Sanchez Energy (SNECQ) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 26, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	Sanchez Energy Corp
Entity Central Index Key	1,528,837
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 534,400,409
Entity Common Stock, Shares Outstanding		62,579,667
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 435,048	$ 473,714
Oil and natural gas receivables	30,668	69,795
Joint interest billings receivables	1,259	14,676
Accounts receivable - related entities	3,697	386
Fair value of derivative instruments	172,494	100,181
Other current assets	23,452	23,002
Total current assets	666,618	681,754
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	253,529	385,827
Proved oil and natural gas properties	2,914,867	2,582,441
Total oil and natural gas properties	3,168,396	2,968,268
Less: Accumulated depreciation, depletion, amortization and impairment	(2,412,293)	(706,590)
Total oil and natural gas properties, net	756,103	2,261,678
Other assets:
Debt issuance costs, net	41,039	48,168
Fair value of derivative instruments	5,789	24,024
Deferred tax asset		7,443
Investments	49,985
Other assets	22,809	19,101
Total assets	1,542,343	3,042,168
Current liabilities:
Accounts payable	4,184	29,487
Other payables	2,004	4,415
Accrued liabilities:
Capital expenditures	51,983	162,726
Other	69,974	67,162
Deferred premium liability	24,548
Other current liabilities	14,813	5,166
Total current liabilities	167,506	268,956
Long term debt, net of premium (discount)	1,746,966	1,746,263
Asset retirement obligations	25,907	25,694
Fair value of derivative instruments		889
Other liabilities	58,133	779
Total liabilities	$ 1,998,512	$ 2,042,581
Commitments and Contingencies (Note 14)
Stockholders' equity (deficit):
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of December 31, 2015 and 2014 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 and 3,532,330 shares issued and outstanding as of December 31, 2015 and 2014 of 6.500% Convertible Perpetual Preferred Stock, Series B, respectively)	$ 53	$ 53
Common stock ($0.01 par value, 150,000,000 shares authorized; 61,928,089 and 58,580,870 shares issued and outstanding as of December 31, 2015 and 2014, respectively)	619	586
Additional paid-in capital	1,079,513	1,064,667
Accumulated deficit	(1,536,354)	(65,719)
Total stockholders’ equity (deficit)	(456,169)	999,587
Total liabilities and stockholders’ equity (deficit)	$ 1,542,343	$ 3,042,168

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	61,928,089	58,580,870
Common stock, shares outstanding	61,928,089	58,580,870
Preferred Class A
Preferred stock, shares issued	1,838,985	1,838,985
Preferred stock, shares outstanding	1,838,985	1,838,985
Dividend rate (as a percent)	4.875%	4.875%
Preferred Class B
Preferred stock, shares issued	3,527,830	3,532,330
Preferred stock, shares outstanding	3,527,830	3,532,330
Dividend rate (as a percent)	6.50%	6.50%

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil sales	$ 307,971	$ 538,887	$ 290,322
Natural gas liquid sales	69,011	66,989	13,013
Natural gas sales	98,797	60,188	11,085
Total revenues	475,779	666,064	314,420
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	156,528	93,581	35,669
Production and ad valorem taxes	26,870	37,787	17,334
Depreciation, depletion, amortization and accretion	344,572	338,097	134,845
Impairment of oil and natural gas properties	1,365,000	213,821	0
General and administrative (inclusive of stock-based compensation expense of $14,831, $12,843, and $17,751 and for 2015, 2014, and 2013, respectively)	74,160	63,692	47,951
Total operating costs and expenses	1,967,130	746,978	235,799
Operating income (loss)	(1,491,351)	(80,914)	78,621
Other income (expense):
Interest income and other income (expense)	(2,163)	289	135
Interest expense	(126,399)	(89,800)	(30,934)
Net gains (losses) on commodity derivatives	172,886	137,205	(16,938)
Total other expense	44,324	47,694	(47,737)
Loss before income taxes	(1,447,027)	(33,220)	30,884
Income tax expense (benefit)	7,600	(11,429)	3,986
Net loss	(1,454,627)	(21,791)	26,898
Less:
Preferred stock dividends	(16,008)	(33,590)	(18,525)
Net loss allocable to participating securities			(364)
Net income (loss) attributable to common stockholders	$ (1,470,635)	$ (55,381)	$ 8,009
Net income (loss) per common share - basic (in dollars per share)	$ (25.70)	$ (1.06)	$ 0.22
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic (in shares)	57,229	52,338	36,379
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - diluted (in shares)	57,229	52,338	36,379

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Consolidated Statements of Operations
General and administrative, stock-based compensation expense (in dollars)	$ 14,831	$ 12,843	$ 17,751

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Stockholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Preferred Class A	Preferred Class B	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Total
Balance at Dec. 31, 2012	$ 30		$ 338	$ 385,086	$ (18,711)	$ 366,743
Balance (in shares) at Dec. 31, 2012	3,000		33,762
Increase (Decrease) in Stockholders' Equity (Deficit)
Common shares issued			$ 111	241,309		241,420
Common shares issued (in shares)			11,040
Issuance of Preferred Stock, net of offering costs		$ 45		216,515		216,560
Issuance of Series B Preferred Stock, net of offering costs (in shares)		4,500
Preferred stock dividends					(18,525)	(18,525)
Purchase of oil and natural gas properties for common stock			$ 3	7,517		7,520
Purchase of oil and natural gas properties for common stock (in shares)			343
Restricted stock awards, net of forfeitures			$ 13	(13)
Restricted stock awards, net of forfeitures (in shares)			1,276
Purchases of common stock			$ (1)	(1,057)		(1,058)
Purchases of common stock (in shares)			(52)
Stock-based compensation				17,751		17,751
Net income (loss)					26,898	26,898
Balance at Dec. 31, 2013	$ 30	$ 45	$ 464	867,108	(10,338)	857,309
Balance (in shares) at Dec. 31, 2013	3,000	4,500	46,369
Increase (Decrease) in Stockholders' Equity (Deficit)
Common shares issued			$ 50	167,469		167,519
Common shares issued (in shares)			5,000
Preferred stock dividends					(16,293)	(16,293)
Restricted stock awards, net of forfeitures			$ 17	(17)
Restricted stock awards, net of forfeitures (in shares)			1,673
Exchange of preferred stock for common stock	$ (12)	$ (10)	$ 55	17,264	(17,297)
Exchange of preferred stock for common stock (in shares)	(1,161)	(968)	5,539
Stock-based compensation				12,843		12,843
Net income (loss)					(21,791)	(21,791)
Balance at Dec. 31, 2014	$ 18	$ 35	$ 586	1,064,667	(65,719)	999,587
Balance (in shares) at Dec. 31, 2014	1,839	3,532	58,581
Increase (Decrease) in Stockholders' Equity (Deficit)
Preferred stock dividends					(15,960)	(15,960)
Restricted stock awards, net of forfeitures			$ 33	(33)
Restricted stock awards, net of forfeitures (in shares)			3,337
Exchange of preferred stock for common stock				48	(48)
Exchange of preferred stock for common stock (in shares)		(4)	10
Stock-based compensation				14,831		14,831
Net income (loss)					(1,454,627)	(1,454,627)
Balance at Dec. 31, 2015	$ 18	$ 35	$ 619	$ 1,079,513	$ (1,536,354)	$ (456,169)
Balance (in shares) at Dec. 31, 2015	1,839	3,528	61,928

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Offering costs	$ 37,364	$ 24,112
Preferred Class B
Offering costs		8,440
Common Stock
Offering costs	$ 8,731	$ 12,500

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (1,454,627)	$ (21,791)	$ 26,898
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	344,572	338,097	134,845
Impairment of oil and natural gas properties	1,365,000	213,821	0
Stock-based compensation expense	14,831	12,843	17,751
Net (gains) losses on commodity derivative contracts	(172,886)	(137,205)	16,938
Net cash settlement received (paid) on commodity derivative contracts	131,123	5,600	(4,959)
Cash reimbursements received for operating leasehold improvements	2,648
Premiums paid on derivative contracts	(121)	(596)	(1,024)
Loss on investment in SPP	935
Amortization of deferred gain on Catarina Midstream Sale	(3,086)
Amortization of debt issuance costs	7,529	9,002	6,902
Accretion of debt discount (premium)	703	755	258
Deferred taxes	7,443	(11,429)	3,986
Changes in operating assets and liabilities:
Accounts receivable	60,480	(26,971)	(47,649)
Other current assets	(450)	(21,633)	(969)
Accounts payable	(25,303)	(2,868)	32,355
Accounts receivable - related entities	(3,311)	(1,347)	(12,494)
Other payables	(2,290)	1,522	2,286
Accrued liabilities	2,813	51,590	14,137
Other current liabilities	(5,166)	5,166
Other liabilities	1,188	779
Net cash provided by operating activities	272,025	415,335	189,261
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(656,136)	(791,260)	(479,908)
Payments for other property and equipment	(8,123)	(14,062)	(2,050)
Proceeds from sale of oil and natural gas properties	427,571
Acquisition of oil and natural gas properties	(7,658)	(555,942)	(622,996)
Purchases of investments	(49,985)
Sale of investments			11,591
Net cash used in investing activities	(294,331)	(1,361,264)	(1,093,363)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		100,000	236,000
Repayment of borrowings		(100,000)	(236,000)
Issuance of senior notes, net of premium and discount		1,152,250	593,000
Issuance of common stock		176,250	253,920
Issuance of preferred stock			225,000
Payments for offering costs		(8,731)	(20,939)
Financing costs	(400)	(37,364)	(24,112)
Preferred dividends paid	(15,960)	(16,293)	(18,525)
Purchase of common stock			(1,058)
Net cash provided by (used in) financing activities	(16,360)	1,266,112	1,007,286
Increase (decrease) in cash and cash equivalents	(38,666)	320,183	103,184
Cash and cash equivalents, beginning of period	473,714	153,531	50,347
Cash and cash equivalents, end of period	435,048	473,714	153,531
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	(1,877)	20,303	3,386
Change in accrued capital expenditures	(110,744)	75,843	43,323
Capital expenditures in accounts payable		14,545	14,545
Purchase of oil and natural gas properties in exchange for common stock			7,520
Common stock issued in exchange for preferred stock	273	123,731
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes	158
Cash paid for interest	$ 121,644	$ 48,064	$ 25,927

Organization

Organization	12 Months Ended
	Dec. 31, 2015
Organization
Organization	Note 1. Organization and Busines s Sanchez Energy Corporation (together with our consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms) is an independent exploration and production company, formed in August 2011 as a Delaware corporation, focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale. We have included definitions of some of the oil and natural gas terms used in this Annual Report on Form 10 ‑K in the “Glossary of Selected Oil and Natural Gas Terms.”

