.2 million to Meade Pipeline Co LLC (Meade)).

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.

Meade Pipeline Co LLC

In February 2014, the Company acquired a 20% equity interest in Meade. Meade was formed to participate in the development and construction of a 177-mile pipeline (Central Penn Line) that will transport natural gas from Susquehanna County, Pennsylvania to an interconnect with Transcontinental Gas Pipe Line Company, LLC’s (Transco) mainline in Lancaster County, Pennsylvania. The new pipeline will be constructed and operated by Transco and will be owned by Transco and Meade in proportion to their respective ownership percentages of approximately 61% and 39%, respectively. Under the terms of the Meade LLC agreement, the Company agreed to invest its proportionate share of Meade’s anticipated costs associated with the new pipeline of $149 million, which is expected to occur over the next three to four years. The expected in-service date for the new pipeline is scheduled for the second half of 2017.

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4. Debt and Credit Agreements

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



(In thousands)	September 30, 2014		December 31, 2013
Long-Term 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% 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		—
Revolving credit facility	—		460,000
	$	1,612,000	$	1,147,000

Effective April 15, 2014, the lenders under the Company’s revolving credit facility approved an increase in the Company’s borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At September 30, 2014, the Company had no borrowings outstanding under its revolving credit facility and had $1.4 billion available for future borrowings. The Company’s weighted-average effective interest rate for the three months ended September 30, 2014 and 2013 was approximately 2.2% and for the nine months ended September 30, 2014 and 2013 was approximately 2.2% and 2.3%, respectively.

The Company was in compliance with all restrictive financial covenants for both the revolving credit facility and fixed rate notes as of September 30, 2014.

3.65% Weighted-Average Fixed Rate Notes

In September 2014, the Company issued $925 million principal amount of senior unsecured fixed-rate notes to a group of 24 investors in a private placement. The notes have bullet maturities and were issued in three separate tranches as follows:



	Principal	Term	Maturity Date	Coupon
Tranche 1	$100,000,000	7 years	September 2021	3.24	%
Tranche 2	$575,000,000	10 years	September 2024	3.67	%
Tranche 3	$250,000,000	12 years	September 2026	3.77	%

Interest on each series of the 3.65% weighted‑average fixed rate notes is payable semi‑annually. The Company may prepay all or any portion of the notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make‑whole premium. The notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. Those covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) of at least 1.75 to 1.0 and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. The notes are also subject to customary events of default.

5. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivatives to manage its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes.

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. Accordingly, the change in the fair value of derivatives designated as hedges that are effective is recorded to accumulated other comprehensive income (loss) in stockholders’ equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges and the change in fair

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value of realized cash settlements of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

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 will be reclassified into natural gas and crude oil and condensate revenues in the Condensed Consolidated Statement of Operations in future periods as the underlying hedge transactions occur. Through September 30, 2014, the Company has reclassified after-tax losses of $26.8 million that were previously frozen in accumulated other comprehensive income (loss) to natural gas and crude oil and condensate revenues in the Condensed Consolidated Statement of Operations. As of September 30, 2014, the Company expects to reclassify $17.4 million in after-tax losses associated with its commodity derivatives from accumulated other comprehensive income (loss) to natural gas and crude oil and condensate revenues in the Condensed Consolidated Statement of Operations over the next three months.

As of September 30, 2014, the Company had the following outstanding commodity derivatives:



				Collars						Swaps
				Floor			Ceiling
Type of Contract	Volume		Contract Period	Range	Weighted-Average		Range	Weighted- Average		Weighted- Average
Natural gas	84.9	Bcf	Oct. 2014 - Dec. 2014	$3.60-$4.37	$	4.13	$4.22-$4.80	$	4.51
Natural gas	26.8	Bcf	Oct. 2014 - Dec. 2014							$	4.05
Natural gas	35.5	Bcf	Jan. 2015 - Dec. 2015	—	$	3.86	$4.36-$4.43	$	4.40
Natural gas	35.5	Bcf	Jan. 2015 - Dec. 2015							$	4.12
Crude oil	184.0	Mbbl	Oct. 2014 - Dec. 2014							$	97.00

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

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, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Derivatives Designated as Hedges
Commodity contracts	Other current assets	$	—	$	3,019	$	—	$	—
Commodity contracts	Accrued liabilities	—		—		—		13,912
Derivatives Not Designated as Hedges
Commodity contracts	Other current assets	16,503		—		—		—
Commodity contracts	Accrued liabilities	—		—		102		—
Commodity contracts	Other liabilities	—		—		549		—
		$	16,503	$	3,019	$	651	$	13,912

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



(In thousands)	September 30, 2014			December 31, 2013
Derivative Assets
Gross amounts of recognized assets	$	19,445		$	13,792
Gross amounts offset in the statement of financial position	(2,942		)	(10,773		)
Net amounts of assets presented in the statement of financial position	16,503			3,019
Gross amounts of financial instruments not offset in the statement of financial position	238			373
Net amount	$	16,741		$	3,392

Derivative Liabilities
Gross amounts of recognized liabilities	$	3,593		$	24,685
Gross amounts offset in the statement of financial position	(2,942		)	(10,773		)
Net amounts of liabilities presented in the statement of financial position	651			13,912
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	651		$	13,912

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

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	2014		2013			2014			2013
Commodity contracts	$	—	$	(2,384	)	$	(133,310	)	$	51,783

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2014⁽¹⁾			2013			2014⁽¹⁾			2013
Natural gas revenues	$	(21,427	)	$	20,766		$	(114,304	)	$	33,822
Crude oil and condensate revenues	(130		)	(1,082		)	(984		)	3,054
	$	(21,557	)	$	19,684		$	(115,288	)	$	36,876


(1)	The Company ceased hedge accounting effective April 1, 2014. For the three and nine months ended September 30, 2014, a loss of approximately $21.6 million and $44.5 million, respectively, were reclassified into income. These amounts were previously frozen in accumulated other comprehensive income (loss).

