Exhibit 99.1

STONE ENERGY CORPORATION

Announces Second Quarter 2014 Results

LAFAYETTE, LA. August 5, 2014

Stone Energy Corporation (NYSE: SGY) today announced financial and operational results for the second quarter of 2014. Some of the highlights include:

• On schedule with Cardona/Cardona South development project

• Sanctioned Amethyst development

• Spud Utica test well in the Mary field

• Equity offering raised $226 million

• Sold non-core conventional shelf assets for $200 million

Chairman, President and Chief Executive Officer David Welch stated, “In the second quarter of 2014, we continued to execute our growth model by sanctioning our deep water Amethyst discovery, spudding the Utica shale test well, progressing our Cardona development project, obtaining an agreement to sell our non-core conventional shelf assets, and completing a successful equity offering. The deep water Cardona project is expected to come on production less than six months after drilling was completed. The divestiture of non-core shelf assets coupled with the equity offering were important steps in our growth plan as we look to secure a multi-year deep water rig contract, advance our deep water and deep gas exploration prospects, and evaluate development options for our Utica position. Our deep water development projects and steady Appalachia drilling underpin our projected production growth through 2016, while our deep water portfolio, deep gas prospects and Utica position provide material exploration exposure into the future.”

Financial Results

For the second quarter of 2014, Stone reported net income of $4.4 million, or $0.08 per share, on oil and gas revenue of $205.0 million, compared to net income of $25.9 million, or $0.52 per share, on oil and gas revenue of $222.6 million in the first quarter of 2014, and compared to net income of $39.0 million, or $0.78 per share, on oil and gas revenue of $243.5 million in the second quarter of 2013. Lower natural gas and natural gas liquids (NGL) realized prices and a higher unit depreciation, depletion and amortization (DD&A) rate were the primary causes of the reduced earnings in the second quarter of 2014 compared to the first quarter of 2014.

Discretionary cash flow totaled $117.5 million during the second quarter of 2014, as compared to $138.0 million during the first quarter of 2014, and as compared to $169.6 million during the second quarter of 2013. Please see “Non-GAAP Financial Measures” and the accompanying financial statements for a reconciliation of discretionary cash flow, a non-GAAP financial measure, to net cash flow provided by operating activities.

Net daily production during the second quarter of 2014 averaged 44.1 thousand barrels of oil equivalent (MBoe) per day (264 million cubic feet of gas equivalent (MMcfe) per day), compared with net daily production of 44.8 MBoe (269 MMcfe) per day in the first quarter of 2014, and net daily production of 45.4 MBoe (272 MMcfe) per day in the second quarter of 2013. Second quarter of 2014 production mix was 37% oil, 12% natural gas liquids and 51% natural gas. Second quarter of 2014 production was negatively impacted by unscheduled third party pipeline downtime at the Mary field in West Virginia, a slight delay in bringing new Appalachian wells on production, paraffin plug at Main Pass 288 and scheduled downtime at the Pompano deep water platform. All three fields have been returned to full production.

For the third quarter of 2014 and full year 2014, the sale of the non-core shelf properties on July 31, 2014, has been reflected in the updated production guidance. Production volumes associated with these properties averaged approximately 48 MMcfe per day (58% natural gas) in July 2014. In July 2014, the Amberjack platform had scheduled pipeline maintenance which lasted approximately three weeks, which is also reflected in the third quarter production guidance. Production from over 30 Appalachian wells (four different pads) is expected to impact volumes for the third and fourth quarters and is reflected in the updated production guidance for 2014.

Prices realized during the second quarter of 2014 averaged $96.15 per barrel of oil, $34.12 per barrel of NGLs and $3.77 per Mcf of natural gas. Average realized prices for the second quarter of 2013 were $104.41 per barrel of oil, $27.52 per barrel of NGLs and $4.07 per Mcf of natural gas. Effective hedging transactions decreased the average realized price of natural gas by $0.26 per Mcf and decreased the average realized price of oil by $4.15 per barrel in the second quarter of 2014. Effective hedging transactions increased the average realized price of natural gas by $0.17 per Mcf and increased the average realized price of oil by $3.02 per barrel in the second quarter of 2013.