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies	Note 2. Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Recent Accounting Pronouncements During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions . ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. Adoption of this guidance affected the balance sheets as of December 31, 2014 as follows (in thousands): Decrease in Non - current assets of approximately $33,242 Decrease in Current liabilities of approximately $33,242 In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. Principles of Consolidation The Company’s consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. Cash Equivalents Cash and cash equivalents consist primarily of cash on deposit, money market accounts and investment grade commercial paper that are readily convertible into cash and purchased with original maturities of three months or less. Oil and Natural Gas Receivables The majority of the Company’s receivables arise from sales of oil, natural gas liquids (“NGLs”) or natural gas. The Company does not have any off ‑balance ‑sheet credit exposure related to its customers. Receivables from the sale of oil and natural gas are generally unsecured. Allowances for doubtful accounts are determined based on management’s assessment of the creditworthiness of the customer. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all the collection attempts have been exhausted. At December 31, 2015 and 2014, management believed that all balances were fully collectible and no allowance for doubtful accounts was deemed necessary. Oil and Natural Gas Properties The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units ‑of ‑production method. Depletion is calculated based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantities of proved reserves. Full Cost Ceiling Test —Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10% , of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with Securities and Exchange Commission (“SEC”) rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12 ‑month average prices, calculated as the unweighted arithmetic average of the first ‑day ‑of ‑the ‑month price for each month within the 12 ‑month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the year ended December 31, 2015, the Company recorded a full cost ceiling test impairment after income taxes of $1,365 million. During the year ended December 31, 2014 , the Company recorded a full cost ceiling test impairment before income taxes of $213.8 million. No impairment expense was recorded for the year ended December 31, 2013. Depreciation, depletion, amortization and accretion— Depreciation, depletion, amortization and accretion (“DD&A”) is provided using the units-of-production method based upon estimates of proved oil, NGL and natural gas reserves with oil, NGL and natural gas production being converted to a common unit of measure based upon their relative energy content. All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. In arriving at depletion rates under the units ‑of ‑production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by internal and third party geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion and impairment expense. Unproved Properties —Costs associated with unproved properties and properties under development are excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base. Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred into the full cost pool subject to amortization when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. Based on management’s review and current operating plans, 11% , 9% and 11% of the unproved property balance at December 31, 2015 is expected to be added to the amortization base during the years 2016, 2017 and 2018, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2018, and represent leasehold interests that have expiration dates beginning in 2019 or leasehold interests that are currently held by production. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2 015, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2013 2013 2014 2015 Total Leasehold acquisition costs $ $ $ $ $ Exploration costs Development costs — Total $ $ $ $ $ Oil and Natural Gas Reserve Quantities The Company’s most significant estimates relate to its proved oil and natural gas reserves. The estimates of oil and natural gas reserves as of December 31, 2015, 2014 and 2013 are based on reports prepared by a third party engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”). Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Ryder Scott has historically prepared a reserve and economic evaluation of the Company’s properties, utilizing information provided to it by management and other information available, including information from the operators of the property. The standards of the Financial Accounting Standards Board (“FASB”) and rules of the SEC permit the use of new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. These rules allow, but do not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average price based upon the prior 12-month first-day-of-the-month price rather than a period-end price. Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. Debt Issuance Costs Debt issuance costs relating to long ‑term debt have been deferred and are being amortized and recorded as interest expense over the term of the related debt instrument. During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement (as defined in Note 5, “Long-Term Debt”). During 2014, the Company capitalized approximately $37.4 million in costs associated with the issuance of the 6.125% Notes (as defined in Note 5, “Long-Term Debt”) and costs incurred to enter into the Second Amended and Restated Credit Agreement. The Company expensed $3.9 million of debt issuance costs during 2014 in conjunction with the termination of our senior unsecured Bridge Facility (as defined in Note 5, “Long-Term Debt”) obtained in connection with the acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells (the “Catarina Acquisition”). At December 31, 2015 and December 31, 2014, the Company had approximately $41.0 million and $48.2 million, respectively, of debt issuance costs (net of accumulated amortization of $14.7 million and $7.2 million, respectively) remaining that are being amortized over the terms of the respective debt. Environmental Expenditures The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non ‑capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally not discounted unless the timing of cash payments for the liability or component is fixed or reliably determinable. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. Management believes the Company is currently in compliance with all applicable federal, state and local regulations associated with its properties. Accordingly, no environmental remediation liability or loss associated with the Company’s properties was recorded as of December 31, 2015 and 2014. Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool. To estimate the fair value of an asset retirement obligation, the Company employs a present value technique, which reflects certain assumptions, including its credit ‑adjusted risk ‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in change to the carrying amount of the liability. Stock ‑Based Compensation The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (as defined in Note 7, “Stock-Based Compensation”) (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period using the straight-line method. Compensation expense for these awards will be revalued at each period end until vested. Revenue Recognition Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, NGL and natural gas sales. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in ‑kind” and, in doing so, take more or less than their respective entitled percentage. As of December 31, 2015, 2014 and 2013 there were no material oil and natural gas imbalances. Sales to Major Customers The Company’s oil, NGL and natural gas production was sold to certain customers representing 10% or more of its total revenues for the years ended December 31, 2015, 2014 and 2013 as listed below: 2015 2014 2013 Customer A Customer B Customer C Customer D Production is normally sold to relatively few customers. Substantially all of the Company’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Management believes the loss of any of the Company’s major customers would not have a long ‑term material adverse effect on the Company’s operations. General and Administrative Expenses On December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (“SOG”), pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf. See detailed discussion of the Company’s relationship with SOG in Note 9, “Related Party Transactions.” Derivative Instruments The Company utilizes derivative instruments in order to manage price risk associated with future crude oil and natural gas production. Management sets and implements all of the hedging policies, including volumes, types of instruments and counterparties, on a monthly basis. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings because it does not designate its derivatives as cash flow hedges. Income Taxes The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary difference and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered. Additionally, the Company is required to determine whether it is more likely than not (a likelihood of more than 50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax expense. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact the Company’s financial position, results of operations and cash flows. The Company does not have any material uncertain tax positions during the years ended December 31, 2015 or 2014. Earnings per Share Basic net income (loss) per common share are computed using the two-class method. The two-class method is required for those entities that have participating securities. The two-class method is an earnings allocation formula that determines net income (loss) per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. The Company’s restricted shares of common stock (see Note 7, “Stock ‑Based Compensation”) are participating securities under ASC 260, “Earnings per Share,” because they may participate in undistributed earnings with common stock. Participating securities do not have a contractual obligation to share in the Company’s losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Diluted net income (loss) per common share reflect the dilutive effects of the participating securities using the two-class method or the treasury stock method, whichever is more dilutive. They also reflect the effects of the potential conversion of the Company’s Series A and Series B Convertible Perpetual Preferred Stock using the if ‑converted method, if the effect is dilutive.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Acquisitions and Divestitures
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. Catarina Acquisition On June 30, 2014, we completed the Catarina Acquisition for an aggregate adjusted purchase price of $557.1 million. The effective date of the transaction was January 1, 2014. The purchase price was funded with a portion of the proceeds from the issuance of the $850 million senior unsecured 6.125% notes due 2023 (the ‘‘Original 6.125% Notes’’) and cash on hand. The purchase price allocation for the Catarina Acquisition is preliminary and is subject to further adjustments and the settlement of certain post-closing adjustments with the seller. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $ Wycross Acquisition On October 4, 2013, we completed our acquisition of contiguous acreage in McMullen County, Texas with 13 gross producing wells (the “Wycross Acquisition”) for an aggregate adjusted purchase price of $229.6 million. The effective date of the transaction was July 1, 2013. The purchase price was funded with proceeds from the issuance of the Additional 7.75% Notes (as defined in Note 5, “Long-Term Debt”), the issuance of 11,040,000 shares of common stock, and cash on hand. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Other liabilities assumed Fair value of net assets acquired $ Cotulla Acquisition On May 31, 2013, we completed our acquisition of acreage in Dimmit, Frio, LaSalle and Zavala Counties, Texas with 53 gross producing wells (the “Cotulla Acquisition”) for an aggregate adjusted purchase price of $280.9 million. The effective date of the transaction was March 1, 2013. The purchase price was funded with borrowings under the Company’s Amended and Restated Credit Agreement (as defined in Note 5, “Long-Term Debt”), cash on hand, and proceeds from the Company’s private placement of the Series B Convertible Perpetual Preferred Stock. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Fair value of assets acquired Asset retirement obligations Other liabilities assumed Fair value of net assets acquired $ Palmetto Disposition On March 31, 2015, we completed our disposition to a subsidiary of Sanchez Production Partners LP (“SPP”) of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas (the “Palmetto Disposition”) for an adjusted sales price of approximately $83.4 million. The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser’s working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of approximately $83.0 million (approximately $81.4 million as adjusted) cash and 1,052,632 common units of SPP (the “SPP Common Units”) valued at approximately $2.0 million as of the date of the closing. These SPP Common Units were later sold back to SPP in October 2015 as part of the Western Catarina Midstream Divestiture described below. The Company did not record any gains or losses related to the Palmetto Disposition. Western Catarina Midstream Divestiture On October 14, 2015, the Company and SN Catarina, LLC (“SN Catarina”) completed the sale of SN Catarina’s interests in Catarina Midstream, LLC, a wholly-owned subsidiary of SN Catarina (“Catarina Midstream”), which as of the closing included certain midstream gathering lines and associated assets and interests located in Dimmit County and Webb County, Texas and 105,263 SPP Common Units to SPP for an adjusted purchase price of $345.8 million in cash (the “Western Catarina Midstream Divestiture”). In connection with the closing of the Western Catarina Midstream Divestiture, SN Catarina and Catarina Midstream entered into a Firm Gathering and Processing Agreement (the “Gathering Agreement”) on October 14, 2015 for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream. In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each case, subject to an annual escalation for a positive increase in the consumer price index. In addition, SN Catarina has, under certain circumstances, a right of first refusal during the term of the agreement and afterwards with respect to dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company recorded a deferred gain of approximately $74.1 million as a result of Gathering Agreement being accounted for as an operating lease. This deferred gain will be amortized straight-line over the firm commitment term of five years as an offset to the transportation fees paid to SPP under the Gathering Agreement. Pro Forma Operating Results (Unaudited) The following unaudited pro forma combined results for the year ended December 31, 2014 reflects the consolidated results of operations of the Company as if the Catarina Acquisition and related financing had occurred on January 1, 2013. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, impairment and interest expense and debt issuance cost amortization for acquisition debt. The unaudited pro forma combined financial statements give effect to the events set forth below:  The Catarina Acquisition completed on June 30, 2014.  Issuance of the Original 6.125% Notes to finance a portion of the Catarina Acquisition, and the related adjustments to interest expense: Year Ended December 31, 2014 Revenues $ Net income (loss) attributable to common stockholders $ Net income (loss) per common share, basic and diluted $ The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Catarina Acquisition and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Post ‑Acquisition Operating Results The amounts of revenue and excess of revenues over direct operating expenses included in the Company’s consolidated statements of operations for the years ended December 31, 201 5 and 201 4 , for the Catarina Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2015 2014 Revenues $ $ Excess of revenues over direct operating expenses $ $