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Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

The amount of gain (loss) recognized in the Condensed Consolidated Statement of Operations on derivative instruments is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2014			2013			2014			2013
Derivatives Designated as Hedges
Realized
Natural gas	$	—		$	20,766		$	(70,557	)	$	33,822
Crude oil and condensate	—			(1,082		)	(218		)	3,054
	$	—		$	19,684		$	(70,775	)	$	36,876
Derivatives Not Designated as Hedges
Realized
Natural gas	$	(21,427	)	$	—		$	(43,747	)	$	—
Crude oil and condensate	(130		)	—			(766		)	—
Gain (loss) on derivative instruments	40,073			—			24,811			—
Unrealized
Gain (loss) on derivative instruments	31,833			—			44,766			—
	$	50,349		$	—		$	25,064		$	—

	$	50,349		$	19,684		$	(45,711	)	$	36,876

For the three and nine months ended September 30, 2014 and 2013, respectively, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations related to derivative instruments designated as hedges.

Additional Disclosures about Derivative Instruments and Hedging Activities

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligations under the agreements. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty.

Certain counterparties to the Company’s derivative instruments are also lenders under its revolving credit facility. The Company’s revolving credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liabilities in certain situations.

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

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties and other assets, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were impaired as of September 30, 2014 and 2013 and no other assets or liabilities were required to be recognized at fair value on a non-recurring basis, additional disclosures were not provided.

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

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Financial Assets and Liabilities

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



(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		September 30, 2014
Assets
Deferred compensation plan	$	12,815	$	—	$	—	$	12,815
Derivative contracts	—		1,578		17,867		19,445
Total assets	$	12,815	$	1,578	$	17,867	$	32,260
Liabilities
Deferred compensation plan	$	30,277	$	—	$	—	$	30,277
Derivative contracts	—		1,216		2,377		3,593
Total liabilities	$	30,277	$	1,216	$	2,377	$	33,870



(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		December 31, 2013
Assets
Deferred compensation plan	$	12,507	$	—	$	—	$	12,507
Derivative contracts	—		—		13,792		13,792
Total assets	$	12,507	$	—	$	13,792	$	26,299
Liabilities
Deferred compensation plan	$	33,211	$	—	$	—	$	33,211
Derivative contracts	—		6,983		17,702		24,685
Total liabilities	$	33,211	$	6,983	$	17,702	$	57,896

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

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

The 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 net financial assets (liabilities) classified as Level 3 in the fair value hierarchy:



	Nine Months Ended September 30,
(In thousands)	2014			2013
Balance at beginning of period	$	(3,910	)	$	41,159
Total gains (losses) (realized or unrealized):
Realized and unrealized gains (losses) included in earnings	(33,804		)	33,822
Included in other comprehensive income	(21,068		)	24,287
Settlements	74,271			(33,822		)
Transfers in and/or out of level 3	—			—
Balance at end of period	$	15,489		$	65,446

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

There were no transfers between Level 1 and Level 2 measurements for the three and nine months ended September 30, 2014 and 2013.

Fair Value of Other Financial Instruments

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

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of long-term debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and 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 long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy due to the unobservable nature of the inputs.

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



	September 30, 2014				December 31, 2013
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	1,612,000	$	1,697,654	$	1,147,000	$	1,224,273

7. Asset Retirement Obligation

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



(In thousands)	Nine Months Ended September 30, 2014
Balance at beginning of period	$	75,853
Liabilities incurred	4,360
Liabilities settled	(411		)
Liabilities divested	(899		)
Change in estimate	33,810
Accretion expense	3,528
Balance at end of period	$	116,241

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The change in estimate during 2014 is attributable to an increase in costs of materials and services. The increase in cost of materials and services is primarily due to more rigorous plugging and abandonment techniques associated with the Company's horizontal wells in certain areas of its operations and the lack of availability of service providers in areas with minimal activity.

As of both September 30, 2014 and December 31, 2013, 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 obligation.

8. Commitments and Contingencies

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. Except for certain new and amended transportation agreements described below, 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.

Transportation and Gathering Agreements

During the first nine months of 2014, the Company entered into or amended certain natural gas transportation agreements associated with the Company’s production in Pennsylvania. These agreements increased the Company’s future aggregate obligations under its transportation commitments by approximately $230.5 million over the next 13 years compared to those amounts 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 is not material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

9. Postretirement Benefits

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2014		2013		2014		2013
Service cost	$	456	$	455	$	1,368	$	1,285
Interest cost	407		355		1,221		1,145
Amortization of net loss	—		116		—		525
	$	863	$	926	$	2,589	$	2,955

The guidance for retirement benefits provides that the net actuarial loss is not amortized if it is less than 10% of the postretirement obligation. Accordingly, the Company does not expect to amortize its net actuarial loss from accumulated other comprehensive income (loss) during 2014.