Lease operating expenses during the second quarter of 2014 totaled $49.5 million ($12.34 per Boe or $2.06 per Mcfe), compared to $50.5 million ($12.23 per Boe or $2.04 per Mcfe), in the second quarter of 2013. We expect lease operating expenses to decline in the second half of 2014 due to the sale of non-core shelf properties.

Depreciation, depletion and amortization (DD&A) on oil and gas properties for the second quarter of 2014 totaled $91.9 million ($22.93 per Boe or $3.82 per Mcfe), compared to $86.3 million ($20.88 per Boe or $3.48 per Mcfe), in the second quarter of 2013. The increase in DD&A on a per unit basis was primarily due to the higher unit cost of reserve additions attributable to our GOM exploration program, which included the Amethyst, Cardona, Cardona South, Mica Deep and Tomcat projects. We anticipate that DD&A on a unit of production basis will decrease slightly in the second half of 2014 with the expected booking of additional Appalachian reserves at a lower unit cost.

Salaries, general and administrative (SG&A) expenses for the second quarter of 2014 were $16.6 million ($4.15 per Boe or $0.69 per Mcfe), compared to $15.2 million ($3.68 per Boe or $0.61 per Mcfe), in the second quarter of 2013.

Capital expenditures before capitalized SG&A and interest during the second quarter of 2014 were approximately $252.9 million, which includes $15.1 million of plugging and abandonment expenditures. Additionally, $8.4 million of SG&A and $11.3 million of interest were capitalized during the second quarter of 2014. This is compared to capital expenditures before capitalized SG&A and interest during the second quarter of 2013 of approximately $190.4 million, which includes $22.5 million of plugging and abandonment expenditures. Additionally, $7.5 million of SG&A and $10.9 million of interest were capitalized during the second quarter of 2013. Based on the results of our drilling program in the first half of 2014, we expect to have additional capital requirements in 2014 related to the development of our oil and gas properties, which may require an increase in our capital expenditure budget for 2014.

In May of 2014, Stone completed an equity offering, which generated $226 million in net proceeds after deducting the underwriting discount and offering expenses. Stone sold 5.75 million shares of our common stock at a price to the public of $41.00 per share in the offering.

On July 31, 2014, Stone Energy Corporation completed the previously announced sale of its non-core Gulf of Mexico conventional shelf properties to Talos Energy Offshore LLC for cash consideration of approximately $178 million, after giving effect to preliminary purchase price adjustments. Talos also assumed the future undiscounted abandonment liabilities estimated at approximately $117 million. The effective date of the sale was April 1, 2014. At December 31, 2013, the estimated proved reserves associated with these properties represented approximately 9% of Stone’s year end 2013 total estimated proved reserves. Production volumes associated with these properties averaged approximately 48 MMcfe per day (58% natural gas) in July 2014. Under the terms of the agreement, Stone will retain a four-year option for a 50% working interest in the deep drilling rights on the properties.

On June 24, 2014, Stone entered into an amended and restated revolving credit facility, which matures on July 1, 2019. The initial borrowing base under the bank credit facility has been set at $500 million, an increase from the previous borrowing base of $400 million. As of June 30 and August 5, 2014, there were no outstanding borrowings under the bank credit facility and $21.0 million in letters of credit had been issued, leaving $479.0 million of availability. As of August 5, 2014, we had cash on hand of approximately $445 million.

Operational Update 

Mississippi Canyon 29 – Cardona and Cardona South (Deep Water). The downhole sections of the Cardona and Cardona South wells have been completed and the rig has been released. The looped gathering system for both wells is being installed and is projected to be completed in the fourth quarter of 2014. Both wells will be flowed back to the Stone owned (100%) and operated Pompano platform. The combined gross rate is expected to be approximately 12,000 barrels of oil equivalent per day, with production expected by early first quarter of 2015. The Cardona and Cardona South successes extend the productive zone of the Mississippi Canyon 29 TB-9 well to the adjacent fault blocks to the north and south, with potential for a second and third well in the fault block to the south. Stone holds a 65% working interest in the project and is the operator.