Cash and Cash Equivalents

Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2015
Cash and Cash Equivalents
Cash and Cash Equivalents	Note 4. Cash and Cash Equivalents As of December 31, 2015 and 2014, cash and cash equivalents consisted of the following (in thousands): December 31, December 31, 2015 2014 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Long-Term Debt	Note 5. Long ‑Term Debt Long-term debt as of December 31, 2015 consisted of $1.15 billion face value of 6.125% senior notes (the “6.125% Notes,” consisting of $850 million in Original 6.125% Notes and $300 million in Additional 6.125% Notes (defined below), which were issued at a premium to face value of $2.3 million) maturing on January 15, 2023, and $600 million principal amount of 7.75% senior notes (the “7.75% Notes,” consisting of $400 million in Original 7.75% Notes (defined below) and $200 million in Additional 7.75% Notes, which were issued at a discount to face value of $7.0 million), maturing on June 15, 2021. As of December 31, 2015 and 2014 the Company’s long-term debt consisted of the following: Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Maturity date 2015 2014 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Total long-term debt $ $ The components of interest expense are (in thousands): Year Ended December 31, 2015 2014 2013 Interest on Senior Notes $ $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes — Total interest expense $ $ $ Credit Facility Previous Credit Agreement: On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC (“SEP III”), SN Marquis LLC (“SN Marquis”) and SN Cotulla Assets, LLC (“SN Cotulla”), collectively, as the borrowers, entered into a revolving credit facility represented by a $500 million Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital Markets as sole lead arranger and sole book runner and each of the other lenders party thereto (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement was to mature on May 31, 2018. On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit Agreement. The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million outstanding. Second Amended and Restated Credit Agreement: On June 30, 2014, the Company, as borrower, and SEP III, SN Marquis, SN Cotulla, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC as loan parties, entered into a revolving credit facility represented by a $1.5 billion Second Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent, Compass Bank and SunTrust Bank as co-documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the lenders party thereto (the ‘‘Second Amended and Restated Credit Agreement’’). The Company has elected an available commitment amount under the Second Amended and Restated Credit Agreement of $300 million. Additionally, the Second Amended and Restated Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $80 million and the total availability thereunder. As of December 31, 2015, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement. Availability under the Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base and aggregate elected commitment. The borrowing base under the Second Amended and Restated Credit Agreement was set at $362.5 million upon issuance of the Additional 6.125% Notes and was increased to $650 million in connection with the October 1, 2014 redetermination. However, the Company elected a commitment amount of $300 million and the Company retained the ability to increase the aggregate elected commitment up to the $650 million approved borrowing base upon written notice from the Company and compliance with certain conditions, including the consent of any lender whose elected commitment was increased. On March 31, 2015, pursuant to an amendment of the Second Amended and Restated Credit Agreement, the borrowing base under such agreement was changed to $550 million, with the aggregate elected commitment amount of $300 million remaining unchanged. The borrowing base was reduced as a result of several factors that included the decrease in reserve value from the decline in commodity prices along with the reduction in reserves in connection with the Palmetto disposition discussed above partially offset by underlying new reserve growth through drilling. On November 20, 2015, in connection with the October 1, 2015 redetermination, the borrowing base under the Second Amended and Restated Credit Agreement changed from $550 million to $500 million, with the aggregate elected commitment amount of $300 million remaining unchanged. The borrowing base was further reduced to $425 million, without any change to the aggregate elected commitment amount, by the Sixth Amendment (as defined below), as further discussed in Note 18, “Subsequent Events.” All of the aggregate elected commitment amount was available for future revolver borrowings as of December 31, 2015. The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement can be subsequently redetermined up or down by the lenders based on, among other things, their evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves. Redeterminations of the borrowing base are scheduled to occur semi-annually on or before April 1 and October 1 of each year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the aggregate amount of the Company’s high yield debt and (from the date of the Sixth Amendment and as further discussed in Note 18, “Subsequent Events”) second lien debt, other than second lien debt representing the payment of interest in kind, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii) interim redetermination at the election of the administrative agent at the direction of a majority of the credit exposures or, if none, the elected commitments of the lenders, once between each scheduled redetermination and (iv) if the required lenders so direct in connection with asset sales and swap terminations involving more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of the assets so sold and swaps so terminated. The Company’s obligations under the Second Amended and Restated Credit Agreement are secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries not designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries not designated as “unrestricted subsidiaries.” The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the Company’s existing and future subsidiaries not designated as “unrestricted subsidiaries.” At the Company’s election, borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 0.50% to 2.50% for alternate base rate borrowings and from 1.50% to 2.50% for eurodollar borrowings, depending on the utilization of the borrowing base. Furthermore, the Company is also required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum , depending on the utilization of the elected commitment. The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark-to-market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million. Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times , and (ii) senior secured debt to consolidated last twelve months (“LTM”) EBITDA of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter. On October 30, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement (the “Fifth Amendment”) which Fifth Amendment, among other things, (1) amended the Second Amended and Restated Credit Agreement and its exhibits and schedules to (a) update certain disclosures to be effective as of the date of the Fifth Amendment, including (i) the organizational chart and subsidiary list in the schedules to the Second Amended and Restated Credit Agreement to reflect the disposition of Catarina Midstream, LLC and (ii) the lists of marketing contracts and swap agreements in the schedules to the Second Amended and Restated Credit Agreement; (b) modify certain representations and the form of compliance certificate under the Second Amended and Restated Credit Agreement to reference updated disclosures provided to the Administrative Agent pursuant to the terms of the Second Amended and Restated Credit Agreement; (c) modify certain covenants to expressly (i) not require the Company to deliver fourth quarter financial statements prior to the delivery of annual financial statements, (ii) not require that certain insurance policies of the Loan Parties contain certain endorsements or loss payable provisions and (iii) permit the Loan Parties to enter into certain leases; (d) permit the Loan Parties to deliver certain financial statements and related documents required under the Second Amended and Restated Credit Agreement electronically and provide that, except in the case of compliance certificates or for other deliveries to the Administrative Agent or a lender that requests physical delivery, any such statements and documents that are filed with the SEC are deemed delivered when posted on the Company’s website or other internet or intranet website to which each lender and the Administrative Agent have access; (e)(i) specifically identify TPL South Texas Processing Company LP as the counterparty to the previously permitted Eagle Ford Midstream JV Transaction (as defined in the Fifth Amendment), (ii) separately identify and permit the “Gathering JV” component of such transaction and increase from $80 million to $115 million the permitted investment basket for investments in the Eagle Ford Midstream JV Transaction generally, thereby making the entire existing $50 million “other” permitted investment basket available for investments either in such transaction or other investments in unrestricted subsidiaries of the Company and (iii) provide that none of the transactions comprising the Eagle Ford Midstream JV Transaction shall be considered synthetic leases; (f) modify the change-in-business covenant to permit unrestricted subsidiaries to make direct or indirect investments in the oil and gas industry and related businesses and activities without restrictions on geography; (g) change the definition of “Material Adverse Effect” to (i) reference, among other things, (x) the ability of the Loan Parties to perform their obligations under the Loan Documents (as defined in the Second Amended and Restated Credit Agreement), rather than the ability of any Loan Party to perform any of its obligations under any Loan Document, (y) the validity or enforceability of the Loan Documents, rather than the validity or enforceability of any Loan Document, (z) the rights and remedies of or benefits available to the Administrative Agent, any issuing bank or any lender under the Loan Documents, rather than under any Loan Document and (ii) provide that general market or industry conditions, which do not affect the Company in a disproportionately adverse manner, shall not constitute or be taken into account in determining whether there has been a “Material Adverse Effect”; and (h) provide for other technical amendments, clarifications and corrections; and (2) waived any existing breaches of, and any resulting defaults or events of defaults under the Second Amended and Restated Credit Agreement with respect to, the Company’s covenants in the Second Amended and Restated Credit Agreement (a) to deliver fourth quarter financial statements within 45 days after the end of such fiscal quarter; (b) to provide certain loss payable clauses or provisions and endorsements with respect to certain insurance maintained by the Loan Parties; and (c) in respect of leases other than capital leases and leases of hydrocarbon interests. On January 22, 2016, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth Amendment”) to modify certain representations, covenants, exhibits and schedules and to waive any existing breaches of, and any resulting defaults or events of default with respect to certain covenants of the Second Amended and Restated Credit Agreement, all as further discussed in Note 18, “Subsequent Events.” From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions. As of December 31, 2015, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement. Bridge Commitment: In connection with the Catarina Acquisition we obtained a commitment (the “Bridge Commitment”) from Royal Bank of Canada, RBC Capital Markets, Credit Suisse AG, Credit Suisse Securities (USA) LLC, Capital One, National Association and SunTrust Bank to provide, arrange, bookrun and agent, as applicable, a senior unsecured bridge facility (the “Bridge Facility”), in an aggregate amount up to $300 million (reduced by the aggregate principal amount of the Additional 6.125% Notes). The Bridge Commitment was set to expire upon the earliest to occur of (a) August 19, 2014, (b) the date of execution and delivery of definitive bridge documentation by us and the lenders under the Bridge Facility or (c) the termination of the commitments by us. The Company terminated the Bridge Commitment upon the execution of the Second Amended and Restated Credit Agreement on June 30, 2014 and wrote off $3.9 million in costs associated with obtaining the Bridge Commitment to interest expense at that time. 7.75% Senior Notes Due 2021 On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest is payable on each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay outstanding indebtedness under our credit facilities. The Original 7.75% Notes are the senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries. On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75% senior notes due 2021 (the “Additional 7.75% Notes” and, together with the Original 7.75% Notes, the “7.75% Notes”) in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net proceeds of $188.8 million (after deducting the initial purchasers’ discounts and offering expenses of $4.2 million) from the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional 7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are therefore treated as a single class of securities under the indenture. We used the net proceeds from the offering to partially fund the Wycross Acquisition completed in October 2013, a portion of the 2013 and 2014 capital budgets, and for general corporate purposes. The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future. The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. We have the option to redeem all or a portion of the 7.75% Notes, at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets. On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the ‘‘Securities Act’’), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act. 6.125% Senior Notes Due 2023 On June 27, 2014, the Company completed a private offering of the Original 6.125% Notes. Interest is payable on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the $100 million in borrowings outstanding under its Amended and Restated Credit Agreement and to finance a portion of the purchase price of the Catarina Acquisition. We used the remaining proceeds from the offering to fund a portion of the remaining 2014 capital budget and for general corporate purposes. The Original 6.125% Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125% senior notes due 2023 (the ‘‘Additional 6.125% Notes’’ and, together with the Original 6.125% Notes, the 6.125% Notes and, together with the 7.75% Notes, the ‘‘Senior Notes’’) in a private offering at an issue price of 100.75% of the principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial purchasers’ discounts, adding premiums to face value of $2.3 million and deducting estimated offering expenses of $6.4 million. The Company also received cash for accrued interest from June 27, 2014 through the date of the issuance of $3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional 6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are therefore treated as a single class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the 2014 capital budget and intend to use the remainder of the net proceeds to fund a portion of the 2015 capital budget, and for general corporate purposes. The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior unsecured basis in the future. The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. The Company has the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15, 2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the 6.125% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to July 15, 2018. In addition, the Company may redeem up to 35% of the 6.125% Notes prior to July 15, 2017 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain Company assets. On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the 6.125% Notes that had been registered under the Securities Act, for an equal amount of the 6.125% Notes that had not been registered under the Securities Act.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity
Stockholders' Equity	Note 6. Stockholders’ Equity Common Stock Offerings — On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00 per share. The Company received net proceeds from this offering of approximately $241.4 million, after deducting underwriters’ fees and offering expenses of approximately $12.5 million. The Company used the net proceeds from the offering to partially fund the Wycross Acquisition completed in October 2013 and a portion of the 2013 and 2014 capital budgets, and for general corporate purposes. On June 12, 2014, the Company completed a public offering of 5,000,000 shares of common stock, at an issue price of $35.25 per share. The Company received net proceeds from this offering of $167.5 million, after deducting underwriters’ fees and offering expenses of $8.7 million. The Company used the net proceeds from the offering to partially fund the 2014 capital budget and for general corporate purposes. Series A Convertible Perpetual Preferred Stock Offering —On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A Convertible Perpetual Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The issue price of each share of the Series A Convertible Perpetual Preferred Stock was $50.00 . The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs of approximately $5.5 million. Each share of Series A Convertible Perpetual Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.325 shares of common stock per share of Series A Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 4,275,640 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Convertible Perpetual Preferred Stock. The annual dividend on each share of Series A Convertible Perpetual Preferred Stock is 4.875% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Company’s Board of Directors (the “Board”). The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and as of December 31, 2015, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series A Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series A Convertible Perpetual Preferred Stock and the holders of the Series B Convertible Perpetual Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number. At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Convertible Perpetual Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Convertible Perpetual Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Convertible Perpetual Preferred Stock as a result of the fundamental change. Series B Convertible Perpetual Preferred Stock Offering —On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Convertible Perpetual Preferred Stock. The issue price of each share of the Series B Convertible Perpetual Preferred Stock was $50.00 . The Company received net proceeds from the private placement of $216.6 million, after deducting placement agent’s fees and offering costs of $8.4 million. Each share of Series B Convertible Perpetual Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of approximately $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 8,255,055 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Convertible Perpetual Preferred Stock. The annual dividend on each share of Series B Convertible Perpetual Preferred Stock is 6.500% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and as of December 31, 2015, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series B Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series B Convertible Perpetual Preferred Stock and the holders of the Series A Convertible Perpetual Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number. At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the Series B Convertible Perpetual Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series B Convertible Perpetual Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series B Convertible Perpetual Preferred Stock as a result of the fundamental change. Preferred Stock Exchanges —On February 12, 2014 and February 13, 2014, the Company entered into exchange agreements with certain holders (the ‘‘February 2014 Holders’’) of the Company’s Series A Convertible Perpetual Preferred Stock, and of Series B Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 947,490 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,425,574 shares of the Company’s common stock, and (ii) 756,850 shares of the Series B Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,021,066 shares of common stock. Additionally, on May 29, 2014, the Company entered into exchange agreements with certain holders (the ‘‘May 2014 Holders’’) of the Company’s Series A Convertible Perpetual Preferred Stock, and of Series B Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 166,025 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 418,715 shares of the Company’s common stock, and (ii) 210,820 shares of the Series B Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 553,980 shares of common stock. Further, on August 28, 2014, the Company entered into exchange agreements with certain holders (the ‘‘August 2014 Holders,’’ and together with the May 2014 Holders and the February 2014 Holders, the ‘‘Holders’’) of the Company’s Series A Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of 47,500 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 119,320 shares of the Company’s common stock. Since the Holders were not entitled to any consideration over and above the initial conversion rates of 2.325 and 2.337 common shares for each preferred share exchanged for Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock, respectively, any consideration is considered an inducement for the Holders to convert earlier than the Company could have forced conversion. The Company has determined the fair value of consideration transferred to the Holders and the fair value of consideration transferrable pursuant to the original conversion terms. The $13.9 million, $3.1 million and $0.3 million excess of the fair value of the shares of common stock issued over the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed in connection with the exchange agreements entered into in February, May and August 2014, respectively, has been reflected as an additional preferred stock dividend, that is, as an increase in accumulated deficit to arrive at net loss attributable to common shareholders in our condensed consolidated financial statements. Preferred Stock Conversion— On November 20, 2015, a holder of our Series B Convertible Perpetual Preferred Stock exercised its right to convert 4,500 shares our Series B Convertible Perpetual Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock, in exchange for 10,517 shares of our common stock. NOL Rights Plan —On July 28, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights plan (the “Rights Plan”) with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, the Board declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of our common stock. The dividend was paid on August 10, 2015 to stockholders of record as of the close of business on August 7, 2015 (the “NOL Record Date”). In addition, one Right automatically attaches to each share of common stock issued between the NOL Record Date and such date as when the Rights become exercisable. Earnings (Loss) Per Share — The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2015, 2014, and 2013 (in thousands, except per share amounts): Year Ended December 31, 2015 2014 2013 Net income (loss) $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — Net income (loss) attributable to common stockholders $ $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share Dilutive shares (3)(4)(5) — — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic and diluted $ $ $ (1) The Company's restricted shares of common stock are participating securities. (2) For the years ended December 31, 2015 and 2014, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company's losses. (3) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314 sh ares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (4) The year ended December 31, 2014 excludes 1,732,888 shares of weighted average restricted stock and 13,527,738 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (5) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive .