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10. Stock-based Compensation

General

Stock-based compensation expense during the first nine months of 2014 and 2013 was $15.1 million and $41.0 million, respectively, and is included in general and administrative expense in the Condensed Consolidated Statement of Operations. Stock-based compensation expense in the third quarter of 2014 and 2013 was $5.7 million and $12.2 million, respectively.

During the first nine months of 2014 and 2013, the Company realized a $6.0 million and $9.3 million tax benefit, respectively, 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.

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

Restricted Stock Awards

During the first nine months of 2014, 46,000 restricted stock awards were granted to employees with a weighted-average grant date per share value of $34.96. The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The Company used an annual forfeiture rate assumption of 5.0% for purposes of recognizing stock-based compensation expense for restricted stock awards.

Restricted Stock Units

During the first nine months of 2014, 35,870 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date per unit value of $38.73. The fair value of these units is measured based on the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.

Performance Share Awards

The performance period for the awards granted in 2014 commenced on January 1, 2014 and ends on December 31, 2016. 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 average of the high and low 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 2014, 241,130 Employee Performance Share Awards were granted at a grant date per share value of $39.43. 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, 2014, it is considered probable that the criteria for these awards will be met.

Hybrid Performance Share Awards. During the first nine months of 2014, 123,257 Hybrid Performance Share Awards were granted at a grant date per share value of $39.43. The 2014 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, 2014, 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 Company calculates the fair value of these awards using a Monte Carlo simulation model. The equity component of these awards is valued on the grant date and is not marked to market, while the liability component of the awards is valued as of the end of each reporting period on a mark-to-market basis.

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TSR Performance Share Awards. During the first nine months of 2014, 184,885 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 fourteen other companies in the Company’s peer group over a three-year performance period.

The following assumptions were used to determine the grant date fair value of the equity component (February 20, 2014) and the period-end fair value of the liability component of the TSR Performance Share Awards:



	Grant Date			September 30, 2014
Fair value per performance share award	$	32.04		$7.19 - $25.22
Assumptions:
Stock price volatility	41.3		%	27.5% - 120.4%
Risk free rate of return	0.7		%	0.02% - 0.7%
Expected dividend yield	0.2		%	0.2	%

Supplemental Employee Incentive Plan

The Company recognized stock-based compensation expense of $0.2 million and $4.1 million for the three months ended September 30, 2014 and 2013, respectively, and $3.3 million and $9.2 million for the nine months ended September 30, 2014 and 2013, respectively, related to the Company’s Supplemental Employee Incentive Plans, which is included in general and administrative expense in the Condensed Consolidated Statement of Operations. In August 2014, the Company paid $13.0 million associated with amounts that were previously deferred in accordance with the Company’s Supplemental Employee Incentive Plan III. Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for additional information on the provisions of the Plan.

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



	September 30, 2014
Stock price volatility	33.9	%
Risk free rate of return	1.0	%
Annual salary increase rate	4.0	%
Annual turnover rate	4.6	%

11. Earnings per Common Share

Basic 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.



	Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2014	2013	2014	2013
Weighted-average shares - basic	416,173	420,986	416,785	420,664
Dilution effect of stock appreciation rights and stock awards at end of period	1,920	2,467	1,683	2,160
Weighted-average shares - diluted	418,093	423,453	418,468	422,824

Weighted-average stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	—	1	461	3

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12. Accumulated Other Comprehensive Income (Loss)

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



(In thousands)	Net Gain (Loss) on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2013	$	(6,551	)	$	(1,810	)	$	(8,361	)
Other comprehensive income before reclassifications	(80,175		)	—			(80,175		)
Amounts reclassified from accumulated other comprehensive income	69,337			—			69,337
Net current-period other comprehensive income	(10,838		)	—			(10,838		)
Balance at September 30, 2014	$	(17,389	)	$	(1,810	)	$	(19,199	)

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)	2014			2013			2014			2013			Consolidated Statement of Operations
Net gain (loss) on cash flow hedges
Commodity contracts	$	(21,427	)	$	20,766		$	(114,304	)	$	33,822		Natural gas revenues
Commodity contracts	(130		)	(1,082		)	(984		)	3,054			Crude oil and condensate revenues

Postretirement benefits
Amortization of net loss	—			(116		)	—			(525		)	General and administrative expense
	(21,557		)	19,568			(115,288		)	36,351			Total before tax
	8,592			(7,696		)	45,951			(14,298		)	Tax benefit (expense)
Total reclassifications for the period	$	(12,965	)	$	11,872		$	(69,337	)	$	22,053		Net of tax

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13. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:



(In thousands)	September 30, 2014			December 31, 2013
Accounts receivable, net
Trade accounts	$	190,328		$	215,361
Joint interest billing	1,493			7,261
Income taxes receivable	—			922
Other accounts	439			746
	192,260			224,290
Allowance for doubtful accounts	(990		)	(1,814		)
	$	191,270		$	222,476

Inventories
Natural gas in storage	$	3,596		$	9,056
Tubular goods and well equipment	10,080			8,396
Other accounts	55			16
	$	13,731		$	17,468