Mississippi Canyon 26 – Amethyst (Deep Water). A development plan for Amethyst was sanctioned early in the second quarter of 2014 and long lead items have been ordered for a single well tie-back to the Stone owned and operated Pompano platform, located less than five miles from the discovery. Production is expected to begin in 2016. The Amethyst discovery (100% working interest) encountered approximately 90 feet of net hydrocarbon pay. Production results from the Amethyst well will assist in the evaluation of Stone’s Derbio prospect located nearby.

Amberjack Development Drill Program (Deep Water). Stone expects to secure a platform rig for its Amberjack (Mississippi Canyon 109) drill program. The rig is expected to become available in late 2014 or early 2015. The program is expected to consist of four to six development wells.

Pompano Development Drill Program (Deep Water). Stone expects to secure a platform rig for its Pompano (Viosca Knoll 989) drill program. It is anticipated that the rig will become available in late 2015. The program is expected to consist of four to five development wells.

Mississippi Canyon 118 - Harrier (Deep Water). The Harrier exploration well targets the Miocene interval and is projected to spud in early 2015. Stone currently controls a 37% working interest in the prospect, which is operated by ConocoPhillips. The well is estimated to take four months to drill.

Walker Ridge 89 - Goodfellow (Deep Water). The Goodfellow exploration well targets the Lower Tertiary and is projected to spud early in 2015. Stone currently holds an approximate 13% working interest in the prospect, which is operated by Eni. The well is estimated to take five months to drill.

Utica Shale Test (Appalachian Basin). Stone spudded a Utica shale test well late in the second quarter of 2014 on its existing acreage in the Mary field in West Virginia. Stone plans to drill, log and take sidewall cores in a vertical well drilled through the Utica formation (11,000 feet true vertical depth). Following evaluation of the vertical hole, Stone plans to plug back and drill a 3,750 foot horizontal lateral through the Point Pleasant member of the Utica shale. Currently, intermediate casing is being run at 8,400 feet in preparation to drill the vertical section through the Utica formation. The well is scheduled to be completed during the third quarter of 2014 with the production test commencing in the fourth quarter of 2014.

Marcellus Shale Drilling Program Update (Appalachian Basin). Stone drilled nine horizontal Marcellus shale wells and performed completion operations on 18 wells during the second quarter of 2014. By year-end 2014, Stone expects to have drilled 32 to 38 wells and to have completed 28 to 34 wells in the Marcellus shale.

Marcellus Shale Production Update (Appalachian Basin). During the second quarter of 2014, Stone averaged approximately 81 MMcfe per day (56 MMcf per day of gas and 4,200 barrels per day of liquids) from Stone’s Marcellus shale position, despite a week of shut in production at the Mary field due to third party pipeline issues, which affected approximately 70 MMcfepd. In the third quarter of 2014, Stone expects to bring the 10-well Howell pad online in the Mary field. In addition, Stone plans to bring on the 8-well Stone pad, the 5-well Pribble pad (includes Utica test well), and the 8-well ZMBG pad during the fourth quarter of 2014. In the Heather field, capacity limitations at the Mobley gas processing plant have restricted the 8-well Mills-Wetzel pad #3 from producing at full rate. This issue is expected to be resolved late in the third quarter of 2014.

West Cameron 176 – Tomcat (Deep Gas). The Tomcat exploration well was tied back to the nearby Stone operated East Cameron 64 production platform and was brought online in June 2014. The well is producing approximately 750 barrels of oil and 2.4 MMcf of gas per day. Stone is 100% owner and operator of the well.

La Montana (Deep Gas). A rig has been secured for the La Montana exploration well, which is expected to spud in late 2014 or the first half of 2015. Stone is targeting a 75% working interest in the project and is the operator. The well is estimated to take four months to drill.

Cayenne (Deep Gas). The Cayenne exploration well, slated to use the same rig as the La Montana exploration well, is expected to spud in the second or third quarter of 2015. Stone holds a 50% working interest in the project and is the operator. The well is estimated to take four months to drill.

2014 Guidance

Guidance for the third quarter and full year 2014 is shown in the table below (updated guidance numbers are italicized and bolded). The guidance for Production and Lease operating expenses has been adjusted to account for the sale of the non-core conventional shelf properties, which closed on July 31, 2014. Without the sale of these properties, the previous guidance for production and lease operating expenses for the full year would have been reaffirmed. Based on the results of our drilling program in the first half of 2014, we expect to have additional capital requirements which may require an increase in our capital expenditure budget for 2014. The guidance is subject to all the cautionary statements and limitations described below and under the caption “Forward Looking Statements.”