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Stock-Based Compensation
Stock-Based Compensation	Note 7. Stock ‑Based Compensation At the Annual Meeting of Stockholders of the Company held on May 21, 2015 (“2015 Annual Meeting”), the Company’s stockholders approved the Sanchez Energy Corporation Second Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Board had previously approved the LTIP on April 20, 2015, subject to stockholder approval. The Company’s directors and consultants as well as employees of SOG, Sanchez Energy Partners I, LP, and their affiliates (excluding the Company) (collectively, the “Sanchez Group”) who provide services to the Company are eligible to participate in the LTIP. Awards to participants may be made in the form of restricted shares, phantom shares, share options, share appreciation rights and other share-based awards. The maximum number of shares that may be delivered pursuant to the LTIP is limited to (i) 4,000,000 shares of common stock plus the number of shares of common stock available under the predecessor to the LTIP on the record date of the 2015 Annual Meeting (the "Record Date") at which the stockholders approved the LTIP as well as (ii) upon the issuance of additional shares of common stock from time to time after the Record Date, an automatic increase of 15% of such issuance of additional shares of common stock, unless the Board determines to increase the maximum number of shares of common stock by a lesser amount. Shares withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of shares, the shares subject to such award are then available for new awards under the LTIP. Shares delivered pursuant to awards under the LTIP may be newly issued shares, shares acquired by the Company in the open market, shares acquired by the Company from any other person, or any combination of the foregoing. The LTIP is administered by the Board or the Compensation Committee as appointed by the Board. The Board may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. The Board has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of shares that may be granted, subject to shareholder approval as may be required by the exchange upon which the common shares are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by the Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. During the year ended December 31, 2015, the Company issued 95,237 shares of restricted common stock pursuant to the LTIP to five directors of the Company that vest within one year from the date of grant. Pursuant to ASC 718, stock-based compensation expense for these awards was based on their grant date fair values of $12.65 and $9.80 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the vesting period The Company also issued approximately 3.4 million shares of restricted common stock pursuant to the LTIP to certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services agreement. Approximately 3.3 million shares of restricted common stock vest in equal annual amounts over a three -year period and the remaining 0.1 million shares of restricted common stock vest in equal amounts over a five -year period. During the year ended December 31, 2014, the Company issued 35,769 shares of restricted common stock pursuant to the LTIP to four directors of the Company that vest within one year from the date of grant. Pursuant to ASC 718, stock-based compensation expense for these awards was based on their grant date fair values of $33.05 and $14.90 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the vesting period The Company also issued approximately 2.0 million shares of restricted common stock pursuant to the LTIP to certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services agreement. Approximately 0.7 million shares of restricted common stock vest in equal annual amounts over a two -year period and approximately 1.3 million shares of restricted common stock vest in equal annual amounts over a three -year period. During the year ended December 31, 2013, the Company issued 28,600 shares of restricted common stock pursuant to the LTIP to three directors of the Company that vest one year from the date of grant. Pursuant to ASC 718, stock-based compensation expense for these awards was based on their grant date fair value of $21.98 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the one year vesting period. The Company also issued approximately 1.3 million shares of restricted common stock pursuant to the LTIP to certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services agreement. Approximately 0.5 million shares of restricted common stock vest in equal annual amounts over a two -year period and approximately 0.8 million shares of restricted common stock vest in equal annual amounts over a three -year period. The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the consolidated statements of operations. Year Ended December 31, 2015 2014 2013 Restricted stock awards, directors $ $ $ Restricted stock awards, non-employees Total stock-based compensation expense $ $ $ Based on the $4.31 per share closing price of the Company’s common stock on December 31, 2015, there was approximately $25.7 million of unrecognized compensation cost related to these non ‑vested restricted shares outstanding. The cost is expected to be recognized over a weighted average period of approximately 1.84 years. A summary of the status of the non ‑vested shares as of December 31, 2015 is presented below (in thousands, except per share amounts): Weighted Aggregate Average Weighted Intrinsic Remaining Number of Average Value Contractual Shares Fair Value (in thousands) Life (Years) Non-vested common stock at December 31, 2014 $ $ Granted Vested Forfeited Non-vested common stock at December 31, 2015 $ $ As of December 31, 2015, approximately 5.2 million shares remain available for future issuance to participants.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes
Income Taxes	Note 8. Income Taxes The components of the federal income tax provision for the years ended December 31, 2015, 2014 and 2013 are (in thousands): Year Ended December 31, 2015 2014 2013 Current expense as a result of current operations $ $ — $ — Deferred expense (benefit) as a result of current operations Increase (decrease) in valuation allowance — Net income tax expense (benefit) $ $ $ The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate is summarized as follows (in thousands): Year Ended December 31, 2015 2014 2013 Income tax expense (benefit) at the federal statutory rate $ $ $ Officers' compensation limitation — — State Taxes (net of federal benefit) — — Non-deductible general and administrative expenses Percentage depletion carryforward — — Differences between actual income taxes and amounts estimated in prior years — Income tax expense (benefit) Valuation allowance — Net income tax expense (benefit) $ $ $ The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands): As of December 31, 2015 2014 Deferred tax assets (liabilities): Derivative assets $ $ Depreciable, depletable property, plant and equipment Share-based compensation Revenue Recognition — Other Federal net operating loss carryforward State net operating loss carryforward — Deferred tax assets: Valuation allowance — Total Deferred tax assets $ — $ As of December 31, 2015, the Company had NOLs of approximately $765. 9 million which begin to expire in 2031. Additionally, the Company had net operating losses in the states of Montana, Mississippi, and Louisiana which will begin to expire in 2018, 2033 and 2026, respectively. Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2015. On the basis of this evaluation, as of December 31, 2015, a valuation allowance of approximately $51 4.4 million has been recorded to record only the portion of the deferred tax asset that is more likely than not to be realized. The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions . ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. Adoption of this guidance affected the balance sheets as of December 31, 2014 as follows (in thousands): Decrease in Non - current assets of approximately $33,242 . Decrease in Current liabilities of approximately $33,242 . The Company files income tax returns in the U.S. and various state jurisdictions. Sanchez is no longer subject to examination by federal income tax authorities prior to 2012. State statues vary by jurisdiction. As of December 31, 2015, 2014 and 2013, the Company had no material uncertain tax positions.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions
Related Party Transactions	Note 9. Related Party Transactions SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Company does not have any employees. On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third party service providers. Sa laries and associated benefits of SOG employees and are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on a detailed analysis of actual time spent by the professional staff on Company projects and activities. General and administrative expenses such as office rent, utilities, supplies and other overhead costs, are allocated on the same percentages as the SOG employee salaries. Expenses allocated to the Company for general and administrative expenses for the years ended December 31, 2015, 2014 and 2013 are as follows (in thousands): Year Ended December 31, 2015 2014 2013 Administrative fees $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $ As of December 31, 2015 and December 31, 2014, the Company had a net receivable from SOG and other members of the Sanchez Group of $3.7 million and $0.4 million, respectively, which are reflected as “Accounts receivable—related entities” and “Accounts payable—related entities,” respectively, in the consolidated balance sheets. The net receivable as of December 31, 2015 and December 31, 2014 consists primarily of advances paid related to leasehold and other costs paid to SOG. In addition, the net receivable as of December 31, 2015 and December 31, 2014 includes approximately $0.7 million and $0.1 million, respectively, of net receivable from Sanchez Resources, LLC (“Sanchez Resources”). As of December 31, 2015 , the Company had a net payable to SPP of approximately $4.4 million that consists primarily of the December accrual for fees associated with the Gathering Agreement (see Note 3, “Acquisitions and Divestitures” for further discussion), which is reflected in the “Other Accrued liabilities” account on the consolidated balance sheets. Palmetto Disposition On March 31, 2015, we completed the Palmetto Disposition discussed above to a subsidiary of SPP, which is a related party (see Note 3, “Acquisitions and Divestitures”). Western Catarina Midstream Divestiture On October 14, 2015, we completed the Western Catarina Midstream Divestiture discussed above to SPP, which is a related party (see Note 3, “Acquisitions and Divestitures”). TMS Asset Purchase In August 2013, we acquired rights to approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS (the “TMS Transaction”) for cash and shares of our common stock. In connection with the TMS Transaction, we established an Area of Mutual Interest (‘‘AMI’’) in the TMS with SR Acquisition I, LLC (‘‘SR’’), a subsidiary of our affiliate Sanchez Resources, which transaction included a carry on drilling costs for up to 6 gross ( 3 net) wells. Sanchez Resources is indirectly owned, in part, by our Chief Executive Officer and the Executive Chairman of the Board, who each also serve on our Board. Eduardo Sanchez, Patricio Sanchez and Ana Lee Sanchez Jacobs, each an immediate family member of our Chief Executive Officer and the Executive Chairman of our Board, collectively, either directly or indirectly, own a majority of the equity interests of Sanchez Resources. Sanchez Resources is managed by Eduardo Sanchez, who is the brother of our Chief Executive Officer and the son of our Executive Chairman of the Board. In addition, Eduardo Sanchez was named President of Sanchez Energy, effective as of October 1, 2015. As part of the transaction, we acquired our working interests in the AMI owned at closing from three sellers ( two third parties and one related party of the Company, SR) resulting in our owning an undivided 50% working interest across the AMI through the TMS. Total consideration for the transactions consisted of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The total cash consideration provided to SR, an affiliate of the Company, was $14.4 million, before consideration of any well carries. The acquisitions were accounted for as the purchase of assets at cost at the acquisition date. We also committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI (the “Initial Well Carry”) with an option to drill an additional 6 gross (3 net) TMS wells (“Additional Wells”) within the AMI. In August 2015, after completing the Initial Well Carry, the Company signed an agreement with SR whereby the Company paid SR approximately $8 million in lieu of drilling the remaining two Additional Wells (the “Buyout Agreement”). The Buyout Agreement stipulates that SN has earned full rights to all acreage stated in the TMS Transaction and effectively terminates any future well carry commitments .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments
Derivative Instruments	Note 10. Derivative Instruments To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. Under ASC Topic 815, “ Derivatives and Hedging , ” all derivative instruments are recorded on the consolidated balance sheets at fair value as either short ‑term or long ‑term assets or liabilities based on their anticipated settlement date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings since the Company has elected not to designate its current derivative contracts as hedges. As of December 31, 2015, the Company had the following NYMEX WTI crude oil swaps covering anticipated future production: Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 $ $ - $ As of December 31, 2015, the Company had the following NYMEX WTI crude oil puts covering anticipated future production: Calendar Year Volumes (Bbls) Put Price per Bbl Put Price Range per Bbl 2016 $ $ - $ As of December 31, 2015, the Company had the following NYMEX Henry Hub natural gas swaps covering anticipated future production: Calendar Year Volumes (Mmbtu) Average Price per Mmbtu Price Range per Mmbtu 2016 $ $ - $ 2017 $ $ The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2015, 2014, and 2013 (in thousands): Year Ended December 31, 2015 2014 2013 Beginning fair value of commodity derivatives $ $ $ Net gains on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts: Crude oil — Ending fair value of commodity derivatives $ $ $ Balance Sheet Presentation The Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the consolidated balance sheets. The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets (in thousands): December 31, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ — December 31, 2014 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value of Financial Instruments
Fair Value of Financial Instruments	Note 11. Fair Value of Financial Instruments Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The valuation models used to value derivatives associated with the Company’s oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Fair Value on a Recurring Basis The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 (in thousands): As of December 31, 2015 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $ As of December 31, 2014 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ $ Financial Instruments: The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s consolidated balance sheets as of December 31, 2015 and 2014. The Company’s money market funds represent cash equivalents backed by the assets of high ‑quality banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. The Company’s derivative instruments, which consist of swaps, enhanced swaps, collars and puts, are classified as Level 2 as of December 31, 2015, and either Level 2 or Level 3 as of December 31, 2014, in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes. Since swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. As of December 31, 2014, the Company’s enhanced swaps, puts, collars and three-way collars included some level of unobservable inputs, such as volatility curves, and were therefore classified as Level 3. As of December 31, 2015, the Company believes that substantially all of the inputs required to calculate the fair value of puts and swaps observable in the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and are therefore classified as Level 2. Derivative instruments are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s derivative instruments. There were no derivative instruments classified as Level 3 as of December 31, 2015. The fair values of the Company’s derivative instruments classified as Level 3 as of December 31, 2014 and 2013 were $75.5 million and ($0.5) million, respectively. The significant unobservable inputs for Level 3 contracts as of December 31, 2014 include unpublished forward prices of commodities, market volatility and credit risk of counterparties The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): (Level 3) Year Ended December 31, 2015 2014 2013 Beginning balance $ $ $ Total gains (losses) included in earnings Net settlements on derivative contracts (1) Derivative contracts transferred to Level 2 — — Ending balance $ — $ $ Gains (losses) included in earnings related to derivatives still held as of December 31, 2015, 2014, and 2013 $ $ $ (1) Includes ($12,919) of net settlements in Level 2 that were transferred from Level 3 during 2015. Fair Value on a Non ‑Recurring Basis The Company follows the provisions of ASC 820 ‑10 for nonfinancial assets and liabilities measured at fair value on a non ‑recurring basis. Fair value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocations for the Catarina, Wycross and Cotulla Acquisitions are presented in Note 3, “Acquisitions and Divestitures.” Liabilities assumed include asset retirement obligations existing at the date of acquisition. Asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 12, “Asset Retirement Obligations.” In connection with the exchange agreements entered into in February, May and August 2014 by the Company with certain holders of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock, the Company issued common stock according to the conversion rate pursuant to each agreement and additional shares to induce the holders of the preferred stock to convert prior to the date the Company could mandate conversion. In addition, on November 20, 2015, a holder of our Series B Convertible Perpetual Preferred Stock exercised its right to convert 4,500 shares our Series B Convertible Perpetual Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock, in exchange for 10,517 shares of our common stock. The fair value of the common stock issued is based on the price of the Company’s common stock on the date of issuance. As there is an active market for the Company’s common stock, the Company has designated this fair value measurement as Level 1. A detailed description of the Company’s common stock and preferred stock issuances and redemptions is presented in Note 6, ‘‘Stockholders’ Equity.’’ Fair Value of Other Financial Instruments Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payable and accrued liabilities and long-term debt. The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to the highly liquid nature of these short term instruments. The registered 7.75% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 7.75% Notes was $366 million as of December 31, 2015, and was calculated using quoted market prices based on trades of such debt as of that date. The Company uses a market approach to determine fair value of its unregistered 6.125% Notes using observable market data. However, as the market for the 6.125% Notes is far less active than that of the 7.75% Notes, the Company also uses comparable market values for similar instruments, which results in a Level 2 fair value measurement. The estimated fair value of the 6.125% Notes was $61 5 .3 million as of December 31, 2015.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Asset Retirement Obligations	Note 12. Asset Retirement Obligations The Company’s asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The changes in the asset retirement obligation for the years ended December 31, 2015 and 2014 were as follows (in thousands): 2015 2014 Abandonment liability as of January 1, $ $ Liabilities incurred during period Acquisitions — Divestitures — Revisions Accretion expense Abandonment liability as of December 31, $ $

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities
Accrued Liabilities	Note 13. Accrued Liabilities The following information summarizes accrued liabilities as of December 31, 2015 and 2014 (in thousands): As of December 31, 2015 2014 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Leasehold improvements — Total accrued liabilities $ $