Other current assets
Prepaid balances and other	$	2,730		$	2,587
Derivative instruments	16,503			3,019
	$	19,233		$	5,606

Other assets
Deferred compensation plan	$	12,815		$	12,507
Debt issuance cost	18,725			16,476
Other accounts	70			79
	$	31,610		$	29,062

Accounts payable
Trade accounts	$	53,938		$	26,023
Natural gas purchases	6,813			2,052
Royalty and other owners	102,933			79,150
Accrued capital costs	185,525			146,899
Taxes other than income	12,906			13,677
Drilling advances	89			14,093
Other accounts	17,583			6,907
	$	379,787		$	288,801

Accrued liabilities
Employee benefits	$	18,798		$	43,599
Taxes other than income	10,459			6,894
Interest payable	12,833			20,211
Derivative instruments	102			13,912
Other accounts	2,651			2,897
	$	44,843		$	87,513

Other liabilities
Deferred compensation plan	$	30,277		$	33,211
Derivative instruments	549			—
Other accounts	6,963			13,043
	$	37,789		$	46,254

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14. CAPITAL STOCK

Incentive Plans

On May 1, 2014, the Company’s shareholders approved the 2014 Incentive Plan, which replaced the 2004 Incentive Plan that expired on April 29, 2014. Under the 2014 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2014 Incentive Plan consisting of stock options or stock awards. A total of 18 million shares of common stock may be issued under the 2014 Incentive Plan. Under the 2014 Incentive Plan, no more than 10 million shares may be issued pursuant to incentive stock options. No additional awards may be granted under the 2014 Incentive Plan on or after May 1, 2024.

No additional awards will be granted under any of the Company’s prior plans, including the 2004 Incentive Plan. Awards outstanding under the 2004 Incentive Plan will remain outstanding in accordance with their original terms and conditions.

Increase in Authorized Shares

In May 2014, the Company’s shareholders approved an increase in the authorized number of shares of common stock from 480 million to 960 million shares.

Treasury Stock

In August 1998, the Board of Directors authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of any stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs currently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase common stock of the Company.

During the first nine months of 2014, the Company repurchased 4.0 million shares for a total cost of $130.8 million. Since the authorization date, the Company has repurchased 29.6 million shares of the 40.0 million total shares authorized for a total cost of approximately $380.3 million, of which 20.0 million shares have been retired. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. As of September 30, 2014, 9.6 million shares were held as treasury stock.

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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, 2014, and the related condensed consolidated statements of operations and of comprehensive income for the three and nine month periods ended September 30, 2014 and 2013 and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 2014 and 2013. 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, 2013, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and of cash flows for the year then ended (not presented herein), and in our report dated February 28, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet information as of December 31, 2013, 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 24, 2014

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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, 2014 and 2013 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, 2013 (Form 10-K).

Overview

On an equivalent basis, our production for the nine months ended September 30, 2014 increased by 30% compared to the nine months ended September 30, 2013. For the nine months ended September 30, 2014, we produced 379.9 Bcfe, or 1.4 Bcfe per day, compared to 291.7 Bcfe, or 1.1 Bcfe per day, for the nine months ended September 30, 2013. Natural gas production increased by 86.7 Bcf, or 31%, to 364.3 Bcf for the first nine months of 2014 compared to 277.5 Bcf for the first nine months of 2013. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program. Partially offsetting the production increase in the Marcellus Shale were decreases in production in west Texas and Oklahoma due to certain non-core asset dispositions in the fourth quarter of 2013 and normal production declines in Texas and West Virginia. Crude oil/condensate/NGL production increased by 0.2 MMbbls, or 10%, to 2.6 MMbbls in the first nine months of 2014 from 2.4 MMbbls in the first nine months of 2013. This increase was due to higher production resulting from our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for the first nine months of 2014 was $3.41 per Mcf, 6% lower than the $3.62 per Mcf realized in the first nine months of 2013. Our average realized crude oil price for the first nine months of 2014 was $97.05 per Bbl, 6% lower than the $103.07 per Bbl realized in the first nine months of 2013. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to “Results of Operations” below.

Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, crude oil and NGL prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success.

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments are accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments, we will likely experience volatility in our earnings from time to time due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 5 to the Condensed Consolidated Financial Statements for more information.

During the first nine months of 2014, we drilled 125 gross wells (108.5 net) with a success rate of 99% compared to 134 gross wells (110.7 net) with a success rate of 98% for the comparable period of the prior year. Our total capital and exploration expenditures were $1,029.8 million for the nine months ended September 30, 2014 compared to $867.4 million for the nine months ended September 30, 2013. The increase in capital spending was the result of our Marcellus Shale horizontal drilling program in northeast Pennsylvania and our drilling program in the Eagle Ford Shale in south Texas. We allocate our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources. Our 2014 capital program includes $1.45 billion to $1.55 billion in capital and exploration expenditures (excluding the south Texas acquisition discussed below) and approximately $36.2 million in expected contributions to our equity method investments and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our revolving credit facility. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

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Acquisitions and Divestitures

In October 2014, we completed the acquisition of certain proved and unproved oil and gas properties in south Texas for approximately $210.0 million. Total cash consideration paid as of the closing date was approximately $186.2 million, subject to customary post-closing adjustments, which reflects the impact of customary purchase price adjustments and an adjustment for consents that the seller was unable to obtain for certain leaseholds prior to closing. The acquisition was funded with proceeds from the private placement of senior unsecured fixed rate notes completed in September 2014.