	Third Quarter	Full Year
Production—MBoe per day	37-39		41-44
(MMcfe per day)	(222 - 234)		(246 -  264)
Lease operating expenses (in millions) (excluding transportation/processing expenses)	—		$175 - $195
Transportation, processing and gathering (in millions)	—		$56 - $68
Salaries, General & Administrative expenses (in millions) (excluding incentive compensation)	—		$65 - $69
Depreciation, Depletion & Amortization (per Boe)	—		$21.00 - $22.50
(per Mcfe)			$3.50 - $3.75
Corporate Tax Rate (%)	—		36% - 38%
Capital Expenditure Budget (in millions) (excluding acquisitions)	—		$825

Hedge Position

The following table illustrates our derivative positions for 2014, 2015 and 2016 as of August 5, 2014:

	Fixed-Price Swaps
	NYMEX (except where noted)
	Natural Gas					Oil
	Daily Volume (MMBtus/d)			Swap Price		Daily Volume (Bbls/d)			Swap Price
2014		10,000		$	4.000		1,000		$	90.06
2014		10,000			4.040		1,000	**		90.25
2014		10,000			4.105		1,000			92.25
2014		10,000			4.190		1,000			93.55
2014		10,000	*		4.250		1,000			94.00
2014		10,000			4.250		1,000			98.00
2014		10,000			4.350		1,000			98.30
2014							2,000	***		98.85
2014							1,000			99.65
2014							1,000	†		103.30
2015		10,000			4.005		1,000			89.00
2015		10,000			4.120		1,000			90.00
2015		10,000			4.150		1,000			90.25
2015		10,000			4.165		1,000			90.40
2015		10,000			4.220		1,000			93.28
2015		10,000			4.255		1,000			93.37
2015							1,000			94.85
2015							1,000			95.00
2016		10,000			4.110
2016		10,000			4.120

* February—December

** October—December

*** January—June

† Brent oil contract

Other Information

Stone Energy has planned a conference call for 9:00 a.m. Central Time on Wednesday, August 6, 2014 to discuss the operational and financial results for the second quarter of 2014. Anyone wishing to participate should visit our website at www.StoneEnergy.com for a live web cast or dial 1-877-228-3598 and request the “Stone Energy Call.” If you are unable to participate in the original conference call, a replay will be available immediately following the completion of the call on Stone Energy’s website. The replay will be available for one month.

Non-GAAP Financial Measures

In this press release, we refer to a non-GAAP financial measure we call “discretionary cash flow.” Management believes discretionary cash flow is a financial indicator of our company’s ability to internally fund capital expenditures and service debt. Management also believes this non-GAAP financial measure of cash flow is useful information to investors because it is widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the oil and gas exploration and production industry. Discretionary cash flow should not be considered an alternative to net cash provided by operating activities or net income, as defined by GAAP. Please see the “Reconciliation of Non-GAAP Financial Measure” for a reconciliation of discretionary cash flow to cash flow provided by operating activities.

Forward Looking Statements

Certain statements in this press release are forward-looking and are based upon Stone’s current belief as to the outcome and timing of future events. All statements, other than statements of historical facts, that address activities that Stone plans, expects, believes, projects, estimates or anticipates will, should or may occur in the future, including future production of oil and gas, future capital expenditures and drilling of wells and future financial or operating results are forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks, liquidity risks, political and regulatory developments and legislation, including developments and legislation relating to our operations in the Gulf of Mexico and Appalachia, and other risk factors and known trends and uncertainties as described in Stone’s Annual Report on Form 10-K and Quarterly Reports on Form 10-Q as filed with the SEC. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Stone’s actual results and plans could differ materially from those expressed in the forward-looking statements.

Estimates for Stone’s future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes and numerous other factors. Stone’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Delays experienced in well permitting could affect the timing of drilling and production. Lease operating expenses, which include major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Estimates of DD&A rates can vary according to reserve additions, capital expenditures, future development costs, and other factors. Therefore, we can give no assurance that our future production volumes, lease operating expenses or DD&A rates will be as estimated.