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies
Commitments and Contingencies	Note 14. Commitments and Contingencies From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. We are not aware of any material governmental proceedings against us or contemplated to be brought against us. On December 4, 13 and 16, 2013, three derivative actions were filed in the Court of Chancery of the State of Delaware against the Company, certain of its officers and directors, Sanchez Resources, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC (Friedman v. A.R. Sanchez, Jr. et al., No. 9158; City of Roseville Employees’ Retirement System v. A.R. Sanchez, Jr. et al., No. 9132; and Delaware County Employees Retirement Fund v. A.R. Sanchez, Jr. et al., No. 9165 (collectively, the ‘‘Consolidated Derivative Actions’’)). On December 20, 2013, the Consolidated Derivative Actions were consolidated, co-lead counsel for the plaintiffs was appointed and the plaintiffs were ordered to file an amended consolidated complaint (In re Sanchez Energy Derivative Litigation, Consolidated C.A. No. 9132-VCG, hereinafter, the “Delaware Derivative Action”). On January 28, 2014, a verified consolidated stockholder derivative complaint was filed. The Consolidated Derivative Actions concern the Company’s purchase of working interests in the TMS from Sanchez Resources. Plaintiffs alleged breaches of fiduciary duty against the individual defendants as directors of the Company; breaches of fiduciary duty against Antonio R. Sanchez, III as an executive director of the Company; aiding and abetting breaches of fiduciary duty against Sanchez Resources, Eduardo Sanchez, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC; and unjust enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. All of the defendants filed a motion to dismiss on April 1, 2014. Briefing concerning the motions to dismiss concluded on June 27, 2014. A hearing was held on August 11, 2014, on the motions to dismiss, and the court subsequently granted the motions to dismiss. The plaintiffs appealed the case to the Delaware Supreme Court for which the parties fully briefed the appeal and provided oral argument. On October 2, 2015, the Delaware Supreme Court reversed the motions to dismiss and remanded the case to the Court of Chancery of the State of Delaware. No scheduling order for the matter has been set at this time. The Company is unable to reasonably predict an outcome or to reasonably estimate a range of possible loss. On January 9, 2014, a derivative action was filed in 333rd district court in Harris County, Texas against the Company and certain of its officers and directors, styled Martin v. Sanchez, No. 2014-01028 (333rd Dist. Harris County, Texas). The complaint alleged a breach of fiduciary duty, corporate waste and unjust enrichment against various officers and directors. No action has been taken to date and damages are unspecified. On March 14, 2014, this action was stayed following a ruling on the motion to dismiss in the Delaware Derivative Action. After the motions to dismiss were granted in the Delaware Derivative Action, the parties entered into another agreed stay pending the appeal of the Delaware Derivative Action to the Delaware Supreme Court. This stay was entered by the court on February 5, 2015. Since the Delaware Supreme Court has ruled on the appeal, the parties agreed to another stay for 60 days following the completion of fact discovery in the Delaware Derivative Action. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. Defendants believe that the allegations contained in the matters described above are without merit and intend to vigorously defend themselves against the claims raised. In connection with the Catarina Acquisition, the 77,000 acres of undeveloped acreage that were included in the acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120 - day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the minimum number of wells required to maintain access to such undeveloped acreage. As of December 31, 2015, the Company had $265.4 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $200.7 million in payments due with respect to firm commitment of oil and natural gas volumes under the Gathering Agreement contract signed with SPP as part of the Western Catarina Midstream Divestiture that commenced on October 14, 2015 and continues until October 13, 2020, (ii) $50.8 million for a new corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (iii) $ 7.1 million for a ground lease agreement for land owned by the Calhoun Port Authority that commenced during the third quarter of 2014 and has an expiration date in August 2024 and (iv) $ 6.8 million for a 10 year acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas. This acreage lease agreement includes a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term. The Company’s ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the Company to the lessor in addition to a $1 million termination payment. The Company has the right to terminate its lease obligation for its acreage in Kenedy County, Texas at any time without penalty with six months advanced written notice and payment of any accrued leasehold expenses. On October 2, 2015, the Company, through SN Midstream LLC, a wholly-owned subsidiary of the Company (“SN Midstream”), entered into joint venture agreements with an affiliate of Targa to construct a new cryogenic natural gas processing plant (the “Processing Plant”) and associated high pressure gathering pipelines near the Company’s Catarina asset in the Eagle Ford Shale. In connection with the Processing Plant joint venture agreement, SN Midstream has committed to invest approximately $80 million and receive a 50% ownership interest in the joint venture owning the Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, SN Midstream has committed to invest approximately $35 million and receive a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. Construction on the gathering pipelines is expected to be completed in 2016. As of December 31, 2015, the Company had invested approximately $20 million in the Processing Plant joint venture, and approximately $17.5 million in the gathering pipeline joint venture. As of December 31, 2015, the Company has guaranteed SN Midstream’s remaining commitment to invest approximately $60 million and $17.5 million, respectively, in the Processing Plant and gathering pipelines joint ventures. Membership percentage interests in the Processing Plant joint venture and the gathering pipelines joint venture for the Company and Targa are calculated based on the aggregate capital contributions made by each party related to the total capital contributions made by both parties. If SN Midstream fails to make capital contributions or the Company fails to fulfill the guarantee or, in the case of the Processing Plant joint venture, the Company does not elect to contribute more than $80 million (if the cost to construct the Processing Plant exceeds $160 million) our membership interest in the joint venture could be reduced. If our membership interest falls below 20% , we have the potential to lose appointed board seats and voting rights.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2015
Subsidiary Guarantors
Subsidiary Guarantors	Note 15. Subsidiary Guarantors The Company filed registration statements on Form S ‑3 with the SEC, which became effective January 14, 2013 and June 11, 2014 and registered, among other securities, debt securities. The subsidiaries of the Company named therein are co ‑registrants with the Company, and the registration statement registered guarantees of debt securities by such subsidiaries. As of December 31, 2015, such subsidiaries are 100 percent owned by the Company and any guarantees by these subsidiaries will be full and unconditional (except for customary release provisions). In the event that more than one of these subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations. The Company also filed a registration statement on Form S-4 with the SEC, which became effective on June 20, 2014, pursuant to which the Company completed an offering of the 7.75% Notes, which are guaranteed by its subsidiaries named therein. As of December 31, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are “minor” within the meaning of Rule 3-10 of Regulation S-X. The Company also filed a registration statement on Form S-4 with the SEC, which became effective on January 23, 2015, pursuant to which the Company completed an offering of the 6.125% Notes, which are guaranteed by its subsidiaries named therein. As of December 31, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are “minor” within the meaning of Rule 3-10 of Regulation S-X. The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of its subsidiaries to distribute funds to the Company.

Investments

Investments	12 Months Ended
	Dec. 31, 2015
Investments.
Investments	Note 16. Investments On October 2, 2015, the Company, via SN Midstream, entered into joint venture agreements with an affiliate of Targa to, among other things, construct the Processing Plant and associated high pressure gathering pipelines near the Company’s Catarina asset in the Eagle Ford Shale. The Processing Plant, which will be located in La Salle County, Texas, is expected to have initial capacity of 200 MMcf per day with the ability to increase to 260 MMcf per day. In connection with the Processing Plant joint venture agreement, the SN Midstream has committed to invest approximately $80 million and receive a 50% ownership interest in the joint venture owning the Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, the SN Midstream has committed to invest approximately $35 million and receive a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. Construction on the gathering pipelines is expected to be completed in 2016. The Company is accounting for these joint ventures as equity method investments as Targa is the operator of the joint ventures and has the most influence with respect to the normal day-to-day construction and operating decisions. As of December 31, 2015, the Company had invested approximately $20 million in the Processing Plant joint venture, and approximately $17.5 million in the gathering pipeline joint venture. We have included these equity method investment balances in the “Other Assets” long-term asset line on the balance sheet. There were no earnings or losses from the Processing Plant joint venture or the gathering pipelines joint venture for the period ended December 31, 2015. On October 2, 2015, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the Silver Oak II Gas Processing Facility (the “SOII Facility”) in Bee County, Texas for a purchase price of $12.5 million. Targa owns the remaining undivided 90% interest in the SOII Facility, which is operated by Targa. Concurrently with the execution of the purchase and sale agreement for the SOII Facility, the Company entered into a firm gas processing agreement, whereby Targa will process a firm quantity, 125,000 Mcf/d, from the firm commencement date of March 1, 2016 until the in-service date of the Processing Plant discussed above. The Company is accounting for the investment in the SOII Facility as an equity method investment as Targa is the operator and majority interest owner of the SOII Facility. As of December 31, 2015, the Company had invested $12.5 million in the SOII Facility. Losses from the SOII Facility investment for the period ended December 31, 2015 were immaterial to the consolidated financial statements.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events.
Subsequent Events	Note 17. Subsequent Events On January 22, 2016, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Sixth Amendment. The Sixth Amendment, among other things, amended the Second Amended and Restated Credit Agreement and its exhibits and schedules to (a) permit repurchases of senior unsecured notes and equity interests issued by the Company for aggregate cash consideration not to exceed approximately $98.5 million ($100 million less approximately $1.5 million attributable to equity interests already purchased by an unrestricted subsidiary and distributed to the Company), subject to a sublimit of approximately $48.5 million for repurchases of equity interests other than preferred stock, subject to certain limitations; (b) permit the incurrence by the Company of (x) secured second lien debt; provided that: (i) such debt shall be (A) in an aggregate principal amount not to exceed $400,000,000 plus any principal representing payment of interest in kind and (B) subject to an approved intercreditor agreement at all times that any obligation under the Second Amended and Restated Credit Agreement is outstanding; and (ii) such debt shall not (A) provide for any scheduled payment of principal, scheduled mandatory redemption or scheduled sinking fund payment before the date that is 180 days following June 30, 2019 or (B) contain terms and conditions, taken as a whole, more restrictive than those set forth in the Second Amended and Restated Credit Agreement and (y) second lien debt refinancing or replacing the foregoing debt, to the extent permitted under the intercreditor agreement; (c) reduce the borrowing base from $500 million to $425 million; (d) provide for the reduction of the borrowing base by 25% of the amount of any second lien debt incurred (other than second lien debt issued in exchange for or the proceeds of which are used to redeem the Company’s senior unsecured notes and other than second lien debt that refinances second lien debt or represents payment of interest in kind); (e) provide that the maximum amount of senior unsecured notes issued by the Company that may be outstanding at any time, after giving effect to such issuance and any repayment of senior unsecured notes out of the proceeds thereof and the proceeds of any permitted second lien debt issued substantially contemporaneously therewith, is not greater than $2,150,000,000 minus the aggregate principal amount of second lien debt (excluding refinancings and replacements thereof and principal comprised of payments of interest in kind); (f) reflect the formation and designation of two additional unrestricted subsidiaries; (g) permit the Loan Parties to make investments in unrestricted subsidiaries in the form of equity interests of other unrestricted subsidiaries; (h) eliminate the ability of unrestricted subsidiaries to purchase debt and equity interests issued by the Company; and (i) provide for other technical amendments, clarifications and corrections.

Basis of Presentation and Sum26

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Basis of Presentation and Summary of Significant Accounting Policies
Principles of Consolidation	Principles of Consolidation The Company’s consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated.
Use of Estimates	Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.
Basis of Presentation	Basis of Presentation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
Cash Equivalents	Cash Equivalents Cash and cash equivalents consist primarily of cash on deposit, money market accounts and investment grade commercial paper that are readily convertible into cash and purchased with original maturities of three months or less.
Oil and Natural Gas Receivables	Oil and Natural Gas Receivables The majority of the Company’s receivables arise from sales of oil, natural gas liquids (“NGLs”) or natural gas. The Company does not have any off ‑balance ‑sheet credit exposure related to its customers. Receivables from the sale of oil and natural gas are generally unsecured. Allowances for doubtful accounts are determined based on management’s assessment of the creditworthiness of the customer. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all the collection attempts have been exhausted. At December 31, 2015 and 2014, management believed that all balances were fully collectible and no allowance for doubtful accounts was deemed necessary.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units ‑of ‑production method. Depletion is calculated based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantities of proved reserves. Full Cost Ceiling Test —Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10% , of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with Securities and Exchange Commission (“SEC”) rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12 ‑month average prices, calculated as the unweighted arithmetic average of the first ‑day ‑of ‑the ‑month price for each month within the 12 ‑month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the year ended December 31, 2015, the Company recorded a full cost ceiling test impairment after income taxes of $1,365 million. During the year ended December 31, 2014 , the Company recorded a full cost ceiling test impairment before income taxes of $213.8 million. No impairment expense was recorded for the year ended December 31, 2013. Depreciation, depletion, amortization and accretion— Depreciation, depletion, amortization and accretion (“DD&A”) is provided using the units-of-production method based upon estimates of proved oil, NGL and natural gas reserves with oil, NGL and natural gas production being converted to a common unit of measure based upon their relative energy content. All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. In arriving at depletion rates under the units ‑of ‑production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by internal and third party geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion and impairment expense. Unproved Properties —Costs associated with unproved properties and properties under development are excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base. Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred into the full cost pool subject to amortization when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. Based on management’s review and current operating plans, 11% , 9% and 11% of the unproved property balance at December 31, 2015 is expected to be added to the amortization base during the years 2016, 2017 and 2018, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2018, and represent leasehold interests that have expiration dates beginning in 2019 or leasehold interests that are currently held by production. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2 015, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2013 2013 2014 2015 Total Leasehold acquisition costs $ $ $ $ $ Exploration costs Development costs — Total $ $ $ $ $
Oil and Natural Gas Reserve Quantities	Oil and Natural Gas Reserve Quantities The Company’s most significant estimates relate to its proved oil and natural gas reserves. The estimates of oil and natural gas reserves as of December 31, 2015, 2014 and 2013 are based on reports prepared by a third party engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”). Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Ryder Scott has historically prepared a reserve and economic evaluation of the Company’s properties, utilizing information provided to it by management and other information available, including information from the operators of the property. The standards of the Financial Accounting Standards Board (“FASB”) and rules of the SEC permit the use of new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. These rules allow, but do not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average price based upon the prior 12-month first-day-of-the-month price rather than a period-end price. Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs relating to long ‑term debt have been deferred and are being amortized and recorded as interest expense over the term of the related debt instrument. During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement (as defined in Note 5, “Long-Term Debt”). During 2014, the Company capitalized approximately $37.4 million in costs associated with the issuance of the 6.125% Notes (as defined in Note 5, “Long-Term Debt”) and costs incurred to enter into the Second Amended and Restated Credit Agreement. The Company expensed $3.9 million of debt issuance costs during 2014 in conjunction with the termination of our senior unsecured Bridge Facility (as defined in Note 5, “Long-Term Debt”) obtained in connection with the acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells (the “Catarina Acquisition”). At December 31, 2015 and December 31, 2014, the Company had approximately $41.0 million and $48.2 million, respectively, of debt issuance costs (net of accumulated amortization of $14.7 million and $7.2 million, respectively) remaining that are being amortized over the terms of the respective debt.
Environmental Expenditures	Environmental Expenditures The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non ‑capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally not discounted unless the timing of cash payments for the liability or component is fixed or reliably determinable. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. Management believes the Company is currently in compliance with all applicable federal, state and local regulations associated with its properties. Accordingly, no environmental remediation liability or loss associated with the Company’s properties was recorded as of December 31, 2015 and 2014.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool. To estimate the fair value of an asset retirement obligation, the Company employs a present value technique, which reflects certain assumptions, including its credit ‑adjusted risk ‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in change to the carrying amount of the liability.
Stock-Based Compensation	Stock ‑Based Compensation The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (as defined in Note 7, “Stock-Based Compensation”) (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period using the straight-line method. Compensation expense for these awards will be revalued at each period end until vested.
Revenue Recognition	Revenue Recognition Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, NGL and natural gas sales. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in ‑kind” and, in doing so, take more or less than their respective entitled percentage. As of December 31, 2015, 2014 and 2013 there were no material oil and natural gas imbalances.
Sales to Major Customers	Sales to Major Customers The Company’s oil, NGL and natural gas production was sold to certain customers representing 10% or more of its total revenues for the years ended December 31, 2015, 2014 and 2013 as listed below: 2015 2014 2013 Customer A Customer B Customer C Customer D Production is normally sold to relatively few customers. Substantially all of the Company’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Management believes the loss of any of the Company’s major customers would not have a long ‑term material adverse effect on the Company’s operations.
General and Administrative Expenses	General and Administrative Expenses On December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (“SOG”), pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf. See detailed discussion of the Company’s relationship with SOG in Note 9, “Related Party Transactions.”
Derivative Instruments	Derivative Instruments The Company utilizes derivative instruments in order to manage price risk associated with future crude oil and natural gas production. Management sets and implements all of the hedging policies, including volumes, types of instruments and counterparties, on a monthly basis. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings because it does not designate its derivatives as cash flow hedges.
Income Taxes	Income Taxes The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary difference and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered. Additionally, the Company is required to determine whether it is more likely than not (a likelihood of more than 50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax expense. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact the Company’s financial position, results of operations and cash flows. The Company does not have any material uncertain tax positions during the years ended December 31, 2015 or 2014.
Earnings per Share	Earnings per Share Basic net income (loss) per common share are computed using the two-class method. The two-class method is required for those entities that have participating securities. The two-class method is an earnings allocation formula that determines net income (loss) per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. The Company’s restricted shares of common stock (see Note 7, “Stock ‑Based Compensation”) are participating securities under ASC 260, “Earnings per Share,” because they may participate in undistributed earnings with common stock. Participating securities do not have a contractual obligation to share in the Company’s losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Diluted net income (loss) per common share reflect the dilutive effects of the participating securities using the two-class method or the treasury stock method, whichever is more dilutive. They also reflect the effects of the potential conversion of the Company’s Series A and Series B Convertible Perpetual Preferred Stock using the if ‑converted method, if the effect is dilutive.
Recent Accounting Pronouncements	Recent Accounting Pronouncements During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions . ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. Adoption of this guidance affected the balance sheets as of December 31, 2014 as follows (in thousands): Decrease in Non - current assets of approximately $33,242 Decrease in Current liabilities of approximately $33,242 In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Basis of Presentation and Sum27