In October 2014, we completed the divestiture of certain proved and unproved oil and gas properties in east Texas to a third party for approximately $44.3 million. Total cash consideration received by the Company as of the closing date was approximately $39.9 million, subject to customary post-closing adjustments, which reflects the impact of customary purchase price adjustments.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the nine months ended September 30, 2014 were from funds generated from the sale of natural gas and crude oil production and the issuance of fixed-rate notes. These cash flows were primarily used to fund our capital and exploration expenditures, repayment of borrowings under our revolving credit facility, share repurchases and payment of dividends. See below for additional discussion and analysis of cash flow.

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, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

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



	Nine Months Ended September 30,
(In thousands)	2014			2013
Cash flows provided by operating activities	$	943,250		$	766,676
Cash flows used in investing activities	(977,344		)	(836,978		)
Cash flows provided by financing activities	320,681			67,498
Net increase (decrease) in cash and cash equivalents	$	286,587		$	(2,804	)

Operating Activities. Net cash provided by operating activities in the first nine months of 2014 increased by $176.6 million over the first nine months of 2013. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and an increase in working capital and other assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production, partially offset by the decrease in realized natural gas and crude oil prices. Equivalent production volumes increased by 30% for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 primarily due to higher natural gas production. Average realized natural gas prices decreased by 6% and average realized crude oil prices decreased by 6% for the first nine months of 2014 compared to the first nine months of 2013.

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

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Investing Activities. Cash flows used in investing activities increased by $140.4 million for the first nine months of 2014 compared to the first nine months of 2013. The increase was due to $121.3 million of higher capital expenditures, a $20.2 million increase in capital contributions associated with our equity method investments, a $15.7 million increase in acquisition expenditures related to the deposit paid associated with the acquisition of south Texas assets that closed in October 2014 and a decrease of $11.3 million in proceeds from sale of assets. Partially offsetting the increases was a $28.1 million decrease in restricted cash related to the release of funds by our qualified intermediary due to a lapse in the statutory holding period and the funding of oil and gas lease acquisitions during the first nine months of 2014 associated with like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.

Financing Activities. Cash flows provided by financing activities increased by $253.2 million for the first nine months of 2014 compared to the first nine months of 2013. This increase was primarily due to $390.0 million of higher net borrowings, partially offset by an increase in share repurchases of $119.8 million, an $8.2 million increase in dividend payments, an increase of $5.6 million associated with capitalized debt issuance costs and a decrease of $3.3 million in tax benefits associated with our stock-based compensation.

In September 2014, we completed a private placement of $925 million aggregate principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 3.65%, consisting of amounts due in 2021, 2024 and 2026.

Effective April 15, 2014, the lenders under our revolving credit facility approved an increase in our borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At September 30, 2014, we had no borrowings outstanding and had $1.4 billion available for future borrowings under our revolving credit facility.

See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details regarding our long-term debt.

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

Capitalization

Information about our capitalization is as follows:



(Dollars in thousands)	September 30, 2014			December 31, 2013
Debt ⁽¹⁾	$	1,612,000		$	1,147,000
Stockholders' equity	2,366,471			2,204,602
Total capitalization	$	3,978,471		$	3,351,602
Debt to capitalization	41		%	34		%
Cash and cash equivalents	$	309,987		$	23,400


(1)	Includes $460.0 million of borrowings outstanding under our revolving credit facility at December 31, 2013. At September 30, 2014, there were no borrowings outstanding under our revolving credit facility.

During the nine months ended September 30, 2014, we repurchased 4.0 million shares for a total cost of $130.8 million. We also paid dividends of $25.0 million ($0.06 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

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, when necessary, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.

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



	Nine Months Ended September 30,
(In thousands)	2014		2013
Capital expenditures
Drilling and facilities	$	936,887	$	793,601
Leasehold acquisitions	43,582		55,023
Property acquisitions	15,826		128
Pipeline and gathering	723		579
Other	12,797		5,584
	1,009,815		854,915
Exploration expense	19,963		12,444
Total	$	1,029,778	$	867,359

For the full year of 2014, we plan to drill approximately 180 to 190 gross wells (165 to 175 net). In 2014, we plan to spend between $1.45 billion to $1.55 billion in total capital and exploration expenditures (excluding property acquisition costs, as discussed in Note 2 to the Condensed Consolidated Financial Statements). See “Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. Except for certain new and amended transportation agreements described in Note 8 to the Condensed Consolidated Financial Statements included in this Form 10-Q, there have been no material changes to our contractual obligations described under “Transportation 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.

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.

Accounting for Derivative Instruments and Hedging Activities

Through March 31, 2014, we elected to designate our commodity derivatives as cash flow hedges for accounting purposes. Effective April 1, 2014, we elected to discontinue hedge accounting for our commodity derivatives on a prospective basis. Accordingly, the change in the fair value of derivatives designated as hedges that were effective was recorded to accumulated other comprehensive income (loss) in stockholders’ equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges and the change in fair value and realized cash settlements of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

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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. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern, as a new Sub-topic, Accounting Standards Codification Sub-topic 205.40. The new going concern standard codifies in generally accepted accounting principles (GAAP) management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for interim and annual periods beginning on or after December 15, 2016 and early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.