Stone Energy is an independent oil and natural gas exploration and production company headquartered in Lafayette, Louisiana with additional offices in New Orleans, Houston and Morgantown, West Virginia. Stone is engaged in the acquisition, exploration, and development of properties in the Deep Water Gulf of Mexico, Appalachia, and the onshore and offshore Gulf Coast. For additional information, contact Kenneth H. Beer, Chief Financial Officer, at 337-521-2210 phone, 337-521-9880 fax or via e-mail at CFO@StoneEnergy.com.

STONE ENERGY CORPORATION

SUMMARY STATISTICS

(In thousands, except per share/unit amounts)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
FINANCIAL RESULTS
Net income	$	4,444	$	39,022	$	30,387	$	79,780
Net income per share	$	0.08	$	0.78	$	0.59	$	1.60
PRODUCTION QUANTITIES
Oil (MBbls)		1,481		1,767		2,899		3,434
Gas (MMcf)		12,363		11,745		25,004		22,103
Natural gas liquids (MBbls)		467		407		977		623
Oil, gas and NGLs (MBoe)		4,009		4,132		8,043		7,741
Oil, gas and NGLs (MMcfe)		24,051		24,789		48,260		46,445
AVERAGE DAILY PRODUCTION
Oil (MBbls)		16.3		19.4		16.0		19.0
Gas (MMcf)		135.9		129.1		138.1		122.1
Natural gas liquids (MBbls)		5.1		4.5		5.4		3.4
Oil, gas and NGLs (MBoe)		44.1		45.4		44.4		42.8
Oil, gas and NGLs (MMcfe)		264.3		272.4		266.6		256.6
REVENUE DATA
Oil revenue	$	142,393	$	184,498	$	280,682	$	371,423
Gas revenue		46,667		47,832		103,029		84,654
Natural gas liquids revenue		15,936		11,200		43,906		20,378
Total oil, gas and NGL revenue	$	204,996	$	243,530	$	427,617	$	476,455
AVERAGE PRICES
Prior to the cash settlement of effective hedging transactions:
Oil (per Bbl)	$	100.30	$	101.39	$	99.80	$	105.28
Gas (per Mcf)		4.03		3.90		4.43		3.56
Natural gas liquids (per Bbl)		34.12		27.52		44.94		32.71
Oil, gas and NGLs (per Boe)		53.44		57.16		55.20		59.50
Oil, gas and NGLs (per Mcfe)		8.91		9.53		9.20		9.92
Including the cash settlement of effective hedging transactions:
Oil (per Bbl)	$	96.15	$	104.41	$	96.82	$	108.16
Gas (per Mcf)		3.77		4.07		4.12		3.83
Natural gas liquids (per Bbl)		34.12		27.52		44.94		32.71
Oil, gas and NGLs (per Boe)		51.13		58.94		53.17		61.55
Oil, gas and NGLs (per Mcfe)		8.52		9.82		8.86		10.26
COST DATA
Lease operating expenses	$	49,454	$	50,517	$	96,357	$	103,561
Salaries, general and administrative expenses		16,637		15,198		32,966		29,150
DD&A expense on oil and gas properties		91,921		86,295		173,709		160,827
AVERAGE COSTS
Lease operating expenses (per Boe)	$	12.34	$	12.23	$	11.98	$	13.38
Lease operating expenses (per Mcfe)		2.06		2.04		2.00		2.23
Salaries, general and administrative expenses (per Boe)		4.15		3.68		4.10		3.77
Salaries, general and administrative expenses (per Mcfe)		0.69		0.61		0.68		0.63
DD&A expense on oil and gas properties (per Boe)		22.93		20.88		21.60		20.78
DD&A expense on oil and gas properties (per Mcfe)		3.82		3.48		3.60		3.46
AVERAGE SHARES OUTSTANDING – Diluted		52,373		48,725		50,727		48,691