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Basis of Presentation and Summary of Significant Accounting Policies
Schedule of cost of unproved properties excluded from the amortization base	The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2 015, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2013 2013 2014 2015 Total Leasehold acquisition costs $ $ $ $ $ Exploration costs Development costs — Total $ $ $ $ $
Schedule of entity's oil, NGL and natural gas production sold to certain customers representing 10% or more of its total revenues	2015 2014 2013 Customer A Customer B Customer C Customer D

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Acquisitions
Schedule of unaudited pro forma combined statements of operations	Year Ended December 31, 2014 Revenues $ Net income (loss) attributable to common stockholders $ Net income (loss) per common share, basic and diluted $
Schedule of revenue and revenues in excess of direct operating expenses	Year Ended December 31, 2015 2014 Revenues $ $ Excess of revenues over direct operating expenses $ $
Catarina
Acquisitions
Schedule of total purchase price allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition	The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $
Wycross
Acquisitions
Schedule of total purchase price allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition	The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Other liabilities assumed Fair value of net assets acquired $
Cotulla
Acquisitions
Schedule of total purchase price allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition	The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Fair value of assets acquired Asset retirement obligations Other liabilities assumed Fair value of net assets acquired $

Cash and Cash Equivalents (Tabl

Cash and Cash Equivalents (Tables)	12 Months Ended
	Dec. 31, 2015
Cash and Cash Equivalents
Schedule of cash and cash equivalents	As of December 31, 2015 and 2014, cash and cash equivalents consisted of the following (in thousands): December 31, December 31, 2015 2014 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Schedule of long-term debt	Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Maturity date 2015 2014 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Total long-term debt $ $
Schedule of interest expense	The components of interest expense are (in thousands): Year Ended December 31, 2015 2014 2013 Interest on Senior Notes $ $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes — Total interest expense $ $ $

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity
Schedule of computation of basic and diluted net loss per share	The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2015, 2014, and 2013 (in thousands, except per share amounts): Year Ended December 31, 2015 2014 2013 Net income (loss) $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — Net income (loss) attributable to common stockholders $ $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share Dilutive shares (3)(4)(5) — — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic and diluted $ $ $ (1) The Company's restricted shares of common stock are participating securities. (2) For the years ended December 31, 2015 and 2014, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company's losses. (3) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314 sh ares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (4) The year ended December 31, 2014 excludes 1,732,888 shares of weighted average restricted stock and 13,527,738 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Stock-Based Compensation
Schedule of stock-based compensation expense	The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the consolidated statements of operations. Year Ended December 31, 2015 2014 2013 Restricted stock awards, directors $ $ $ Restricted stock awards, non-employees Total stock-based compensation expense $ $ $
Summary of the status of the non-vested shares	A summary of the status of the non ‑vested shares as of December 31, 2015 is presented below (in thousands, except per share amounts): Weighted Aggregate Average Weighted Intrinsic Remaining Number of Average Value Contractual Shares Fair Value (in thousands) Life (Years) Non-vested common stock at December 31, 2014 $ $ Granted Vested Forfeited Non-vested common stock at December 31, 2015 $ $

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes
Schedule of components of the federal income tax provision	The components of the federal income tax provision for the years ended December 31, 2015, 2014 and 2013 are (in thousands): Year Ended December 31, 2015 2014 2013 Current expense as a result of current operations $ $ — $ — Deferred expense (benefit) as a result of current operations Increase (decrease) in valuation allowance — Net income tax expense (benefit) $ $ $
Summary of difference between the statutory federal income taxes calculated using U.S. Federal statutory corporate income tax rate of 35% and company's effective tax rate	The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate is summarized as follows (in thousands): Year Ended December 31, 2015 2014 2013 Income tax expense (benefit) at the federal statutory rate $ $ $ Officers' compensation limitation — — State Taxes (net of federal benefit) — — Non-deductible general and administrative expenses Percentage depletion carryforward — — Differences between actual income taxes and amounts estimated in prior years — Income tax expense (benefit) Valuation allowance — Net income tax expense (benefit) $ $ $
Schedule of significant components of the deferred tax assets	Significant components of the deferred tax assets and liabilities are as follows (in thousands): As of December 31, 2015 2014 Deferred tax assets (liabilities): Derivative assets $ $ Depreciable, depletable property, plant and equipment Share-based compensation Revenue Recognition — Other Federal net operating loss carryforward State net operating loss carryforward — Deferred tax assets: Valuation allowance — Total Deferred tax assets $ — $

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions
Schedule of expenses allocated to the Company for general and administrative expenses	Expenses allocated to the Company for general and administrative expenses for the years ended December 31, 2015, 2014 and 2013 are as follows (in thousands): Year Ended December 31, 2015 2014 2013 Administrative fees $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative contract covering anticipated future production
Schedule of reconciliation of the changes in fair value of the Company's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2015, 2014, and 2013 (in thousands): Year Ended December 31, 2015 2014 2013 Beginning fair value of commodity derivatives $ $ $ Net gains on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts: Crude oil — Ending fair value of commodity derivatives $ $ $
Summary of balance sheet presentation of the Company's commodity derivatives	The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets (in thousands): December 31, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ — December 31, 2014 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $
Crude oil
Derivative contract covering anticipated future production
Schedule of anticipated future production	As of December 31, 2015, the Company had the following NYMEX WTI crude oil swaps covering anticipated future production: Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 $ $ - $
Crude oil | Enhanced swaps
Derivative contract covering anticipated future production
Schedule of anticipated future production	As of December 31, 2015, the Company had the following NYMEX WTI crude oil puts covering anticipated future production: Calendar Year Volumes (Bbls) Put Price per Bbl Put Price Range per Bbl 2016 $ $ - $
Natural gas
Derivative contract covering anticipated future production
Schedule of anticipated future production	As of December 31, 2015, the Company had the following NYMEX Henry Hub natural gas swaps covering anticipated future production: Calendar Year Volumes (Mmbtu) Average Price per Mmbtu Price Range per Mmbtu 2016 $ $ - $ 2017 $ $

Fair Value of Financial Instr36

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value of Financial Instruments
Schedule of financial assets and liabilities measured at fair value on a recurring basis	The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 (in thousands): As of December 31, 2015 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $ As of December 31, 2014 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ $
Reconciliation of changes in the fair value of the oil derivative instruments classified as Level 3 in the fair value hierarchy	The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): (Level 3) Year Ended December 31, 2015 2014 2013 Beginning balance $ $ $ Total gains (losses) included in earnings Net settlements on derivative contracts (1) Derivative contracts transferred to Level 2 — — Ending balance $ — $ $ Gains (losses) included in earnings related to derivatives still held as of December 31, 2015, 2014, and 2013 $ $ $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Schedule of changes in asset retirement obligation	The Company’s asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The changes in the asset retirement obligation for the years ended December 31, 2015 and 2014 were as follows (in thousands): 2015 2014 Abandonment liability as of January 1, $ $ Liabilities incurred during period Acquisitions — Divestitures — Revisions Accretion expense Abandonment liability as of December 31, $ $

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities
Summary of accrued liabilities	The following information summarizes accrued liabilities as of December 31, 2015 and 2014 (in thousands): As of December 31, 2015 2014 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Leasehold improvements — Total accrued liabilities $ $

Basis of Presentation and Sum39

Basis of Presentation and Summary of Significant Accounting Policies (Details) $ in Thousands	Sep. 12, 2014USD ($)	Oct. 04, 2013item	Sep. 18, 2013USD ($)	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Jun. 30, 2014	Jun. 27, 2014	May. 12, 2014	Jun. 13, 2013
Oil and Natural Gas Receivables
Allowance for doubtful accounts				$ 0	$ 0
Oil and Natural Gas Properties
Impairment expense				$ 1,365,000	213,821	$ 0
Percentage of the unproved property balance expected to be added to the amortization base during the year 2016				11.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2017				9.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2018				11.00%
Cost of unproved properties excluded from the amortization base
Leasehold acquisition costs				$ 17,211	129,485	78,944	$ 6,566
Exploration costs				343	2,454	2,588	442
Development costs				8,870	5,380	1,246
Total				26,424	137,319	$ 82,778	$ 7,008
Cost of unproved properties excluded from the amortization base, cumulative
Total Leasehold acquisition cost				232,206
Total Exploration cost				5,827
Total development costs				15,496
Total cumulative costs of unproved properties				253,529
Debt Issuance Costs
Amount of cost capitalized which is associated with issuance of debt and amendments to the agreement				400	37,400
Debt issuance costs remaining that are being amortized over the lives of the debt				41,000	48,200
Accumulated amortization				14,700	7,200
Environmental Expenditures
Environmental remediation liability or loss associated with the Company's properties				$ 0	$ 0
Revenue Recognition
Number of Owners required to take production in-kind to generate oil and natural gas imbalances | item				2
Catarina
Debt Issuance Costs
Productive Oil and Gas wells number of wells gross | item				176
Catarina | Bridge Loan
Debt Issuance Costs
Debt issuance cost				$ 3,900
Wycross
Debt Issuance Costs
Interest rate (as a percent)		7.75%
Productive Oil and Gas wells number of wells gross | item		13
Senior Notes 6.125 Percent Due 2023
Debt Issuance Costs
Interest rate (as a percent)				6.125%					6.125%	6.125%
Debt issuance cost	$ 6,400
Senior Notes 6.125 Percent Due 2023 | Catarina
Debt Issuance Costs
Interest rate (as a percent)								6.125%
Senior Notes 7.75 Percent Due 2021
Debt Issuance Costs
Interest rate (as a percent)				7.75%							7.75%
Debt issuance cost			$ 4,200

Basis of Presentation and Sum40

Basis of Presentation and Summary of Significant Accounting Policies (Concentrations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings per Share
Portion of loss allocated to participating securities	$ 0
Customer A
Sales to Major Customers
Concentration risk percentage	7.00%	23.00%	41.00%
Customer B
Sales to Major Customers
Concentration risk percentage	14.00%	4.00%	0.00%
Customer C
Sales to Major Customers
Concentration risk percentage	4.00%	15.00%	23.00%
Customer D
Sales to Major Customers
Concentration risk percentage	38.00%	37.00%	19.00%

Basis of Presentation and Sum41

Basis of Presentation and Summary of Significant Accounting Policies (RecentAcctg) (Details) $ in Thousands	Dec. 31, 2014USD ($)
New accounting pronouncement
Deferred tax asset, non-current	$ 7,443
New accounting pronouncement, early adoption, effect | ASU-Classification of deferred taxes
New accounting pronouncement
Deferred tax liability, current	(33,242)
Deferred tax asset, non-current	$ (33,242)

Acquisitions and Divestitures42

Acquisitions and Divestitures (Details) $ / shares in Units, $ in Thousands	Sep. 12, 2014USD ($)	Jun. 30, 2014USD ($)	Jun. 27, 2014USD ($)	Oct. 04, 2013USD ($)itemshares	May. 31, 2013USD ($)item	Aug. 31, 2013shares	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)	May. 12, 2014
Acquisitions
Proceeds from issuance of debt								$ 100,000	$ 236,000
Total purchase price allocated to assets purchased and liabilities assumed
Common stock issued in acquisition (in shares) | shares						342,760
Unaudited pro forma combined statements of operations
Revenues								825,404
Net loss attributable to common stockholders								$ 115,985
Net loss per common share, basic and diluted (in dollars per share) | $ / shares								$ 2.22
Revenue, post-acquisition							$ 274,364	$ 134,885
Excess of revenues over direct operating expenses, post acquisition							$ 156,095	$ 96,225
Senior Notes 6.125 Percent Due 2023
Acquisitions
Proceeds from issuance of debt	$ 295,900		$ 829,000
Interest rate (as a percent)			6.125%				6.125%			6.125%
Catarina
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties		$ 446,906
Unproved properties		122,224
Other assets acquired		2,682
Fair value of assets acquired		571,812
Asset retirement obligations		(14,723)
Fair value of net assets acquired		557,089
Gross producing wells | item							176
Catarina | Senior Notes 6.125 Percent Due 2023
Acquisitions
Proceeds from issuance of debt		$ 850,000
Interest rate (as a percent)		6.125%
Wycross
Acquisitions
Interest rate (as a percent)				7.75%
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties				$ 215,265
Unproved properties				13,095
Other assets acquired				1,523
Fair value of assets acquired				229,883
Asset retirement obligations				(158)
Other liabilities assumed				(113)
Fair value of net assets acquired				$ 229,612
Gross producing wells | item				13
Common stock issued in acquisition (in shares) | shares				11,040,000
Cotulla
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties					$ 265,466
Unproved properties					16,745
Fair value of assets acquired					282,211
Asset retirement obligations					(1,138)
Other liabilities assumed					(190)
Fair value of net assets acquired					$ 280,883
Gross producing wells | item					53