Results of Operations

Third Quarters of 2014 and 2013 Compared

We reported net income in the third quarter of 2014 of $100.8 million, or $0.24 per share, compared to $69.9 million, or $0.17 per share, in the third quarter of 2013. The increase in net income was due to an increase in operating revenues, partially offset by higher operating expenses and income taxes.

Revenue, Price and Volume Variances

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



	Three Months Ended September 30,				Variance
Revenue Variances (In thousands)	2014		2013		Amount			Percent
Natural gas	$	347,970	$	341,901	$	6,069		2	%
Crude oil and condensate	82,563		84,209		(1,646		)	(2	)%
Gain (loss) on derivative instruments	71,906		—		71,906			100	%
Brokered natural gas	6,501		7,165		(664		)	(9	)%
Other	3,077		2,575		502			19	%
	$	512,017	$	435,850	$	76,167		17	%



	Three Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2014		2013		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	2.75	$	3.36	$	(0.61	)	(18	)%	$	(77,780	)
Crude oil and condensate ⁽²⁾	$	94.68	$	103.76	$	(9.08	)	(9	)%	(7,912		)
Total										$	(85,692	)
Volume Variances
Natural gas (Bcf)	126.7		101.7		25.0			25	%	$	83,849
Crude oil and condensate (Mbbl)	872		812		60			7	%	6,266
Total										$	90,115


(1)	These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.17 per Mcf in 2014 and increased the price by $0.20 per Mcf in 2013.


(2)	These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.15 per Bbl and $1.33 per Bbl in 2014 and 2013, respectively.

Natural Gas Revenues

The increase in natural gas revenues of $6.1 million is due to higher production, offset by lower natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by a decrease in production in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and lower production in Texas and West Virginia due to normal production declines.

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Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $1.6 million is due to lower crude oil prices, offset by higher production. The increase in production was a result of our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013.

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 with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. Gain (loss) on derivative instruments includes a $40.1 million gain related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $31.8 million unrealized mark-to-market gain on our commodity derivative instruments.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized and unrealized impact of our derivative instruments:



	Three Months Ended September 30,
(In thousands)	2014			2013
Realized
Natural gas	$	(21,427	)	$	20,766
Crude oil and condensate	(130		)	(1,082		)
Gain (loss) on derivative instruments	40,073			—
	$	18,516		$	19,684
Unrealized
Gain (loss) on derivative instruments	31,833			—
	$	50,349		$	19,684

Brokered Natural Gas Revenue and Cost



	Three Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2014		2013		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	4.31	$	4.22	$	0.09		2	%	$	136
Volume brokered (Mmcf)	x	1,508	x	1,697	(189		)	(11	)%	(800		)
Brokered natural gas (In thousands)	$	6,501	$	7,165						$	(664	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	3.77	$	3.48	$	0.29		8	%	$	(441	)
Volume brokered (Mmcf)	x	1,508	x	1,697	(189		)	(11	)%	674
Brokered natural gas (In thousands)	$	5,680	$	5,913						$	233

Brokered natural gas margin (In thousands)	$	821	$	1,252						$	(431	)

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

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Operating and Other Expenses



	Three Months Ended September 30,				Variance
(In thousands)	2014		2013		Amount			Percent
Operating and Other Expenses
Direct operations	$	37,802	$	32,923	$	4,879		15	%
Transportation and gathering	85,966		60,803		25,163			41	%
Brokered natural gas	5,680		5,913		(233		)	(4	)%
Taxes other than income	10,933		11,532		(599		)	(5	)%
Exploration	8,812		3,891		4,921			126	%
Depreciation, depletion and amortization	154,013		168,980		(14,967		)	(9	)%
General and administrative	19,579		24,697		(5,118		)	(21	)%
Total operating expense	$	322,785	$	308,739	$	14,046		5	%

Earnings (loss) on equity method investments	$	1,063	$	278	$	785		282	%
Gain (loss) on sale of assets	46		4,421		(4,375		)	(99	)%
Interest expense	17,422		16,074		1,348			8	%
Income tax expense	72,131		45,847		26,284			57	%

Total costs and expenses from operations increased by $14.0 million, or 5%, in the third quarter of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

•

Direct operations increased $4.9 million largely due to higher operating costs as a result of higher production, an increase in disposal and recycling costs related to our Marcellus Shale operations and costs associated with oil processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas. Partially offsetting these increases were lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.


•	Transportation and gathering increased $25.2 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during the first nine months of 2014.


•	Brokered natural gas decreased $0.2 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.


•	Taxes other than income decreased $0.6 million due to $0.4 million lower ad valorem and production taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.


•	Exploration expense increased $4.9 million as a result of higher exploratory dry hole costs of $4.4 million and higher geophysical and geological and other expenses.

•

Depreciation, depletion and amortization decreased $15.0 million, as the $36.3 million increase due to higher equivalent production volumes was more than offset by $40.5 million due to a lower DD&A rate of $1.13 per Mcfe for the third quarter of 2014 compared to $1.43 per Mcfe for the third quarter of 2013. The lower DD&A rate was primarily due to lower costs of reserve additions associated with our Marcellus drilling program and the impact of the disposition of higher rate fields in Oklahoma and west Texas in the fourth quarter of 2013. In addition, amortization of unproved properties decreased $11.4 million in the third quarter of 2014 due to a decrease in amortization rates as a result of favorable results from our drilling program in Pennsylvania.