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Operating revenue:
Oil production	$	142,393		$	184,498		$	280,682		$	371,423
Gas production		46,667			47,832			103,029			84,654
Natural gas liquids production		15,936			11,200			43,906			20,378
Other operational income		2,050			979			3,047			1,786
Derivative income, net		0			1,368			0			147
Total operating revenue		207,046			245,877			430,664			478,388
Operating expenses:
Lease operating expenses		49,454			50,517			96,357			103,561
Transportation, processing and gathering		14,098			8,896			28,724			14,293
Other operational expense		0			73			212			145
Production taxes		3,257			4,091			6,319			6,180
Depreciation, depletion and amortization		92,835			87,209			175,481			162,644
Accretion expense		7,733			8,318			15,288			16,581
Salaries, general and administrative expenses		16,637			15,198			32,966			29,150
Incentive compensation expense		3,903			2,050			7,037			3,481
Derivative expense, net		2,516			0			3,115			0
Total operating expenses		190,433			176,352			365,499			336,035
Income from operations		16,613			69,525			65,165			142,353
Other (income) expenses:
Interest expense		9,913			8,895			18,270			18,530
Interest income		(193	)		(115	)		(336	)		(232	)
Other income, net		(722	)		(682	)		(1,429	)		(1,408	)
Other expense		179			0			179			0
Total other expenses		9,177			8,098			16,684			16,890
Income before taxes		7,436			61,427			48,481			125,463
Provision (benefit) for income taxes:
Current		0			(6,993	)		0			(10,739	)
Deferred		2,992			29,398			18,094			56,422
Total income taxes		2,992			22,405			18,094			45,683
Net income	$	4,444		$	39,022		$	30,387		$	79,780

STONE ENERGY CORPORATION

RECONCILIATION OF NON-GAAP FINANCIAL MEASURE

(In thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income as reported	$	4,444		$	39,022		$	30,387		$	79,780
Reconciling items:
Depreciation, depletion and amortization		92,835			87,209			175,481			162,644
Deferred income tax provision		2,992			29,398			18,094			56,422
Accretion expense		7,733			8,318			15,288			16,581
Stock compensation expense		3,111			2,570			5,358			4,866
Non-cash interest expense		4,159			4,140			8,229			8,181
Other		2,249			(1,074	)		2,697			207
Discretionary cash flow		117,523			169,583			255,534			328,681
Changes in income taxes payable		(6	)		(6,997	)		(6	)		(16,399	)
Settlement of asset retirement obligations		(15,073	)		(22,455	)		(24,915	)		(37,335	)
Other working capital changes		39,044			(10,924	)		26,347			1,026
Net cash provided by operating activities	$	141,488		$	129,207		$	256,960		$	275,973

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands)

(Unaudited)

	June 30,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	333,886		$	331,224
Accounts receivable		197,495			171,971
Fair value of derivative contracts		—			4,549
Current income tax receivable		7,372			7,366
Deferred taxes		36,308			31,710
Inventory		3,723			3,723
Other current assets		1,955			1,874
Total current assets		580,739			552,417
Oil and gas properties, full cost method of accounting:
Proved		8,520,195			7,804,117
Less: accumulated depreciation, depletion and amortization		(6,144,815	)		(5,908,760	)
Net proved oil and gas properties		2,375,380			1,895,357
Unevaluated		554,201			724,339
Other property and equipment, net		28,302			26,178
Fair value of derivative contracts		415			1,378
Other assets, net		43,015			48,887
Total assets	$	3,582,052		$	3,248,556
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	193,900		$	195,677
Undistributed oil and gas proceeds		62,927			37,029
Accrued interest		9,025			9,022
Fair value of derivative contracts		25,711			7,753
Asset retirement obligations		77,132			67,161
Other current liabilities		79,539			54,520
Total current liabilities		448,234			371,162
7 1⁄2% Senior Notes due 2022		775,000			775,000
1 3⁄4% Senior Convertible Notes due 2017		258,931			252,084
Deferred taxes		404,188			390,693
Asset retirement obligations		431,060			435,352
Fair value of derivative contracts		5,251			470
Other long-term liabilities		47,843			53,509
Total liabilities		2,370,507			2,278,270
Common stock		549			488
Treasury stock		(860	)		(860	)
Additional paid-in capital		1,624,795			1,397,885
Accumulated deficit		(394,778	)		(425,165	)
Accumulated other comprehensive loss		(18,161	)		(2,062	)
Total stockholders’ equity		1,211,545			970,286
Total liabilities and stockholders’ equity	$	3,582,052		$	3,248,556