Acquisitions and Divestitures43

Acquisitions and Divestitures (Divestitures) (Details) - Disposed of by sale, not discontinued operations	Oct. 14, 2015USD ($)aitemshares	Mar. 31, 2015USD ($)itemshares
Palmetto
Divestitures
Number of wellbores having partial interest | item		59
Consideration		$ 83,400,000
Percentage of working interest initially conveyed per wellbore		18.25%
Percentage of working interest owned		47.50%
Percentage of working interest retained per wellbore		2.50%
Consideration in cash		$ 83,000,000
Adjusted consideration in cash		$ 81,400,000
Western Catarina Midstream Divestiture
Divestitures
Consideration	$ 345,800,000
Common units (in shares) | shares	105,263
Term of agreement	15 years
Area under agreement (in acres) | a	35,000
Term of gas gathering agreement	5 years
Deferred gain	$ 74,100,000
SPP | Palmetto
Divestitures
Common units (in shares) | shares		1,052,632
Value of equity method investment		$ 2,000,000
Crude oil | Western Catarina Midstream Divestiture
Divestitures
Daily delivery commitment (in units) | item	10,200
Gathering and processing fees	$ 0.96
Natural gas | Western Catarina Midstream Divestiture
Divestitures
Daily delivery commitment (in units) | item	142,000
Gathering and processing fees	$ 0.74

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash and cash equivalents
Total cash and cash equivalents	$ 435,048	$ 473,714	$ 153,531	$ 50,347
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	35,600	73,528
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	$ 399,448	$ 400,186

Long-Term Debt (Summary) (Detai

Long-Term Debt (Summary) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 27, 2015	Sep. 12, 2014	Jul. 18, 2014	Jun. 30, 2014	Jun. 27, 2014	May. 12, 2014	Sep. 18, 2013	Jun. 13, 2013
Long-Term Debt
Face value of debt	$ 1,750,000	$ 1,750,000
Total long-term debt	1,746,966	1,746,263
Interest expense
Interest on Senior Notes	(116,938)	(78,479)	$ (21,355)
Interest expense and commitment fees on credit agreement	(1,229)	(1,564)	(2,418)
Amortization of debt issuance costs	(7,529)	(9,002)	(6,902)
Amortization of discount on additional 7.75% notes	(904)	(905)	(259)
Amortization of premium on additional 6.125% notes	201	150
Total interest expense	$ (126,399)	(89,800)	$ (30,934)
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Interest rate (as a percent)	7.75%										7.75%
Face value of debt	$ 600,000	600,000				$ 600,000				$ 200,000	$ 400,000
Unamortized discount on Additional 7.75% Notes	$ (4,933)	(5,837)								$ (7,000)
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Interest rate (as a percent)	6.125%							6.125%	6.125%
Face value of debt	$ 1,150,000	1,150,000			$ 300,000		$ 850,000
Unamortized premium on Additional 6.125% Notes	$ 1,899	$ 2,100			$ 2,300
Senior Unsecured Notes
Long-Term Debt
Face value of debt				$ 1,150,000

Long-Term Debt (Detail) (Detail

Long-Term Debt (Detail) (Details)	Jan. 22, 2016USD ($)	Sep. 12, 2014USD ($)	Jun. 27, 2014USD ($)	Sep. 18, 2013USD ($)	Jun. 13, 2013USD ($)	Jun. 30, 2014USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2013USD ($)	Sep. 30, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Oct. 01, 2014USD ($)	Jul. 18, 2014USD ($)	May. 12, 2014USD ($)	May. 31, 2013USD ($)
Long-Term Debt
Face value of debt										$ 1,750,000,000	$ 1,750,000,000
Interest expense										126,399,000	89,800,000	$ 30,934,000
Proceeds from issuance of debt											100,000,000	$ 236,000,000
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Face value of debt				$ 200,000,000	$ 400,000,000					$ 600,000,000	600,000,000					$ 600,000,000
Interest rate (as a percent)					7.75%					7.75%
Proceeds for issuance of notes, net of discount/premium and related offering expenses				$ 188,800,000	$ 388,000,000			$ 192,900,000
Percentage value of Additional Notes at which they are offered in private offering				96.50%
Debt issuance cost				$ 4,200,000
Proceeds from Interest Received									$ 4,100,000
Senior Notes 7.75 Percent Due 2021 | Prior to June 15, 2017
Long-Term Debt
Redemption price of debt instrument (as a percent)										100.00%
Percentage of debt instrument redeem under certain circumstances										35.00%
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Face value of debt		$ 300,000,000				$ 850,000,000				$ 1,150,000,000	1,150,000,000
Interest rate (as a percent)			6.125%							6.125%							6.125%
Proceeds for issuance of notes, net of discount/premium and related offering expenses											$ 299,700,000
Percentage value of Additional Notes at which they are offered in private offering		100.75%
Debt issuance cost		$ 6,400,000
Redemption price of debt instrument (as a percent)										100.00%
Percentage of debt instrument redeem under certain circumstances										35.00%
Proceeds from issuance of debt		295,900,000	$ 829,000,000
Accrued interest							$ 3,800,000
Previous First Lien Credit Agreement
Long-Term Debt
Maximum borrowing capacity																		$ 500,000,000
Face value of debt																	$ 100,000,000
Previous First Lien Credit Agreement | Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Repayment of debt using proceeds from senior note offering			$ 100,000,000														$ 100,000,000
Second Amended And Restated Credit Agreement
Long-Term Debt
Maximum borrowing capacity						1,500,000,000							$ 115,000,000		$ 650,000,000
Borrowing base		$ 362,500,000				$ 300,000,000				$ 500,000,000				$ 550,000,000
Face value of debt										$ 10,000,000
Aggregate elected commitment amount														$ 300,000,000	$ 300,000,000
Percentage of increased net debt used to calculate reduction in borrowing base										25.00%
Threshold on investments to develop a midstream facility													$ 50,000,000
Second Amended And Restated Credit Agreement | Minimum
Long-Term Debt
Percentage of value of asset sales and swaps terminations										10.00%
Percentage of commitment fee on the unused committed amount										0.375%
Current ratio										1
Second Amended And Restated Credit Agreement | Maximum
Long-Term Debt
Percentage of commitment fee on the unused committed amount										0.50%
Ratio of total debt outstanding to consolidated EBITDA						2.25
Second Amended And Restated Credit Agreement | Alternate base rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage										0.50%
Second Amended And Restated Credit Agreement | Alternate base rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage										2.50%
Second Amended And Restated Credit Agreement | Eurodollar rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage										1.50%
Second Amended And Restated Credit Agreement | Eurodollar rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage										2.50%
Letters of credit
Long-Term Debt
Maximum borrowing capacity						$ 80,000,000
Bridge Loan
Long-Term Debt
Maximum borrowing capacity						300,000,000
Interest expense						$ 3,900,000
Subsequent Events | Second Amended And Restated Credit Agreement
Long-Term Debt
Maximum borrowing capacity	$ 2,150,000,000
Borrowing base	$ 425,000,000
Subsequent Events | Second Lien Credit Agreement
Long-Term Debt
Percentage of increased net debt used to calculate reduction in borrowing base	25.00%

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Thousands	Nov. 20, 2015shares	Jul. 28, 2015itemshares	Aug. 28, 2014USD ($)shares	Jun. 12, 2014USD ($)$ / sharesshares	May. 29, 2014USD ($)shares	Feb. 13, 2014shares	Feb. 12, 2014USD ($)shares	Sep. 18, 2013USD ($)$ / sharesshares	Mar. 26, 2013USD ($)$ / sharesshares	Sep. 17, 2012USD ($)$ / sharesshares	Dec. 31, 2015item$ / shares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)
Common stock, par value (in dollars per share) | $ / shares											$ 0.01	$ 0.01
Proceeds from the private placement of preferred stock | $													$ 225,000
Payments for offering costs | $												$ 8,731	$ 20,939
Fair value of the shares of common stock issued in excess of the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed | $			$ 300		$ 3,100		$ 13,900
Number of rights declared for each common stock		1
Number of rights automatically attached | item		1
Common Stock
Number of shares issued				5,000,000				11,040,000
Number of shares issued pursuant to the exercise of over-allotment option by underwriters								1,440,000
Issue price (in dollars per share) | $ / shares				$ 35.25				$ 23
Net proceeds from public offering of shares of common stock | $				$ 167,500				$ 241,400
Payments for offering costs | $				$ 8,700				$ 12,500
Number of shares of common stock to be issued if all preferred shares are converted										4,275,640
Preferred Class A
Number of shares issued										3,000,000
Issue price (in dollars per share) | $ / shares										$ 50
Proceeds from the private placement of preferred stock | $										$ 144,500
Payments for offering costs | $										$ 5,500
Conversion ratio (in shares)						2.325	2.325			2.3250
Conversion price (in dollars per share) | $ / shares										$ 21.51
Annual dividend (as a percent)											4.875%	4.875%
Liquidation preference (in dollars per share) | $ / shares											$ 50
Number of directors who can be elected upon failure to pay dividend for six or more quarters | item											2
Preferred stock converted into shares of common stock			47,500		166,025	947,490	947,490
Shares of common stock issued upon conversion of preferred stock			119,320		418,715	2,425,574	2,425,574
Preferred Class A | Minimum
Period of failure to pay dividend, resulting into appointment of board of directors											1 year 6 months
Condition for automatic conversion: Closing sale price of common stock as a percentage of conversion price for specified period prior to conversion											130.00%
Preferred Class B
Number of shares issued									4,500,000
Issue price (in dollars per share) | $ / shares									$ 50
Proceeds from the private placement of preferred stock | $									$ 216,600
Payments for offering costs | $									$ 8,400
Conversion ratio (in shares)	2.337					2.337	2.337		2.3370
Conversion price (in dollars per share) | $ / shares									$ 21.40
Number of shares of common stock to be issued if all preferred shares are converted									8,255,055
Annual dividend (as a percent)											6.50%	6.50%
Liquidation preference (in dollars per share) | $ / shares											$ 50
Number of directors who can be elected upon failure to pay dividend for six or more quarters | item											2
Preferred stock converted into shares of common stock	4,500				210,820	756,850	756,850
Shares of common stock issued upon conversion of preferred stock	10,517				553,980	2,021,066	2,021,066
Preferred Class B | Minimum
Period of failure to pay dividend, resulting into appointment of board of directors											1 year 6 months
Condition for automatic conversion: Closing sale price of common stock as a percentage of conversion price for specified period prior to conversion											130.00%

Stockholders' Equity (EPS) (Det

Stockholders' Equity (EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings (Loss) Per Share
Net income (loss)	$ (1,454,627)	$ (21,791)	$ 26,898
Preferred stock dividends	(16,008)	(33,590)	(18,525)
Net loss allocable to participating securities			(364)
Net income (loss) attributable to common stockholders	$ (1,470,635)	$ (55,381)	$ 8,009
Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share	57,229,000	52,338,000	36,379,000
Denominator for diluted net loss per common share	57,229,000	52,338,000	36,379,000
Net loss per common share - basic and diluted (in dollars per share)	$ (25.70)	$ (1.06)	$ 0.22
Net income (loss) per common share - basic ( in dollars per share)	$ (25.70)	$ (1.06)	$ 0.22
Outstanding stock awards prior to its initial grants in January 2012	4,425,767	2,718,286
Restricted stock
Earnings (Loss) Per Share
Anti-dilutive common stock	2,663,010	1,732,888	757,963
Outstanding stock awards prior to its initial grants in January 2012		0		0
Convertible Preferred Stock
Earnings (Loss) Per Share
Anti-dilutive common stock	12,529,314	13,527,738	14,979,225

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)item$ / sharesshares	Dec. 31, 2014USD ($)item$ / sharesshares	Dec. 31, 2013USD ($)item$ / sharesshares
Stock-Based Compensation
Maximum number of shares of common stock	4,000,000
Common stock available for incentive awards, as a percentage of the issued and outstanding shares of common stock	15.00%
Granted (in dollars per share) | $ / shares	$ 9.03
Total stock-based compensation expense | $	$ 14,831	$ 12,843	$ 17,751
Number of Non-Vested Shares
Non-vested common stock at the beginning of the period (in shares)	2,718,286
Granted (in shares)	3,482,337
Vested (in shares)	(1,629,221)
Forfeited (in shares)	(145,635)
Non-vested common stock at the end of the period (in shares)	4,425,767	2,718,286
Weighted Average Fair Value
Non-vested common stock at the beginning of the period (in dollars per share) | $ / shares	$ 22.98
Vested (in dollars per share) | $ / shares	22.56
Forfeited (in dollars per share) | $ / shares	21.39
Non-vested common stock at the end of the period (in dollars per share) | $ / shares	$ 12.21	$ 22.98
Aggregate Intrinsic Value
Non-vested common stock at the beginning of the period (in dollars) | $	$ 62,477
Granted (in dollars) | $	31,452
Vested (in dollars) | $	(36,761)
Forfeited (in dollars) | $	(3,115)
Non-vested common stock at the end of the period (in dollars) | $	$ 54,053	$ 62,477
Weighted Average Remaining Contractual Life	1 year 10 months 2 days
Restricted stock
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares	$ 4.31
Unrecognized compensation costs related to non-vested restricted shares outstanding | $	$ 25,700
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	1 year 10 months 2 days
Number of Non-Vested Shares
Shares available for future issuance to participants	5,200,000
Restricted stock | Employees and consultants of SOG, with whom the company has a services agreement
Number of Non-Vested Shares
Granted (in shares)	3,400,000	2,000,000	1,300,000
Restricted stock | Employees and consultants of SOG, with whom the company has a services agreement | Two-year vesting period
Stock-Based Compensation
Vesting period		2 years	2 years
Number of Non-Vested Shares
Granted (in shares)		700,000	500,000
Restricted stock | Employees and consultants of SOG, with whom the company has a services agreement | Three-year vesting period
Stock-Based Compensation
Vesting period	3 years	3 years	3 years
Number of Non-Vested Shares
Granted (in shares)	3,300,000	1,300,000	800,000
Restricted stock | Employees and consultants of SOG, with whom the company has a services agreement | Five-year vesting period
Stock-Based Compensation
Vesting period	5 years
Number of Non-Vested Shares
Granted (in shares)	100,000
Restricted stock | Directors
Stock-Based Compensation
Number of directors to whom awards are issued | item	5	4	3
Vesting period	1 year	1 year	1 year
Granted (in dollars per share) | $ / shares	$ 12.65	$ 33.05	$ 21.98
Total stock-based compensation expense | $	$ 917	$ 802	$ 655
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares	$ 9.80	$ 14.90
Number of Non-Vested Shares
Granted (in shares)	95,237	35,769	28,600
Restricted stock | Non-employees
Stock-Based Compensation
Total stock-based compensation expense | $	$ 13,914	$ 12,041	$ 17,096