•	General and administrative decreased $5.1 million due to lower stock-based compensation expense of $6.6 million associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price during 2014 compared to 2013, partially offset by increases in other expenses that were not individually significant.

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Gain (Loss) on Sale of Assets

An aggregate gain of $4.4 million was recognized in the third quarter of 2013 due to the sale of certain of our proved oil and gas properties in Oklahoma. There were no significant gains or losses on the sale of assets in the third quarter of 2014.

Interest Expense

Interest expense increased $1.3 million primarily due to 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%.

Income Tax Expense

Income tax expense increased $26.3 million due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the third quarter of 2014 and 2013 was 41.7% and 39.6%, respectively. The increase in the effective tax rate was due to changes in permanent taxable items, as well as an increased blended state effective tax rate.

First Nine Months of 2014 and 2013 Compared

We reported net income in the first nine months of 2014 of $326.2 million, or $0.78 per share, compared to $201.8 million, or $0.48 per share, in the first nine months of 2013. The increase in net income was due to an increase in operating revenues, partially offset by higher operating expenses and income taxes.

Revenue, Price and Volume Variances

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



	Nine Months Ended September 30,				Variance
Revenue Variances (In thousands)	2014		2013		Amount		Percent
Natural gas	$	1,218,540	$	1,004,085	$	214,455	21	%
Crude oil and condensate	228,047		220,090		7,957		4	%
Gain (loss) on derivative instruments	69,577		—		69,577		100	%
Brokered natural gas	27,794		26,302		1,492		6	%
Other	11,049		8,338		2,711		33	%
	$	1,555,007	$	1,258,815	$	296,192	24	%



	Nine Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2014		2013		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas ⁽¹⁾	$	3.35	$	3.62	$	(0.27	)	(8	)%	$	(99,260	)
Crude oil and condensate ⁽²⁾	$	97.21	$	103.07	$	(5.86	)	(6	)%	(13,756		)
Total										$	(113,016	)
Volume Variances
Natural gas (Bcf)	364.3		277.5		86.8			31	%	$	313,715
Crude oil and condensate (Mbbl)	2,346		2,135		211			10	%	21,713
Total										$	335,428


(1)	These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.31 per Mcf in 2014 and increased the price by $0.12 per Mcf in 2013.


(2)	These prices include the realized impact of cash flow hedge settlements, which decreased the price by $0.42 per Bbl in 2014 and increased the price by $1.43 per Bbl in 2013.

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Natural Gas Revenues

The increase in natural gas revenues of $214.5 million is due to higher production, partially offset by lower natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by a decrease in production in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and lower production in Texas and West Virginia due to normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $8.0 million is due to higher production associated with our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013 and lower crude oil prices.

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 with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. Gain (loss) on derivative instruments includes a $24.8 million gain related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $44.8 million unrealized mark-to-market gain on our commodity derivative instruments.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized and unrealized impact of our derivative instruments:



	Nine Months Ended September 30,
(In thousands)	2014			2013
Realized
Natural gas	$	(114,304	)	$	33,822
Crude oil and condensate	(984		)	3,054
Gain (loss) on derivative instruments	24,811			—
	$	(90,477	)	$	36,876
Unrealized
Gain (loss) on derivative instruments	44,766			—
	$	(45,711	)	$	36,876

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Brokered Natural Gas Revenue and Cost



	Nine Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2014		2013		Amount			Percent
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	4.76	$	4.06	$	0.70		17	%	$	4,085
Volume brokered (Mmcf)	x	5,835	x	6,478	(643		)	(10	)%	(2,593		)
Brokered natural gas (In thousands)	$	27,794	$	26,302						$	1,492

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	4.21	$	3.24	$	0.97		30	%	$	(5,649	)
Volume brokered (Mmcf)	x	5,835	x	6,478	(643		)	(10	)%	2,085
Brokered natural gas (In thousands)	$	24,570	$	21,006						$	(3,564	)

Brokered natural gas margin (In thousands)	$	3,224	$	5,296						$	(2,072	)

The $2.1 million decrease in brokered natural gas margin is a result of an increase in purchase price that outpaced the increase in sales price and lower brokered volumes.

Operating and Other Expenses



	Nine Months Ended September 30,					Variance
(In thousands)	2014			2013		Amount			Percent
Operating and Other Expenses
Direct operations	$	109,241		$	101,398	$	7,843		8	%
Transportation and gathering	247,707			159,672		88,035			55	%
Brokered natural gas	24,570			21,006		3,564			17	%
Taxes other than income	36,794			34,583		2,211			6	%
Exploration	19,963			12,444		7,519			60	%
Depreciation, depletion and amortization	458,995			469,022		(10,027		)	(2	)%
General and administrative	61,342			82,009		(20,667		)	(25	)%
Total operating expense	$	958,612		$	880,134	$	78,478		9	%

Earnings (loss) on equity method investments	$	1,819		$	614	$	1,205		196	%
Gain (loss) on sale of assets	(2,735		)	4,601		(7,336		)	(159	)%
Interest expense	50,312			49,366		946			2	%
Income tax expense	218,928			132,703		86,225			65	%

Total costs and expenses from operations increased by $78.5 million, or 9%, in the first nine months of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

•

Direct operations increased $7.8 million largely due to higher operating costs as a result of higher production, an increase in disposal and recycling costs related to our Marcellus Shale operations and an increase in costs associated with oil processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas. Partially offsetting these increases were lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.


•	Transportation and gathering increased $88.0 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during the first nine months of 2014.

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•	Brokered natural gas increased $3.6 million. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

•

Taxes other than income increased $2.2 million due to $2.6 million higher drilling impact fees associated with our Marcellus Shale drilling activities and $1.3 million higher production taxes. Production taxes increased due to higher oil production in south Texas, offset by taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013. These increases are partially offset by a $1.6 million decrease in ad valorem taxes.


•	Exploration expense increased $7.5 million as a result of higher exploratory dry hole costs of $5.7 million and higher geophysical and geological and other expenses.

•

Depreciation, depletion and amortization decreased $10.0 million, as the $132.0 million increase due to higher equivalent production volumes, was mostly offset by $126.0 million due to a lower DD&A rate of $1.16 per Mcfe for the first nine months of 2014 compared to $1.50 per Mcfe for the first nine months of 2013. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our Marcellus drilling program and the impact of the disposition of higher rate fields in Oklahoma and west Texas in the fourth quarter of 2013. In addition, amortization of unproved properties decreased $16.9 million in the first nine months in 2014 due to a decrease in amortization rates as a result of favorable results from our drilling program in Pennsylvania.

•

General and administrative decreased $20.7 million due to lower stock-based compensation expense of $25.8 million associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price during 2014 compared to 2013 and lower professional fees, partially offset by increases in other expenses that were not individually significant.

Gain (Loss) on Sale of Assets

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 our proved oil and gas properties in Oklahoma and the sale of heavy-duty equipment. An aggregate gain of $4.6 million was recognized in the first nine months of 2013, primarily due to the sale of certain of our proved oil and gas properties in Oklahoma.

Interest Expense

Interest expense increased $0.9 million due to an increase in interest expense of $2.0 million associated with our credit facility due to an increase in weighted-average borrowings based on daily balances of approximately $535.4 million compared to approximately $408.2 million during the first nine months 2014 and 2013, respectively, interest expense of $1.2 million 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 amortization of debt issuance costs of $0.6 million. These increases were partially offset by a decrease of $3.1 million due to the repayment of $75.0 million of our 7.33% weighted-average fixed rate notes in July 2013.

Income Tax Expense

Income tax expense increased $86.2 million due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first nine months of 2014 and 2013 was 40.2% and 39.7%, respectively. The increase in the effective tax rate is due to an increase in the state effective tax rate.

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.

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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 only provide 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 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, 2014, 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	84.9	Bcf	Oct. 2014 - Dec. 2014	$3.60-$4.37	$	4.13	$4.22-$4.80	$	4.51			$	3,131
Natural gas	26.8	Bcf	Oct. 2014 - Dec. 2014							$	4.05	11,614
Natural gas	35.5	Bcf	Jan. 2015 - Dec. 2015	—	$	3.86	$4.36-$4.43	$	4.40			(194		)
Natural gas	35.5	Bcf	Jan. 2015 - Dec. 2015							$	4.12	44
Crude oil	184.0	Mbbl	Oct. 2014 - Dec. 2014							$	97.00	1,249
												$	15,844

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

The amounts set forth under the estimated fair value asset (liability) column in the table above represent our total unrealized derivative position at September 30, 2014 and exclude the impact of non-performance risk. Non-performance risk is primarily evaluated by reviewing credit default swap spreads for the various financial institutions 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 2014, natural gas collars with floor prices ranging from $3.60 to $4.37 per Mcf and ceiling prices ranging from $4.22 to $4.80 per Mcf covered 251.9 Bcf, or 69%, of natural gas production at an average price of $4.41 per Mcf. Natural gas swaps covered 73.5 Mcf, or 20%, of natural gas production at an average price of $4.06 per Mcf. Crude oil swaps covered 428 Mbbl, or 18%, of crude oil production at an average price of $97.00 per Bbl.

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. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of America, Bank of Montreal, Goldman Sachs, ING Capital Markets, JPMorgan, and Morgan Stanley.

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

Fair Market Value of Other Financial Instruments

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

The fair value of long-term debt is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and 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.

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



	September 30, 2014				December 31, 2013
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	1,612,000	$	1,697,654	$	1,147,000	$	1,224,273

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 2014 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, 2013.

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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 shares included in the table below were repurchased on the open market and were held as treasury stock as of September 30, 2014.



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
July 2014	—	—		—	14,361,834
August 2014	1,829,746	$	32.88	1,829,746	12,532,088
September 2014	2,191,068	$	32.18	2,191,068	10,341,020
Total	4,020,814			4,020,814	10,341,020

ITEM 6. Exhibits



Exhibit Number		Description

4.1		Note Purchase Agreement dated September 18, 2014 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K dated September 24, 2014).

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 24, 2014	By:	/S/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 24, 2014	By:	/S/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 24, 2014	By:	/S/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)