Income Taxes - (Details)

Income Taxes - (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of income tax provision
Current expense as a result of current operations	$ 158
Deferred expense (benefit) as a result of current operations	(506,943)	$ (11,429)	$ 10,813
Increase (decrease) in valuation allowance	514,385		(6,827)
Net income tax expense (benefit)	$ 7,600	(11,429)	3,986
Reconciliation of the statutory federal income tax with the income tax provision
Federal statutory corporate income tax rate (as a percent)	35.00%
Income tax expense (benefit) at the federal statutory rate	$ (506,460)	(11,627)	10,809
Officers' compensation limitation	1,328
State Taxes (net of federal benefit)	(5,463)
Non-deductible general and administrative expenses	309	231	4
Percentage depletion carry forward		(107)
Differences between actual income taxes and amounts estimated in prior years	3,501	74
Income tax expense (benefit)	(506,785)	(11,429)	10,813
Valuation allowance	514,385		(6,827)
Net income tax expense (benefit)	7,600	(11,429)	3,986
Deferred tax assets (liabilities):
Derivative assets	(54,638)	(43,087)
Depreciable, depletable property, plant and equipment	288,736
Depreciable, depletable property, plant and equipment (liability)		(178,164)
Share based compensation	2,897	3,221
Revenue Recognition	8,417
Other	(535)	(300)
Federal net operating loss carryforward	268,068	225,773
State net operating loss carryforward	1,440
Deferred tax assets	514,385	7,443
Valuation allowance	(514,385)
Net deferred tax assets		7,443
Net operating loss carryforwards	765,900
Uncertain tax positions	$ 0	$ 0	$ 0

Income Taxes (Reclass) (Details

Income Taxes (Reclass) (Details) $ in Thousands	Dec. 31, 2014USD ($)
New accounting pronouncement
Deferred tax asset, non-current	$ 7,443
New accounting pronouncement, early adoption, effect | ASU-Classification of deferred taxes
New accounting pronouncement
Deferred tax asset, non-current	(33,242)
Deferred tax liability, current	$ (33,242)

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2013USD ($)aitemshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Related Party Transactions
Accounts receivable - related entities		$ 3,697	$ 386
Common stock issued in acquisition (in shares) | shares	342,760
TMS
Related Party Transactions
Number of sellers | item	3
Number of third-parties | item	2
Number of related parties | item	1
Ownership interest in total area of property (as a percent)	50.00%
SOG
Related Party Transactions
Administrative fees		30,430	33,610	$ 19,259
Third-party expenses		5,427	4,515	10,941
Total included in general and administrative expenses		35,857	38,125	$ 30,200
Accounts receivable - related entities		3,700	400
SR
Related Party Transactions
Accounts receivable - related entities		700	$ 100
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item	3
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item	1.5
SR | TMS
Related Party Transactions
Area of property acquired (in acres) | a	40,000
Cash paid	$ 70,000
Company valued	7,500
Cash consideration	$ 14,400
Obligation for working interest for partner's portion of the completed well costs, on the initial wells to be drilled within the AMI (as a percent)	50.00%
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item	6
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item	3
Amount payable in lieu of drilling the two additional wells	$ 8,000
Number of additional wells planned for deferred drilling | item	2
SR | TMS | Maximum
Related Party Transactions
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item	6
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item	3
SPP
Related Party Transactions
Accounts payable - related entities		$ 4,400

Related Party Transactions (Div

Related Party Transactions (Divestiture) (Details) - Disposed of by sale, not discontinued operations - Western Catarina Midstream Divestiture	Oct. 14, 2015USD ($)aitemshares
Divestiture
Common units (in shares) | shares	105,263
Term of agreement	15 years
Area under agreement (in acres) | a	35,000
Term of gas gathering agreement	5 years
Crude oil
Divestiture
Daily delivery commitment (in units) | item	10,200
Gathering and processing fees | $	$ 0.96
Natural gas
Divestiture
Daily delivery commitment (in units) | item	142,000
Gathering and processing fees | $	$ 0.74

Derivative Instruments (Details

Derivative Instruments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Reconciliation of the changes in fair value of the commodity derivatives
Net premiums on derivative contracts | $	$ (121)	$ (596)	$ (1,024)
Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	2,562,000
Average price per unit | $ / bbl	70.11
Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	36,290,000
Average price per unit	3.12
Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	27,945,000
Average price per unit	3
Minimum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	62
Minimum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu	2.54
Minimum | Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu	2.89
Maximum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	80.15
Maximum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.92
Maximum | Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.65

Derivative Instruments (BalShee

Derivative Instruments (BalSheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 178,339	$ 218,977
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(56)	(94,772)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	178,283	124,205
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(56)	(95,661)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	56	94,772
Net Amounts Presented in the Condensed Consolidated Balance Sheets		(889)
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	172,518	194,953
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(24)	(94,772)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	172,494	100,181
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	5,821	24,024
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(32)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	5,789	24,024
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(24)	(94,772)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	24	94,772
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(32)	(889)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	$ 32
Net Amounts Presented in the Condensed Consolidated Balance Sheets		$ (889)

Fair Value of Financial Instr56

Fair Value of Financial Instruments (Details) - Recurring basis - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value of Financial Instruments
Total	$ 577,731	$ 523,502
Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	399,448	400,186
Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Total	399,448	400,186
Active Market for Identical Assets (Level 1) | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	399,448	400,186
Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total	178,283	47,793
Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Total		75,523
Swaps | Crude oil
Fair Value of Financial Instruments
Derivative instruments	72,887	33,975
Swaps | Crude oil | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	72,887	33,975
Swaps | Natural gas
Fair Value of Financial Instruments
Derivative instruments	28,813	13,818
Swaps | Natural gas | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	28,813	13,818
Enhanced swaps | Crude oil
Fair Value of Financial Instruments
Derivative instruments		44,586
Enhanced swaps | Crude oil | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		44,586
Enhanced swaps | Natural gas
Fair Value of Financial Instruments
Derivative instruments		5,193
Enhanced swaps | Natural gas | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		5,193
Three-way collar contracts | Crude oil
Fair Value of Financial Instruments
Derivative instruments		24,264
Three-way collar contracts | Crude oil | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		24,264
Three-way collar contracts | Natural gas
Fair Value of Financial Instruments
Derivative instruments		1,480
Three-way collar contracts | Natural gas | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		$ 1,480
Puts | Crude oil
Fair Value of Financial Instruments
Derivative instruments	76,583
Puts | Crude oil | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	$ 76,583

Fair Value of Financial Instr57

Fair Value of Financial Instruments (Level3 Rec) (Details) - USD ($) $ in Thousands	Nov. 20, 2015	May. 29, 2014	Feb. 13, 2014	Feb. 12, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 27, 2014	May. 12, 2014	Jun. 13, 2013	Mar. 26, 2013
Senior Notes 7.75 Percent Due 2021
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Interest rate (as a percent)					7.75%					7.75%
Senior Notes 6.125 Percent Due 2023
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Interest rate (as a percent)					6.125%			6.125%	6.125%
Recurring basis | Derivative instrument
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Beginning balance					$ 75,523	$ (519)	$ 3,015
Total gains (losses) included in earnings					418	81,404	(8,947)
Net settlements on derivative contracts					(14,277)	(5,362)	5,413
Derivative contracts transferred to Level 2					(61,664)
Ending balance						75,523	(519)
Gains (losses) included in earnings related to derivatives still held					(940)	$ 76,760	$ (6,304)
Recurring basis | Observable Inputs (Level 2) | Derivative instrument
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Net settlements on derivative contracts					(12,919)
Recurring basis | Estimated fair value | Senior Notes 7.75 Percent Due 2021
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Debt fair value					366,000
Recurring basis | Estimated fair value | Senior Notes 6.125 Percent Due 2023
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Debt fair value					$ 615,300
Preferred Class B
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Preferred stock converted into shares of common stock	4,500	210,820	756,850	756,850
Conversion ratio (in shares)	2.337		2.337	2.337							2.3370
Shares of common stock issued upon conversion of preferred stock	10,517	553,980	2,021,066	2,021,066
Preferred Class B | Non-Recurring | Active Market for Identical Assets (Level 1)
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Preferred stock converted into shares of common stock	4,500
Conversion ratio (in shares)	2.337
Shares of common stock issued upon conversion of preferred stock	10,517

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in the asset retirement obligation
Abandonment liability, beginning of period	$ 25,694	$ 4,130
Liabilities incurred during period	6,021	3,922
Acquisitions		14,723
Divestitures	(379)
Revisions	(7,623)	1,658
Accretion expense	2,194	1,261
Abandonment liability, end of period	$ 25,907	$ 25,694

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities
Capital expenditures	$ 51,983	$ 162,726
General and administrative costs	5,214	830
Production taxes	2,532	3,137
Ad valorem taxes	886	1,994
Lease operating expenses	27,077	22,354
Interest payable	34,265	37,743
Leasehold improvements		1,104
Total accrued liabilities	$ 121,957	$ 229,888

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Feb. 05, 2015	Dec. 16, 2013item	Dec. 31, 2015USD ($)aitem	Oct. 02, 2015USD ($)
Operating leases
Lease payment obligation			$ 265.4
Catarina
Commitments and contingencies
Area of undeveloped acreage acquired (in acres) | a			77,000
Maximum number of wells to be drilled in each annual period commencing July 1, 2014 | item			50
Minimum number of wells to be drilled in any consecutive 120 days period in order to continue to maintain rights to any future undeveloped acreage | item			1
Consecutive period over which at least one well can be drilled in order to continue to maintain rights to any future undeveloped acreage			120 days
Maximum number of wells that can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis | item			30
Consolidated Derivative Actions
Commitments and contingencies
Number of derivative actions filed | item		3
Martin v. Sanchez
Commitments and contingencies
Period for which derivative action was stayed	60 days
Corporate office Lease
Operating leases
Lease payment obligation			$ 50.8
Land Lease
Operating leases
Lease payment obligation			$ 7.1
Advanced written notice required to terminate lease obligation			180 days
Lease termination penalty			$ 1
Acreage Lease
Operating leases
Lease payment obligation			$ 6.8
Term of lease			10 years
Permanent improvements
Operating leases
Lease payment obligation			$ 4
Advanced written notice required to terminate lease obligation			6 months
Western Catarina Midstream Divestiture
Operating leases
Lease payment obligation			$ 200.7
Midstream Processing Plant
Investment
Amount committed			60	$ 80
Ownership of equity investment (as a percent)				50.00%
Equity method investment cost			20
Estimated cost of project				$ 160
Minimum ownership (as a percent)				20.00%
Midstream Gathering System
Investment
Amount committed			17.5	$ 35
Ownership of equity investment (as a percent)				50.00%
Equity method investment cost			$ 17.5

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Jun. 27, 2014	May. 12, 2014	Jun. 13, 2013
Ownership interest in Subsidiaries (as a percent)	100.00%
Amount of independent assets	$ 0
Amount of independent operations	$ 0
Senior Notes 7.75 Percent Due 2021
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	7.75%			7.75%
Senior Notes 6.125 Percent Due 2023
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	6.125%	6.125%	6.125%

Investments (Details)

Investments (Details) $ in Millions	Oct. 02, 2015USD ($)Mcf	Dec. 31, 2015USD ($)
Midstream Joint Venture
Investments in marketable securities
Equity method gains (losses)		$ 0
Midstream Processing Plant
Investments in marketable securities
Amount committed	$ 80	60
Ownership of equity investment (as a percent)	50.00%
Equity method investment cost		20
Midstream Gathering System
Investments in marketable securities
Amount committed	$ 35	17.5
Ownership of equity investment (as a percent)	50.00%
Equity method investment cost		17.5
SOII Facility
Investments in marketable securities
Gas processing plant capacity (in MMcf) | Mcf	125,000
Amount committed	$ 12.5
Ownership of equity investment (as a percent)	10.00%
Equity method investment cost		$ 12.5
Targa | SOII Facility
Investments in marketable securities
Ownership of equity investment (as a percent)	90.00%
Minimum | Midstream Processing Plant
Investments in marketable securities
Gas processing plant capacity (in MMcf) | Mcf	200
Maximum | Midstream Processing Plant
Investments in marketable securities
Gas processing plant capacity (in MMcf) | Mcf	260

Subsequent Events (Details)

Subsequent Events (Details)	Jan. 22, 2016USD ($)item	Dec. 31, 2015USD ($)	Oct. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Oct. 01, 2014USD ($)	Sep. 12, 2014USD ($)	Jun. 30, 2014USD ($)
Second Amended And Restated Credit Agreement
Subsequent Events
Borrowing base		$ 500,000,000		$ 550,000,000		$ 362,500,000	$ 300,000,000
Percentage of increased net debt used to calculate reduction in borrowing base		25.00%
Maximum borrowing capacity			$ 115,000,000		$ 650,000,000		$ 1,500,000,000
Second Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Amount of debt allowed to repurchase	$ 98,500,000
Amount of debt allowed to repurchase including equity repurchased	100,000,000
Equity interest purchased	1,500,000
Amount of equity allowed to repurchase	48,500,000
Borrowing base	425,000,000
Maximum borrowing capacity	$ 2,150,000,000
Number of additional unrestricted subsidiaries | item	2
Second Lien Credit Agreement | Subsequent Events
Subsequent Events
Commitments secured for debt financing	$ 400,000,000
Period allowed for debt repayment	180 days
Percentage of increased net debt used to calculate reduction in borrowing base	25.00%